[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2019 Edition]
[From the U.S. Government Publishing Office]



[[Page i]]

          

          Title 30

Mineral Resources


________________________

Parts 200 to 699

                         Revised as of July 1, 2019

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2019
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

[[Page ii]]

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[[Page iii]]




                            Table of contents



                                                                    Page
  Explanation.................................................       v

  Title 30:
          Chapter II--Bureau of Safety and Environmental 
          Enforcement, Department of the Interior                    3
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 357
          Chapter V--Bureau of Ocean Energy Management, 
          Department of the Interior                               369
  Finding Aids:
      Table of CFR Titles and Chapters........................     657
      Alphabetical List of Agencies Appearing in the CFR......     677
      List of CFR Sections Affected...........................     687

[[Page iv]]





                     ----------------------------

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 30 CFR 203.0 refers 
                       to title 30, part 203, 
                       section 0.

                     ----------------------------

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

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[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
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[[Page vii]]

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    Oliver A. Potts,
    Director,
    Office of the Federal Register
    July 1, 2019







[[Page ix]]



                               THIS TITLE

    Title 30--Mineral Resources is composed of three volumes. The parts 
in these volumes are arranged in the following order: parts 1--199, 
parts 200--699, and part 700 to end. The contents of these volumes 
represent all current regulations codified under this title of the CFR 
as of July 1, 2019.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of John 
Hyrum Martinez, assisted by Stephen J. Frattini.

[[Page 1]]



                       TITLE 30--MINERAL RESOURCES




                  (This book contains parts 200 to 699)

  --------------------------------------------------------------------
                                                                    Part

chapter ii--Bureau of Safety and Environmental Enforcement, 
  Department of the Interior................................         203

chapter iv--Geological Survey, Department of the Interior...         401

chapter v--Bureau of Ocean Energy Management, Department of 
  the Interior..............................................         519

[[Page 3]]



 CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT 
                             OF THE INTERIOR




  --------------------------------------------------------------------

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
200-202

[Reserved]

203             Relief or reduction in royalty rates........           5
219

[Reserved]

                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................          44
251             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         309
252             Outer Continental Shelf (OCS) Oil and Gas 
                    Information Program.....................         314
253

[Reserved]

254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         319
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         334
259-260

[Reserved]

270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         336
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         338
281

[Reserved]

282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         339
285

[Reserved]

                          SUBCHAPTER C--APPEALS
290             Appeal procedures...........................         350
291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         351
292-299

[Reserved]

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT



                        PARTS 200	202 [RESERVED]



PART 203_RELIEF OR REDUCTION IN ROYALTY RATES--Table of Contents



                      Subpart A_General Provisions

Sec.
203.0 What definitions apply to this part?
203.1 What is BSEE's authority to grant royalty relief?
203.2 How can I obtain royalty relief?
203.3 Do I have to pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types of 
          leases and projects?
203.5 What is BSEE's authority to collect information?

               Subpart B_OCS Oil, Gas, and Sulfur General

 Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
                        Deep Water Royalty Relief

203.30 Which leases are eligible for royalty relief as a result of 
          drilling a phase 2 or phase 3 ultra-deep well?
203.31 If I have a qualified phase 2 or qualified phase 3 ultra-deep 
          well, what royalty relief would that well earn for my lease?
203.32 What other requirements or restrictions apply to royalty relief 
          for a qualified phase 2 or phase 3 ultra-deep well?
203.33 To which production do I apply the RSV earned by qualified phase 
          2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34 To which production may an RSV earned by qualified phase 2 and 
          phase 3 ultra-deep wells on my lease not be applied?
203.35 What administrative steps must I take to use the RSV earned by a 
          qualified phase 2 or phase 3 ultra-deep well?
203.36 Do I keep royalty relief if prices rise significantly?

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep 
                          Water Royalty Relief

203.40 Which leases are eligible for royalty relief as a result of 
          drilling a deep well or a phase 1 ultra-deep well?
203.41 If I have a qualified deep well or a qualified phase 1 ultra-deep 
          well, what royalty relief would my lease earn?
203.42 What conditions and limitations apply to royalty relief for deep 
          wells and phase 1 ultra-deep wells?
203.43 To which production do I apply the RSV earned from qualified deep 
          wells or qualified phase 1 ultra-deep wells on my lease?
203.44 What administrative steps must I take to use the royalty 
          suspension volume?
203.45 If I drill a certified unsuccessful well, what royalty relief 
          will my lease earn?
203.46 To which production do I apply the royalty suspension supplements 
          from drilling one or two certified unsuccessful wells on my 
          lease?
203.47 What administrative steps do I take to obtain and use the royalty 
          suspension supplement?
203.48 Do I keep royalty relief if prices rise significantly?
203.49 May I substitute the deep gas drilling provisions in this part 
          for the deep gas royalty relief provided in my lease terms?

                  Royalty Relief for End-of-Life Leases

203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will BSEE grant?
203.54 How does my relief arrangement for an oil and gas lease operate 
          if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief 
          arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?

  Royalty Relief for Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects

203.60 Who may apply for royalty relief on a case-by-case basis in deep 
          water in the Gulf of Mexico or offshore of Alaska?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development 
          project?
203.65 How long will BSEE take to evaluate my application?
203.66 What happens if BSEE does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on an 
          authorized field or project?
203.68 What pre-application costs will BSEE consider in determining 
          economic viability?

[[Page 6]]

203.69 If my application is approved, what royalty relief will I 
          receive?
203.70 What information must I provide after BSEE approves relief?
203.71 How does BSEE allocate a field's suspension volume between my 
          lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will BSEE reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might BSEE withdraw or reduce the approved size of my 
          relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief approved by BSEE under this part for my lease, 
          unit or project if prices rise significantly?
203.79 How do I appeal BSEE's decisions related to royalty relief for a 
          deepwater lease or a development or expansion project?
203.80 When can I get royalty relief if I am not eligible for royalty 
          relief under other sections in the subpart?

                            Required Reports

203.81 What supplemental reports do royalty-relief applications require?
203.82 What is BSEE's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

    Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 
2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 
1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-
15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 
1801 et seq.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



                      Subpart A_General Provisions



Sec.  203.0  What definitions apply to this part?

    Authorized field means a field:
    (1) Located in a water depth of at least 200 meters and in the Gulf 
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
    (2) That includes one or more pre-Act leases; and
    (3) From which no current pre-Act lease produced, other than test 
production, before November 28, 1995.
    Certified unsuccessful well means an original well or a sidetrack 
with a sidetrack measured depth (i.e., length) of at least 10,000 feet, 
on your lease that:
    (1) You begin drilling on or after March 26, 2003, and before May 3, 
2009, on a lease that is located in water partly or entirely less than 
200 meters deep and that is not a non-converted lease, or on or after 
May 18, 2007, and before May 3, 2013, on a lease that is located in 
water entirely more than 200 meters and entirely less than 400 meters 
deep;
    (2) You begin drilling before your lease produces gas or oil from a 
well with a perforated interval the top of which is at least 18,000 feet 
true vertical depth subsea (TVD SS), (i.e., below the datum at mean sea 
level);
    (3) You drill to at least 18,000 feet TVD SS with a target reservoir 
on your lease, identified from seismic and related data, deeper than 
that depth;
    (4) Fails to meet the producibility requirements of 30 CFR part 550, 
subpart A, and does not produce gas or oil, or meets those producibility 
requirements and Bureau of Ocean Energy Management (BOEM) agrees it is 
not commercially producible; and
    (5) For which you have provided the notices and information required 
under Sec.  203.47.

[[Page 7]]

    Complete application means an original and two copies of the six 
reports consisting of the data specified in Sec. Sec.  203.81, 203.83, 
and 203.85 through 203.89, along with one set of digital information, 
which Bureau of Safety and Environmental Enforcement (BSEE) has reviewed 
and found complete.
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS and 
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at 
less than 15,000 feet TVD SS in the same reservoir is still a deep well.
    Determination means the binding decision by BSEE on whether your 
field qualifies for relief or how large a royalty-suspension volume must 
be to make the field economically viable.
    Development project means a project to develop one or more oil or 
gas reservoirs located on one or more contiguous leases that have had no 
production (other than test production) before the current application 
for royalty relief and are either:
    (1) Located in a planning area offshore Alaska; or
    (2) Located in the GOM in a water depth of at least 200 meters and 
wholly west of 87 degrees, 30 minutes West longitude, and were issued in 
a sale held after November 28, 2000.
    Draft application means the preliminary set of information and 
assumptions you submit to seek a nonbinding assessment on whether a 
field could be expected to qualify for royalty relief.
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Expansion project means a project that meets the following 
requirements:
    (1) You must propose the project in a (BOEM) Development and 
Production Plan, a BOEM Development Operations Coordination Document 
(DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of the 
Interior after November 28, 1995.
    (2) The project must be located on either:
    (i) A pre-Act lease in the GOM, or a lease in the GOM issued in a 
sale held after November 28, 2000, located wholly west of 87 degrees, 30 
minutes West longitude; or
    (ii) A lease in a planning area offshore Alaska.
    (3) On a pre-Act lease in the GOM, the project:
    (i) Must significantly increase the ultimate recovery of resources 
from one or more reservoirs that have not previously produced (extending 
recovery from reservoirs already in production does not constitute a 
significant increase); and
    (ii) Must involve a substantial capital investment (e.g., fixed-leg 
platform, subsea template and manifold, tension-leg platform, multiple 
well project, etc.).
    (4) For a lease issued in a planning area offshore Alaska, or in the 
GOM after November 28, 2000, the project must involve a new well drilled 
into a reservoir that has not previously produced.
    (5) On a lease in the GOM, the project must not include a reservoir 
the production from which an RSV under Sec. Sec.  203.30 through 203.36 
or Sec. Sec.  203.40 through 203.48 would be applied.
    Fabrication (or start of construction) means evidence of an 
irreversible commitment to a concept and scale of development. Evidence 
includes copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that continuous 
construction has begun, and a receipt for the customary down payment.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata or laterally by local geologic barriers, or both.
    Lease means a lease or unit.
    New production means any production from a current pre-Act lease 
from which no royalties are due on production, other than test 
production, before November 28, 1995. Also, it means any

[[Page 8]]

additional production resulting from new lease-development activities on 
a lease issued in a sale after November 28, 2000, or a current pre-Act 
lease under a BOEM DOCD or a BOEM Supplement approved by the Secretary 
of the Interior after November 28, 1995.
    Nonbinding assessment means an opinion by BSEE of whether your field 
could qualify for royalty relief. It is based on your draft application 
and does not entitle the field to relief.
    Non-converted lease means a lease located partly or entirely in 
water less than 200 meters deep issued in a lease sale held after 
January 1, 2001, and before January 1, 2004, whose original lease terms 
provided for an RSV for deep gas production and the lessee has not 
exercised the option under Sec.  203.49 to replace the lease terms for 
royalty relief with those in Sec.  203.0 and Sec. Sec.  203.40 through 
203.48.
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled from 
the original wellbore either before the drilling rig moves off the well 
location or after a temporary rig move that BSEE agrees was forced by a 
weather or safety threat and drilling resumes within 1 year. A bypass 
from an original well (e.g., drilling around material blocking the hole 
or to straighten crooked holes) is part of the original well.
    Participating area means that part of the unit area that BSEE 
determines is reasonably proven by drilling and completion of producible 
wells, geological and geophysical information, and engineering data to 
be capable of producing hydrocarbons in paying quantities.
    Performance conditions mean minimum conditions you must meet, after 
we have granted relief and before production begins, to remain qualified 
for that relief. If you do not meet each one of these performance 
conditions, we consider it a change in material fact significant enough 
to invalidate our original evaluation and approval.
    Phase 1 ultra-deep well means an ultra-deep well on a lease that is 
located in water partly or entirely less than 200 meters deep for which 
drilling began before May 18, 2007, and that begins production before 
May 3, 2009, or that meets the requirements to be a certified 
unsuccessful well.
    Phase 2 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007; and that either meets the requirements 
to be a certified unsuccessful well or that begins production:
    (1) Before the date which is 5 years after the lease issuance date 
on a non-converted lease; or
    (2) Before May 3, 2009, on all other leases located in water partly 
or entirely less than 200 meters deep; or
    (3) Before May 3, 2013, on a lease that is located in water entirely 
more than 200 meters and entirely less than 400 meters deep.
    Phase 3 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007, and that begins production:
    (1) On or after the date which is 5 years after the lease issuance 
date on a non-converted lease; or
    (2) On or after May 3, 2009, on all other leases located in water 
partly or entirely less than 200 meters deep; or
    (3) On or after May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    Pre-Act lease means a lease that:
    (1) Results from a sale held before November 28, 1995;
    (2) Is located in the GOM in water depths of 200 meters or deeper; 
and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude.
    Production means all oil, gas, and other relevant products you save, 
remove, or sell from a tract or those quantities allocated to your tract 
under a unitization formula, as measured for the purposes of determining 
the amount of royalty payable to the United States.
    Project means any activity that requires at least a permit to drill.
    Qualified deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, a deep well for which 
drilling began on or after March 26, 2003, that produces natural gas 
(other than test production), including gas associated with oil 
production, before May 3, 2009, and for

[[Page 9]]

which you have met the requirements prescribed in Sec.  203.44;
    (2) On a non-converted lease, a deep well that produces natural gas 
(other than test production) before the date which is 5 years after the 
lease issuance date from a reservoir that has not produced from a deep 
well on any lease; or
    (3) On a lease that is located in water entirely more than 200 
meters but entirely less than 400 meters deep, a deep well for which 
drilling began on or after May 18, 2007, that produces natural gas 
(other than test production), including gas associated with oil 
production before May 3, 2013, and for which you have met the 
requirements prescribed in Sec.  203.44.
    Qualified ultra-deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, an ultra-deep well 
for which drilling began on or after March 26, 2003, that produces 
natural gas (other than test production), including gas associated with 
oil production, and for which you have met the requirements prescribed 
in Sec.  203.35 or Sec.  203.44, as applicable; or
    (2) On a lease that is located in water entirely more than 200 
meters and entirely less than 400 meters deep, or on a non-converted 
lease, an ultra-deep well for which drilling began on or after May 18, 
2007, that produces natural gas (other than test production), including 
gas associated with oil production, and for which you have met the 
requirements prescribed in Sec.  203.35.
    Qualified well means either a qualified deep well or a qualified 
ultra-deep well.
    Redetermination means our reconsideration of our determination on 
royalty relief because you request it after:
    (1) We have rejected your application;
    (2) We have granted relief but you want a larger suspension volume;
    (3) We withdraw approval; or
    (4) You renounce royalty relief.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.
    Reservoir means an underground accumulation of oil or natural gas, 
or both, characterized by a single pressure system and segregated from 
other such accumulations.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale offering that lease; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Royalty suspension supplement (RSS) means a royalty suspension 
volume resulting from drilling a certified unsuccessful well that is 
applied to future natural gas and oil production generated at any 
drilling depth on, or allocated under a BSEE-approved unit agreement to, 
the same lease.
    Royalty suspension volume (RSV) means a volume of production from a 
lease that is not subject to royalty under the provisions of this part.
    Sidetrack means, for the purpose of this subpart, a well resulting 
from drilling an additional hole to a new objective bottom-hole location 
by leaving a previously drilled hole. A sidetrack also includes drilling 
a well from a platform slot reclaimed from a previously drilled well or 
re-entering and deepening a previously drilled well. A bypass from a 
sidetrack (e.g., drilling around material blocking the hole, or to 
straighten crooked holes) is part of the sidetrack.
    Sidetrack measured depth means the actual distance or length in feet 
a sidetrack is drilled beginning where it exits a previously drilled 
hole to the bottom hole of the sidetrack, that is, to its total depth.
    Sunk costs for an authorized field means the after-tax eligible 
costs that you (not third parties) incur for exploration, development, 
and production from the spud date of the first discovery on the field to 
the date we receive your complete application for royalty relief. The 
discovery well must be qualified as producible under 30 CFR part 550, 
subpart A. Sunk costs include the rig mobilization and material costs 
for the discovery well that you incurred before its spud date.

[[Page 10]]

    Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the first 
well that encounters hydrocarbons in the reservoir(s) included in the 
application and that meets the producibility requirements under 30 CFR 
part 550, subpart A on each lease participating in the application. Sunk 
costs include rig mobilization and material costs for the discovery 
wells that you incurred before their spud dates.
    Ultra-deep well means either an original well or a sidetrack 
completed with a perforated interval the top of which is at least 20,000 
feet TVD SS. An ultra-deep well subsequently re-perforated less than 
20,000 feet TVD SS in the same reservoir is still an ultra-deep well.
    Withdraw means action we take on a field that has qualified for 
relief if you have not met one or more of the performance conditions.



Sec.  203.1  What is BSEE's authority to grant royalty relief?

    The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as 
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes 
us to grant royalty relief in four situations.
    (a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any 
royalty or a net profit share specified for an OCS lease to promote 
increased production.
    (b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or 
eliminate any royalty or net profit share to promote development, 
increase production, or encourage production of marginal resources on 
certain leases or categories of leases. This authority is restricted to 
leases in the GOM that are west of 87 degrees, 30 minutes West 
longitude, and in the planning areas offshore Alaska.
    (c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for 
designated volumes of new production from any lease if:
    (1) Your lease is in deep water (water at least 200 meters deep);
    (2) Your lease is in designated areas of the GOM (west of 87 
degrees, 30 minutes West longitude);
    (3) Your lease was acquired in a lease sale held before the DWRRA 
(before November 28, 1995);
    (4) We find that your new production would not be economic without 
royalty relief; and
    (5) Your lease is on a field that did not produce before enactment 
of the DWRRA, or if you propose a project to significantly expand 
production under a Development Operations Coordination Document (DOCD) 
or a supplementary DOCD, that the Bureau of Ocean Energy Management 
(BOEM) approved after November 28, 1995.
    (d) Under 42 U.S.C. 15904-15905, we may suspend royalties for 
designated volumes of gas production from deep and ultra-deep wells on a 
lease if:
    (1) Your lease is in shallow water (water less than 400 meters deep) 
and you produce from an ultra-deep well (top of the perforated interval 
is at least 20,000 feet TVD SS) or your lease is in waters entirely more 
than 200 meters and entirely less than 400 meters deep and you produce 
from a deep well (top of the perforated interval is at least 15,000 feet 
TVD SS);
    (2) Your lease is in the designated area of the GOM (wholly west of 
87 degrees, 30 minutes west longitude); and
    (3) Your lease is not eligible for deep water royalty relief.



Sec.  203.2  How can I obtain royalty relief?

    We may reduce or suspend royalties for Outer Continental Shelf (OCS) 
leases or projects that meet the criteria in the following table.

----------------------------------------------------------------------------------------------------------------
                                                                                     Then we may grant you . . .
        If you have a lease . . .                      And if you . . .
----------------------------------------------------------------------------------------------------------------
(a) With earnings that cannot sustain      Would abandon otherwise potentially       A reduced royalty rate on
 production (i.e., End-of-life lease),      recoverable resources but seek to         current monthly production
                                            increase production by operating beyond   and a higher royalty rate
                                            the point at which the lease is           on additional monthly
                                            economic under the existing royalty       production (see Sec.  Sec.
                                            rate,                                       203.50 through 203.56).

[[Page 11]]

 
(b) Located in a designated GOM deep       Propose an expansion project and can      A royalty suspension for a
 water area (i.e., 200 meters or greater)   demonstrate your project is uneconomic    minimum production volume
 and acquired in a lease sale held before   without royalty relief,                   plus any additional
 November 28, 1995, or after November 28,                                             production large enough to
 2000,                                                                                make the project economic
                                                                                      (see Sec.  Sec.   203.60
                                                                                      through 203.79).
(c) Located in a designated GOM deep       Are on a field from which no current pre- A royalty suspension for a
 water area and acquired in a lease sale    Act lease produced (other than test       minimum production volume
 held before November 28, 1995 (Pre-Act     production) before November 28, 1995,     plus any additional volume
 lease),                                    (Authorized field,)                       needed to make the field
                                                                                      economic (see Sec.  Sec.
                                                                                      203.60 through 203.79).
(d) Located in a designated GOM deep       Propose a development project and can     A royalty suspension for a
 water area and acquired in a lease sale    demonstrate that the suspension volume,   minimum production volume
 held after November 28, 2000,              if any, for your lease is not enough to   plus any additional volume
                                            make development economic,                needed to make your
                                                                                      project economic (see Sec.
                                                                                       Sec.   203.60 through
                                                                                      203.79).
(e) Where royalty relief would recover     Are not eligible to apply for end-of-     A royalty modification in
 significant additional resources or,       life or deep water royalty relief, but    size, duration, or form
 offshore Alaska or in certain areas of     show us you meet certain eligibility      that makes your lease or
 the GOM, would enable development,         conditions,                               project economic (see Sec.
                                                                                        203.80).
(f) Located in a designated GOM shallow    Drill a deep well on a lease that is not  A royalty suspension for a
 water area and acquired in a lease sale    eligible for deep water royalty relief    volume of gas produced
 held before January 1, 2001, or after      and you have not previously produced      from successful deep and
 January 1, 2004, or have exercised an      oil or gas from a deep well or an ultra-  ultra-deep wells, or, for
 option to substitute for royalty relief    deep well,                                certain unsuccessful deep
 in your lease terms,                                                                 and ultra-deep wells, a
                                                                                      smaller royalty suspension
                                                                                      for a volume of gas or oil
                                                                                      produced by all wells on
                                                                                      your lease (see Sec.  Sec.
                                                                                        203.40 through 203.49).
(g) Located in a designated GOM shallow    Drill and produce gas from an ultra-deep  A royalty suspension for a
 water area,                                well on a lease that is not eligible      volume of gas produced
                                            for deep water royalty relief and you     from successful ultra-deep
                                            have not previously produced oil or gas   and deep wells on your
                                            from an ultra-deep well,                  lease (see Sec.  Sec.
                                                                                      203.30 through 203.36).
(h) Located in planning areas offshore     Propose an expansion project or propose   A royalty suspension for a
 Alaska,                                    a development project and can             minimum production volume
                                            demonstrate that the project is           plus any additional volume
                                            uneconomic without relief or that the     needed to make your
                                            suspension volume, if any, for your       project economic (see Sec.
                                            lease is not enough to make development    Sec.   203.60, 203.62,
                                            economic,                                 203.67 through 203.70,
                                                                                      203.73, and 203.76 through
                                                                                      203.79).
----------------------------------------------------------------------------------------------------------------



Sec.  203.3  Do I have to pay a fee to request royalty relief?

    When you submit an application or ask for a preview assessment, you 
must include a fee to reimburse us for our costs of processing your 
application or assessment. Federal policy and law require us to recover 
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 
9701), Office of Management and Budget Circular A-25, and the Omnibus 
Appropriations Bill (Pub. L. 104-134, 110 Stat. 1321, April 26, 1996) 
authorize us to collect these fees.
    (a) We will specify the necessary fees for each of the types of 
royalty relief applications and possible BSEE audits in a Notice to 
Lessees. We will periodically update the fees to reflect changes in 
costs, as well as provide other information necessary to administer 
royalty relief.
    (b) You must file all payments electronically through the Fees for 
Services page on the BSEE Web site at http://www.bsee.gov, and you must 
include a copy of the Pay.gov confirmation receipt page with your 
application or assessment.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



Sec.  203.4  How do the provisions in this part apply to different types of leases and projects?

    The tables in this section summarize the similar application and 
approval provisions for the discretionary end-of-life and deep water 
royalty relief programs in Sec. Sec.  203.50 to 203.91. Because royalty 
relief for deep gas on leases not subject to deep water royalty relief, 
as provided for under Sec. Sec.  203.40 to 203.48, does not involve an 
application, its provisions do not parallel the other two royalty relief 
programs and are not summarized in this section.

[[Page 12]]

    (a) We require the information elements indicated by an X in the 
following table and described in Sec. Sec.  203.51, 203.62, and 203.81 
through 203.89 for applications for royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                 Information elements                        lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report.................              X            X            X               X
(2) Net revenue and relief justification report                     X   ...........  ...........
 (prescribed format)..................................
(3) Economic viability and relief justification report  ..............           X            X               X
 (Royalty Suspension Viability Program (RSVP) model
 inputs justified with Geological and Geophysical
 (G&G), Engineering, Production, & Cost reports)......
(4) G&G report........................................  ..............           X            X               X
(5) Engineering report................................  ..............           X            X               X
(6) Production report.................................  ..............           X            X               X
(7) Deep water cost report............................  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (b) We require the confirmation elements indicated by an X in the 
following table and described in Sec. Sec.  203.70, 203.81, 203.90 and 
203.91 to retain royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                 Confirmation elements                       lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report..................  ..............           X            X               X
(2) Post-production development report approved by an   ..............           X            X               X
 independent certified public accountant (CPA) * * *..
----------------------------------------------------------------------------------------------------------------

    (c) The following table indicates by an X, and Sec. Sec.  203.50, 
203.52, 203.60 and 203.67 describe, the prerequisites for our approval 
of your royalty relief application.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                  Approval conditions                        lease                     Pre-act      Development
                                                                         Expansion      lease         project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the                      X
 required level of production.........................
(2) Already producing.................................              X   ...........
(3) A producible well into a reservoir that has not     ..............           X            X               X
 produced before......................................
(4) Royalties for qualifying months exceed 75 percent               X   ...........  ...........
 of net revenue (NR)..................................
(5) Substantial investment on a pre-Act lease (e.g.,    ..............  ...........  ...........
 platform, subsea template)...........................
(6) Determined to be economic only with relief........  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (d) The following table indicates by an X, and Sec. Sec.  203.52, 
203.74, and 203.75 describe, the prerequisites for a redetermination of 
our royalty relief decision.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
              Redetermination conditions                     lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same               X   ...........  ...........
 as for approval......................................
(2) For material change in geologic data, prices,       ..............           X            X               X
 costs, or available technology.......................
----------------------------------------------------------------------------------------------------------------


[[Page 13]]

    (e) The following table indicates by an X, and Sec. Sec.  203.53 and 
203.69 describe, the characteristics of approved royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
 Relief rate and volume, subject to certain conditions       lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on                X   ...........  ...........
 the qualifying amount, 1.5 times pre-application
 effective lease rate on additional production up to
 twice the qualifying amount, and the pre-application
 effective lease rate for any larger volumes..........
(2) Qualifying amount is the average monthly                        X   ...........  ...........
 production for 12 qualifying months..................
(3) Zero royalty rate on the suspension volume and the  ..............           X            X               X
 original lease rate on additional production.........
(4) Suspension volume is at least 17.5, 52.5 or 87.5    ..............  ...........           X
 million barrels of oil equivalent (MMBOE)............
(5) Suspension volume is at least the minimum set in    ..............           X   ...........              X
 the Notice of Sale, the lease, or the regulations....
(6) Amount needed to become economic..................  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (f) The following table indicates by an X, and Sec. Sec.  203.54 and 
203.78 describe, circumstances under which we discontinue your royalty 
relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
               Full royalty resumes when                     lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least              X   ...........  ...........
 25 percent above the average for the qualifying
 months...............................................
(2) Average NYMEX price for last calendar year exceeds  ..............           X            X
 $28/bbl or $3.50/mcf, escalated by the gross domestic
 product (GDP) deflator since 1994....................
(3) Average prices for designated periods exceed        ..............           X   ...........              X
 levels we specify in the Notice of Sale or the lease.
----------------------------------------------------------------------------------------------------------------

    (g) The following table indicates by an X, and Sec. Sec.  203.55, 
203.76, and 203.77 describe, circumstances under which we end or reduce 
royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
              Relief withdrawn or reduced                    lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests.............................              X            X            X               X
(2) Lease royalty rate is at the effective rate for 12              X   ...........  ...........
 consecutive months...................................
(3) Conditions occur that we specified in the approval              X   ...........  ...........
 letter in individual cases...........................
(4) Recipient does not submit post-production report    ..............           X            X               X
 that compares expected to actual costs...............
(5) Recipient changes development system..............  ..............           X            X               X
(6) Recipient excessively delays starting fabrication.  ..............           X            X               X
(7) Recipient spends less than 80 percent of proposed   ..............           X            X               X
 pre-production costs prior to start of production....
(8) Amount of relief volume is produced...............  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------



Sec.  203.5  What is BSEE's authority to collect information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq., and assigned OMB Control Number 1014-0005. The title of this 
information collection is ``30 CFR part 203, Relief or Reduction in 
Royalty Rates.''
    (b) BSEE collects this information to make decisions on the economic 
viability of leases requesting a suspension or elimination of royalty or 
net profit share. Responses are required to obtain

[[Page 14]]

a benefit or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will 
protect information considered proprietary under applicable law and 
under regulations at Sec.  203.61, ``How do I assess my chances for 
getting relief?'' and 30 CFR 250.197, ``Data and information to be made 
available to the public or for limited inspection.''
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



               Subpart B_OCS Oil, Gas, and Sulfur General

 Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
                        Deep Water Royalty Relief



Sec.  203.30  Which leases are eligible for royalty relief as a result
of drilling a phase 2 or phase 3 ultra-deep well?

    Your lease may receive a royalty suspension volume (RSV) under 
Sec. Sec.  203.31 through 203.36 if the lease meets all the requirements 
of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a deep well or an 
ultra-deep well, except as provided in Sec.  203.31(b).
    (c) If the lease is located entirely in more than 200 meters and 
entirely less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec.  203.60 through 203.79.



Sec.  203.31  If I have a qualified phase 2 or qualified phase 3 
ultra-deep well, what royalty relief would that well earn for my lease?

    (a) Subject to the administrative requirements of Sec.  203.35 and 
the price conditions in Sec.  203.36, your qualified well earns your 
lease an RSV shown in the following table in billions of cubic feet 
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec.  203.33:

------------------------------------------------------------------------
   If you have a qualified phase 2 or    Then your lease earns an RSV on
 qualified phase 3 ultra-deep well that   this volume of gas production:
                  is:
------------------------------------------------------------------------
(1) An original well,                    35 BCF.
(2) A sidetrack with a sidetrack         35 BCF.
 measured depth of at least 20,000
 feet,
(3) An ultra-deep short sidetrack that   4 BCF plus 600 MCF times
 is a phase 2 ultra-deep well,           sidetrack measured depth
                                          (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
(4) An ultra-deep short sidetrack that   0 BCF.
 is a phase 3 ultra-deep well,
------------------------------------------------------------------------

    (b)(1) This paragraph applies if your lease:
    (i) Has produced gas or oil from a deep well with a perforated 
interval the top of which is less than 18,000 feet TVD SS;
    (ii) Was issued in a lease sale held between January 1, 2004, and 
December 31, 2005; and
    (iii) The terms of your lease expressly incorporate the provisions 
of Sec. Sec.  203.41 through 203.47 as they existed at the time the 
lease was issued.
    (2) Subject to the administrative requirements of Sec.  203.35 and 
the price conditions in Sec.  203.36, your qualified well earns your 
lease an RSV shown in the

[[Page 15]]

following table in BCF or MCF as prescribed in Sec.  203.33:

------------------------------------------------------------------------
                                         Then your lease earns an RSV on
 If you have a qualified phase 2 ultra-   this volume of gas production:
        deep well that is . . .
------------------------------------------------------------------------
(i) An original well or a sidetrack      10 BCF.
 with a sidetrack measured depth of at
 least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,      4 BCF plus 600 MCF times
                                          sidetrack measured depth
                                          (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (c) Lessees may request a refund of or recoup royalties paid on 
production from qualified phase 2 or phase 3 ultra-deep wells that:
    (1) Occurs before December 18, 2008, and
    (2) Is subject to application of an RSV under either Sec.  203.31 or 
Sec.  203.41.
    (d) The following examples illustrate how this section applies. 
These examples assume that your lease is located in the GOM west of 87 
degrees, 30 minutes West longitude and in water less than 400 meters 
deep (see Sec.  203.30(a)), has no existing deep or ultra-deep wells and 
that the price thresholds prescribed in Sec.  203.36 have not been 
exceeded.

    Example 1: In 2008, you drill and begin producing from an ultra-deep 
well with a perforated interval the top of which is 25,000 feet TVD SS, 
and your lease has had no prior production from a deep or ultra-deep 
well. Assuming your lease has no deepwater royalty relief (see Sec.  
203.30(c)), your lease is eligible (according to Sec.  203.30(b)) to 
earn an RSV under Sec.  203.31 because it has not yet produced from a 
deep well. Your lease earns an RSV of 35 BCF under this section when 
this well begins producing. According to Sec.  203.31(a), your 25,000 
foot well qualifies your lease for this RSV because the well was drilled 
after the relief authorized here became effective (when the proposed 
version of this rule was published on May 18, 2007) and produced from an 
interval that meets the criteria for an ultra-deep well (i.e., is a 
phase 2 ultra-deep well as defined in Sec.  203.0). Then in 2014, you 
drill and produce from another ultra-deep well with a perforated 
interval the top of which is 29,000 feet TVD SS. Your lease earns no 
additional RSV under this section when this second ultra-deep well 
produces, because your lease no longer meets the condition in (Sec.  
203.30(b)) of no production from a deep well. However, any remaining RSV 
earned by the first ultra-deep well on your lease would be applied to 
production from both the first and the second ultra-deep wells as 
prescribed in Sec.  203.33(a)(2), or Sec.  203.33(b)(2) if your lease is 
part of a unit.
    Example 2: In 2005, you spudded and began producing from an ultra-
deep well with a perforated interval the top of which is 23,000 feet TVD 
SS. Your lease earns no RSV under this section from this phase 1 ultra-
deep well (as defined in Sec.  203.0) because you spudded the well 
before the publication date (May 18, 2007) of the proposed rule when 
royalty relief under Sec.  203.31(a) became effective. However, this 
ultra-deep well may earn an RSV of 25 BCF for your lease under Sec.  
203.41 (that became effective May 3, 2004), if the lease is located in 
water depths partly or entirely less than 200 meters and has not 
previously produced from a deep well (Sec.  203.30(b)).
    Example 3: In 2000, you began producing from a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS and your 
lease is located in water 100 meters deep. Then in 2008, you drill and 
produce from a new ultra-deep well with a perforated interval the top of 
which is 24,000 feet TVD SS. Your lease earns no RSV under either this 
section or Sec.  203.41 because the 16,000-foot well was drilled before 
we offered any way to earn an RSV for producing from a deep well (see 
dates in the definition of qualified well in Sec.  203.0) and because 
the existence of the 16,000-foot well means the lease is not eligible 
(see Sec.  203.30(b)) to earn an RSV for the 24,000-foot well. Because 
the lease existed in the year 2000, it cannot be eligible for the 
exception to this eligibility condition provided in Sec.  203.31(b).
    Example 4: In 2008, you spud and produce from an ultra-deep well 
with a perforated interval the top of which is 22,000 feet TVD SS, your 
lease is located in water 300 meters deep, and your lease has had no 
previous production from a deep or ultra-deep well. Your lease earns an 
RSV of 35 BCF under this section when this well begins producing because 
your lease meets the conditions in Sec.  203.30 and the well fits the 
definition of a phase 2 ultra-deep well (in Sec.  203.0). Then in 2010, 
you spud and produce from a deep well with a perforated interval the top 
of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV 
because it is on a lease that already has a producing well at least 
18,000 feet subsea (see Sec.  203.42(a)), but any remaining RSV earned 
by the ultra-deep well would also be applied to production from the deep 
well as prescribed in Sec.  203.33(a)(2), or Sec.  203.33(b)(2) if your 
lease is part of a unit and Sec.  203.43(a)(2),

[[Page 16]]

or Sec.  203.43(b)(2) if your lease is part of a unit. However, if the 
16,000-foot deep well does not begin production until 2016 (or if your 
lease were located in water less than 200 meters deep), then the 16,000-
foot well would not be a qualified deep well because this well does not 
begin production within the interval specified in the definition of a 
qualified well in Sec.  203.0, and the RSV earned by the ultra-deep well 
would not be applied to production from this (unqualified) deep well.
    Example 5: In 2008, you spud a deep well with a perforated interval 
the top of which is 17,000 feet TVD SS that becomes a qualified well and 
earns an RSV of 15 BCF under Sec.  203.41 when it begins producing. Then 
in 2011, you spud an ultra-deep well with a perforated interval the top 
of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a 
qualified ultra-deep well because it meets the date and depth conditions 
in this definition under Sec.  203.0 when it begins producing, but your 
lease earns no additional RSV under this section or Sec.  203.41 because 
it is on a lease that already has production from a deep well (see Sec.  
203.30(b)). Both the qualified deep well and the qualified ultra-deep 
well would share your lease's total RSV of 15 BCF in the manner 
prescribed in Sec. Sec.  203.33 and 203.43.
    Example 6: In 2008, you spud a qualified ultra-deep well that is a 
sidetrack with a sidetrack measured depth of 21,000 feet and a 
perforated interval the top of which is 25,000 feet TVD SS. This well 
meets the definition of an ultra-deep well but is too long to be 
classified an ultra-deep short sidetrack in Sec.  203.0. If your lease 
is located in 150 meters of water and has not previously produced from a 
deep well, your lease earns an RSV of 35 BCF because it was drilled 
after the effective date for earning this RSV. Further, this RSV applies 
to gas production from this and any future qualified deep and qualified 
ultra-deep wells on your lease, as prescribed in Sec.  203.33. The 
absence of an expiration date for earning an RSV on an ultra-deep well 
means this long sidetrack well becomes a qualified well whenever it 
starts production. If your sidetrack has a sidetrack measured depth of 
14,000 feet and begins production in March 2009, it earns an RSV of 12.4 
BCF under this section because it meets the definitions of a phase 2 
ultra-deep well (production begins before the expiration date for the 
pre-existing relief in its water depth category) and an ultra-deep short 
sidetrack in Sec.  203.0. However, if it does not begin production until 
2010, it earns no RSV because it is too short as a phase 3 ultra-deep 
well to be a qualified ultra-deep well.
    Example 7: Your lease was issued in June 2004 and expressly 
incorporates the provisions of Sec. Sec.  203.41 through 203.47 as they 
existed at that time. In January 2005, you spud a deep well (well no. 1) 
with a perforated interval the top of which is 16,800 feet TVD SS that 
becomes a qualified well and earns an RSV of 15 BCF under Sec.  203.41 
when it begins producing. Then in February 2008, you spud an ultra-deep 
well (well no. 2) with a perforated interval the top of which is 22,300 
feet that begins producing in November 2008, after well no. 1 has 
started production. Well no. 2 earns your lease an additional RSV of 10 
BCF under paragraph (b) of this section because it begins production in 
time to be classified as a phase 2 ultra-deep well. If, on the other 
hand, well no. 2 had begun producing in June 2009, it would earn no 
additional RSV for the lease because it would be classified as a phase 3 
ultra-deep well and thus is not entitled to the exception under 
paragraph (b) of this section.



Sec.  203.32  What other requirements or restrictions apply to royalty
relief for a qualified phase 2 or phase 3 ultra-deep well?

    (a) If a qualified ultra-deep well on your lease is within a 
unitized portion of your lease, the RSV earned by that well under this 
section applies only to your lease and not to other leases within the 
unit or to the unit as a whole.
    (b) If your qualified ultra-deep well is a directional well (either 
an original well or a sidetrack) drilled across a lease line, then 
either:
    (1) The lease with the perforated interval that initially produces 
earns the RSV or
    (2) If the perforated interval crosses a lease line, the lease where 
the surface of the well is located earns the RSV.
    (c) Any RSV earned under Sec.  203.31 is in addition to any royalty 
suspension supplement (RSS) for your lease under Sec.  203.45 that 
results from a different wellbore.
    (d) If your lease earns an RSV under Sec.  203.31 and later produces 
from a deep well that is not a qualified well, the RSV is not forfeited 
or terminated, but you may not apply the RSV earned under Sec.  203.31 
to production from the non-qualified well.
    (e) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any RSVs allowed under paragraphs (a) and 
(b) of Sec.  203.31.
    (f) Unused RSVs transfer to a successor lessee and expire with the 
lease.

[[Page 17]]



Sec.  203.33  To which production do I apply the RSV earned by qualified
 phase 2 and phase 3 ultra-deep wells on my lease or in my unit?

    (a) You must apply the RSV allowed in Sec.  203.31(a) and (b) to gas 
volumes produced from qualified wells on or after May 18, 2007, reported 
on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease 
under 30 CFR 1210.102. All gas production from qualified wells reported 
on the OGOR-A, including production not subject to royalty, counts 
toward the total lease RSV earned by both deep or ultra-deep wells on 
the lease.
    (b) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well that is not within a BSEE-approved unit. Subject 
to the price conditions of Sec.  203.36, you must apply the RSV 
prescribed in Sec.  203.31 as required under the following paragraphs 
(b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date the first qualified 
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins 
production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec.  203.35 or Sec.  203.44.
    (c) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well where all or part of the lease is within a BSEE-
approved unit. Under the unit agreement, a share of the production from 
all the qualified wells in the unit participating area would be 
allocated to your lease each month according to the participating area 
percentages. Subject to the price conditions of Sec.  203.36, you must 
apply the RSV prescribed in Sec.  203.31 as follows:
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date that the first 
qualified phase 2 or phase 3 ultra-deep well that earns your lease the 
RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec.  203.35 or Sec.  203.44; and
    (ii) Allocated to your lease under a BSEE-approved unit agreement 
from qualified wells on unitized areas of your lease and on other leases 
in participating areas of the unit, regardless of their depth, for which 
the requirements in Sec.  203.35 or Sec.  203.44 have been met. The 
allocated share under paragraph (a)(2)(ii) of this section does not 
increase the RSV for your lease.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified phase 2 ultra-deep well on the non-unitized 
portion of lease A that earns lease A an RSV of 35 BCF under Sec.  
203.31, one qualified deep well on the unitized portion of lease A 
(drilled after the ultra-deep well on the non-unitized portion of that 
lease) and a qualified phase 2 ultra-deep well on lease B that earns 
lease B a 35 BCF RSV under Sec.  203.31. The participating area 
percentages allocate 40 percent of production from both of the unit 
qualified wells to lease A and 60 percent to lease B. If the non-
unitized qualified phase 2 ultra-deep well on lease A produces 12 BCF, 
and the unitized qualified well on lease A produces 18 BCF, and the 
qualified well on lease B produces 37 BCF, then the production volume 
from and allocated to lease A to which the lease A RSV applies is 34 BCF 
[12 + (18 + 37)(0.40)]. The production volume allocated to lease B to 
which the lease B RSV applies is 33 BCF [(18 + 37)(0.60)]. None of the 
volumes produced from a well that is not within a unit participating 
area may be allocated to other leases in the unit.

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (b) of this section, reaches the applicable RSV 
allowed under Sec.  203.31 or Sec.  203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production from or allocated to your lease that exceeds the RSV 
remaining at the beginning of that month.



Sec.  203.34  To which production may an RSV earned by qualified
phase 2 and phase 3 ultra-deep wells on my lease not be applied?

    You may not apply an RSV earned under Sec.  203.31:

[[Page 18]]

    (a) To production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (b) To production from a deep well or ultra-deep well on any other 
lease, except as provided in paragraph (c) of Sec.  203.33;
    (c) To any liquid hydrocarbon (oil and condensate) volumes; or
    (d) To production from a deep well or ultra-deep well that commenced 
drilling before:
    (1) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep; or
    (2) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.



Sec.  203.35  What administrative steps must I take to use the RSV
 earned by a qualified phase 2 or phase 3 ultra-deep well?

    To use an RSV earned under Sec.  203.31:
    (a) You must notify the BSEE Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all your ultra-deep wells.
    (b) Before beginning production, you must meet any production 
measurement requirements that the BSEE Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
part 250, subpart L.
    (c)(1) Within 30 days of the beginning of production from any wells 
that would become qualified phase 2 or phase 3 ultra-deep wells by 
satisfying the requirements of this section:
    (i) Provide written notification to the BSEE Regional Supervisor for 
Production and Development that production has begun; and
    (ii) Request confirmation of the size of the RSV earned by your 
lease.
    (2) If you produced from a qualified phase 2 or phase 3 ultra-deep 
well before December 18, 2008, you must provide the information in 
paragraph (c)(1) of this section no later than January 20, 2009.
    (d) If you cannot produce from a well that otherwise meets the 
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep 
short sidetrack before May 3, 2009, on a lease that is located entirely 
or partly in water less than 200 meters deep, or before May 3, 2013, on 
a lease that is located entirely in water more than 200 meters but less 
than 400 meters deep, the BSEE Regional Supervisor for Production and 
Development may extend the deadline for beginning production for up to 1 
year, based on the circumstances of the particular well involved, if it 
meets all the following criteria.
    (1) The delay occurred after drilling reached the total depth in 
your well.
    (2) Production (other than test production) was expected to begin 
from the well before May 3, 2009, on a lease that is located entirely or 
partly in water less than 200 meters deep or before May 3, 2013, on a 
lease that is located entirely in water more than 200 meters but less 
than 400 meters deep. You must provide a credible activity schedule with 
supporting documentation.
    (3) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which BSEE deems were 
unavoidable.



Sec.  203.36  Do I keep royalty relief if prices rise significantly?

    (a) You must pay the Office of Natural Resources Revenue royalties 
on all gas production to which an RSV otherwise would be applied under 
Sec.  203.33 for any calendar year in which the average daily closing 
New York Mercantile Exchange (NYMEX) natural gas price exceeds the 
applicable threshold price shown in the following table.

------------------------------------------------------------------------
 A price threshold in year 2007 dollars
                of . . .                         Applies to . . .
------------------------------------------------------------------------
(1) $10.15 per MMBtu,                    (i) The first 25 BCF of RSV
                                          earned under Sec.   203.31(a)
                                          by a phase 2 ultra-deep well
                                          on a lease that is located in
                                          water partly or entirely less
                                          than 200 meters deep issued
                                          before December 18, 2008; and
                                         (ii) Any RSV earned under Sec.
                                           203.31(b) by a phase 2 ultra-
                                          deep well.

[[Page 19]]

 
(2) $4.55 per MMBtu,                     (i) Any RSV earned under Sec.
                                          203.31(a) by a phase 3 ultra-
                                          deep well unless the lease
                                          terms prescribe a different
                                          price threshold;
                                         (ii) The last 10 BCF of the 35
                                          BCF of RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a lease that is
                                          located in water partly or
                                          entirely less than 200 meters
                                          deep issued before December
                                          18, 2008, and that is not a
                                          non-converted lease;
                                         (iii) The last 15 BCF of the 35
                                          BCF of RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a non-converted
                                          lease;
                                         (iv) Any RSV earned under Sec.
                                           203.31(a) by a phase 2 ultra-
                                          deep well on a lease in water
                                          partly or entirely less than
                                          200 meters deep issued on or
                                          after December 18, 2008,
                                          unless the lease terms
                                          prescribe a different price
                                          threshold; and
                                         (v) Any RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a lease in water
                                          entirely more than 200 meters
                                          deep and entirely less than
                                          400 meters deep.
(3) $4.08 per MMBtu,                     (i) The first 20 BCF of RSV
                                          earned by a well that is
                                          located on a non-converted
                                          lease issued in OCS Lease Sale
                                          178.
(4) $5.83 per MMBtu,                     (i) The first 20 BCF of RSV
                                          earned by a well that is
                                          located on a non-converted
                                          lease issued in OCS Lease
                                          Sales 180, 182, 184, 185, or
                                          187.
------------------------------------------------------------------------

    (b) For purposes of paragraph (a) of this section, determine the 
threshold price for any calendar year after 2007 by:
    (1) Determining the percentage of change during the year in the 
Department of Commerce's implicit price deflator for the gross domestic 
product; and
    (2) Adjusting the threshold price for the previous year by that 
percentage.
    (c) The following examples illustrate how this section applies.

    Example 1: Assume that a lessee drills and begins producing from a 
qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in 
less than 200 meters of water that earns the lease an RSV of 35 BCF. 
Further, assume the well produces a total of 18 BCF by the end of 2009 
and in both of those years, the average daily NYMEX closing natural gas 
price is less than $10.15 (adjusted for inflation after 2007). The 
lessee does not pay royalty on the 18 BCF because the gas price 
threshold under paragraph (a)(1) of this section applies to the first 25 
BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the 
well produces another 13 BCF. In that year, the average daily closing 
NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for 
inflation after 2007), but less than $10.15 per MMBtu (adjusted for 
inflation after 2007). The first 7 BCF produced in 2010 will exhaust the 
first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV 
that the well earned. The lessee must pay royalty on the remaining 6 BCF 
produced in 2010, because it is subject to the $4.55 per MMBtu threshold 
under paragraph (a)(2)(ii) of this section which was exceeded.
    Example 2: Assume that a lessee:
    (1) Drills and produces from well no.1, a qualified deep well in 
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the 
lease under Sec.  203.41, which would be subject to a price threshold of 
$10.15 per MMBtu (adjusted for inflation after 2007), meaning the lease 
is partly or entirely in less than 200 meters of water;
    (2) Later in 2008, drills and produces from well no. 2, a second 
qualified deep well to a depth of 17,000 feet TVD SS that earns no 
additional RSV (see Sec.  203.41(c)(1)); and
    (3) In 2015, drills and produces from well no. 3, a qualified phase 
3 ultra-deep well that earns no additional RSV since the lease already 
has an RSV established by prior deep well production. Further assume 
that in 2015, the average daily closing NYMEX natural gas price exceeds 
$4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed 
$10.15 per MMBtu (adjusted for inflation after 2007). In 2015, any 
remaining RSV earned by well no. 1 (which would have been applied to 
production from well nos. 1 and 2 in the intervening years), would be 
applied to production from all three qualified wells. Because the price 
threshold applicable to that RSV was not exceeded, the production from 
all three qualified wells would be royalty-free until the 15 BCF RSV 
earned by well no. 1 is exhausted.
    Example 3: Assume the same initial facts regarding the three wells 
as in Example 2. Further assume that well no. 1 stopped producing in 
2011 after it had produced 8 BCF, and that well no. 2 stopped producing 
in 2012 after it had produced 5 BCF. Two BCF of the RSV earned by well 
no. 1 remain. That RSV would be applied to production from well no.

[[Page 20]]

3 until it is exhausted, and the lessee therefore would not pay royalty 
on those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted 
for inflation after 2007) price threshold is not exceeded. The 
determination of which price threshold applies to deep gas production 
depends on when the first qualified well earned the RSV for the lease, 
not on which wells use the RSV.
    Example 4: Assume that in February 2010, a lessee completes and 
begins producing from an ultra-deep well (at a depth of 21,500 feet TVD 
SS) on a lease located in 325 meters of water with no prior production 
from any deep well and no deep water royalty relief. The ultra-deep well 
would be a phase 2 ultra-deep well (see definition in Sec.  203.0), and 
would earn the lease an RSV of 35 BCF under Sec. Sec.  203.30 and 
203.31. Further assume that the average daily closing NYMEX natural gas 
price exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but 
does not exceed $10.15 per MMBtu (adjusted for inflation after 2007) 
during 2010. Because the lease is located in more than 200 but less than 
400 meters of water, the $4.55 per MMBtu price threshold applies to the 
whole RSV (see paragraph (a)(2)(v) of this section), and the lessee will 
owe royalty on all gas produced from the ultra-deep well in 2010.

    (d) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under 30 CFR 1218.54 from April 1 until the date of payment.
    (e) Production volumes on which you must pay royalty under this 
section count as part of your RSV.

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep 
                          Water Royalty Relief



Sec.  203.40  Which leases are eligible for royalty relief as a
 result of drilling a deep well or a phase 1 ultra-deep well?

    Your lease may receive an RSV under Sec. Sec.  203.41 through 
203.44, and may receive an RSS under Sec. Sec.  203.45 through 203.47, 
if it meets all the requirements of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a well with a 
perforated interval the top of which is 18,000 feet TVD SS or deeper 
that commenced drilling either:
    (1) Before March 26, 2003, on a lease that is located partly or 
entirely in water less than 200 meters deep; or
    (2) Before May 18, 2007, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    (c) In the case of a lease located partly or entirely in water less 
than 200 meters deep, the lease was issued in a lease sale held either:
    (1) Before January 1, 2001;
    (2) On or after January 1, 2001, and before January 1, 2004, and, in 
cases where the original lease terms provided for an RSV for deep gas 
production, the lessee has exercised the option provided for in Sec.  
203.49; or
    (3) On or after January 1, 2004, and the lease terms provide for 
royalty relief under Sec. Sec.  203.41 through 203.47. (Note: Because 
the original Sec.  203.41 has been divided into new Sec. Sec.  203.41 
and 203.42 and subsequent sections have been redesignated as Sec. Sec.  
203.43 through 203.48, royalty relief in lease terms for leases issued 
on or after January 1, 2004, should be read as referring to Sec. Sec.  
203.41 through 203.48.)
    (d) If the lease is located entirely in more than 200 meters and 
less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec.  203.60 through 203.79.



Sec.  203.41  If I have a qualified deep well or a qualified phase 1
 ultra-deep well, what royalty relief would my lease earn?

    (a) To qualify for a suspension volume under paragraphs (b) or (c) 
of this section, your lease must meet the requirements in Sec.  203.40 
and the requirements in the following table.

[[Page 21]]



------------------------------------------------------------------------
                               And if it later . .   Then your lease . .
 If your lease has not . . .            .                     .
------------------------------------------------------------------------
(1) produced gas or oil from  Has a qualified deep  earns an RSV
 any deep well or ultra-deep   well or qualified     specified in
 well,                         phase 1 ultra-deep    paragraph (b) of
                               well,                 this section.
(2) produced gas or oil from  Has a qualified deep  earns an RSV
 a well with a perforated      well with a           specified in
 interval whose top is         perforated interval   paragraph (c) of
 18,000 feet TVD SS or         whose top is 18,000   this section.
 deeper,                       feet TVD SS or
                               deeper or a
                               qualified phase 1
                               ultra-deep well,
------------------------------------------------------------------------

    (b) If your lease meets the requirements in paragraph (a)(1) of this 
section, it earns the RSV prescribed in the following table:

------------------------------------------------------------------------
 If you have a qualified deep well or a  Then your lease earns an RSV on
 qualified phase 1 ultra-deep well that   this volume of gas production:
                  is:
------------------------------------------------------------------------
(1) An original well with a perforated   15 BCF.
 interval the top of which is from
 15,000 to less than 18,000 feet TVD
 SS,
(2) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is from        sidetrack measured depth
 15,000 to less than 18,000 feet TVD      (rounded to the nearest 100
 SS,                                      feet) but no more than 15 BCF.
(3) An original well with a perforated   25 BCF.
 interval the top of which is at least
 18,000 feet TVD SS,
(4) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is at least    sidetrack measured depth
 18,000 feet TVD SS,                      (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
------------------------------------------------------------------------

    (c) If your lease meets the requirements in paragraph (a)(2) of this 
section, it earns the RSV prescribed in the following table. The RSV 
specified in this paragraph is in addition to any RSV your lease already 
may have earned from a qualified deep well with a perforated interval 
whose top is from 15,000 feet to less than 18,000 feet TVD SS.

------------------------------------------------------------------------
 If you have a qualified deep well or a
 qualified phase 1 ultra-deep well that    Then you earn an RSV on this
                is . . .                    amount of gas production:
------------------------------------------------------------------------
(1) An original well or a sidetrack      0 BCF.
 with a perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS,
(2) An original well with a perforated   10 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper,
(3) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper,                   (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (d) Lessees may request a refund of or recoup royalties paid on 
production from qualified wells on a lease that is located in water 
entirely deeper than 200 meters but entirely less than 400 meters deep 
that:
    (1) Occurs before December 18, 2008; and
    (2) Is subject to application of an RSV under either Sec.  203.31 or 
Sec.  203.41.
    (e) The following examples illustrate how this section applies, 
assuming your lease meets the location, prior production, and lease 
issuance conditions in Sec.  203.40 and paragraph (a) of this section:

    Example 1: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
your lease earns an RSV of 15 BCF under paragraph (b)(1) of this 
section. This RSV must be applied to gas production from all qualified 
wells on your lease, as prescribed in Sec. Sec.  203.43 and 203.48. 
However, if the top of the perforated interval is 18,500 feet TVD SS, 
the RSV is 25 BCF according to paragraph (b)(3) of this section.
    Example 2: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 6,789 feet, we round the measured depth to 
6,800 feet and your lease earns an RSV of 8.08 BCF under paragraph 
(b)(2) of this section. This RSV would be applied to gas production from 
all qualified wells on your lease, as prescribed in Sec. Sec.  203.43 
and 203.48.
    Example 3: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15 
BCF. This RSV would be applied to gas production from all qualified 
wells on your lease, as prescribed in Sec. Sec.  203.43 and 203.48, even 
though 4 BCF plus 600 MCF per foot of sidetrack measured

[[Page 22]]

depth equals 15.7 BCF because paragraph (b)(2) of this section limits 
the RSV for a sidetrack at the amount an original well to the same depth 
would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before March 
26, 2003 (and the well therefore is not a qualified well and has earned 
no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your lease 
earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV 
would be applied to gas production from qualified wells on your lease, 
as prescribed in Sec. Sec.  203.43 and 203.48; or
    (iii) A qualified deep well that is a sidetrack with a perforated 
interval the top of which is 19,000 feet TVD SS, that has a sidetrack 
measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under 
paragraph (c)(3) of this section. This RSV would be applied to gas 
production from qualified wells on your lease, as prescribed in 
Sec. Sec.  203.43 and 203.48.
    Example 5: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
and later drill a second qualified well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, we increase 
the total RSV for your lease from 15 BCF to 25 BCF under paragraph 
(c)(2) of this section. We will apply that RSV to gas production from 
all qualified wells on your lease, as prescribed in Sec. Sec.  203.43 
and 203.48. If the second well has a perforated interval the top of 
which is 22,000 feet TVD SS (instead of 19,000 feet), the total RSV for 
your lease would increase to 25 BCF only in 2 situations: (1) If the 
second well was a phase 1 ultra-deep well, i.e., if drilling began 
before May 18, 2007, or (2) the exception in Sec.  203.31(b) applies. In 
both situations, your lease must be partly or entirely in less than 200 
meters of water and production must begin on this well before May 3, 
2009. If drilling of the second well began on or after May 18, 2007, the 
second well would be qualified as a phase 2 or phase 3 ultra-deep well 
and, unless the exception in Sec.  203.31(b) applies, would not earn any 
additional RSV (as prescribed in Sec.  203.30), so the total RSV for 
your lease would remain at 15 BCF.
    Example 6: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 4,000 feet, and later drill a second 
qualified well that is a sidetrack, with a perforated interval the top 
of which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000 
feet, we increase the total RSV for your lease from 6.4 BCF [4 + (600 * 
4,000)/1,000,000] to 15.2 BCF {6.4 + [4 + (600 * 8,000)/
1,000,000)]{time}  under paragraphs (b)(2) and (c)(3) of this section. 
We would apply that RSV to gas production from all qualified wells on 
your lease, as prescribed in Sec. Sec.  203.43 and 203.48. The 
difference of 8.8 BCF represents the RSV earned by the second sidetrack 
that has a perforated interval the top of which is deeper than 18,000 
feet TVD SS.



Sec.  203.42  What conditions and limitations apply to royalty relief
 for deep wells and phase 1 ultra-deep wells?

    The conditions and limitations in the following table apply to 
royalty relief under Sec.  203.41.

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or oil      your lease cannot earn an
 from a well with a perforated interval      RSV under Sec.   203.41 as
 the top of which is 18,000 feet TVD SS or   a result of drilling any
 deeper,                                     subsequent deep wells or
                                             phase 1 ultra-deep wells.
(b) You determine RSV under Sec.   203.41   that determination
 for the first qualified deep well or        establishes the total RSV
 qualified phase 1 ultra-deep well on your   available for that drilling
 lease (whether an original well or a        depth interval on your
 sidetrack) because you drilled and          lease (i.e., either 15,000-
 produced it within the time intervals set   18,000 feet TVD SS, or
 forth in the definitions for qualified      18,000 feet TVD SS and
 wells,                                      deeper), regardless of the
                                             number of subsequent
                                             qualified wells you drill
                                             to that depth interval.
(c) A qualified deep well or qualified      the RSV earned by that well
 phase 1 ultra-deep well on your lease is    under Sec.   203.41 applies
 within a unitized portion of your lease,    only to production from
                                             qualified wells on or
                                             allocated to your lease and
                                             not to other leases within
                                             the unit.
(d) Your qualified deep well or qualified   the lease with the
 phase 1 ultra-deep well is a directional    perforated interval that
 well (either an original well or a          initially produces earns
 sidetrack) drilled across a lease line,     the RSV. However, if the
                                             perforated interval crosses
                                             a lease line, the lease
                                             where the surface of the
                                             well is located earns the
                                             RSV.
(e) You earn an RSV under Sec.   203.41,    that RSV is in addition to
                                             any RSS for your lease
                                             under Sec.   203.45 that
                                             results from a different
                                             wellbore.
(f) Your lease earns an RSV under Sec.      the RSV is not forfeited or
 203.41 and later produces from a well       terminated, but you may not
 that is not a qualified well,               apply the RSV under Sec.
                                             203.41 to production from
                                             the non-qualified well.
(g) You qualify for an RSV under            you still owe minimum
 paragraphs (b) or (c) of Sec.   203.41,     royalties or rentals in
                                             accordance with your lease
                                             terms.

[[Page 23]]

 
(h) You transfer your lease,                unused RSVs transfer to a
                                             successor lessee and expire
                                             with the lease.
------------------------------------------------------------------------


    Example to paragraph (b): If your first qualified deep well is a 
sidetrack with a perforated interval whose top is 16,000 feet TVD SS and 
earns an RSV of 12.5 BCF, and you later drill a qualified original deep 
well to 17,000 feet TVD SS, the RSV for your lease remains at 12.5 BCF 
and does not increase to 15 BCF. However, under paragraph (c) of Sec.  
203.41, if you subsequently drill a qualified deep well to a depth of 
18,000 feet or greater TVD SS, you may earn an additional RSV.



Sec.  203.43  To which production do I apply the RSV earned from
qualified deep wells or qualified phase 1 ultra-deep wells on my lease?

    (a) You must apply the RSV prescribed in Sec.  203.41(b) and (c) to 
gas volumes produced from qualified wells on or after May 3, 2004, 
reported on the OGOR-A for your lease under 30 CFR 1210.102, as and to 
the extent prescribed in Sec. Sec.  203.43 and 203.48.
    (1) Except as provided in paragraph (a)(2) of this section, all gas 
production from qualified wells reported on the OGOR-A, including 
production that is not subject to royalty, counts toward the lease RSV.
    (2) Production to which an RSS applies under Sec. Sec.  203.45 and 
203.46 does not count toward the lease RSV.
    (b) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when no part of the lease is within 
a BSEE-approved unit. Subject to the price conditions in Sec.  203.48, 
you must apply the RSV prescribed in Sec.  203.41 as required under the 
following paragraphs (b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified deep well or 
qualified phase 1 ultra-deep well on a lease that is located entirely or 
partly in water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec.  203.35 or Sec.  203.44.

    Example 1: On a lease in water less than 200 meters deep, you began 
drilling an original deep well with a perforated interval the top of 
which is 18,200 feet TVD SS in September 2003, that became a qualified 
deep well in July 2004, when it began producing and using the RSV that 
it earned. You subsequently drill another original deep well with a 
perforated interval the top of which is 16,600 feet TVD SS, which 
becomes a qualified deep well when production begins in August 2008. The 
first well earned an RSV of 25 BCF (see Sec.  203.41(a)(1) and (b)(3)). 
You must apply any remaining RSV each month beginning in August 2008 to 
production from both wells until the 25 BCF RSV is fully utilized 
according to paragraph (b)(2) of this section. If the second well had 
begun production in August 2009, it would not be a qualified deep well 
because it started production after expiration in May 2009 of the 
ability to qualify for royalty relief in this water depth, and could not 
share any of the remaining RSV (see definition of a qualified deep well 
in Sec.  203.0).
    Example 2: On a lease in water between 200 and 400 meters deep, you 
begin drilling an original deep well with a perforated interval the top 
of which is 17,100 feet TVD SS in November 2010 that becomes a qualified 
deep well in June 2011 when it begins producing and using the RSV. You 
subsequently drill another original deep well with a perforated interval 
the top of which is 15,300 feet TVD SS which becomes a qualified deep 
well by beginning production in October 2011 (see definition of a 
qualified deep well in Sec.  203.0). Only the first well earns an RSV 
equal to 15 BCF (see Sec.  203.41(a) and (b)). You must apply any 
remaining RSV each month beginning in October 2011 to production from 
both qualified deep wells until the 15 BCF RSV is fully utilized 
according to paragraph (b)(2) of this section.

    (c) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when all or part of the lease is 
within a BSEE-approved unit. Under the unit agreement, a share of the 
production from all the qualified wells in the unit

[[Page 24]]

participating area would be allocated to your lease each month according 
to the participating area percentages. Subject to the price conditions 
in Sec.  203.48, you must apply the RSV prescribed under Sec.  203.41 as 
required under the following paragraphs (c)(1) through (3) of this 
section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified well or qualified 
phase 1 ultra-deep well on a lease that is located entirely or partly in 
water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From all qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec.  203.35 or Sec.  203.44; and,
    (ii) Allocated to your lease under a BSEE-approved unit agreement 
from qualified wells on unitized areas of your lease and on unitized 
areas of other leases in the unit, regardless of their depth, for which 
the requirements in Sec.  203.35 or Sec.  203.44 have been met.
    (3) The allocated share under paragraph (c)(2)(ii) of this section 
does not increase the RSV for your lease. None of the volumes produced 
from a well that is not within a unit participating area may be 
allocated to other leases in the unit.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified 19,000-foot TVD SS deep well on the non-
unitized portion of lease A, one qualified 18,500-foot TVD SS deep well 
on the unitized portion of lease A, and a qualified 19,400-foot TVD SS 
deep well on lease B. The participating area percentages allocate 32 
percent of production from both of the unit qualified deep wells to 
lease A and 68 percent to lease B. If the non-unitized qualified deep 
well on lease A produces 12 BCF and the unitized qualified deep well on 
lease A produces 15 BCF, and the qualified deep well on lease B produces 
10 BCF, then the production volume from and allocated to lease A to 
which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The 
production volume allocated to lease B to which the lease B RSV applies 
is 17 BCF [(15 + 10) * (0.68)].

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (c) of this section, reaches the applicable RSV 
allowed under Sec.  203.31 or Sec.  203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production that exceeds the RSV remaining at the beginning of 
that month.
    (e) You may not apply the RSV allowed under Sec.  203.41 to:
    (1) Production from completions less than 15,000 feet TVD SS, except 
in cases where the qualified deep well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (2) Production from a deep well or phase 1 ultra-deep well on any 
other lease, except as provided in paragraph (c) of this section;
    (3) Any liquid hydrocarbon (oil and condensate) volumes; or
    (4) Production from a deep well or phase 1 ultra-deep well that 
commenced drilling before:
    (i) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep, or
    (ii) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.



Sec.  203.44  What administrative steps must I take to use the royalty
suspension volume?

    (a) You must notify the BSEE Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all deep wells and phase 1 ultra-deep wells; and
    (b) Within 30 days of the beginning of production from all wells 
that would become qualified wells by satisfying the requirements of this 
section, you must:
    (1) Provide written notification to the BSEE Regional Supervisor for 
Production and Development that production has begun; and

[[Page 25]]

    (2) Request confirmation of the size of the royalty suspension 
volume earned by your lease.
    (c) Before beginning production, you must meet any production 
measurement requirements that the BSEE Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
part 250, subpart L.
    (d) You must provide the information in paragraph (b) of this 
section by January 20, 2009, if you produced before December 18, 2008, 
from a qualified deep well or qualified phase 1 ultra-deep well on a 
lease that is located entirely in water more than 200 meters and less 
than 400 meters deep.
    (e) The BSEE Regional Supervisor for Production and Development may 
extend the deadline for beginning production for up to one year for a 
well that cannot begin production before the applicable date prescribed 
in the definition of ``qualified deep well'' in Sec.  203.0 if it meets 
all of the following criteria.
    (1) The well otherwise meets the criteria in the definition of a 
qualified deep well in Sec.  203.0.
    (2) The delay in production occurred after reaching total depth in 
the well.
    (3) Production (other than test production) was expected to begin 
from the well before the applicable deadline in the definition of a 
qualified deep well in Sec.  203.0. You must provide a credible activity 
schedule with supporting documentation.
    (4) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which BSEE deems were 
unavoidable.



Sec.  203.45  If I drill a certified unsuccessful well, what royalty
relief will my lease earn?

    Your lease may earn a royalty suspension supplement. Subject to 
paragraph (d) of this section, the royalty suspension supplement is in 
addition to any royalty suspension volume your lease may earn under 
Sec.  203.41.
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec.  203.47, subject to the price 
conditions in Sec.  203.48, your lease earns an RSS shown in the 
following table. The RSS is shown in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) 
and is applicable to oil and gas production as prescribed in Sec.  
203.46.

------------------------------------------------------------------------
                                            Then your lease earns an RSS
                                              on this volume of oil and
 If you have a certified unsuccessful well  gas production as prescribed
                that is:--                    in this section and Sec.
                                                      203.46:--
------------------------------------------------------------------------
(1) An original well and your lease has     5 BCFE.
 not produced gas or oil from a deep well
 or an ultra-deep well,
(2) A sidetrack (with a sidetrack measured  0.8 BCFE plus 120 MCFE times
 depth of at least 10,000 feet) and your     sidetrack measured depth
 lease has not produced gas or oil from a    (rounded to the nearest 100
 deep well or an ultra-deep well,            feet) but no more than 5
                                             BCFE.
(3) An original well or a sidetrack (with   2 BCFE.
 a sidetrack measured depth of at least
 10,000 feet) and your lease has produced
 gas or oil from a deep well with a
 perforated interval the top of which is
 from 15,000 to less than 18,000 feet TVD
 SS,
------------------------------------------------------------------------

    (b) This paragraph applies to oil and gas volumes you report on the 
OGOR-A for your lease under 30 CFR 1210.102.
    (1) You must apply the RSS prescribed in paragraph (a) of this 
section, in accordance with the requirements in Sec.  203.46, to all oil 
and gas produced from the lease:
    (i) On or after December 18, 2008, if your lease is located in water 
more than 200 meters but less than 400 meters deep; or
    (ii) On or after May 3, 2004, if your lease is located in water 
partly or entirely less than 200 meters deep.
    (2) Production to which an RSV applies under Sec. Sec.  203.31 
through 203.33 and Sec. Sec.  203.41 through 203.43 does not count 
toward the lease RSS. All other production, including production that is 
not subject to royalty, counts toward the lease RSS.

    Example 1: If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, your lease earns an RSS of 
5 BCFE that would be applied to gas

[[Page 26]]

and oil production if your lease has not previously produced from a deep 
well or an ultra-deep well, or you earn an RSS of 2 BCFE of gas and oil 
production if your lease has previously produced from a deep well with a 
perforated interval from 15,000 to less than 18,000 feet TVD SS, as 
prescribed in Sec.  203.46.
    Example 2: If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack 
measured depth of 12,545 feet, and your lease has not produced gas or 
oil from any deep well or ultra-deep well, BSEE rounds the sidetrack 
measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of 
gas and oil production as prescribed in Sec.  203.45.

    (c) The conversion from oil to gas for using the royalty suspension 
supplement is specified in Sec.  203.73.
    (d) Each lease is eligible for up to two royalty suspension 
supplements. Therefore, the total royalty suspension supplement for a 
lease cannot exceed 10 BCFE.
    (1) You may not earn more than one royalty suspension supplement 
from a single wellbore.
    (2) If you begin drilling a certified unsuccessful well on one lease 
but the completion target is on a second lease, the entire royalty 
suspension supplement belongs to the second lease. However, if the 
target straddles a lease line, the lease where the surface of the well 
is located earns the royalty suspension supplement.
    (e) If the same wellbore that earns an RSS as a certified 
unsuccessful well later produces from a perforated interval the top of 
which is 15,000 feet TVD or deeper and becomes a qualified well, it will 
be subject to the following conditions:
    (1) Beginning on the date production starts, you must stop applying 
the royalty suspension supplement earned by that wellbore to your lease 
production.
    (2) If the completion of this qualified well is on your lease or, in 
the case of a directional well, is on another lease, then you must 
subtract from the royalty suspension volume earned by that qualified 
well the royalty suspension supplement amounts earned by that wellbore 
that have already been applied either on your lease or any other lease. 
The difference represents the royalty suspension volume earned by the 
qualified well.
    (f) If the same wellbore that earned a royalty suspension supplement 
later has a sidetrack drilled from that wellbore, you are not required 
to subtract any royalty suspension supplement earned by that wellbore 
from the royalty suspension volume that may be earned by the sidetrack.
    (g) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty suspension supplements under 
this section.



Sec.  203.46  To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells on
my lease?

    (a) Subject to the requirements of Sec. Sec.  203.40, 203.43, 
203.45, 203.47, and 203.48 you must apply an RSS in Sec.  203.45 to the 
earliest oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec.  203.47(b),
    (2) From, or allocated under a BSEE-approved unit agreement to, the 
lease on which the certified unsuccessful well was drilled, without 
regard to the drilling depth of the well producing the gas or oil.
    (b) If you have a royalty suspension volume for the lease under 
Sec.  203.41, you must use the royalty suspension volumes for gas 
produced from qualified wells on the lease before using royalty 
suspension supplements for gas produced from qualified wells.

    Example to paragraph (b): You have two shallow oil wells on your 
lease. Then you drill a certified unsuccessful well and earn a royalty 
suspension supplement of 5 BCFE. Thereafter, you begin production from 
an original well that is a qualified well that earns a royalty 
suspension volume of 15 BCF. You use only 2 BCFE of the royalty 
suspension supplement before the oil wells deplete. You must use up the 
15 BCF of royalty suspension volume before you use the remaining 3 BCFE 
of the royalty suspension supplement for gas produced from the qualified 
well.

    (c) If you have no current production on which to apply the RSS 
allowed under Sec.  203.45, your RSS applies to the earliest subsequent 
production of gas and oil from, or allocated under a BSEE-approved unit 
agreement to, your lease.

[[Page 27]]

    (d) Unused royalty suspension supplements transfer to a successor 
lessee and expire with the lease.
    (e) You may not apply the RSS allowed under Sec.  203.45 to 
production from any other lease, except for production allocated to your 
lease from a BSEE-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to a BSEE-approved unit 
agreement, the lessees of other leases in the unit may not apply any 
portion of the RSS for your lease to production from the other leases in 
the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under a BSEE-approved unit 
agreement to, your lease (excluding any gas produced from qualified 
wells subject to a royalty suspension volume allowed under Sec.  203.41) 
reaches the applicable royalty suspension supplement. For the month in 
which the cumulative production reaches this royalty suspension 
supplement, you owe royalties on the portion of gas or oil production 
that exceeds the amount of the royalty suspension supplement remaining 
at the beginning of that month.



Sec.  203.47  What administrative steps do I take to obtain and use
the royalty suspension supplement?

    (a) Before you start drilling a well on your lease targeted to a 
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the 
BSEE Regional Supervisor for Production and Development of your intent 
to begin drilling operations and the depth of the target.
    (b) After drilling the well, you must provide the BSEE Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows BSEE to confirm that you drilled a 
certified unsuccessful well as defined under Sec.  203.0, including:
    (i) Well log data, if your original well or sidetrack does not meet 
the producibility requirements of 30 CFR part 550, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 550, subpart A; 
and
    (2) Information that allows BSEE to confirm the size of the royalty 
suspension supplement for a sidetrack, including sidetrack measured 
depth and supporting documentation.
    (c) If you commenced drilling a well that otherwise meets the 
criteria for a certified unsuccessful well on a lease located entirely 
in more than 200 meters and entirely less than 400 meters of water on or 
after May 18, 2007, and finished it before December 18, 2008, you must 
provide the information in paragraph (b) of this section no later than 
February 17, 2009.



Sec.  203.48  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
an RSV or an RSS otherwise would be allowed under Sec. Sec.  203.40 
through 203.47 for any calendar year when the average daily closing 
NYMEX natural gas price exceeds the applicable threshold price shown in 
the following table.

------------------------------------------------------------------------
For a lease located in                          The applicable threshold
      water . . .          And issued . . .          price is . . .
------------------------------------------------------------------------
(1) Partly or entirely  before December 18,    $10.15 per MMBtu,
 less than 200 meters    2008,                  adjusted annually after
 deep,                                          calendar year 2007 for
                                                inflation.
(2) Partly or entirely  after December 18,     $4.55 per MMBtu, adjusted
 less than 200 meters    2008,                  annually after calendar
 deep,                                          year 2007 for inflation
                                                unless the lease terms
                                                prescribe a different
                                                price threshold.
(3) Entirely more than  on any date,           $4.55 per MMBtu, adjusted
 200 meters and                                 annually after calendar
 entirely less than                             year 2007 for inflation
 400 meters deep,                               unless the lease terms
                                                prescribe a different
                                                price threshold.
------------------------------------------------------------------------

    (b) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.
    (c) You must pay any royalty due under this section no later than 
March

[[Page 28]]

31 of the year following the calendar year for which you owe royalty. If 
you do not pay by that date, you must pay late payment interest under 30 
CFR 1218.54 from April 1 until the date of payment.
    (d) Production volumes on which you must pay royalty under this 
section count as part of your RSV and RSS.



Sec.  203.49  May I substitute the deep gas drilling provisions in
this part for the deep gas royalty relief provided in my lease terms?

    (a) You may exercise an option to replace the applicable lease terms 
for royalty relief related to deep-well drilling with those in Sec.  
203.0 and Sec. Sec.  203.40 through 203.48 if you have a lease issued 
with royalty relief provisions for deep-well drilling. Such leases:
    (1) Must be issued as part of an OCS lease sale held after January 
1, 2001, and before April 1, 2004; and
    (2) Must be located wholly west of 87 degrees, 30 minutes West 
longitude in the GOM entirely or partly in water less than 200 meters 
deep.
    (b) To exercise the option under paragraph (a) of this section, you 
must notify, in writing, the BSEE Regional Supervisor for Production and 
Development of your decision before September 1, 2004, or 180 days after 
your lease is issued, whichever is later, and specify the lease and 
block number.
    (c) Once you exercise the option under paragraph (a) of this 
section, you are subject to all the activity, timing, and administrative 
requirements pertaining to deep gas royalty relief as specified in 
Sec. Sec.  203.40 through 203.48.
    (d) Exercising the option under paragraph (a) of this section is 
irrevocable. If you do not exercise this option, then the terms of your 
lease apply.

                  Royalty Relief for End-of-Life Leases



Sec.  203.50  Who may apply for end-of-life royalty relief?

    You may apply for royalty relief in two situations.
    (a) Your end-of-life lease (as defined in Sec.  203.2) is an oil and 
gas lease and has average daily production of at least 100 barrels of 
oil equivalent (BOE) per month (as calculated in Sec.  203.73) in at 
least 12 of the past 15 months. The most recent of these 12 months are 
considered the qualifying months. These 12 months should reflect the 
basic operation you intend to use until your resources are depleted. If 
you changed your operation significantly (e.g., begin re-injecting 
rather than recovering gas) during the qualifying months, or if you do 
so while we are processing your application, we may defer action on your 
application until you revise it to show the new circumstances.
    (b) Your end-of-life lease is other than an oil and gas lease (e.g., 
sulphur) and has production in at least 12 of the past 15 months. The 
most recent of these 12 months are considered the qualifying months.



Sec.  203.51  How do I apply for end-of-life royalty relief?

    You must submit a complete application and the required fee to the 
appropriate BSEE Regional Director. Your BSEE regional office will 
provide specific guidance on the report formats. A complete application 
for relief includes:
    (a) An administrative information report (specified in Sec.  203.83) 
and
    (b) A net revenue and relief justification report (specified in 
Sec.  203.84).



Sec.  203.52  What criteria must I meet to get relief?

    (a) To qualify for relief, you must demonstrate that the sum of 
royalty payments over the 12 qualifying months exceeds 75 percent of the 
sum of net revenues (before-royalty revenues minus allowable costs, as 
defined in Sec.  203.84).
    (b) To re-qualify for relief, e.g., either applying for additional 
relief on top of relief already granted, or applying for relief sometime 
after your earlier agreement terminated, you must demonstrate that:
    (1) You have met the criterion listed in paragraph (a) of this 
section, and
    (2) The 12 required qualifying months of operation have occurred 
under the current royalty arrangement.



Sec.  203.53  What relief will BSEE grant?

    (a) If we approve your application and you meet certain conditions, 
we

[[Page 29]]

will reduce the pre-application effective royalty rate by one-half on 
production up to the relief volume amount. If you produce more than the 
relief volume amount:
    (1) We will impose a royalty rate equal to 1.5 times the effective 
royalty rate on your additional production up to twice the relief volume 
amount; and
    (2) We will impose a royalty rate equal to the effective rate on all 
production greater than twice the relief volume amount.
    (b) Regardless of the level of production or prices (see Sec.  
203.54), royalty payments due under end-of-life relief will not exceed 
the royalty obligations that would have been due at the effective 
royalty rate.
    (1) The effective royalty rate is the average lease rate paid on 
production during the 12 qualifying months.
    (2) The relief volume amount is the average monthly BOE production 
for the 12 qualifying months.



Sec.  203.54  How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?

    In those months when your current reference price rises by at least 
25 percent above your base reference price, you must pay the effective 
royalty rate on all monthly production.
    (a) Your current reference price is a weighted average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (b) Your base reference price is a weighted average of daily closing 
prices on the NYMEX for light sweet crude oil and natural gas during the 
qualifying months; and
    (c) Your weighting factors are the proportions of your total 
production volume (in BOE) provided by oil and gas during the qualifying 
months.



Sec.  203.55  Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?

    (a) If you have an end-of-life royalty relief arrangement, you may 
renounce it at any time. The lease rate will return to the effective 
rate during the qualifying period in the first full month following our 
receipt of your renouncement of the relief arrangement.
    (b) If you pay the effective lease rate for 12 consecutive months, 
we will terminate your relief. The lease rate will return to the 
effective rate in the first full month following this termination.
    (c) We may stipulate in the letter of approval for individual cases 
certain events that would cause us to terminate relief because they are 
inconsistent with an end-of-life situation.



Sec.  203.56  Does relief transfer when a lease is assigned?

    Yes. Royalty relief is based on the lease circumstances, not 
ownership. It transfers upon lease assignment.

  Royalty Relief for Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects



Sec.  203.60  Who may apply for royalty relief on a case-by-case basis
in deep water in the Gulf of Mexico or offshore of Alaska?

    You may apply for royalty relief under Sec. Sec.  203.61(b) and 
203.62 for an individual lease, unit or project if you:
    (a) Hold a pre-Act lease (as defined in Sec.  203.0) that we have 
assigned to an authorized field (as defined in Sec.  203.0);
    (b) Propose an expansion project (as defined in Sec.  203.0); or
    (c) Propose a development project (as defined in Sec.  203.0).



Sec.  203.61  How do I assess my chances for getting relief?

    You may ask for a nonbinding assessment (a formal opinion on whether 
a field would qualify for royalty relief) before turning in your first 
complete application on an authorized field. This field must have a 
qualifying well under 30 CFR part 550, subpart A, or be on a lease that 
has allocated production under an approved unit agreement.
    (a) To request a nonbinding assessment, you must:
    (1) Submit a draft application in the format and detail specified in 
guidance from the BSEE regional office for the GOM;
    (2) Propose to drill at least one more appraisal well if you get a 
favorable assessment; and
    (3) Pay a fee under Sec.  203.3.

[[Page 30]]

    (b) You must wait at least 90 days after receiving our assessment to 
apply for relief under Sec.  203.62.
    (c) This assessment is not binding because a complete application 
may contain more accurate information that does not support our original 
assessment. It will help you decide whether your proposed inputs for 
evaluating economic viability and your supporting data and assumptions 
are adequate.



Sec.  203.62  How do I apply for relief?

    (a) You must send a complete application and the required fee to the 
BSEE Regional Director for your region.
    (b) Your application for royalty relief offshore Alaska or in deep 
water in the GOM must include an original and two copies (one set of 
digital information) of:
    (1) Administrative information report;
    (2) Economic viability and relief justification report;
    (3) G&G report;
    (4) Engineering report;
    (5) Production report; and
    (6) Cost report.
    (c) Section 203.82 explains why we are authorized to require these 
reports.
    (d) Sections 203.81, 203.83, and 203.85 through 203.89 describe what 
these reports must include. The BSEE regional office for your region 
will guide you on the format for the required reports, and we encourage 
you to contact this office before preparing your application for this 
guidance.



Sec.  203.63  Does my application have to include all leases in the field?

    (a) For authorized fields, we will accept only one joint application 
for all leases that are part of the designated field on the date of 
application, except as provided in paragraph (a)(3) of this section and 
Sec.  203.64. However, we will evaluate all acreage that may eventually 
become part of the authorized field. Therefore, if you have any other 
leases that you believe may eventually be part of the authorized field, 
you must submit data for these leases according to Sec.  203.81.
    (1) The Regional Director maintains a Field Names Master List with 
updates of all leases in each designated field.
    (2) To avoid sharing proprietary data with other lessees on the 
field, you may submit your proprietary G&G report separately from the 
rest of your application. Your application is not complete until we 
receive all the required information for each lease on the field. We 
will not disclose proprietary data when explaining our assumptions and 
reasons for our determinations under Sec.  203.67.
    (3) We will not require a joint application if you show good cause 
and honest effort to get all lessees in the field to participate. If you 
must exclude a lease from your application because its lessee will not 
participate, that lease is ineligible for the royalty relief for the 
designated field.
    (b) If your application seeks only relief for a development project 
or an expansion project, your application does not have to include all 
leases in the field.



Sec.  203.64  How many applications may I file on a field or a 
development project?

    You may file one complete application for royalty relief during the 
life of the field or for a development project or an expansion project 
designed to produce a reservoir or set of reservoirs. However, you may 
send another application if:
    (a) You are eligible to apply for a redetermination under Sec.  
203.74;
    (b) You apply for royalty relief for an expansion project;
    (c) You withdraw the application before we make a determination; or
    (d) You apply for end-of-life royalty relief.



Sec.  203.65  How long will BSEE take to evaluate my application?

    (a) We will determine within 20 working days if your application for 
royalty relief is complete. If your application is incomplete, we will 
explain in writing what it needs. If you withdraw a complete 
application, you may reapply.
    (b) We will evaluate your first application on a field within 180 
days, evaluate your first application on a development project or an 
expansion project

[[Page 31]]

within 150 days and evaluate a redetermination under Sec.  203.75 within 
120 days after we determine that it is complete.
    (c) We may ask to extend the review period for your application 
under the conditions in the following table.

------------------------------------------------------------------------
                If . . .                        Then we may . . .
------------------------------------------------------------------------
(1) We need more records to audit sunk   Ask to extend the 120-day or
 costs,                                   180-day evaluation period. The
                                          extension we request will
                                          equal the number of days
                                          between when you receive our
                                          request for records and the
                                          day we receive the records.
(2) We cannot evaluate your application  Add another 30 days. We may add
 for a valid reason, such as missing      more than 30 days, but only if
 vital information or inconsistent or     you agree.
 inconclusive supporting data,
(3) We need more data, explanations, or  Ask to extend the 120-day or
 revision,                                180-day evaluation period. The
                                          extension we request will
                                          equal the number of days
                                          between when you receive our
                                          request and the day we receive
                                          the information.
------------------------------------------------------------------------

    (d) We may change your assumptions under Sec.  203.62 if our 
technical evaluation reveals others that are more appropriate. We may 
consult with you before a final decision and will explain any changes.
    (e) We will notify all designated lease operators within a field 
when royalty relief is granted.



Sec.  203.66  What happens if BSEE does not act in the time allowed?

    If we do not act within the timeframes established under Sec.  
203.65, you get royalty relief according to the following table.

------------------------------------------------------------------------
                              And we do not decide
  If you apply for royalty       within the time       As long as you
         relief for                specified,
------------------------------------------------------------------------
(a) An authorized field,      You get the minimum   Abide by Sec.  Sec.
                               suspension volumes     203.70 and 203.76.
                               specified in Sec.
                               203.69,
(b) An expansion project,     You get a royalty     Abide by Sec.  Sec.
                               suspension for the     203.70 and 203.76.
                               first year of
                               production,
(c) A development project,    You get a royalty     Abide by Sec.  Sec.
                               suspension for         203.70 and 203.76.
                               initial production
                               for the number of
                               months that a
                               decision is delayed
                               beyond the
                               stipulated
                               timeframes set by
                               Sec.   203.65, plus
                               all the royalty
                               suspension volume
                               for which you
                               qualify,
------------------------------------------------------------------------



Sec.  203.67  What economic criteria must I meet to get royalty relief
on an authorized field or project?

    We will not approve applications if we determine that royalty relief 
cannot make the field, development project, or expansion project 
economically viable. Your field or project must be uneconomic while you 
are paying royalties and must become economic with royalty relief.



Sec.  203.68  What pre-application costs will BSEE consider in
determining economic viability?

    (a) We will not consider ineligible costs as set forth in Sec.  
203.89(h) in determining economic viability for purposes of royalty 
relief.
    (b) We will consider sunk costs according to the following table.

----------------------------------------------------------------------------------------------------------------
                    We will . . .                                       When determining . . .
----------------------------------------------------------------------------------------------------------------
(1) Include sunk costs,                               Whether a field that includes a pre-Act lease which has
                                                       not produced, other than test production, before the
                                                       application or redetermination submission date needs
                                                       relief to become economic.
(2) Not include sunk costs,                           Whether an authorized field, a development project, or an
                                                       expansion project can become economic with full relief
                                                       (see Sec.   203.67).
(3) Not include sunk costs,                           How much suspension volume is necessary to make the field,
                                                       a development project, or an expansion project economic
                                                       (see Sec.   203.69(c)).
(4) Include sunk costs for the project discovery      Whether a development project or an expansion project
 well on each lease,                                   needs relief to become economic.
----------------------------------------------------------------------------------------------------------------


[[Page 32]]



Sec.  203.69  If my application is approved, what royalty relief
 will I receive?

    If we approve your application, subject to certain conditions, we 
will not collect royalties on a specified suspension volume for your 
field, development project, or expansion project. Suspension volumes 
include volumes allocated to a lease under an approved unit agreement, 
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel 
gas).
    (a) For authorized fields, the minimum royalty-suspension volumes 
are:
    (1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 
to 400 meters of water;
    (2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
    (3) 87.5 MMBOE for fields in more than 800 meters of water.
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty relief, if any, with which we 
issued your lease.
    (c) If your project is economic given the royalty relief with which 
we issued your lease, we will reject the application.
    (d) If the lease has earned or may earn deep gas royalty relief 
under Sec. Sec.  203.40 through 203.49 or ultra-deep gas royalty relief 
under Sec. Sec.  203.30 through 203.36, we will take the deep gas 
royalty relief or ultra-deep gas royalty relief into account in 
determining whether further royalty relief for a development project is 
necessary for production to be economic.
    (e) If neither paragraph (c) nor (d) of this section apply, the 
minimum royalty suspension volumes are as shown in the following table:

------------------------------------------------------------------------
                                  The minimum royalty
           For . . .            suspension volume is .     Plus . . .
                                          . .
------------------------------------------------------------------------
(1) RS leases in the GOM or     A volume equal to the   10 percent of
 leases offshore Alaska,         combined royalty        the median of
                                 suspension volumes      the
                                 (or the volume          distribution of
                                 equivalent based on     known
                                 the data in your        recoverable
                                 approved application    resources upon
                                 for other forms of      which BSEE
                                 royalty suspension)     based approval
                                 with which BSEE         of your
                                 issued the leases       application
                                 participating in the    from all
                                 application that have   reservoirs
                                 or plan a well into a   included in the
                                 reservoir identified    project.
                                 in the application,
(2) Leases offshore Alaska or   A volume equal to 10
 other deep water GOM leases     percent of the median
 issued in sales after           of the distribution
 November 28, 2000,              of known recoverable
                                 resources upon which
                                 BSEE based approval
                                 of your application
                                 from all reservoirs
                                 included in the
                                 project.
------------------------------------------------------------------------

    (f) If your application includes pre-Act leases in different 
categories of water depth, we apply the minimum royalty suspension 
volume for the deepest such lease then assigned to the field. We base 
the water depth and makeup of a field on the water-depth delineations in 
the ``Lease Terms and Economic Conditions'' map and the ``Fields 
Directory'' documents and updates in effect at the time your application 
is deemed complete. These publications are available from the BSEE Gulf 
of Mexico Regional Office.
    (g) You will get a royalty suspension volume above the minimum if we 
determine that you need more to make the field or development project 
economic.
    (h) For expansion projects, the minimum royalty suspension volume 
equals 10 percent of the median of the distribution of known recoverable 
resources upon which we based approval of your application from all 
reservoirs included in your project plus any suspension volumes required 
under Sec.  203.66. If we determine that your expansion project may be 
economic only with more relief, we will determine and grant you the 
royalty suspension volume necessary to make the project economic.
    (i) The royalty suspension volume applicable to specific leases will 
continue through the end of the month in which cumulative production 
reaches that volume. You must calculate cumulative production from all 
the leases in the authorized field or project that are entitled to share 
the royalty suspension volume.

[[Page 33]]



Sec.  203.70  What information must I provide after BSEE approves relief?

    You must submit reports to us as indicated in the following table. 
Sections 203.81, 203.90, and 203.91 describe what these reports must 
include. The BSEE Regional Office for your region will prescribe the 
formats.

------------------------------------------------------------------------
       Required report          When due to BSEE     Due date extensions
------------------------------------------------------------------------
(a) Fabricator's              Within 18 months      BSEE Director may
 confirmation report.          after approval of     grant you an
                               relief.               extension under
                                                     Sec.   203.79(c)
                                                     for up to 6 months.
(b) Post-production report.   Within 120 days       With acceptable
                               after the start of    justification from
                               production that is    you, the BSEE
                               subject to the        Regional Director
                               approved royalty      for your region may
                               suspension volume.    extend the due date
                                                     up to 30 days.
------------------------------------------------------------------------



Sec.  203.71  How does BSEE allocate a field's suspension volume
 between my lease and other leases on my field?

    The allocation depends on when production occurs, when we issued the 
lease, when we assigned it to the field, and whether we award the volume 
suspension by an approved application or establish it in the lease 
terms, as prescribed in this section.
    (a) If your authorized field has an approved royalty suspension 
volume under Sec. Sec.  203.67 and 203.69, we will suspend payment of 
royalties on production from all leases in the field that participate in 
the application until their cumulative production equals the approved 
volume. The following conditions also apply:

------------------------------------------------------------------------
          If . . .                 Then . . .             And . . .
------------------------------------------------------------------------
(1) We assign an eligible     We will not change    Production from the
 lease to your authorized      your authorized       assigned eligible
 field after we approve        field's royalty       lease(s) counts
 relief,                       suspension volume     toward the royalty
                               determined under      suspension volume
                               Sec.   203.69,        for the authorized
                                                     field, but the
                                                     eligible lease will
                                                     not share any
                                                     remaining royalty
                                                     suspension volume
                                                     for the authorized
                                                     field after the
                                                     eligible lease has
                                                     produced the volume
                                                     applicable under 30
                                                     CFR 560.114.
(2) We assign a pre-Act or    We will not change    The assigned
 post-November 2000 deep       your field's          lease(s) may share
 water lease to your field     royalty suspension    in any remaining
 after we approve your         volume,               royalty relief by
 application,                                        filing the short-
                                                     form application
                                                     specified in Sec.
                                                     203.83 and
                                                     authorized in Sec.
                                                      203.82. An
                                                     assigned RS lease
                                                     also gets any
                                                     portion of its
                                                     royalty suspension
                                                     volume remaining
                                                     even after the
                                                     field has produced
                                                     the approved relief
                                                     volume.
(3) We assign another lease   In our evaluation of  (i) You toll the
 that you operate to your      your authorized       time period for
 field while we are            field, we will take   evaluation until
 evaluating your               into account the      you modify your
 application,                  value of any          application to be
                               royalty relief the    consistent with the
                               added lease already   newly constituted
                               has under 30 CFR      field;
                               560.114 or its       (ii) We have an
                               lease document. If    additional 60 days
                               we find your          to review the new
                               authorized field      information; and
                               still needs          (iii) The assigned
                               additional royalty    pre-Act lease or
                               suspension volume,    royalty suspension
                               that volume will be   lease shares the
                               at least the          royalty suspension
                               combined royalty      we grant to the
                               suspension volume     newly constituted
                               to which all added    field. An eligible
                               leases on the field   lease does not
                               are entitled, or      share the royalty
                               the minimum           suspension we grant
                               suspension volume     to the new field.
                               of the authorized     If you do not agree
                               field, whichever is   to toll, we will
                               greater,              have to reject your
                                                     application due to
                                                     incomplete
                                                     information.
                                                     Production from an
                                                     assigned eligible
                                                     lease counts toward
                                                     the royalty
                                                     suspension volume
                                                     that we grant under
                                                     Sec.   203.69 for
                                                     your authorized
                                                     field, but you will
                                                     not owe royalty on
                                                     production from the
                                                     eligible lease
                                                     until it has
                                                     produced the volume
                                                     applicable under 30
                                                     CFR 560.114.

[[Page 34]]

 
(4) We assign another         We will change your   (i) You both toll
 operator's lease to your      field's minimum       the time period for
 field while we are            suspension volume     evaluation until
 evaluating your               provided the          both of you modify
 application,                  assigned lease        your application to
                               joins the             be consistent with
                               application and is    the new field;
                               entitled to a        (ii) We have an
                               larger minimum        additional 60 days
                               suspension volume,    to review the new
                                                     information; and
                                                    (iii) The assigned
                                                     lease(s) shares the
                                                     royalty suspension
                                                     we grant to the new
                                                     field. If you (the
                                                     original applicant)
                                                     do not agree to
                                                     toll, the other
                                                     operator's lease
                                                     retains any
                                                     suspension volume
                                                     it has or may share
                                                     in any relief that
                                                     we grant by filing
                                                     the short form
                                                     application
                                                     specified in Sec.
                                                     203.83 and
                                                     authorized in Sec.
                                                      203.82.
(5) We reassign a well on a   The past production   For any field based
 pre-Act, eligible, or         from the well         relief, the past
 royalty suspension lease      counts toward the     production for that
 from field A to field B,      royalty suspension    well will not count
                               volume that we        toward any royalty
                               grant under Sec.      suspension volume
                               203.69 to field B,    that we grant under
                                                     Sec.   203.69 to
                                                     field A. Moreover,
                                                     past production
                                                     from that well will
                                                     count toward the
                                                     royalty suspension
                                                     volume applicable
                                                     for the lease under
                                                     30 CFR 560.114 if
                                                     the well is on an
                                                     eligible lease or
                                                     under 30 CFR
                                                     560.124 if the well
                                                     is on a royalty
                                                     suspension lease.
------------------------------------------------------------------------

    (b) When a project has more than one lease, the royalty suspension 
volume for each lease equals that lease's actual production from the 
project (or production allocated under an approved unit agreement) until 
total production for all leases in the project equals the project's 
approved royalty suspension volume.
    (c) You may receive a royalty-suspension volume only if your entire 
lease is west of 87 degrees, 30 minutes West longitude. If the field 
lies on both sides of this meridian, only leases located entirely west 
of the meridian will receive a royalty-suspension volume.



Sec.  203.72  Can my lease receive more than one suspension volume?

    Yes. You may apply for royalty relief that involves more than one 
suspension volume under Sec.  203.62 in two circumstances.
    (a) Each field that includes your lease may receive a separate 
royalty-suspension volume, if it meets the evaluation criteria of Sec.  
203.67.
    (b) An expansion project on your lease may receive a separate 
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the 
reserves associated with the project must not have been part of our 
original determination, and the project must meet the evaluation 
criteria of Sec.  203.67.



Sec.  203.73  How do suspension volumes apply to natural gas?

    You must measure natural gas production under the royalty-suspension 
volume as follows: 5.62 thousand cubic feet of natural gas, measured in 
accordance with 30 CFR part 250, subpart L, equals one barrel of oil 
equivalent.



Sec.  203.74  When will BSEE reconsider its determination?

    You may request a redetermination after we withdraw approval or 
after you renounce royalty relief, unless we withdraw approval due to 
your providing false or intentionally inaccurate information. Under 
certain conditions you may also request a redetermination if we deny 
your application or if you want your approved royalty suspension volume 
to change. In these instances, to be eligible for a redetermination, at 
least one of the following four conditions must occur.
    (a) You have significant new G&G data and you previously have not 
either requested a redetermination or reapplied for relief after we 
withdrew approval or you relinquished royalty relief. ``Significant'' 
means that the new G&G data:
    (1) Results from drilling new wells or getting new three-dimensional 
seismic data and information (but not reinterpreting old data);
    (2) Did not exist at the time of the earlier application; and

[[Page 35]]

    (3) Changes your estimates of gross resource size, quality, or 
projected flow rates enough to materially affect the results of our 
earlier determination.
    (b) You demonstrate in your new application that the technology that 
most efficiently develops this field or lease was not considered or 
deemed feasible in the original application. Your newly proposed 
technology must improve the profitability, under equivalent market 
conditions, of the field or lease relative to the development system 
proposed in the prior application.
    (c) Your current reference price decreases by more than 25 percent 
from your base reference price as calculated under this paragraph.
    (1) Your current reference price is a weighted-average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (2) Your base reference price is a weighted average of daily closing 
prices on the NYMEX for light sweet crude oil and natural gas for the 
full 12 calendar months preceding the date of your most recently 
approved application for this royalty relief; and
    (3) The weighting factors are the proportions of the total 
production volume (in BOE) for oil and gas associated with the most 
likely scenario (identified in Sec. Sec.  203.85 and 203.88) from your 
most recently approved application for this royalty relief.
    (d) Before starting to build your development and production system, 
you have revised your estimated development costs, and they are more 
than 120 percent of the eligible development costs associated with the 
most likely scenario from your most recently approved application for 
this royalty relief.



Sec.  203.75  What risk do I run if I request a redetermination?

    If you request a redetermination after we have granted you a 
suspension volume, you could lose some or all of the previously granted 
relief. This can happen because you must file a new complete application 
and pay the required fee, as discussed in Sec.  203.62. We will evaluate 
your application under Sec.  203.67 using the conditions prevailing at 
the time of your redetermination request. In our evaluation, we may find 
that you should receive a larger, equivalent, smaller, or no suspension 
volume. This means we could find that you do not qualify for the amount 
of relief previously granted or for any relief at all.



Sec.  203.76  When might BSEE withdraw or reduce the approved size
 of my relief?

    We will withdraw approval of relief for any of the following 
reasons.
    (a) You change the type of development system proposed in your 
application (e.g., change from a fixed platform to floating production 
system, or from an independent development and production system to one 
with subsea wells tied back to a host production facility, etc.).
    (b) You do not start building the proposed development and 
production system within 18 months of the date we approved your 
application, unless the BSEE Director grants you an extension under 
Sec.  203.79(c). If you start building the proposed system and then 
suspend its construction before completion, and you do not restart 
continuous building of the proposed system within 18 months of our 
approval, we will withdraw the relief we granted.
    (c) Your actual development costs are less than 80 percent of the 
eligible development costs estimated in your application's most likely 
scenario, and you do not report that fact in your post-production 
development report (Sec.  203.70). Development costs are those 
expenditures defined in Sec.  203.89(b) incurred between the application 
submission date and start of production. If you report this fact in the 
post-production development report, you may retain the lesser of 50 
percent of the original royalty suspension volume or 50 percent of the 
median of the distribution of the potentially recoverable resources 
anticipated in your application.
    (d) We granted you a royalty-suspension volume after you qualified 
for a redetermination under Sec.  203.74(c), and we find out your actual 
development costs are less than 90 percent of the eligible development 
costs associated with your application's most likely scenario. 
Development costs are those

[[Page 36]]

expenditures defined in Sec.  203.89(b) incurred between your 
application submission date and start of production.
    (e) You do not send us the fabrication confirmation report or the 
post-production development report, or you provide false or 
intentionally inaccurate information that was material to our granting 
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on 
all volumes for which you used the royalty suspension. You also may be 
subject to penalties under other provisions of law.



Sec.  203.77  May I voluntarily give up relief if conditions change?

    Yes, you may voluntarily give up relief by sending a letter to that 
effect to the BSEE Regional office for your region.



Sec.  203.78  Do I keep relief approved by BSEE under this part for
 my lease, unit or project if prices rise significantly?

    If prices rise above a base price threshold for light sweet crude 
oil or natural gas, you must pay full royalties on production otherwise 
subject to royalty relief approved by BSEE under Sec. Sec.  203.60-
203.77 for your lease, unit or project as prescribed in this section.
    (a) The following table shows the base price threshold for various 
types of leases, subject to paragraph (b) of this section. Note that, 
for post-November 2000 deepwater leases in the GOM, price thresholds 
apply on a lease basis, so different leases on the same development 
project or expansion project approved for royalty relief may have 
different price thresholds.

------------------------------------------------------------------------
                                             The base price threshold is
                 For . . .                              . . .
------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,              set by statute.
(2) Post-November 2000 deep water leases    indicated in your original
 in the GOM or leases offshore of Alaska     lease agreement or, if
 for which the lease or Notice of Sale set   none, those in the Notice
 a base price threshold,                     of Sale under which your
                                             lease was issued.
(3) Post-November 2000 deep water leases    the threshold set by statute
 in the GOM or leases offshore of Alaska     for pre-Act leases.
 for which the lease or Notice of Sale did
 not set a base price threshold,
------------------------------------------------------------------------

    (b) An exception may occur if we determine that the price thresholds 
in paragraphs (a)(2) or (a)(3) of this section mean the royalty 
suspension volume set under Sec.  203.69 and in lease terms would 
provide inadequate encouragement to increase production or development, 
in which circumstance we could specify a different set of price 
thresholds on a case-by-case basis.
    (c) Suppose your base oil price threshold set under paragraph (a) is 
$28.00 per barrel, and the daily closing NYMEX light sweet crude oil 
prices for the previous calendar year exceeds $28.00 per barrel, as 
adjusted in paragraph (h) of this section. In this case, we retract the 
royalty relief authorized in this subpart and you must:
    (1) Pay royalties on all oil production for the previous year at the 
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30 
CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your oil production in the current year.
    (d) Suppose your base gas price threshold set under paragraph (a) is 
$3.50 per million British thermal units (Btu), and the daily closing 
NYMEX light sweet crude oil prices for the previous calendar year 
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this 
section. In this case, we retract the royalty relief authorized in this 
subpart and you must:
    (1) Pay royalties on all gas production for the previous year at the 
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30 
CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your gas production in the current year.
    (e) Production under both paragraphs (c) and (d) of this section 
counts as part of the royalty-suspension volume.
    (f) You are entitled to a refund or credit, with interest, of 
royalties paid on any production (that counts as part of the royalty-
suspension volume):

[[Page 37]]

    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less, as adjusted in 
paragraph (h) of this section, and
    (2) Of gas if the arithmetic average of the closing natural gas 
prices for the current calendar year is $3.50 per million Btu or less, 
as adjusted in paragraph (h) of this section.
    (g) You must follow our regulations in the Office of Natural 
Resources Revenue, 30 CFR chapter XII, for receiving refunds or credits.
    (h) We change the prices referred to in paragraphs (c), (d), and (f) 
of this section periodically. For pre-Act leases, these prices change 
during each calendar year after 1994 by the percentage that the implicit 
price deflator for the gross domestic product changed during the 
preceding calendar year. For post-November 2000 deepwater leases, these 
prices change as indicated in the lease instrument or in the Notice of 
Sale under which we issued the lease.



Sec.  203.79  How do I appeal BSEE's decisions related to royalty
 relief for a deepwater lease or a development or expansion project?

    (a) Once we have designated your lease as part of a field and 
notified you and other affected operators of the designation, you can 
request reconsideration by sending the BSEE Director a letter within 15 
days that also states your reasons. The BSEE Director's response is the 
final agency action.
    (b) Our decisions on your application for relief from paying royalty 
under Sec.  203.67 and the royalty-suspension volumes under Sec.  203.69 
are final agency actions.
    (c) If you cannot start construction by the deadline in Sec.  
203.76(b) for reasons beyond your control (e.g., strike at the 
fabrication yard), you may request an extension up to 1 year by writing 
the BSEE Director and stating your reasons. The BSEE Director's response 
is the final agency action.
    (d) We will notify you of all final agency actions by certified 
mail, return receipt requested. Final agency actions are not subject to 
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 
43 CFR part 4. They are judicially reviewable under section 10(a) of the 
Administrative Procedure Act (5 U.S.C. 702) only if you file an action 
within 30 days of the date you receive our decision.



Sec.  203.80  When can I get royalty relief if I am not eligible for
 royalty relief under other sections in the subpart?

    We may grant royalty relief when it serves the statutory purposes 
summarized in Sec.  203.1 and our formal relief programs, including but 
not limited to the applicable levels of the royalty suspension volumes 
and price thresholds, provide inadequate encouragement to promote 
development or increase production. Unless your lease lies offshore of 
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the 
GOM, your lease must be producing to qualify for relief. Before you may 
apply for royalty relief apart from our programs for end-of-life leases 
or for pre-Act deep water leases and development and expansion projects, 
we must agree that your lease or project has two or more of the 
following characteristics:
    (a) The lease has produced for a substantial period and the lessee 
can recover significant additional resources. Significant additional 
resources mean enough to allow production for at least a year more than 
would be profitable without royalty relief.
    (b) Valuable facilities (e.g., a platform or pipeline that would be 
removed upon lease relinquishment) exist that we do not expect a 
successor lessee to use. If the facilities are located off the lease, 
their preservation must depend on continued production from the lease 
applying for royalty relief. We will only consider an allocable share of 
costs for off-lease facilities in the relief application.
    (c) A substantial risk exists that no new lessee will recover the 
resources.
    (d) The lessee made major efforts to reduce operating costs too 
recently to use the formal program for royalty relief (e.g., recent 
significant change in operations).
    (e) Circumstances beyond the lessee's control, other than water 
depth, preclude reliance on one of the existing royalty relief programs.

[[Page 38]]

                            Required Reports



Sec.  203.81  What supplemental reports do royalty-relief applications
 require?

    (a) You must send us the supplemental reports, indicated in the 
following table by an X, that apply to your field. Sections 203.83 
through 203.91 describe these reports in detail.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                                                End-of-life   --------------------------------------------------
              Required reports                     lease          Expansion                        Development
                                                                   project       Pre-act lease       project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.......               X                X                X                X
(2) Net revenue & relief justification                     X   ...............  ...............
 report.....................................
(3) Economic viability & relief               ...............               X                X                X
 justification report (RSVP model inputs
 justified by other required reports).......
(4) G&G report..............................  ...............               X                X                X
(5) Engineering report......................  ...............               X                X                X
(6) Production report.......................  ...............               X                X                X
(7) Deep water cost report..................  ...............               X                X                X
(8) Fabricator's confirmation report........  ...............               X                X                X
(9) Post-production development report......  ...............               X                X                X
----------------------------------------------------------------------------------------------------------------

    (b) You must certify that all information in your application, 
fabricator's confirmation and post-production development reports is 
accurate, complete, and conforms to the most recent content and 
presentation guidelines available from the BSEE Regional office for your 
region.
    (c) With your application and post-production development report, 
you must submit an additional report prepared by an independent CPA 
that:
    (1) Assesses the accuracy of the historical financial information in 
your report; and
    (2) Certifies that the content and presentation of the financial 
data and information conform to our most recent guidelines on royalty 
relief. This means the data and information must:
    (i) Include only eligible costs that are incurred during the 
qualification months; and
    (ii) Be shown in the proper format.
    (d) You must identify the people in the CPA firm who prepared the 
reports referred to in paragraph (c) of this section and make them 
available to us to respond to questions about the historical financial 
information. We may also further review your records to support this 
information.



Sec.  203.82  What is BSEE's authority to collect this information?

    The Office of Management and Budget (OMB) approved the information 
collection requirements in part 203 under 44 U.S.C. 3501 et seq., and 
assigned OMB control number 1010-0071.
    (a) We use the information to determine whether royalty relief will 
result in production that wouldn't otherwise occur. We rely largely on 
your information to make these determinations.
    (1) Your application for royalty relief must contain enough 
information on finances, economics, reservoirs, G&G characteristics, 
production, and engineering estimates for us to determine whether:
    (i) We should grant relief under the law, and
    (ii) The requested relief will ultimately recover more resources and 
return a reasonable profit on project investments.
    (2) Your fabricator confirmation and post-production development 
reports must contain enough information for us to verify that your 
application reasonably represented your plans.
    (b) Applicants (respondents) are Federal OCS oil and gas lessees. 
Applications are required to obtain or retain a benefit. Therefore, if 
you apply for royalty relief, you must provide this information. We will 
protect information considered proprietary under applicable law and 
under regulations at Sec.  203.63 and 30 CFR part 250.
    (c) The Paperwork Reduction Act of 1995 requires us to inform you 
that we may not conduct or sponsor, and you are not required to respond 
to, a collection of information unless it displays a currently valid OMB 
control number.

[[Page 39]]

    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



Sec.  203.83  What is in an administrative information report?

    This report identifies the field or lease for which royalty relief 
is requested and must contain the following items:
    (a) The field or lease name;
    (b) The serial number of leases we have assigned to the field, names 
of the lease title holders of record, the lease operators, and whether 
any lease is part of a unit;
    (c) Well number, API number, location, and status of each well that 
has been drilled on the field or lease or project (not required for non-
oil and gas leases);
    (d) The location of any new wells proposed under the terms of the 
application (not required for non-oil and gas leases);
    (e) A description of field or lease history;
    (f) Full information as to whether you will pay royalties or a share 
of production to anyone other than the United States, the amount you 
will pay, and how much you will reduce this payment if we grant relief;
    (g) The type of royalty relief you are requesting;
    (h) Confirmation that BOEM approved a DOCD or supplemental DOCD 
(Deep Water expansion project applications only); and
    (i) A narrative description of the development activities associated 
with the proposed capital investments and an explanation of proposed 
timing of the activities and the effect on production (Deep Water 
applications only).



Sec.  203.84  What is in a net revenue and relief justification report?

    This report presents cash flow data for 12 qualifying months, using 
the format specified in the ``Guidelines for the Application, Review, 
Approval, and Administration of Royalty Relief for End-of-Life Leases'', 
U.S. Department of the Interior, BSEE. Qualifying months for an oil and 
gas lease are the most recent 12 months out of the last 15 months that 
you produced at least 100 BOE per day on average. Qualifying months for 
other than oil and gas leases are the most recent 12 of the last 15 
months having some production.
    (a) The cash flow table you submit must include historical data for:
    (1) Lease production subject to royalty;
    (2) Total revenues;
    (3) Royalty payments out of production;
    (4) Total allowable costs; and
    (5) Transportation and processing costs.
    (b) Do not include in your cash flow table the non-allowable costs 
listed at 30 CFR 1220.013 or:
    (1) OCS rental payments on the lease(s) in the application;
    (2) Damages and losses;
    (3) Taxes;
    (4) Any costs associated with exploratory activities;
    (5) Civil or criminal fines or penalties;
    (6) Fees for your royalty relief application; and
    (7) Costs associated with existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring the lease, 
depreciation on previously acquired equipment or facilities).
    (c) We may, in reviewing and evaluating your application, disallow 
costs when you have not shown they are necessary to operate the lease, 
or if they are inconsistent with end-of-life operations.



Sec.  203.85  What is in an economic viability and relief justification
 report?

    This report should show that your project appears economic without 
royalties and sunk costs using the RSVP model we provide. The format of 
the report and the assumptions and parameters we specify are found in 
the ``Guidelines for the Application, Review, Approval and 
Administration of the Deep Water Royalty Relief Program,'' U.S. 
Department of the Interior, BSEE. Clearly justify each parameter you set 
in every scenario you

[[Page 40]]

specify in the RSVP. You may provide supplemental information, including 
your own model and results. The economic viability and relief 
justification report must contain the following items for an oil and gas 
lease.
    (a) Economic assumptions we provide which include:
    (1) Starting oil and gas prices;
    (2) Real price growth;
    (3) Real cost growth or decline rate, if any;
    (4) Base year;
    (5) Range of discount rates; and
    (6) Tax rate (for use in determining after-tax sunk costs).
    (b) Analysis of projected cash flow (from the date of the 
application using annual totals and constant dollar values) which shows:
    (1) Oil and gas production;
    (2) Total revenues;
    (3) Capital expenditures;
    (4) Operating costs;
    (5) Transportation costs; and
    (6) Before-tax net cash flow without royalties, overrides, sunk 
costs, and ineligible costs.
    (c) Discounted values which include:
    (1) Discount rate used (selected from within the range we specify).
    (2) Before-tax net present value without royalties, overrides, sunk 
costs, and ineligible costs.
    (d) Demonstrations that:
    (1) All costs, gross production, and scheduling are consistent with 
the data in the G&G, engineering, production, and cost reports 
(Sec. Sec.  203.86 through 203.89) and
    (2) The development and production scenarios provided in the various 
reports are consistent with each other and with the proposed development 
system. You can use up to three scenarios (conservative, most likely, 
and optimistic), but you must link each to a specific range on the 
distribution of resources from the RSVP Resource Module.



Sec.  203.86  What is in a G&G report?

    This report supports the reserve and resource estimates used in the 
economic evaluation and must contain each of the following elements.
    (a) Seismic data which includes:
    (1) Non-interpreted 2D/3D survey lines reflecting any available 
state-of-the-art processing technique in a format readable by BSEE and 
specified by the deep water royalty relief guidelines;
    (2) Interpreted 2D/3D seismic survey lines reflecting any available 
state-of-the-art processing technique identifying all known and 
prospective pay horizons, wells, and fault cuts;
    (3) Digital velocity surveys in the format of the GOM region's 
letter to lessees of 10/1/90;
    (4) Plat map of ``shot points;'' and
    (5) ``Time slices'' of potential horizons.
    (b) Well data which includes:
    (1) Hard copies of all well logs in which--
    (i) The 1-inch electric log shows pay zones and pay counts and 
lithologic and paleo correlation markers at least every 500-feet,
    (ii) The 1-inch type log shows missing sections from other logs 
where faulting occurs,
    (iii) The 5-inch electric log shows pay zones and pay counts and 
labeled points used in establishing resistivity of the formation, 100 
percent water saturated (Ro) and the resistivity of the 
undisturbed formation (Rt), and
    (iv) The 5-inch porosity logs show pay zones and pay counts and 
labeled points used in establishing reservoir porosity or labeled points 
showing values used in calculating reservoir porosity such as bulk 
density or transit time;
    (2) Digital copies of all well logs spudded before December 1, 1995;
    (3) Core data, if available;
    (4) Well correlation sections;
    (5) Pressure data;
    (6) Production test results;
    (7) Pressure-volume-temperature analysis, if available; and
    (8) A table listing the wells and completions, and indicating which 
sands and fault blocks will be targeted for completion or recompletion.
    (c) Map interpretations which includes for each reservoir in the 
field:
    (1) Structure maps consisting of top and base of sand maps showing 
well and seismic shot point locations;
    (2) Isopach maps for net sand, net oil, net gas, all with well 
locations;

[[Page 41]]

    (3) Maps indicating well surface and bottom hole locations, location 
of development facilities, and shot points; and
    (4) An explanation for excluding the reservoirs you are not planning 
to develop.
    (d) Reservoir-specific data which includes:
    (1) Probability of reservoir occurrence with hydrocarbons;
    (2) Probability the hydrocarbon in the reservoir is all oil and the 
probability it is all gas;
    (3) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for the 
parameters used to estimate reservoir size, i.e., acres and net 
thickness;
    (4) Most likely values for porosity, salt water saturation, volume 
factor for oil formation, and volume factor for gas formation;
    (5) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for 
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
    (6) A gas/oil ratio distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each reservoir;
    (7) A yield distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each gas reservoir; and
    (8) Reserve or resource distribution by reservoir.
    (e) Aggregated reserve and resource data which includes:
    (1) The aggregated distributions for reserves and resources (in BOE) 
and oil fraction for your field computed by the resource module of our 
RSVP model;
    (2) A description of anticipated hydrocarbon quality (i.e., specific 
gravity); and
    (3) The ranges within the aggregated distribution for reserves and 
resources that define the development and production scenarios presented 
in the engineering and production reports. Typically there will be three 
ranges specified by two positive reserve and resource points on the 
aggregated distribution. The range at the low end of the distribution 
will be associated with the conservative development and production 
scenario; the middle range will be related to the most likely 
development and production scenario; and, the high end range will be 
consistent with the optimistic development and production scenario.



Sec.  203.87  What is in an engineering report?

    This report defines the development plan and capital requirements 
for the economic evaluation and must contain the following elements.
    (a) A description of the development concept (e.g., tension leg 
platform, fixed platform, floater type, subsea tieback, etc.) which 
includes:
    (1) Its size along with basic design specifications and drawings; 
and
    (2) The construction schedule.
    (b) An identification of planned wells which includes:
    (1) The number;
    (2) The type (platform, subsea, vertical, deviated, horizontal);
    (3) The well depth;
    (4) The drilling schedule;
    (5) The kind of completion (single, dual, horizontal, etc.); and
    (6) The completion schedule.
    (c) A description of the production system equipment which includes:
    (1) The production capacity for oil and gas and a description of 
limiting component(s);
    (2) Any unusual problems (low gravity, paraffin, etc.);
    (3) All subsea structures;
    (4) All flowlines; and
    (5) Schedule for installing the production system.
    (d) A discussion of any plans for multi-phase development which 
includes the conceptual basis for developing in phases and goals or 
milestones required for starting later phases.
    (e) A set of development scenarios consisting of activity timing and 
scale associated with each of up to three production profiles 
(conservative, most likely, optimistic) provided in the production 
report for your field (Sec.  203.88). Each development scenario and 
production profile must denote the likely

[[Page 42]]

events should the field size turn out to be within a range represented 
by one of the three segments of the field size distribution. If you send 
in fewer than three scenarios, you must explain why fewer scenarios are 
more efficient across the whole field size distribution.



Sec.  203.88  What is in a production report?

    This report supports your development and production timing and 
product quality expectations and must contain the following elements.
    (a) Production profiles by well completion and field that specify 
the actual and projected production by year for each of the following 
products: oil, condensate, gas, and associated gas. The production from 
each profile must be consistent with a specific level of reserves and 
resources on the aggregated distribution of field size.
    (b) Production drive mechanisms for each reservoir.



Sec.  203.89  What is in a cost report?

    This report lists all actual and projected costs for your field, 
must explain and document the source of each cost estimate, and must 
identify the following elements.
    (a) Sunk costs. Report sunk costs in dollars not adjusted for 
inflation and only if you have documentation.
    (b) Appraisal, delineation and development costs. Base them on 
actual spending, current authorization for expenditure, engineering 
estimates, or analogous projects. These costs cover:
    (1) Platform well drilling and average depth;
    (2) Platform well completion;
    (3) Subsea well drilling and average depth;
    (4) Subsea well completion;
    (5) Production system (platform); and
    (6) Flowline fabrication and installation.
    (c) Production costs based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Operation;
    (2) Equipment; and
    (3) Existing royalty overrides (we will not use the royalty 
overrides in evaluations).
    (d) Transportation costs, based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Oil or gas tariffs from pipeline or tankerage;
    (2) Trunkline and tieback lines; and
    (3) Gas plant processing for natural gas liquids.
    (e) Abandonment costs, based on historical costs, engineering 
estimates, or analogous projects. You should provide the costs to plug 
and abandon only wells and to remove only production systems for which 
you have not incurred costs as of the time of application submission. 
You should also include a point estimate or distribution of prospective 
salvage value for all potentially reusable facilities and materials, 
along with the source and an explanation of the figures provided.
    (f) A set of cost estimates consistent with each one of up to three 
field-development scenarios and production profiles (conservative, most 
likely, optimistic). You should express costs in constant real dollar 
terms for the base year. You may also express the uncertainty of each 
cost estimate with a minimum and maximum percentage of the base value.
    (g) A spending schedule. You should provide costs for each year (in 
real dollars) for each category in paragraphs (a) through (f) of this 
section.
    (h) A summary of other costs which are ineligible for evaluating 
your need for relief. These costs cover:
    (1) Expenses before first discovery on the field;
    (2) Cash bonuses;
    (3) Fees for royalty relief applications;
    (4) Lease rentals, royalties, and payments of net profit share and 
net revenue share;
    (5) Legal expenses;
    (6) Damages and losses;
    (7) Taxes;
    (8) Interest or finance charges, including those embedded in 
equipment leases;
    (9) Fines or penalties; and
    (10) Money spent on previously existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring a financial position 
in a lease, expenditures for plugging wells and removing and abandoning 
facilities that

[[Page 43]]

existed on the application submission date).



Sec.  203.90  What is in a fabricator's confirmation report?

    This report shows you have committed in a timely way to the approved 
system for production. This report must include the following (or its 
equivalent for unconventionally acquired systems):
    (a) A copy of the contract(s) under which the fabrication yard is 
building the approved system for you;
    (b) A letter from the contractor building the system to the BSEE 
Regional Director for your region certifying when construction started 
on your system; and
    (c) Evidence of an appropriate down payment or equal action that 
you've started acquiring the approved system.



Sec.  203.91  What is in a post-production development report?

    For each cost category in the deep water cost report, you must 
compare actual costs up to the date when production starts to your 
planned pre-production costs. If your application included more than one 
development scenario, you need to compare actual costs with those in 
your scenario of most likely development. Also, you must have this 
report certified by an independent CPA according to Sec.  203.81(c).

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

[[Page 44]]



                          SUBCHAPTER B_OFFSHORE





PART 250_OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL
 SHELF--Table of Contents



                            Subpart A_General

                    Authority and Definition of Terms

Sec.
250.101 Authority and applicability.
250.102 What does this part do?
250.103 Where can I find more information about the requirements in this 
          part?
250.104 How may I appeal a decision made under BSEE regulations?
250.105 Definitions.

                          Performance Standards

250.106 What standards will the Director use to regulate lease 
          operations?
250.107 What must I do to protect health, safety, property, and the 
          environment?
250.108 What requirements must I follow for cranes and other material-
          handling equipment?
250.109 What documents must I prepare and maintain related to welding?
250.110 What must I include in my welding plan?
250.111 Who oversees operations under my welding plan?
250.112 What standards must my welding equipment meet?
250.113 What procedures must I follow when welding?
250.114 How must I install, maintain, and operate electrical equipment?
250.115 What are the procedures for, and effects of, incorporation of 
          documents by reference in this part?
250.116-250.117 [Reserved]

                        Gas Storage or Injection

250.118 Will BSEE approve gas injection?
250.119 [Reserved]
250.120 How does injecting, storing, or treating gas affect my royalty 
          payments?
250.121 What happens when the reservoir contains both original gas in 
          place and injected gas?
250.122 What effect does subsurface storage have on the lease term?
250.123 [Reserved]
250.124 Will BSEE approve gas injection into the cap rock containing a 
          sulphur deposit?

                                  Fees

250.125 Service fees.
250.126 Electronic payment instructions.

                        Inspection of Operations

250.130 Why does BSEE conduct inspections?
250.131 Will BSEE notify me before conducting an inspection?
250.132 What must I do when BSEE conducts an inspection?
250.133 Will BSEE reimburse me for my expenses related to inspections?

                            Disqualification

250.135 What will BSEE do if my operating performance is unacceptable?
250.136 How will BSEE determine if my operating performance is 
          unacceptable?

                       Special Types of Approvals

250.140 When will I receive an oral approval?
250.141 May I ever use alternate procedures or equipment?
250.142 How do I receive approval for departures?
250.143-250.144 [Reserved]
250.145 How do I designate an agent or a local agent?
250.146 Who is responsible for fulfilling leasehold obligations?

  Naming and Identifying Facilities and Wells (Does Not Include MODUs)

250.150 How do I name facilities and wells in the Gulf of Mexico Region?
250.151 How do I name facilities in the Pacific Region?
250.152 How do I name facilities in the Alaska Region?
250.153 Do I have to rename an existing facility or well?
250.154 What identification signs must I display?
250.160-250.167 [Reserved]

                               Suspensions

250.168 May operations or production be suspended?
250.169 What effect does suspension have on my lease?
250.170 How long does a suspension last?
250.171 How do I request a suspension?
250.172 When may the Regional Supervisor grant or direct an SOO or SOP?
250.173 When may the Regional Supervisor direct an SOO or SOP?
250.174 When may the Regional Supervisor grant or direct an SOP?
250.175 When may the Regional Supervisor grant an SOO?
250.176 Does a suspension affect my royalty payment?
250.177 What additional requirements may the Regional Supervisor order 
          for a suspension?

[[Page 45]]

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations

250.180 What am I required to do to keep my lease term in effect?
250.181-250.185 [Reserved]

                 Information and Reporting Requirements

250.186 What reporting information and report forms must I submit?
250.187 What are BSEE's incident reporting requirements?
250.188 What incidents must I report to BSEE and when must I report 
          them?
250.189 Reporting requirements for incidents requiring immediate 
          notification.
250.190 Reporting requirements for incidents requiring written 
          notification.
250.191 How does BSEE conduct incident investigations?
250.192 What reports and statistics must I submit relating to a 
          hurricane, earthquake, or other natural occurrence?
250.193 Reports and investigations of possible violations.
250.194 How must I protect archaeological resources?
250.195 What notification does BSEE require on the production status of 
          wells?
250.196 Reimbursements for reproduction and processing costs.
250.197 Data and information to be made available to the public or for 
          limited inspection.

                               References

250.198 Documents incorporated by reference.
250.199 Paperwork Reduction Act statements--information collection.

                     Subpart B_Plans and Information

                           General Information

250.200 Definitions.
250.201 What plans and information must I submit before I conduct any 
          activities on my lease or unit?
250.202-250.203 [Reserved]
250.204 How must I protect the rights of the Federal government?
250.205 Are there special requirements if my well affects an adjacent 
          property?

          Post-Approval Requirements for the EP, DPP, and DOCD

250.282 Do I have to conduct post-approval monitoring?

                    Deepwater Operations Plans (DWOP)

250.286 What is a DWOP?
250.287 For what development projects must I submit a DWOP?
250.288 When and how must I submit the Conceptual Plan?
250.289 What must the Conceptual Plan contain?
250.290 What operations require approval of the Conceptual Plan?
250.291 When and how must I submit the DWOP?
250.292 What must the DWOP contain?
250.293 What operations require approval of the DWOP?
250.294 May I combine the Conceptual Plan and the DWOP?
250.295 When must I revise my DWOP?

               Subpart C_Pollution Prevention and Control

250.300 Pollution prevention.
250.301 Inspection of facilities.

                Subpart D_Oil and Gas Drilling Operations

                          General Requirements

250.400 General requirements.
250.401-250.403 [Reserved]
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines used on a 
          drilling rig?
250.406 [Reserved]
250.407 What tests must I conduct to determine reservoir 
          characteristics?
250.408 May I use alternative procedures or equipment during drilling 
          operations?
250.409 May I obtain departures from these drilling requirements?

                     Applying for a Permit to Drill

250.410 How do I obtain approval to drill a well?
250.411 What information must I submit with my application?
250.412 What requirements must the location plat meet?
250.413 What must my description of well drilling design criteria 
          address?
250.414 What must my drilling prognosis include?
250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter description?
250.417 [Reserved]
250.418 What additional information must I submit with my APD?

                    Casing and Cementing Requirements

250.420 What well casing and cementing requirements must I meet?
250.421 What are the casing and cementing requirements by type of casing 
          string?
250.422 When may I resume drilling after cementing?
250.423 What are the requirements for casing and liner installation?
250.424-250.426 [Reserved]

[[Page 46]]

250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?

                      Diverter System Requirements

250.430 When must I install a diverter system?
250.431 What are the diverter design and installation requirements?
250.432 How do I obtain a departure to diverter design and installation 
          requirements?
250.433 What are the diverter actuation and testing requirements?
250.434 What are the recordkeeping requirements for diverter actuations 
          and tests?
250.440-250.451 [Reserved]

                       Drilling Fluid Requirements

250.452 What are the real-time monitoring requirements for Arctic OCS 
          exploratory drilling operations?
250.455 What are the general requirements for a drilling fluid program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling 
          areas?

                       Other Drilling Requirements

250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination 
          surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?

            Applying for a Permit To Modify and Well Records

250.465 When must I submit an Application for Permit to Modify (APM) or 
          an End of Operations Report to BSEE?
250.466-250.469 [Reserved]

                   Additional Arctic OCS Requirements

250.470 What additional information must I submit with my APD for Arctic 
          OCS exploratory drilling operations?
250.471 What are the requirements for Arctic OCS source control and 
          containment?
250.472 What are the relief rig requirements for the Arctic OCS?
250.473 What must I do to protect health, safety, property, and the 
          environment while operating on the Arctic OCS?

                            Hydrogen Sulfide

250.490 Hydrogen sulfide.

            Subpart E_Oil and Gas Well-Completion Operations

250.500 General requirements.
250.501 Definition.
250.502 [Reserved]
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506-250.508 [Reserved]
250.509 Well-completion structures on fixed platforms.
250.510 Diesel engine air intakes.
250.511 Traveling-block safety device.
250.512 Field well-completion rules.
250.513 Approval and reporting of well-completion operations.
250.514 Well-control fluids, equipment, and operations.
250.515-250.517 [Reserved]
250.518 Tubing and wellhead equipment.

                       Casing Pressure Management

250.519 What are the requirements for casing pressure management?
250.520 How often do I have to monitor for casing pressure?
250.521 When do I have to perform a casing diagnostic test?
250.522 How do I manage the thermal effects caused by initial production 
          on a newly completed or recompleted well?
250.523 When do I have to repeat casing diagnostic testing?
250.524 How long do I keep records of casing pressure and diagnostic 
          tests?
250.525 When am I required to take action from my casing diagnostic 
          test?
250.526 What do I submit if my casing diagnostic test requires action?
250.527 What must I include in my notification of corrective action?
250.528 What must I include in my casing pressure request?
250.529 What are the terms of my casing pressure request?
250.530 What if my casing pressure request is denied?
250.531 When does my casing pressure request approval become invalid?

             Subpart F_Oil and Gas Well-Workover Operations

250.600 General requirements.
250.601 Definitions.
250.602 [Reserved]
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606-250.608 [Reserved]
250.609 Well-workover structures on fixed platforms.
250.610 Diesel engine air intakes.
250.611 Traveling-block safety device.
250.612 Field well-workover rules.

[[Page 47]]

250.613 Approval and reporting for well-workover operations.
250.614 Well-control fluids, equipment, and operations.
250.615 [Reserved]
250.616 Coiled tubing and snubbing operations.
250.617-250.618 [Reserved]
250.619 Tubing and wellhead equipment.
250.620 Wireline operations.

Subpart G--Well Operations and Equipment

                          General Requirements

250.700 What operations and equipment does this subpart cover?
250.701 May I use alternate procedures or equipment during operations?
250.702 May I obtain departures from these requirements?
250.703 What must I do to keep wells under control?

                            Rig Requirements

250.710 What instructions must be given to personnel engaged in well 
          operations?
250.711 What are the requirements for well-control drills?
250.712 What rig unit movements must I report?
250.713 What must I provide if I plan to use a mobile offshore drilling 
          unit (MODU) for well operations?
250.714 Do I have to develop a dropped objects plan?
250.715 Do I need a global positioning system (GPS) for all MODUs?

                             Well Operations

250.720 When and how must I secure a well?
250.721 What are the requirements for pressure testing casing and 
          liners?
250.722 What are the requirements for prolonged operations in a well?
250.723 What additional safety measures must I take when I conduct 
          operations on a platform that has producing wells or has other 
          hydrocarbon flow?
250.724 What are the real-time monitoring requirements?

               Blowout Preventer (BOP) System Requirements

250.730 What are the general requirements for BOP systems and system 
          components?
250.731 What information must I submit for BOP systems and system 
          components?
250.732 What are the BSEE-approved verification organization (BAVO) 
          requirements for BOP systems and system components?
250.733 What are the requirements for a surface BOP stack?
250.734 What are the requirements for a subsea BOP system?
250.735 What associated systems and related equipment must all BOP 
          systems include?
250.736 What are the requirements for choke manifolds, kelly-type valves 
          inside BOPs, and drill string safety valves?
250.737 What are the BOP system testing requirements?
250.738 What must I do in certain situations involving BOP equipment or 
          systems?
250.739 What are the BOP maintenance and inspection requirements?

                          Records and Reporting

250.740 What records must I keep?
250.741 How long must I keep records?
250.742 What well records am I required to submit?
250.743 What are the well activity reporting requirements?
250.744 What are the end of operation reporting requirements?
250.745 What other well records could I be required to submit?
250.746 What are the recordkeeping requirements for casing, liner, and 
          BOP tests, and inspections of BOP systems and marine risers?

             Subpart H_Oil and Gas Production Safety Systems

                          General Requirements

250.800 General.
250.801 Safety and pollution prevention equipment (SPPE) certification.
250.802 Requirements for SPPE.
250.803 What SPPE failure reporting procedures must I follow?
250.804 Additional requirements for subsurface safety valves (SSSVs) and 
          related equipment installed in high pressure high temperature 
          (HPHT) environments.
250.805 Hydrogen sulfide.
250.806-250.809 [Reserved]

            Surface and Subsurface Safety Systems--Dry Trees

250.810 Dry tree subsurface safety devices--general.
250.811 Specifications for SSSVs--dry trees.
250.812 Surface-controlled SSSVs--dry trees.
250.813 Subsurface-controlled SSSVs.
250.814 Design, installation, and operation of SSSVs--dry trees.
250.815 Subsurface safety devices in shut-in wells--dry trees.
250.816 Subsurface safety devices in injection wells--dry trees.
250.817 Temporary removal of subsurface safety devices for routine 
          operations.
250.818 Additional safety equipment--dry trees.

[[Page 48]]

250.819 Specification for surface safety valves (SSVs).
250.820 Use of SSVs.
250.821 Emergency action and safety system shutdown--dry trees.
250.822-250.824 [Reserved]

           Subsea and Subsurface Safety Systems--Subsea Trees

250.825 Subsea tree subsurface safety devices--general.
250.826 Specifications for SSSVs--subsea trees.
250.827 Surface-controlled SSSVs--subsea trees.
250.828 Design, installation, and operation of SSSVs--subsea trees.
250.829 Subsurface safety devices in shut-in wells--subsea trees.
250.830 Subsurface safety devices in injection wells--subsea trees.
250.831 Alteration or disconnection of subsea pipeline or umbilical.
250.832 Additional safety equipment--subsea trees.
250.833 Specification for underwater safety valves (USVs).
250.834 Use of USVs.
250.835 Specification for all boarding shutdown valves (BSDVs) 
          associated with subsea systems.
250.836 Use of BSDVs.
250.837 Emergency action and safety system shutdown--subsea trees.
250.838 What are the maximum allowable valve closure times and hydraulic 
          bleeding requirements for an electro-hydraulic control system?
250.839 What are the maximum allowable valve closure times and hydraulic 
          bleeding requirements for a direct-hydraulic control system?

                        Production Safety Systems

250.840 Design, installation, and maintenance--general.
250.841 Platforms.
250.842 Approval of safety systems design and installation features.
250.843-250.849 [Reserved]

                Additional Production System Requirements

250.850 Production system requirements--general.
250.851 Pressure vessels (including heat exchangers) and fired vessels.
250.852 Flowlines/Headers.
250.853 Safety sensors.
250.854 Floating production units equipped with turrets and turret-
          mounted systems.
250.855 Emergency shutdown (ESD) system.
250.856 Engines.
250.857 Glycol dehydration units.
250.858 Gas compressors.
250.859 Firefighting systems.
250.860 Chemical firefighting system.
250.861 Foam firefighting systems.
250.862 Fire and gas-detection systems.
250.863 Electrical equipment.
250.864 Erosion.
250.865 Surface pumps.
250.866 Personnel safety equipment.
250.867 Temporary quarters and temporary equipment.
250.868 Non-metallic piping.
250.869 General platform operations.
250.870 Time delays on pressure safety low (PSL) sensors.
250.871 Welding and burning practices and procedures.
250.872 Atmospheric vessels.
250.873 Subsea gas lift requirements.
250.874 Subsea water injection systems.
250.875 Subsea pump systems.
250.876 Fired and exhaust heated components.
250.877-250.879 [Reserved]

                          Safety Device Testing

250.880 Production safety system testing.
250.881-250.889 [Reserved]

                          Records and Training

250.890 Records.
250.891 Safety device training.
250.892-250.899 [Reserved]

                   Subpart I_Platforms and Structures

                   General Requirements for Platforms

250.900 What general requirements apply to all platforms?
250.901 What industry standards must your platform meet?
250.902 What are the requirements for platform removal and location 
          clearance?
250.903 What records must I keep?

                        Platform Approval Program

250.904 What is the Platform Approval Program?
250.905 How do I get approval for the installation, modification, or 
          repair of my platform?
250.906 What must I do to obtain approval for the proposed site of my 
          platform?
250.907 Where must I locate foundation boreholes?
250.908 What are the minimum structural fatigue design requirements?

                      Platform Verification Program

250.909 What is the Platform Verification Program?
250.910 Which of my facilities are subject to the Platform Verification 
          Program?
250.911 If my platform is subject to the Platform Verification Program, 
          what must I do?

[[Page 49]]

250.912 What plans must I submit under the Platform Verification 
          Program?
250.913 When must I resubmit Platform Verification Program plans?
250.914 How do I nominate a CVA?
250.915 What are the CVA's primary responsibilities?
250.916 What are the CVA's primary duties during the design phase?
250.917 What are the CVA's primary duties during the fabrication phase?
250.918 What are the CVA's primary duties during the installation phase?

          Inspection, Maintenance, and Assessment of Platforms

250.919 What in-service inspection requirements must I meet?
250.920 What are the BSEE requirements for assessment of fixed 
          platforms?
250.921 How do I analyze my platform for cumulative fatigue?

             Subpart J_Pipelines and Pipeline Rights-of-Way

250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing, and repair requirements for DOI 
          pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 How must I decommission and take out of service a DOI pipeline?
250.1007 What to include in applications.
250.1008 Reports.
250.1009 Requirements to obtain pipeline right-of-way grants.
250.1010 General requirements for pipeline right-of-way holders.
250.1011 [Reserved]
250.1012 Required payments for pipeline right-of-way holders.
250.1013 Grounds for forfeiture of pipeline right-of-way grants.
250.1014 When pipeline right-of-way grants expire.
250.1015 Applications for pipeline right-of-way grants.
250.1016 Granting pipeline rights-of-way.
250.1017 Requirements for construction under pipeline right-of-way 
          grants.
250.1018 Assignment of pipeline right-of-way grants.
250.1019 Relinquishment of pipeline right-of-way grants.

              Subpart K_Oil and Gas Production Requirements

                                 General

250.1150 What are the general reservoir production requirements?

                         Well Tests and Surveys

250.1151 How often must I conduct well production tests?
250.1152 How do I conduct well tests?
250.1153 [Reserved]

                         Classifying Reservoirs

250.1154-250.1155 [Reserved]

                      Approvals Prior to Production

250.1156 What steps must I take to receive approval to produce within 
          500 feet of a unit or lease line?
250.1157 How do I receive approval to produce gas-cap gas from an oil 
          reservoir with an associated gas cap?
250.1158 How do I receive approval to downhole commingle hydrocarbons?

                            Production Rates

250.1159 May the Regional Supervisor limit my well or reservoir 
          production rates?

                laring, Venting, and Burning Hydrocarbons

250.1160 When may I flare or vent gas?
250.1161 When may I flare or vent gas for extended periods of time?
250.1162 When may I burn produced liquid hydrocarbons?
250.1163 How must I measure gas flaring or venting volumes and liquid 
          hydrocarbon burning volumes, and what records must I maintain?
250.1164 What are the requirements for flaring or venting gas containing 
          H2S?

                           Other Requirements

250.1165 What must I do for enhanced recovery operations?
250.1166 What additional reporting is required for developments in the 
          Alaska OCS Region?
250.1167 What information must I submit with forms and for approvals?

 Subpart L_Oil and Gas Production Measurement, Surface Commingling, and 
                                Security

250.1200 Question index table.
250.1201 Definitions.
250.1202 Liquid hydrocarbon measurement.
250.1203 Gas measurement.
250.1204 Surface commingling.
250.1205 Site security.

                          Subpart M_Unitization

250.1300 What is the purpose of this subpart?
250.1301 What are the requirements for unitization?
250.1302 What if I have a competitive reservoir on a lease?

[[Page 50]]

250.1303 How do I apply for voluntary unitization?
250.1304 How will BSEE require unitization?

            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties

250.1400 How does BSEE begin the civil penalty process?
250.1401 [Reserved]
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will BSEE review for potential civil 
          penalties?
250.1405 When is a case file developed?
250.1406 When will BSEE notify me and provide penalty information?
250.1407 How do I respond to the letter of notification?
250.1408 When will I be notified of the Reviewing Officer's decision?
250.1409 What are my appeal rights?

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

250.1450 What definitions apply to this subpart?

                   Penalties After a Period To Correct

250.1451 What may BSEE do if I violate a statute, regulation, order, or 
          lease term relating to a Federal oil and gas lease?
250.1452 What if I correct the violation?
250.1453 What if I do not correct the violation?
250.1454 How may I request a hearing on the record on a Notice of 
          Noncompliance?
250.1455 Does my request for a hearing on the record affect the 
          penalties?
250.1456 May I request a hearing on the record regarding the amount of a 
          civil penalty if I did not request a hearing on the Notice of 
          Noncompliance?

                  Penalties Without a Period To Correct

250.1460 May I be subject to penalties without prior notice and an 
          opportunity to correct?
250.1461 How will BSEE inform me of violations without a period to 
          correct?
250.1462 How may I request a hearing on the record on a Notice of 
          Noncompliance regarding violations without a period to 
          correct?
250.1463 Does my request for a hearing on the record affect the 
          penalties?
250.1464 May I request a hearing on the record regarding the amount of a 
          civil penalty if I did not request a hearing on the Notice of 
          Noncompliance?

                           General Provisions

250.1470 How does BSEE decide what the amount of the penalty should be?
250.1471 Does the penalty affect whether I owe interest?
250.1472 How will the Office of Hearings and Appeals conduct the hearing 
          on the record?
250.1473 How may I appeal the Administrative Law Judge's decision?
250.1474 May I seek judicial review of the decision of the Interior 
          Board of Land Appeals?
250.1475 When must I pay the penalty?
250.1476 Can BSEE reduce my penalty once it is assessed?
250.1477 How may BSEE collect the penalty?

                           Criminal Penalties

250.1480 May the United States criminally prosecute me for violations 
          under Federal oil and gas leases?

          Subpart O_Well Control and Production Safety Training

250.1500 Definitions.
250.1501 What is the goal of my training program?
250.1503 What are my general responsibilities for training?
250.1504 May I use alternative training methods?
250.1505 Where may I get training for my employees?
250.1506 How often must I train my employees?
250.1507 How will BSEE measure training results?
250.1508 What must I do when BSEE administers written or oral tests?
250.1509 What must I do when BSEE administers or requires hands-on, 
          simulator, or other types of testing?
250.1510 What will BSEE do if my training program does not comply with 
          this subpart?

                      Subpart P_Sulphur Operations

250.1600 Performance standard.
250.1601 Definitions.
250.1602 Applicability.
250.1603 Determination of sulphur deposit.
250.1604 General requirements.
250.1605 Drilling requirements.
250.1606 Control of wells.
250.1607 Field rules.
250.1608 Well casing and cementing.
250.1609 Pressure testing of casing.
250.1610 Blowout preventer systems and system components.
250.1611 Blowout preventer systems tests, actuations, inspections, and 
          maintenance.
250.1612 Well-control drills.

[[Page 51]]

250.1613 Diverter systems.
250.1614 Mud program.
250.1615 Securing of wells.
250.1616 Supervision, surveillance, and training.
250.1617 Application for permit to drill.
250.1618 Application for permit to modify.
250.1619 Well records.
250.1620 Well-completion and well-workover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of well-completion and well-workover 
          operations.
250.1623 Well-control fluids, equipment, and operations.
250.1624 Blowout prevention equipment.
250.1625 Blowout preventer system testing, records, and drills.
250.1626 Tubing and wellhead equipment.
250.1627 Production requirements.
250.1628 Design, installation, and operation of production systems.
250.1629 Additional production and fuel gas system requirements.
250.1630 Safety-system testing and records.
250.1631 Safety device training.
250.1632 Production rates.
250.1633 Production measurement.
250.1634 Site security.

                  Subpart Q_Decommissioning Activities

                                 General

250.1700 What do the terms ``decommissioning'', ``obstructions'', and 
          ``facility'' mean?
250.1701 Who must meet the decommissioning obligations in this subpart?
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 What decommissioning applications and reports must I submit and 
          when must I submit them?
250.1705 [Reserved]
250.1706 Coiled tubing and snubbing operations.
250.1707-250.1709 [Reserved]

                       Permanently Plugging Wells

250.1710 When must I permanently plug all wells on a lease?
250.1711 When will BSEE order me to permanently plug a well?
250.1712 What information must I submit before I permanently plug a well 
          or zone?
250.1713 Must I notify BSEE before I begin well plugging operations?
250.1714 What must I accomplish with well plugs?
250.1715 How must I permanently plug a well?
250.1716 To what depth must I remove wellheads and casings?
250.1717 [Reserved]

                        Temporary Abandoned Wells

250.1721 If I temporarily abandon a well that I plan to re-enter, what 
          must I do?
250.1722 If I install a subsea protective device, what requirements must 
          I meet?
250.1723 What must I do when it is no longer necessary to maintain a 
          well in temporary abandoned status?

                 Removing Platforms and Other Facilities

250.1725 When do I have to remove platforms and other facilities?
250.1726 When must I submit an initial platform removal application and 
          what must it include?
250.1727 What information must I include in my final application to 
          remove a platform or other facility?
250.1728 To what depth must I remove a platform or other facility?
250.1729 After I remove a platform or other facility, what information 
          must I submit?
250.1730 When might BSEE approve partial structure removal or toppling 
          in place?
250.1731 Who is responsible for decommissioning an OCS facility subject 
          to an Alternate Use RUE?

        Site Clearance for Wells, Platforms, and Other Facilities

250.1740 How must I verify that the site of a permanently plugged well, 
          removed platform, or other removed facility is clear of 
          obstructions?
250.1741 If I drag a trawl across a site, what requirements must I meet?
250.1742 What other methods can I use to verify that a site is clear?
250.1743 How do I certify that a site is clear of obstructions?

                        Pipeline Decommissioning

250.1750 When may I decommission a pipeline in place?
250.1751 How do I decommission a pipeline in place?
250.1752 How do I remove a pipeline?
250.1753 After I decommission a pipeline, what information must I 
          submit?
250.1754 When must I remove a pipeline decommissioned in place?

Subpart R [Reserved]

      Subpart S_Safety and Environmental Management Systems (SEMS)

250.1900 Must I have a SEMS program?
250.1901 What is the goal of my SEMS program?
250.1902 What must I include in my SEMS program?
250.1903 Acronyms and definitions.

[[Page 52]]

250.1904 Special instructions.
250.1905-250.1908 [Reserved]
250.1909 What are management's general responsibilities for the SEMS 
          program?
250.1910 What safety and environmental information is required?
250.1911 What hazards analysis criteria must my SEMS program meet?
250.1912 What criteria for management of change must my SEMS program 
          meet?
250.1913 What criteria for operating procedures must my SEMS program 
          meet?
250.1914 What criteria must be documented in my SEMS program for safe 
          work practices and contractor selection?
250.1915 What training criteria must be in my SEMS program?
250.1916 What criteria for mechanical integrity must my SEMS program 
          meet?
250.1917 What criteria for pre-startup review must be in my SEMS 
          program?
250.1918 What criteria for emergency response and control must be in my 
          SEMS program?
250.1919 What criteria for investigation of incidents must be in my SEMS 
          program?
250.1920 What are the auditing requirements for my SEMS program?
250.1921 What qualifications must the ASP meet?
250.1922 What qualifications must an AB meet?
250.1923 [Reserved]
250.1924 How will BSEE determine if my SEMS program is effective?
250.1925 May BSEE direct me to conduct additional audits?
250.1926 [Reserved]
250.1927 What happens if BSEE finds shortcomings in my SEMS program?
250.1928 What are my recordkeeping and documentation requirements?
250.1929 What are my responsibilities for submitting OCS performance 
          measure data?
250.1930 What must be included in my SEMS program for SWA?
250.1931 What must be included in my SEMS program for UWA?
250.1932 What are my EPP requirements?
250.1933 What procedures must be included for reporting unsafe working 
          conditions?

    Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C. 1321(j)(1)(C), 
43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 250 appear at 77 FR 
50891, Aug. 22, 2012.



                            Subpart A_General

                    Authority and Definition of Terms



Sec.  250.101  Authority and applicability.

    The Secretary of the Interior (Secretary) authorized the Bureau of 
Safety and Environmental Enforcement (BSEE) to regulate oil, gas, and 
sulphur exploration, development, and production operations on the Outer 
Continental Shelf (OCS). Under the Secretary's authority, the Director 
requires that all operations:
    (a) Be conducted according to the OCS Lands Act (OCSLA), the 
regulations in this part, BSEE orders, the lease or right-of-way, and 
other applicable laws, regulations, and amendments; and
    (b) Conform to sound conservation practice to preserve, protect, and 
develop mineral resources of the OCS to:
    (1) Make resources available to meet the Nation's energy needs;
    (2) Balance orderly energy resource development with protection of 
the human, marine, and coastal environments;
    (3) Ensure the public receives a fair and equitable return on the 
resources of the OCS;
    (4) Preserve and maintain free enterprise competition; and
    (5) Minimize or eliminate conflicts between the exploration, 
development, and production of oil and natural gas and the recovery of 
other resources.



Sec.  250.102  What does this part do?

    (a) This part 250 contains the regulations of the BSEE Offshore 
program that govern oil, gas, and sulphur exploration, development, and 
production operations on the OCS. When you conduct operations on the 
OCS, you must submit requests, applications, and notices, or provide 
supplemental information for BSEE approval.
    (b) The following table of general references shows where to look 
for information about these processes.

------------------------------------------------------------------------
      For information about . . .                 Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill,..  30 CFR part 250, subpart D.
(2) Development and Production Plans     30 CFR part 550, subpart B.
 (DPP),.
(3) Downhole commingling,..............  30 CFR part 250, subpart K.
(4) Exploration Plans (EP),............  30 CFR part 550, subpart B.
(5) Flaring,...........................  30 CFR part 250, subpart K.

[[Page 53]]

 
(6) Gas measurement,...................  30 CFR part 250, subpart L.
(7) Off-lease geological and             30 CFR part 551.
 geophysical permits,.
(8) Oil spill financial responsibility   30 CFR part 553.
 coverage,.
(9) Oil and gas production safety        30 CFR part 250, subpart H.
 systems,.
(10) Oil spill response plans,.........  30 CFR part 254.
(11) Oil and gas well-completion         30 CFR part 250, subpart E.
 operations,.
(12) Oil and gas well-workover           30 CFR part 250, subpart F.
 operations,.
(13) Decommissioning Activities,.......  30 CFR part 250, subpart Q.
(14) Platforms and structures,.........  30 CFR part 250, subpart I.
(15) Pipelines and Pipeline Rights-of-   30 CFR part 250, subpart J and
 Way,.                                    30 CFR part 550, subpart J.
(16) Sulphur operations,...............  30 CFR part 250, subpart P.
(17) Training,.........................  30 CFR part 250, subpart O.
(18) Unitization,......................  30 CFR part 250, subpart M.
(19) Safety and Environmental            30 CFR part 250, subpart S.
 Management Systems (SEMS),.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 36148, June 6, 2016]



Sec.  250.103  Where can I find more information about the requirements
 in this part?

    BSEE may issue Notices to Lessees and Operators (NTLs) that clarify, 
supplement, or provide more detail about certain requirements. NTLs may 
also outline what you must provide as required information in your 
various submissions to BSEE.



Sec.  250.104  How may I appeal a decision made under BSEE regulations?

    To appeal orders or decisions issued under BSEE regulations in 30 
CFR parts 250 to 282, follow the procedures in 30 CFR part 290.



Sec.  250.105  Definitions.

    Terms used in this part will have the meanings given in the Act and 
as defined in this section:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Affected State means with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved under the provisions 
of the Act, any State:
    (1) The laws of which are declared, under section 4(a)(2) of the 
Act, to be the law of the United States for the portion of the OCS on 
which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installation or 
other device permanently or temporarily attached to the seabed;
    (3) Which is receiving, or according to the proposed activity, will 
receive oil for processing, refining, or transshipment that was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Secretary as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Secretary finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Air pollutant means any airborne agent or combination of agents for 
which the Environmental Protection Agency (EPA) has established, under 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analysis, laboratory analyses of physical and chemical properties,

[[Page 54]]

well logs or charts, results from formation fluid tests, and 
descriptions of hydrocarbon occurrences or hazardous conditions.
    Ancillary activities mean those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without Bureau of Ocean Energy Management (BOEM) 
approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas 
(for more information on these areas, see the Proposed Final OCS Oil and 
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
    Arctic OCS conditions means, for the purposes of this part, the 
conditions operators can reasonably expect during operations on the 
Arctic OCS. Such conditions, depending on the time of year, include, but 
are not limited to: Extreme cold, freezing spray, snow, extended periods 
of low light, strong winds, dense fog, sea ice, strong currents, and 
dangerous sea states. Remote location, relative lack of infrastructure, 
and the existence of subsistence hunting and fishing areas are also 
characteristic of the Arctic region.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best available 
and safest technologies that the BSEE Director determines to be 
economically feasible wherever failure of equipment would have a 
significant effect on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Supervisor will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Cap and flow system means an integrated suite of equipment and 
vessels, including a capping stack and associated flow lines, that, when 
installed or positioned, is used to control the flow of fluids escaping 
from the well by conveying the fluids to the surface to a vessel or 
facility equipped to process the flow of oil, gas, and water. A cap and 
flow system is a high pressure system that includes the capping stack 
and piping necessary to convey the flowing fluids through the choke 
manifold to the surface equipment.
    Capping stack means a mechanical device, including one that is pre-
positioned, that can be installed on top of a subsea or surface wellhead 
or blowout preventer to stop the uncontrolled flow of fluids into the 
environment.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial sea and extends inland from the shorelines 
to the extent necessary to control

[[Page 55]]

shorelands, the uses of which have a direct and significant impact on 
the coastal waters, and the inward boundaries of which may be identified 
by the several coastal States, under the authority in section 305(b)(1) 
of the Coastal Zone Management Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Containment dome means a non-pressurized container that can be used 
to collect fluids escaping from the well or equipment below the sea 
surface or from seeps by suspending the device over the discharge or 
seep location. The containment dome includes all of the equipment 
necessary to capture and convey fluids to the surface.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures mean approvals granted by the appropriate BSEE or BOEM 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease; 
conserve natural resources, or protect life, property, or the marine, 
coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited to 
geophysical activity, drilling, platform construction, and operation of 
all directly related onshore support facilities, and which are for the 
purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities mean those 
G&G and related data-gathering activities on your lease or unit that you 
conduct following discovery of oil, gas, or sulphur in paying quantities 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Director means the Director of BSEE of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the BSEE officer with authority and 
responsibility for operations or other designated program functions for 
a district within a BSEE Region. For activities on the Alaska OCS, any 
reference in this part to District Manager means the BSEE Regional 
Supervisor.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the 
BOEM Director decides are adjacent to the State of Florida. The Eastern 
Gulf of Mexico is not the same as the Eastern Planning Area, an area 
established for OCS lease sales.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations mean pressure maintenance operations, 
secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in 30 CFR 550.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas sniffers, coring, 
or other systems to detect or imply the presence of oil, gas, or 
sulphur; and

[[Page 56]]

    (2) Any drilling conducted for the purpose of searching for 
commercial quantities of oil, gas, and sulphur, including the drilling 
of any additional well needed to delineate any reservoir to enable the 
lessee to decide whether to proceed with development and production.
    Facility means:
    (1) As used in Sec.  250.130, all installations permanently or 
temporarily attached to the seabed on the OCS (including manmade islands 
and bottom-sitting structures). They include mobile offshore drilling 
units (MODUs) or other vessels engaged in drilling or downhole 
operations, used for oil, gas or sulphur drilling, production, or 
related activities. They include all floating production systems (FPSs), 
variously described as column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. They also include facilities for product 
measurement and royalty determination (e.g., lease Automatic Custody 
Transfer Units, gas meters) of OCS production on installations not on 
the OCS. Any group of OCS installations interconnected with walkways, or 
any group of installations that includes a central or primary 
installation with processing equipment and one or more satellite or 
secondary installations is a single facility. The Regional Supervisor 
may decide that the complexity of the individual installations justifies 
their classification as separate facilities.
    (2) As used in 30 CFR 550.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e., with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); 
spars, etc. During production, multiple installations or devices are a 
single facility if the installations or devices are at a single site. 
Any vessel used to transfer production from an offshore facility is part 
of the facility while it is physically attached to the facility.
    (3) As used in Sec.  250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Sec. Sec.  250.900 through 250.921, means all 
installations or devices permanently or temporarily attached to the 
seabed. They are used for exploration, development, and production 
activities for oil, gas, or sulphur and emit or have the potential to 
emit any air pollutant from one or more sources. They include all 
floating production systems (FPSs), including column-stabilized-units 
(CSUs); floating production, storage and offloading facilities (FPSOs); 
tension-leg platforms (TLPs); spars, etc. During production, multiple 
installations or devices are a single facility if the installations or 
devices are at a single site. Any vessel used to transfer production 
from an offshore facility is part of the facility while it is physically 
attached to the facility.
    (5) As used in subpart S of this part, all types of structures 
permanently or temporarily attached to the seabed (e.g., mobile offshore 
drilling units (MODUs); floating production systems; floating 
production, storage and offloading facilities; tension-leg platforms; 
and spars) that are used for exploration, development, and production 
activities for oil, gas, or sulphur in the OCS. Facilities also include 
DOI-regulated pipelines.
    Flaring means the burning of natural gas as it is released into the 
atmosphere.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations mean those G&G surveys 
on your lease or unit that use seismic reflection, seismic refraction, 
magnetic, gravity, gas sniffers, coring, or other

[[Page 57]]

systems to detect or imply the presence of oil, gas, or sulphur in 
commercial quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or producing 
operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, often 
in the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of data 
and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines mean those pipelines owned and operated by a 
lessee or operator that are completely contained within the boundaries 
of a single lease, unit, or contiguous (not cornering) leases of that 
lessee or operator.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the BOEM-approved assignee of the lease, and 
the owner or the BOEM-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that 
will have a significant impact on the quality of the human environment 
requiring preparation of an environmental impact statement under section 
102(2)(C) of the National Environmental Policy Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within the 
coastal zone and on the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Maximum efficient rate (MER) means the maximum sustainable daily oil 
or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals that are authorized by an 
Act of Congress to be produced.

[[Page 58]]

    Natural resources include, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or in 
the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights mean any interest held in a lease with the right to 
explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having control 
or management of operations on the leased area or a portion thereof. An 
operator may be a lessee, the BSEE-approved or BOEM-approved designated 
agent of the lessee(s), or the holder of operating rights under a BOEM-
approved operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data collected 
under a permit or a lease that have been processed or reprocessed. 
Processing involves changing the form of data to facilitate 
interpretation. Processing operations may include, but are not limited 
to, applying corrections for known perturbing causes, rearranging or 
filtering data, and combining or transforming data elements. 
Reprocessing is the additional processing other than ordinary processing 
used in the general course of evaluation. Reprocessing operations may 
include varying identified parameters for the detailed study of a 
specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to shore, 
operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before entering 
the transportation process.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the BSEE officer with responsibility and 
authority for a Region within BSEE.
    Regional Supervisor means the BSEE officer with responsibility and 
authority for operations or other designated program functions within a 
BSEE Region.
    Right-of-use means any authorization issued under 30 CFR Part 550 to 
use OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated by a lessee or operator of that lease or unit;

[[Page 59]]

    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Routine operations, for the purposes of subpart F, mean any of the 
following operations conducted on a well with the tree installed:
    (1) Cutting paraffin;
    (2) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves that can be removed by wireline 
operations;
    (3) Bailing sand;
    (4) Pressure surveys;
    (5) Swabbing;
    (6) Scale or corrosion treatment;
    (7) Caliper and gauge surveys;
    (8) Corrosion inhibitor treatment;
    (9) Removing or replacing subsurface pumps;
    (10) Through-tubing logging (diagnostics);
    (11) Wireline fishing;
    (12) Setting and retrieving other subsurface flow-control devices; 
and
    (13) Acid treatments.
    Sensitive reservoir means a reservoir in which the production rate 
will affect ultimate recovery.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Source control and containment equipment (SCCE) means the capping 
stack, cap and flow system, containment dome, and/or other subsea and 
surface devices, equipment, and vessels the collective purpose of which 
is to control a spill source and stop the flow of fluids into the 
environment or to contain fluids escaping into the environment. 
``Surface devices'' refers to equipment mounted or staged on a barge, 
vessel, or facility to separate, treat, store and/or dispose of fluids 
conveyed to the surface by the cap and flow system or the containment 
dome. ``Subsea devices'' includes, but is not limited to, remotely 
operated vehicles, anchors, buoyancy equipment, connectors, cameras, 
controls and other subsea equipment necessary to facilitate the 
deployment, operation, and retrieval of the SCCE. The SCCE does not 
include a blowout preventer.
    Suspension means a granted or directed deferral of the requirement 
to produce (Suspension of Production (SOP)) or to conduct leaseholding 
operations (Suspension of Operations (SOO)).
    Venting means the release of gas into the atmosphere without 
igniting it. This includes gas that is released underwater and bubbles 
to the atmosphere.
    Waste of oil, gas, or sulphur means:
    (1) The physical waste of oil, gas, or sulphur;
    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes or 
tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or excessive surface loss or 
destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations mean the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or workover 
fluid as appropriate to the particular operation being conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the BOEM Director decides are adjacent to the State of 
Florida. The Western Gulf of Mexico is not the same as the Western 
Planning Area, an area established for OCS lease sales.
    Workover operations mean the work conducted on wells after the 
initial

[[Page 60]]

well-completion operation for the purpose of maintaining or restoring 
the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way 
holder, or a State lessee granted a right-of-use and easement.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20439, Apr. 5, 2013; 81 
FR 46560, July 15, 2016]

                          Performance Standards



Sec.  250.106  What standards will the Director use to regulate
 lease operations?

    The Director will regulate all operations under a lease, right-of-
use and easement, or right-of-way to:
    (a) Promote orderly exploration, development, and production of 
mineral resources;
    (b) Prevent injury or loss of life;
    (c) Prevent damage to or waste of any natural resource, property, or 
the environment; and
    (d) Cooperate and consult with affected States, local governments, 
other interested parties, and relevant Federal agencies.



Sec.  250.107  What must I do to protect health, safety, property,
 and the environment?

    (a) You must protect health, safety, property, and the environment 
by:
    (1) Performing all operations in a safe and workmanlike manner;
    (2) Maintaining all equipment and work areas in a safe condition;
    (3) Utilizing recognized engineering practices that reduce risks to 
the lowest level practicable when conducting design, fabrication, 
installation, operation, inspection, repair, and maintenance activities; 
and
    (4) Complying with all lease, plan, and permit terms and conditions.
    (b) You must immediately control, remove, or otherwise correct any 
hazardous oil and gas accumulation or other health, safety, or fire 
hazard.
    (c) Best available and safest technology. (1) On all new drilling 
and production operations and, except as provided in paragraph (c)(3) of 
this section, on existing operations, you must use the best available 
and safest technologies (BAST) which the Director determines to be 
economically feasible whenever the Director determines that failure of 
equipment would have a significant effect on safety, health, or the 
environment, except where the Director determines that the incremental 
benefits are clearly insufficient to justify the incremental costs of 
utilizing such technologies.
    (2) Conformance with BSEE regulations will be presumed to constitute 
the use of BAST unless and until the Director determines that other 
technologies are required pursuant to paragraph (c)(1) of this section.
    (3) The Director may waive the requirement to use BAST on a category 
of existing operations if the Director determines that use of BAST by 
that category of existing operations would not be practicable. The 
Director may waive the requirement to use BAST on an existing operation 
at a specific facility if you submit a waiver request demonstrating that 
the use of BAST would not be practicable.
    (d) BSEE may issue orders to ensure compliance with this part, 
including, but not limited to, orders to produce and submit records and 
to inspect, repair, and/or replace equipment. BSEE may also issue orders 
to shut-in operations of a component or facility because of a threat of 
serious, irreparable, or immediate harm to health, safety, property, or 
the environment posed by those operations or because the operations 
violate law, including a regulation, order, or provision of a lease, 
plan, or permit.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26014, Apr. 29, 2016; 
81 FR 61915, Sept. 7, 2016]



Sec.  250.108  What requirements must I follow for cranes and other
 material-handling equipment?

    (a) All cranes installed on fixed platforms must be operated in 
accordance with American Petroleum Institute's Recommended Practice for 
Operation and Maintenance of Offshore Cranes, API RP 2D (as incorporated 
by reference in Sec.  250.198).
    (b) All cranes installed on fixed platforms must be equipped with a 
functional anti-two block device.

[[Page 61]]

    (c) If a fixed platform is installed after March 17, 2003, all 
cranes on the platform must meet the requirements of American Petroleum 
Institute Specification for Offshore Pedestal Mounted Cranes, API Spec 
2C (as incorporated by reference in Sec.  250.198).
    (d) All cranes manufactured after March 17, 2003, and installed on a 
fixed platform, must meet the requirements of API Spec 2C.
    (e) You must maintain records specific to a crane or the operation 
of a crane installed on an OCS fixed platform, as follows:
    (1) Retain all design and construction records, including 
installation records for any anti-two block safety devices, for the life 
of the crane. The records must be kept at the OCS fixed platform.
    (2) Retain all inspection, testing, and maintenance records of 
cranes for at least 4 years. The records must be kept at the OCS fixed 
platform.
    (3) Retain the qualification records of the crane operator and all 
rigger personnel for at least 4 years. The records must be kept at the 
OCS fixed platform.
    (f) You must operate and maintain all other material-handling 
equipment in a manner that ensures safe operations and prevents 
pollution.



Sec.  250.109  What documents must I prepare and maintain related
 to welding?

    (a) You must submit a Welding Plan to the District Manager before 
you begin drilling or production activities on a lease. You may not 
begin welding until the District Manager has approved your plan.
    (b) You must keep the following at the site where welding occurs:
    (1) A copy of the plan and its approval letter; and
    (2) Drawings showing the designated safe-welding areas.



Sec.  250.110  What must I include in my welding plan?

    You must include all of the following in the welding plan that you 
prepare under Sec.  250.109:
    (a) Standards or requirements for welders;
    (b) How you will ensure that only qualified personnel weld;
    (c) Practices and procedures for safe welding that address:
    (1) Welding in designated safe areas;
    (2) Welding in undesignated areas, including wellbay;
    (3) Fire watches;
    (4) Maintenance of welding equipment; and
    (5) Plans showing all designated safe-welding areas.
    (d) How you will prevent spark-producing activities (i.e., grinding, 
abrasive blasting/cutting and arc-welding) in hazardous locations.



Sec.  250.111  Who oversees operations under my welding plan?

    A welding supervisor or a designated person in charge must be 
thoroughly familiar with your welding plan. This person must ensure that 
each welder is properly qualified according to the welding plan. This 
person also must inspect all welding equipment before welding.



Sec.  250.112  What standards must my welding equipment meet?

    Your welding equipment must meet the following requirements:
    (a) All engine-driven welding equipment must be equipped with spark 
arrestors and drip pans;
    (b) Welding leads must be completely insulated and in good 
condition;
    (c) Hoses must be leak-free and equipped with proper fittings, 
gauges, and regulators; and
    (d) Oxygen and fuel gas bottles must be secured in a safe place.



Sec.  250.113  What procedures must I follow when welding?

    (a) Before you weld, you must move any equipment containing 
hydrocarbons or other flammable substances at least 35 feet horizontally 
from the welding area. You must move similar equipment on lower decks at 
least 35 feet from the point of impact where slag, sparks, or other 
burning materials could fall. If moving this equipment is impractical, 
you must protect that equipment with flame-proofed covers, shield it 
with metal or fire-resistant guards or curtains, or render the flammable 
substances inert.

[[Page 62]]

    (b) While you weld, you must monitor all water-discharge-point 
sources from hydrocarbon-handling vessels. If a discharge of flammable 
fluids occurs, you must stop welding.
    (c) If you cannot weld in one of the designated safe-welding areas 
that you listed in your safe welding plan, you must meet the following 
requirements:
    (1) You may not begin welding until:
    (i) The welding supervisor or designated person in charge advises in 
writing that it is safe to weld.
    (ii) You and the designated person in charge inspect the work area 
and areas below it for potential fire and explosion hazards.
    (2) During welding, the person in charge must designate one or more 
persons as a fire watch. The fire watch must:
    (i) Have no other duties while actual welding is in progress;
    (ii) Have usable firefighting equipment;
    (iii) Remain on duty for 30 minutes after welding activities end; 
and
    (iv) Maintain a continuous surveillance with a portable gas detector 
during the welding and burning operation if welding occurs in an area 
not equipped with a gas detector.
    (3) You may not weld piping, containers, tanks, or other vessels 
that have contained a flammable substance unless you have rendered the 
contents inert and the designated person in charge has determined it is 
safe to weld. This does not apply to approved hot taps.
    (4) You may not weld within 10 feet of a wellbay unless you have 
shut in all producing wells in that wellbay.
    (5) You may not weld within 10 feet of a production area, unless you 
have shut in that production area.
    (6) You may not weld while you drill, complete, workover, or conduct 
wireline operations unless:
    (i) The fluids in the well (being drilled, completed, worked over, 
or having wireline operations conducted) are noncombustible; and
    (ii) You have precluded the entry of formation hydrocarbons into the 
wellbore by either mechanical means or a positive overbalance toward the 
formation.



Sec.  250.114  How must I install, maintain, and operate electrical
 equipment?

    The requirements in this section apply to all electrical equipment 
on all platforms, artificial islands, fixed structures, and their 
facilities.
    (a) You must classify all areas according to API RP 500, Recommended 
Practice for Classification of Locations for Electrical Installations at 
Petroleum Facilities Classified as Class I, Division 1 and Division 2 
(as incorporated by reference in Sec.  250.198), or API RP 505, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Zone 0, 
Zone 1, and Zone 2 (as incorporated by reference in Sec.  250.198).
    (b) Employees who maintain your electrical systems must have 
expertise in area classification and the performance, operation and 
hazards of electrical equipment.
    (c) You must install all electrical systems according to API RP 14F, 
Recommended Practice for Design and Installation of Electrical Systems 
for Fixed and Floating Offshore Petroleum Facilities for Unclassified 
and Class I, Division 1, and Division 2 Locations (as incorporated by 
reference in Sec.  250.198), or API RP 14FZ, Recommended Practice for 
Design and Installation of Electrical Systems for Fixed and Floating 
Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 
1, and Zone 2 Locations (as incorporated by reference in Sec.  250.198).
    (d) On each engine that has an electric ignition system, you must 
use an ignition system designed and maintained to reduce the release of 
electrical energy.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]



Sec.  250.115  What are the procedures for, and effects of, incorporation
 of documents by reference in this part?

    For the documents incorporated by reference in this part:
    (a) Incorporation by reference of a document is limited to the 
edition of the document, or the specific edition and supplement or 
addendum, that is cited in Sec.  250.198. Future amendments

[[Page 63]]

or revisions of the incorporated document are not included. BSEE will 
publish any changes to the incorporation of the document in the Federal 
Register and amend Sec.  250.198 as appropriate.
    (b) BSEE may make a rule amending the incorporation of a document 
effective without prior opportunity for public comment when BSEE 
determines:
    (1) That the revisions to the document result in safety improvements 
or represent new industry standard technology and do not impose undue 
costs on the affected parties; and
    (2) BSEE meets the requirements for making a rule immediately 
effective under 5 U.S.C. 553.
    (c) The effect of incorporation by reference of a document into the 
regulations in this part is that the incorporated document is a 
requirement. When a section in this part refers to an incorporated 
document, you are responsible for complying with the provisions of that 
entire document, except to the extent that the section that refers to 
the document provides otherwise. When a section in this part refers to a 
part of an incorporated document, you are responsible for complying with 
that part of the document as provided in that section.
    (d) Under Sec. Sec.  250.141 and 250.142, you may comply with a 
later edition of a specific document incorporated by reference, 
provided:
    (1) You show that complying with the later edition provides a degree 
of protection, safety, or performance equal to or better than would be 
achieved by compliance with the listed edition; and
    (2) You obtain prior written approval for alternative compliance 
from the authorized BSEE official.

[84 FR 21968, May 15, 2019]

    Effective Date Note: At 84 FR 21968, May 15, 2019, Sec.  250.115 was 
added, effective July 15, 2019.



Sec. Sec.  250.116-250.117  [Reserved]

                        Gas Storage or Injection



Sec.  250.118  Will BSEE approve gas injection?

    The Regional Supervisor may authorize you to inject gas on the OCS, 
on and off-lease, to promote conservation of natural resources and to 
prevent waste.
    (a) To receive BSEE approval for injection, you must:
    (1) Show that the injection will not result in undue interference 
with operations under existing leases; and
    (2) Submit a written application to the Regional Supervisor for 
injection of gas.
    (b) The Regional Supervisor will approve gas injection applications 
that:
    (1) Enhance recovery;
    (2) Prevent flaring of casinghead gas; or
    (3) Implement other conservation measures approved by the Regional 
Supervisor.



Sec.  250.119  [Reserved]



Sec.  250.120  How does injecting, storing, or treating gas affect my
 royalty payments?

    (a) If you produce gas from an OCS lease and inject it into a 
reservoir on the lease or unit for the purposes cited in Sec.  
250.118(b), you are not required to pay royalties until you remove or 
sell the gas from the reservoir.
    (b) If you produce gas from an OCS lease and store it according to 
30 CFR 550.119, you must pay royalty before injecting it into the 
storage reservoir.
    (c) If you produce gas from an OCS lease and treat it at an off-
lease or off-unit location, you must pay royalties when the gas is first 
produced.



Sec.  250.121  What happens when the reservoir contains both original
 gas in place and injected gas?

    If the reservoir contains both original gas in place and injected 
gas, when you produce gas from the reservoir you must use a BSEE-
approved formula to determine the amounts of injected or stored gas and 
gas original to the reservoir.



Sec.  250.122  What effect does subsurface storage have on the lease term?

    If you use a lease area for subsurface storage of gas, it does not 
affect the continuance or expiration of the lease.

[[Page 64]]



Sec.  250.123  [Reserved]



Sec.  250.124  Will BSEE approve gas injection into the cap rock
 containing a sulphur deposit?

    To receive the Regional Supervisor's approval to inject gas into the 
cap rock of a salt dome containing a sulphur deposit, you must show that 
the injection:
    (a) Is necessary to recover oil and gas contained in the cap rock; 
and
    (b) Will not significantly increase potential hazards to present or 
future sulphur mining operations.

                                  Fees



Sec.  250.125  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to BSEE for the services listed. The fees will be adjusted periodically 
according to the Implicit Price Deflator for Gross Domestic Product by 
publication of a document in the Federal Register. If a significant 
adjustment is needed to arrive at the new actual cost for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

------------------------------------------------------------------------
  Service--processing of the
          following:                  Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Suspension of Operations/   $2,123................  Sec.
 Suspension of Production (SOO/                          250.171(e).
 SOP) Request.
(2) Deepwater Operations Plan   $3,599................  Sec.
 (DWOP).                                                 250.292(q).
(3) Application for Permit to   $2,113 for initial      Sec.
 Drill (APD); Form BSEE-0123.    applications only; no   250.410(d);
                                 fee for revisions.      Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.1617(a).
(4) Application for Permit to   $125..................  Sec.
 Modify (APM); Form BSEE-0124.                           250.465(b);
                                                         Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.613(b);
                                                         Sec.
                                                         250.1618(a);
                                                         Sec.
                                                         250.1704(g).
(5) New Facility Production     $5,426................  Sec.   250.842.
 Safety System Application for  $14,280 additional fee
 facility with more than 125     will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $7,426
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
                                A component is a piece
                                 of equipment or
                                 ancillary system that
                                 is protected by one
                                 or more of the safety
                                 devices required by
                                 API RP 14C (as
                                 incorporated by
                                 reference in Sec.
                                 250.198).
(6) New Facility Production     $1,314................  Sec.   250.842.
 Safety System Application for  $8,967 additional fee
 facility with 25-125            will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $5,141
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
(7) New Facility Production     $652..................  Sec.   250.842.
 Safety System Application for
 facility with fewer than 25
 components.
(8) Production Safety System    $605..................  Sec.   250.842.
 Application--Modification
 with more than 125 components
 reviewed.
(9) Production Safety System    $217..................  Sec.   250.842.
 Application--Modification
 with 25-125 components
 reviewed.
(10) Production Safety System   $92...................  Sec.   250.842.
 Application--Modification
 with fewer than 25 components
 reviewed.
(11) Platform Application--     $22,734...............  Sec.
 Installation--Under the                                 250.905(l).
 Platform Verification Program.
(12) Platform Application--     $3,256................  Sec.
 Installation--Fixed Structure                           250.905(l).
 Under the Platform Approval
 Program.
(13) Platform Application--     $1,657................  Sec.
 Installation--Caisson/Well                              250.905(l)
 Protector.
(14) Platform Application--     $3,884................  Sec.
 Modification/Repair.                                    250.905(l).

[[Page 65]]

 
(15) New Pipeline Application   $3,541................  Sec.
 (Lease Term).                                           250.1000(b).
(16) Pipeline Application--     $2,056................  Sec.
 Modification (Lease Term).                              250.1000(b).
(17) Pipeline Application--     $4,169................  Sec.
 Modification (ROW).                                     250.1000(b).
(18) Pipeline Repair            $388..................  Sec.
 Notification.                                           250.1008(e).
(19) Pipeline Right-of-Way      $2,771................  Sec.
 (ROW) Grant Application.                                250.1015(a).
(20) Pipeline Conversion of     $236..................  Sec.
 Lease Term to ROW.                                      250.1015(a).
(21) Pipeline ROW Assignment..  $201..................  Sec.
                                                         250.1018(b).
(22) 500 Feet From Lease/Unit   $3,892................  Sec.
 Line Production Request.                                250.1156(a).
(23) Gas Cap Production         $4,953................  Sec.   250.1157.
 Request.
(24) Downhole Commingling       $5,779................  Sec.
 Request.                                                250.1158(a).
(25) Complex Surface            $4,056................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(26) Simple Surface             $1,371................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(27) Voluntary Unitization      $12,619...............  Sec.
 Proposal or Unit Expansion.                             250.1303(d).
(28) Unitization Revision.....  $896..................  Sec.
                                                         250.1303(d).
(29) Application to Remove a    $4,684................  Sec.   250.1727.
 Platform or Other Facility.
(30) Application to             $1,142................  Sec.
 Decommission a Pipeline                                 250.1751(a) or
 (Lease Term).                                           Sec.
                                                         250.1752(a).
(31) Application to             $2,170................  Sec.
 Decommission a Pipeline (ROW).                          250.1751(a) or
                                                         Sec.
                                                         250.1752(a).
------------------------------------------------------------------------

    (b) Payment of the fees listed in paragraph (a) of this section must 
accompany the submission of the document for approval or be sent to an 
office identified by the Regional Director. Once a fee is paid, it is 
nonrefundable, even if an application or other request is withdrawn. If 
your application is returned to you as incomplete, you are not required 
to submit a new fee when you submit the amended application.
    (c) Verbal approvals are occasionally given in special 
circumstances. Any action that will be considered a verbal permit 
approval requires either a paper permit application to follow the verbal 
approval or an electronic application submittal within 72 hours. Payment 
must be made with the completed paper or electronic application.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012; 
78 FR 60213, Oct. 1, 2013; 81 FR 26014, Apr. 29, 2016; 81 FR 61916, 
Sept. 7, 2016]



Sec.  250.126  Electronic payment instructions.

    (a) You must file all payments electronically through the Fees for 
Services page on the BSEE Web site at http://www.bsee.gov. This 
includes, but is not limited to, all OCS applications, permits, or any 
filing fees. You must include a copy of the Pay.gov confirmation receipt 
page with your application, permit, or filing fee.
    (b) If you submitted an application or permit through eWell, you 
must use the interactive payment feature in that system, which directs 
you through Pay.gov to make a payment. It is recommended that you keep a 
copy of your payment confirmation receipt in the event that any 
questions arise regarding your transaction.

[81 FR 36149, June 6, 2016]

[[Page 66]]

                        Inspections of Operations



Sec.  250.130  Why does BSEE conduct inspections?

    BSEE will inspect OCS facilities and any vessels engaged in drilling 
or other downhole operations. These include facilities under 
jurisdiction of other Federal agencies that we inspect by agreement. We 
conduct these inspections:
    (a) To verify that you are conducting operations according to the 
Act, the regulations, the lease, right-of-way, the BOEM-approved 
Exploration Plan or Development and Production Plans; or right-of-use 
and easement, and other applicable laws and regulations; and
    (b) To determine whether equipment designed to prevent or ameliorate 
blowouts, fires, spillages, or other major accidents has been installed 
and is operating properly according to the requirements of this part.



Sec.  250.131  Will BSEE notify me before conducting an inspection?

    BSEE conducts both scheduled and unscheduled inspections.



Sec.  250.132  What must I do when BSEE conducts an inspection?

    (a) When BSEE conducts an inspection, you must provide:
    (1) Access to all platforms, artificial islands, and other 
installations on your leases or associated with your lease, right-of-use 
and easement, or right-of-way; and
    (2) Helicopter landing sites and refueling facilities for any 
helicopters we use to regulate offshore operations.
    (b) You must make the following available for us to inspect:
    (1) The area covered under a lease, right-of-use and easement, 
right-of-way, or permit;
    (2) All improvements, structures, and fixtures on these areas; and
    (3) All records of design, construction, operation, maintenance, 
repairs, or investigations on or related to the area.



Sec.  250.133  Will BSEE reimburse me for my expenses related to
 inspections?

    Upon request, BSEE will reimburse you for food, quarters, and 
transportation that you provide for BSEE representatives while they 
inspect lease facilities and operations. You must send us your 
reimbursement request within 90 days of the inspection.

                            Disqualification



Sec.  250.135  What will BSEE do if my operating performance is
 unacceptable?

    BSEE will determine if your operating performance is unacceptable. 
BSEE will refer a determination of unacceptable performance to BOEM, who 
may disapprove or revoke your designation as operator on a single 
facility or multiple facilities. We will give you adequate notice and 
opportunity for a review by BSEE officials before making a determination 
that your operating performance is unacceptable.



Sec.  250.136  How will BSEE determine if my operating performance
 is unacceptable?

    In determining if your operating performance is unacceptable, BSEE 
will consider, individually or collectively:
    (a) Accidents and their nature;
    (b) Pollution events, environmental damages and their nature;
    (c) Incidents of noncompliance;
    (d) Civil penalties;
    (e) Failure to adhere to OCS lease obligations; or
    (f) Any other relevant factors.

                       Special Types of Approvals



Sec.  250.140  When will I receive an oral approval?

    When you apply for BSEE approval of any activity, we normally give 
you a written decision. The following table shows circumstances under 
which we may give an oral approval.

------------------------------------------------------------------------
    When you . . .           We may . . .              And . . .
------------------------------------------------------------------------
(a) Request approval    Give you an oral       You must then confirm the
 orally                  approval,              oral request by sending
                                                us a written request
                                                within 72 hours.
(b) Request approval    Give you an oral       We will send you a
 in writing,             approval if quick      written approval
                         action is needed,      afterward. It will
                                                include any conditions
                                                that we place on the
                                                oral approval.

[[Page 67]]

 
(c) Request approval    Give you an oral       You don't have to follow
 orally for gas          approval,              up with a written
 flaring,                                       request unless the
                                                Regional Supervisor
                                                requires it. When you
                                                stop the approved
                                                flaring, you must
                                                promptly send a letter
                                                summarizing the
                                                location, dates and
                                                hours, and volumes of
                                                liquid hydrocarbons
                                                produced and gas flared
                                                by the approved flaring
                                                (see 30 CFR 250, subpart
                                                K).
------------------------------------------------------------------------



Sec.  250.141  May I ever use alternate procedures or equipment?

    You may use alternate procedures or equipment after receiving 
approval as described in this section.
    (a) Any alternate procedures or equipment that you propose to use 
must provide a level of safety and environmental protection that equals 
or surpasses current BSEE requirements.
    (b) You must receive the District Manager's or Regional Supervisor's 
written approval before you can use alternate procedures or equipment.
    (c) To receive approval, you must either submit information or give 
an oral presentation to the appropriate Regional Supervisor. Your 
presentation must describe the site-specific application(s), performance 
characteristics, and safety features of the proposed procedure or 
equipment.



Sec.  250.142  How do I receive approval for departures?

    We may approve departures to the operating requirements. You may 
apply for a departure by writing to the District Manager or Regional 
Supervisor.



Sec. Sec.  250.143-250.144  [Reserved]



Sec.  250.145  How do I designate an agent or a local agent?

    (a) You or your designated operator may designate for the Regional 
Supervisor's approval, or the Regional Director may require you to 
designate an agent empowered to fulfill your obligations under the Act, 
the lease, or the regulations in this part.
    (b) You or your designated operator may designate for the Regional 
Supervisor's approval a local agent empowered to receive notices and 
submit requests, applications, notices, or supplemental information.



Sec.  250.146  Who is responsible for fulfilling leasehold obligations?

    (a) When you are not the sole lessee, you and your co-lessee(s) are 
jointly and severally responsible for fulfilling your obligations under 
the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582 unless otherwise provided in these regulations.
    (b) If your designated operator fails to fulfill any of your 
obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582, the Regional Supervisor may require you or any or all of 
your co-lessees to fulfill those obligations or other operational 
obligations under the Act, the lease, or the regulations.
    (c) Whenever the regulations in 30 CFR parts 250 through 282 and 30 
CFR parts 550 through 582 require the lessee to meet a requirement or 
perform an action, the lessee, operator (if one has been designated), 
and the person actually performing the activity to which the requirement 
applies are jointly and severally responsible for complying with the 
regulation.

  Naming and Identifying Facilities and Wells (Does Not Include MODUs)



Sec.  250.150  How do I name facilities and wells in the Gulf of
 Mexico Region?

    (a) Assign each facility a letter designation except for those types 
of facilities identified in paragraph (c)(1) of this section. For 
example, A, B, CA, or CB.
    (1) After a facility is installed, rename each predrilled well that 
was assigned only a number and was suspended temporarily at the mudline 
or at the surface. Use a letter and number designation. The letter used 
must be the same as that of the production facility, and the number used 
must correspond to the order in which the well was completed, not 
necessarily the number assigned when it was drilled.

[[Page 68]]

For example, the first well completed for production on Facility A would 
be renamed Well A-1, the second would be Well A-2, and so on; and
    (2) When you have more than one facility on a block, each facility 
installed, and not bridge-connected to another facility, must be named 
using a different letter in sequential order. For example, EC 222A, EC 
222B, EC 222C.
    (3) When you have more than one facility on multiple blocks in a 
local area being co-developed, each facility installed and not connected 
with a walkway to another facility should be named using a different 
letter in sequential order with the block number corresponding to the 
block on which the platform is located. For example, EC 221A, EC 222B, 
and EC 223C.
    (b) In naming multiple well caissons, you must assign a letter 
designation.
    (c) In naming single well caissons, you must use certain criteria as 
follows:
    (1) For single well caissons not attached to a facility with a 
walkway, use the well designation. For example, Well No. 1;
    (2) For single well caissons attached to a facility with a walkway, 
use the same designation as the facility. For example, rename Well No.10 
as A-10; and
    (3) For single well caissons with production equipment, use a letter 
designation for the facility name and a letter plus number designation 
for the well. For example, the Well No. 1 caisson would be designated as 
Facility A, and the well would be Well A-1.



Sec.  250.151  How do I name facilities in the Pacific Region?

    The operator assigns a name to the facility.



Sec.  250.152  How do I name facilities in the Alaska Region?

    Facilities will be named and identified according to the Regional 
Director's directions.



Sec.  250.153  Do I have to rename an existing facility or well?

    You do not have to rename facilities installed and wells drilled 
before January 27, 2000, unless the Regional Director requires it.



Sec.  250.154  What identification signs must I display?

    (a) You must identify all facilities, artificial islands, and mobile 
offshore drilling units with a sign maintained in a legible condition.
    (1) You must display an identification sign that can be viewed from 
the waterline on at least one side of the platform. The sign must use at 
least 3-inch letters and figures.
    (2) When helicopter landing facilities are present, you must display 
an additional identification sign that is visible from the air. The sign 
must use at least 12-inch letters and figures and must also display the 
weight capacity of the helipad unless noted on the top of the helipad. 
If this sign is visible to both helicopter and boat traffic, then the 
sign in paragraph (a)(1) of this section is not required.
    (3) Your identification sign must:
    (i) List the name of the lessee or designated operator;
    (ii) In the GOM OCS Region, list the area designation or 
abbreviation and the block number of the facility location as depicted 
on OCS Official Protraction Diagrams or leasing maps;
    (iii) In the Pacific OCS Region, list the lease number on which the 
facility is located; and
    (iv) List the name of the platform, structure, artificial island, or 
mobile offshore drilling unit.
    (b) You must identify singly completed wells and multiple 
completions as follows:
    (1) For each singly completed well, list the lease number and well 
number on the wellhead or on a sign affixed to the wellhead;
    (2) For wells with multiple completions, downhole splitter wells, 
and multilateral wells, identify each completion in addition to the well 
name and lease number individually on the well flowline at the wellhead; 
and
    (3) For subsea wells that flow individually into separate pipelines, 
affix the required sign on the pipeline or surface flowline dedicated to 
that subsea well at a convenient location on the receiving platform. For 
multiple subsea wells

[[Page 69]]

that flow into a common pipeline or pipelines, no sign is required.



Sec. Sec.  250.160-250.167  [Reserved]

                               Suspensions



Sec.  250.168  May operations or production be suspended?

    (a) You may request approval of a suspension, or the Regional 
Supervisor may direct a suspension (Directed Suspension), for all or any 
part of a lease or unit area.
    (b) Depending on the nature of the suspended activity, suspensions 
are labeled either Suspensions of Operations (SOO) or Suspensions of 
Production (SOP).



Sec.  250.169  What effect does suspension have on my lease?

    (a) A suspension may extend the term of a lease (see Sec.  
250.180(b), (d), and (e)). The extension is equal to the length of time 
the suspension is in effect, except as provided in paragraph (b) of this 
section.
    (b) A Directed Suspension does not extend the term of a lease when 
the Regional Supervisor directs a suspension because of:
    (1) Gross negligence; or
    (2) A willful violation of a provision of the lease or governing 
statutes and regulations.



Sec.  250.170  How long does a suspension last?

    (a) BSEE may issue suspensions for up to 5 years per suspension. The 
Regional Supervisor will set the length of the suspension based on the 
conditions of the individual case involved. BSEE may grant consecutive 
suspension periods.
    (b) An SOO ends automatically when the suspended operation 
commences.
    (c) An SOP ends automatically when production begins.
    (d) A Directed Suspension normally ends as specified in the letter 
directing the suspension.
    (e) BSEE may terminate any suspension when the Regional Supervisor 
determines the circumstances that justified the suspension no longer 
exist or that other lease conditions warrant termination. The Regional 
Supervisor will notify you of the reasons for termination and the 
effective date.



Sec.  250.171  How do I request a suspension?

    You must submit your request for a suspension to the Regional 
Supervisor, and BSEE must receive the request before the end of the 
lease term (i.e., end of primary term, end of the 1-year period 
following the last leaseholding operation, and end of a current 
suspension). Your request must include:
    (a) The justification for the suspension including the length of 
suspension requested;
    (b) A reasonable schedule of work leading to the commencement or 
restoration of the suspended activity;
    (c) A statement that a well has been drilled on the lease and 
determined to be producible according to Sec.  250.1603 (SOP only), 30 
CFR 550.115, or 30 CFR 550.116;
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec.  250.125 of this subpart.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]



Sec.  250.172  When may the Regional Supervisor grant or direct an
 SOO or SOP?

    The Regional Supervisor may grant or direct an SOO or SOP under any 
of the following circumstances:
    (a) When necessary to comply with judicial decrees prohibiting any 
activities or the permitting of those activities. The effective date of 
the suspension will be the effective date required by the action of the 
court;
    (b) When activities pose a threat of serious, irreparable, or 
immediate harm or damage. This would include a threat to life (including 
fish and other aquatic life), property, any mineral deposit, or the 
marine, coastal, or human environment. BSEE may require you to do a 
site-specific study (see Sec.  250.177(a)).
    (c) When necessary for the installation of safety or environmental 
protection equipment;
    (d) When necessary to carry out the requirements of NEPA or to 
conduct an environmental analysis; or
    (e) When necessary to allow for inordinate delays encountered in 
obtaining

[[Page 70]]

required permits or consents, including administrative or judicial 
challenges or appeals.



Sec.  250.173  When may the Regional Supervisor direct an SOO or SOP?

    The Regional Supervisor may direct a suspension when:
    (a) You failed to comply with an applicable law, regulation, order, 
or provision of a lease or permit; or
    (b) The suspension is in the interest of National security or 
defense.



Sec.  250.174  When may the Regional Supervisor grant or direct an SOP?

    The Regional Supervisor may grant or direct an SOP when the 
suspension is in the National interest, and it is necessary because the 
suspension will meet one of the following criteria:
    (a) It will allow you to properly develop a lease, including time to 
construct and install production facilities;
    (b) It will allow you time to obtain adequate transportation 
facilities;
    (c) It will allow you time to enter a sales contract for oil, gas, 
or sulphur. You must show that you are making an effort to enter into 
the contract(s); or
    (d) It will avoid continued operations that would result in 
premature abandonment of a producing well(s).



Sec.  250.175  When may the Regional Supervisor grant an SOO?

    (a) The Regional Supervisor may grant an SOO when necessary to allow 
you time to begin drilling or other operations when you are prevented by 
reasons beyond your control, such as unexpected weather, unavoidable 
accidents, or drilling rig delays.
    (b) The Regional Supervisor may grant an SOO when all of the 
following conditions are met:
    (1) The lease was issued with a primary lease term of 5 years, or 
with a primary term of 8 years with a requirement to drill within 5 
years;
    (2) Before the end of the third year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that indicates:
    (i) The presence of a salt sheet;
    (ii) That all or a portion of a potential hydrocarbon-bearing 
formation may lie beneath or adjacent to the salt sheet; and
    (iii) The salt sheet interferes with identification of the potential 
hydrocarbon-bearing formation.
    (3) The interpreted geophysical information required under paragraph 
(b)(2) of this section must include full 3-D depth migration beneath the 
salt sheet and over the entire lease area.
    (4) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing formation.
    (5) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical data or 
information; or
    (iii) Drill into the potential hydrocarbon-bearing formation 
identified as a result of the activities conducted in paragraphs (b)(2), 
(b)(4), and (b)(5) of this section.
    (c) The Regional Supervisor may grant an SOO to conduct additional 
geological and geophysical data analysis that may lead to the drilling 
of a well below 25,000 feet true vertical depth below the datum at mean 
sea level (TVD SS) when all of the following conditions are met:
    (1) The lease was issued with a primary lease term of:
    (i) Five years; or
    (ii) Eight years with a requirement to drill within 5 years.
    (2) Before the end of the fifth year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that:
    (i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
    (ii) Includes full 3-D depth migration over the entire lease area.
    (3) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing geologic structure or stratigraphic trap lying below 
25,000 feet TVD SS.

[[Page 71]]

    (4) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical or geological 
data or information that would affect the decision to drill the same 
geologic structure or stratigraphic trap, as determined by the Regional 
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; 
or
    (iii) Drill a well below 25,000 feet TVD SS into the geologic 
structure or stratigraphic trap identified as a result of the activities 
conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this 
section.



Sec.  250.176  Does a suspension affect my royalty payment?

    A directed suspension may affect the payment of rental or royalties 
for the lease as provided in 30 CFR 1218.154.



Sec.  250.177  What additional requirements may the Regional
Supervisor order for a suspension?

    If BSEE grants or directs a suspension under paragraph Sec.  
250.172(b), the Regional Supervisor may require you to:
    (a) Conduct a site-specific study.
    (1) The Regional Supervisor must approve or prescribe the scope for 
any site-specific study that you perform.
    (2) The study must evaluate the cause of the hazard, the potential 
damage, and the available mitigation measures.
    (3) You must pay for the study unless you request, and the Regional 
Supervisor agrees to arrange, payment by another party.
    (4) You must furnish copies and results of the study to the Regional 
Supervisor.
    (5) BSEE will make the results available to other interested parties 
and to the public.
    (6) The Regional Supervisor will use the results of the study and 
any other information that becomes available:
    (i) To decide if the suspension can be lifted; and
    (ii) To determine any actions that you must take to mitigate or 
avoid any damage to the environment, life, or property.
    (b) Submit a revised Exploration Plan (including any required 
mitigating measures);
    (c) Submit a revised Development and Production Plan (including any 
required mitigating measures); or
    (d) Submit a revised Development Operations Coordination Document 
according to 30 CFR part 550, subpart B.

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations



Sec.  250.180  What am I required to do to keep my lease term in
 effect?

    (a) If your lease is in its primary term:
    (1) You must submit a report to the District Manager according to 
paragraphs (h) and (i) of this section whenever production begins 
initially, whenever production ceases during the last year of the 
primary term, and whenever production resumes during the last year of 
the primary term.
    (2) Your lease expires at the end of its primary term unless you are 
conducting operations on your lease (see 30 CFR part 556). For purposes 
of this section, the term operations means, drilling, well-reworking, or 
production in paying quantities. The objective of the drilling or well-
reworking must be to establish production in paying quantities on the 
lease.
    (b) If you stop conducting operations during the last year of your 
primary lease term, your lease will expire unless you either resume 
operations or receive an SOO or an SOP from the Regional Supervisor 
under Sec.  250.172, Sec.  250.173, Sec.  250.174, or Sec.  250.175 
before the end of the year after you stop operations.
    (c) If you extend your lease term under paragraph (b) of this 
section, you must pay rental or minimum royalty, as appropriate, for 
each year or part of the year during which your lease continues in force 
beyond the end of the primary lease term.
    (d) If you stop conducting operations on a lease that has continued 
beyond its primary term, your lease will expire

[[Page 72]]

unless you resume operations or receive an SOO or an SOP from the 
Regional Supervisor under Sec.  250.172, Sec.  250.173, Sec.  250.174, 
or Sec.  250.175 before the end of the year after you stop operations.
    (e) You may ask the Regional Supervisor to allow you more than a 
year to resume operations on a lease continued beyond its primary term 
when operating conditions warrant. The request must be in writing and 
explain the operating conditions that warrant a longer period. In 
allowing additional time, the Regional Supervisor must determine that 
the longer period is in the National interest, and it conserves 
resources, prevents waste, or protects correlative rights.
    (f) When you begin conducting operations on a lease that has 
continued beyond its primary term, you must immediately notify the 
District Manager either orally or by fax or e-mail and follow up with a 
written report according to paragraph (g) of this section.
    (g) If your lease is continued beyond its primary term, you must 
submit a report to the District Manager under paragraphs (h) and (i) of 
this section whenever production begins initially, whenever production 
ceases, whenever production resumes before the end of the 1-year period 
after having ceased, or whenever drilling or well-reworking operations 
begin before the end of the 1-year period.
    (h) The reports required by paragraphs (a) and (g) of this section 
must contain:
    (1) Name of lessee or operator;
    (2) The well number, lease number, area, and block;
    (3) As appropriate, the unit agreement name and number; and
    (4) A description of the operation and pertinent dates.
    (i) You must submit the reports required by paragraphs (a) and (g) 
of this section within the following timeframes:
    (1) Initialization of production--within 5 days of initial 
production.
    (2) Cessation of production--within 15 days after the first full 
month of zero production.
    (3) Resumption of production--within 5 days of resuming production 
after ceasing production under paragraph (i)(2) of this section.
    (4) Drilling or well reworking operations--within 5 days of 
beginning and completing the leaseholding operations.
    (j) For leases continued beyond the primary term, you must 
immediately report to the District Manager if operations do not begin 
before the end of the 1-year period.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]



Sec. Sec.  250.181-250.185  [Reserved]

                 Information and Reporting Requirements



Sec.  250.186  What reporting information and report forms must
 I submit?

    (a) You must submit information and reports as BSEE requires.
    (1) You may obtain copies of forms from, and submit completed forms 
to, the District Manager or Regional Supervisor.
    (2) Instead of paper copies of forms available from the District 
Manager or Regional Supervisor, you may use your own computer-generated 
forms that are equal in size to BSEE's forms. You must arrange the data 
on your form identical to the BSEE form. If you generate your own form 
and it omits terms and conditions contained on the official BSEE form, 
we will consider it to contain the omitted terms and conditions.
    (3) You may submit digital data when the Region/District is equipped 
to accept it.
    (b) When BSEE specifies, you must include, for public information, 
an additional copy of such reports.
    (1) You must mark it Public Information
    (2) You must include all required information, except information 
exempt from public disclosure under Sec.  250.197 or otherwise exempt 
from public disclosure under law or regulation.



Sec.  250.187  What are BSEE's incident reporting requirements?

    (a) You must report all incidents listed in Sec.  250.188(a) and (b) 
to the District

[[Page 73]]

Manager. The specific reporting requirements for these incidents are 
contained in Sec. Sec.  250.189 and 250.190.
    (b) These reporting requirements apply to incidents that occur on 
the area covered by your lease, right-of-use and easement, pipeline 
right-of-way, or other permit issued by BOEM or BSEE, and that are 
related to operations resulting from the exercise of your rights under 
your lease, right-of-use and easement, pipeline right-of-way, or permit.
    (c) Nothing in this subpart relieves you from making notifications 
and reports of incidents that may be required by other regulatory 
agencies.
    (d) You must report all spills of oil or other liquid pollutants in 
accordance with 30 CFR 254.46.



Sec.  250.188  What incidents must I report to BSEE and when must
 I report them?

    (a) You must report the following incidents to the District Manager 
immediately via oral communication, and provide a written follow-up 
report (hard copy or electronically transmitted) within 15 calendar days 
after the incident:
    (1) All fatalities.
    (2) All injuries that require the evacuation of the injured 
person(s) from the facility to shore or to another offshore facility.
    (3) All losses of well control. ``Loss of well control'' means:
    (i) Uncontrolled flow of formation or other fluids. The flow may be 
to an exposed formation (an underground blowout) or at the surface (a 
surface blowout);
    (ii) Flow through a diverter; or
    (iii) Uncontrolled flow resulting from a failure of surface 
equipment or procedures.
    (4) All fires and explosions.
    (5) All reportable releases of hydrogen sulfide (H2S) 
gas, as defined in Sec.  250.490(l).
    (6) All collisions that result in property or equipment damage 
greater than $25,000. ``Collision'' means the act of a moving vessel 
(including an aircraft) striking another vessel, or striking a 
stationary vessel or object (e.g., a boat striking a drilling rig or 
platform). ``Property or equipment damage'' means the cost of labor and 
material to restore all affected items to their condition before the 
damage, including, but not limited to, the OCS facility, a vessel, 
helicopter, or equipment. It does not include the cost of salvage, 
cleaning, gas-freeing, dry docking, or demurrage.
    (7) All incidents involving structural damage to an OCS facility. 
``Structural damage'' means damage severe enough so that operations on 
the facility cannot continue until repairs are made.
    (8) All incidents involving crane or personnel/material handling 
operations.
    (9) All incidents that damage or disable safety systems or equipment 
(including firefighting systems).
    (b) You must provide a written report of the following incidents to 
the District Manager within 15 calendar days after the incident:
    (1) Any injuries that result in one or more days away from work or 
one or more days on restricted work or job transfer. One or more days 
means the injured person was not able to return to work or to all of 
their normal duties the day after the injury occurred;
    (2) All gas releases that initiate equipment or process shutdown;
    (3) All incidents that require operations personnel on the facility 
to muster for evacuation for reasons not related to weather or drills;
    (4) All other incidents, not listed in paragraph (a) of this 
section, resulting in property or equipment damage greater than $25,000.
    (c) On the Arctic OCS, in addition to the requirements of paragraphs 
(a) and (b) of this section, you must provide to the BSEE inspector on 
location, if one is present, or to the Regional Supervisor, both of the 
following:
    (1) An immediate oral report if any of the following occur:
    (i) Any sea ice movement or condition that has the potential to 
affect your operation or trigger ice management activities;
    (ii) The start and termination of ice management activities; or
    (iii) Any ``kicks'' or operational issues that are unexpected and 
could result in the loss of well control.
    (2) Within 24 hours after completing ice management activities, a 
written

[[Page 74]]

report of such activities that conforms to the content requirements in 
Sec.  250.190.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]



Sec.  250.189  Reporting requirements for incidents requiring
 immediate notification.

    For an incident requiring immediate notification under Sec.  
250.188(a), you must notify the District Manager via oral communication 
immediately after aiding the injured and stabilizing the situation. Your 
oral communication must provide the following information:
    (a) Date and time of occurrence;
    (b) Operator, and operator representative's, name and telephone 
number;
    (c) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury/fatality);
    (d) Lease number, OCS area, and block;
    (e) Platform/facility name and number, or pipeline segment number;
    (f) Type of incident or injury/fatality;
    (g) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane, etc.); and
    (h) Description of the incident, damage, or injury/fatality.



Sec.  250.190  Reporting requirements for incidents requiring written
 notification.

    (a) For any incident covered under Sec.  250.188, you must submit a 
written report within 15 calendar days after the incident to the 
District Manager. The report must contain the following information:
    (1) Date and time of occurrence;
    (2) Operator, and operator representative's name and telephone 
number;
    (3) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury);
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or pipeline segment number;
    (6) Type of incident or injury;
    (7) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane etc.);
    (8) Description of incident, damage, or injury (including days away 
from work, restricted work or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section, 
provided the report or form contains all required information.
    (c) The District Manager may require you to submit additional 
information about an incident on a case-by-case basis.



Sec.  250.191  How does BSEE conduct incident investigations?

    Any investigation that BSEE conducts under the authority of sections 
22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is a fact-
finding proceeding with no adverse parties. The purpose of the 
investigation is to prepare a public report that determines the cause or 
causes of the incident. The investigation may involve panel meetings 
conducted by a chairperson appointed by BSEE. The following requirements 
apply to any panel meetings involving persons giving testimony:
    (a) A person giving testimony may have legal or other 
representative(s) present to provide advice or counsel while the person 
is giving testimony. The chairperson may require a verbatim transcript 
to be made of all oral testimony. The chairperson also may accept a 
sworn written statement in lieu of oral testimony.
    (b) Only panel members, and any experts the panel deems necessary, 
may address questions to any person giving testimony.
    (c) The chairperson may issue subpoenas to persons to appear and 
provide testimony or documents at a panel meeting. A subpoena may not 
require a person to attend a panel meeting held at a location more than 
100 miles from where a subpoena is served.
    (d) Any person giving testimony may request compensation for 
mileage, and fees for services, within 90 days after the panel meeting. 
The compensated expenses must be similar to mileage and fees the U.S. 
District Courts allow.

[[Page 75]]



Sec.  250.192  What reports and statistics must I submit relating
 to a hurricane, earthquake, or other natural occurrence?

    (a) You must submit evacuation statistics to the Regional Supervisor 
for a natural occurrence, such as a hurricane, a tropical storm, or an 
earthquake. Statistics include facilities and rigs evacuated and the 
amount of production shut-in for gas and oil. You must:
    (1) Submit the statistics by fax or e-mail (for activities in the 
BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when 
evacuation occurs. In lieu of submitting your statistics by fax or e-
mail, you may submit them electronically in accordance with 30 CFR 
250.186(a)(3);
    (2) Submit the statistics on a daily basis by 11 a.m., as conditions 
allow, during the period of shut-in and evacuation;
    (3) Inform BSEE when you resume production; and
    (4) Submit the statistics either by BSEE district, or the total 
figures for your operations in a BSEE region.
    (b) If your facility, production equipment, or pipeline is damaged 
by a natural occurrence, you must:
    (1) Submit an initial damage report to the Regional Supervisor 
within 48 hours after you complete your initial evaluation of the 
damage. You must use Form BSEE-0143, Facility/Equipment Damage Report, 
to make this and all subsequent reports. In lieu of submitting Form 
BSEE-0143 by fax or e-mail, you may submit the damage report 
electronically in accordance with 30 CFR 250.186(a)(3). In the report, 
you must:
    (i) Name the items damaged (e.g., platform or other structure, 
production equipment, pipeline);
    (ii) Describe the damage and assess the extent of the damage (major, 
medium, minor); and
    (iii) Estimate the time it will take to replace or repair each 
damaged structure and piece of equipment and return it to service. The 
initial estimate need not be provided on the form until availability of 
hardware and repair capability has been established (not to exceed 30 
days from your initial report).
    (2) Submit subsequent reports monthly and immediately whenever 
information submitted in previous reports changes until the damaged 
structure or equipment is returned to service. In the final report, you 
must provide the date the item was returned to service.



Sec.  250.193  Reports and investigations of possible violations.

    (a) Any person may report to BSEE any hazardous or unsafe working 
condition on any facility engaged in OCS activities, and any possible 
violation or failure to comply with:
    (1) Any provision of the Act,
    (2) Any provision of a lease, approved plan, or permit issued under 
the Act,
    (3) Any provision of any regulation or order issued under the Act, 
or
    (4) Any other Federal law relating to safety of offshore oil and gas 
operations.
    (b) To make a report under this section, a person is not required to 
know whether any legal requirement listed in paragraph (a) of this 
section has been violated.
    (c) When BSEE receives a report of a possible violation, or when a 
BSEE employee detects a possible violation, BSEE will investigate 
according to BSEE procedures and notify any other Federal agency(ies) 
for further investigation, as appropriate.
    (d) BSEE investigations of possible violations may include:
    (1) Conducting interviews of personnel;
    (2) Requiring the prompt production of documents, data, and other 
evidence;
    (3) Requiring the preservation of all relevant evidence and access 
for BSEE investigators to such evidence; and
    (4) Taking other actions and imposing other requirements as 
necessary to investigate possible violations and assure an orderly 
investigation.
    (e)(1) Reports should contain sufficient credible information to 
establish a reasonable basis for BSEE to investigate whether a violation 
or other hazardous or unsafe working condition exists.
    (2) To report hazardous or unsafe working conditions or a possible 
violation:
    (i) Contact BSEE by:

[[Page 76]]

    (A) Phone at 1-877-440-0173 (BSEE Toll-free Safety Hotline),
    (B) Internet at www.bsee.gov, or
    (C) Mail to: U.S. DOI/BSEE, 1849 C Street NW., Mail Stop 5438, 
Washington, DC 20240 Attention: IRU Hotline Operations.
    (ii) Include the following items in the report:
    (A) Name, address, and telephone number should be provided if you do 
not want to remain anonymous;
    (B) The specific concern, provision or Federal law, if known, 
referenced in (a) that a person violated or with which a person failed 
to comply; and
    (C) Any other facts, data, and applicable information.
    (f) When a possible violation is reported, BSEE will protect a 
person's identity to the extent authorized by law.

[78 FR 20439, Apr. 5, 2013, as amended at 81 FR 36149, June 6, 2016]



Sec.  250.194  How must I protect archaeological resources?

    (a)-(b) [Reserved]
    (c) If you discover any archaeological resource while conducting 
operations in the lease or right-of-way area, you must immediately halt 
operations within the area of the discovery and report the discovery to 
the BSEE Regional Director. If investigations determine that the 
resource is significant, the Regional Director will tell you how to 
protect it.



Sec.  250.195  What notification does BSEE require on the production
 status of wells?

    You must notify the appropriate BSEE District Manager when you 
successfully complete or recomplete a well for production. You must:
    (a) Notify the District Manager within 5 working days of placing the 
well in a production status. You must confirm oral notification by 
telefax or e-mail within those 5 working days.
    (b) Provide the following information in your notification:
    (1) Lessee or operator name;
    (2) Well number, lease number, and OCS area and block designations;
    (3) Date you placed the well on production (indicate whether or not 
this is first production on the lease);
    (4) Type of production; and
    (5) Measured depth of the production interval.



Sec.  250.196  Reimbursements for reproduction and processing costs.

    (a) BSEE will reimburse you for costs of reproducing data and 
information that the Regional Director requests if:
    (1) You deliver geophysical and geological (G&G) data and 
information to BSEE for the Regional Director to inspect or select and 
retain;
    (2) BSEE receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate or at the lowest commercial rate 
established in the area, whichever is less.
    (b) BSEE will reimburse you for the costs of processing geophysical 
information (that does not include cost of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business; or
    (2) If you collected the information under a permit that BSEE issued 
to you before October 1, 1985, and the Regional Director requests and 
retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) BSEE will not reimburse you for data acquisition costs or for 
the costs of analyzing or processing geological information or 
interpreting geological or geophysical information.



Sec.  250.197  Data and information to be made available to the public
 or for limited inspection.

    BSEE will protect data and information that you submit under this 
part, and 30 CFR part 203, as described in this section. Paragraphs (a) 
and (b) of this section describe what data and information will be made 
available to the public without the consent of the lessee, under what 
circumstances, and in what time period. Paragraph (c) of this section 
describes what data and information will be made available for limited 
inspection without the consent of

[[Page 77]]

the lessee, and under what circumstances.
    (a) All data and information you submit on BSEE forms will be made 
available to the public upon submission, except as specified in the 
following table:

------------------------------------------------------------------------
                              Data and information
                                 not immediately     Excepted data will
        On form . . .          available are . . .   be made available .
                                                             . .
------------------------------------------------------------------------
(1) BSEE-0123, Application    Items 15, 16, 22      When the well goes
 for Permit to Drill,          through 25,           on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(2) BSEE-0123S, Supplemental  Items 3, 7, 8, 15     When the well goes
 APD Information Sheet,        and 17,               on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(3) BSEE-0124, Application    Item 17,              When the well goes
 for Permit to Modify,                               on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(4) BSEE-0125, End of         Items 12, 13, 17,     When the well goes
 Operations Report,            21, 22, 26 through    on production or
                               38,                   according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
                                                     However, items 33
                                                     through 38 will not
                                                     be released when
                                                     the well goes on
                                                     production unless
                                                     the period of time
                                                     in the table in
                                                     paragraph (b) has
                                                     expired.
(5) BSEE-0126, Well           Item 101,             2 years after you
 Potential Test Report,                              submit it.
(6) [Reserved]
(7) BSEE-0133 Well Activity   Item 10 Fields        When the well goes
 Report,                       [WELLBORE START       on production or
                               DATE, TD DATE, OP     according to the
                               STATUS, END DATE,     table in paragraph
                               MD, TVD, AND MW       (b) of this
                               PPG]. Item 11         section, whichever
                               Fields [WELLBORE      is earlier.
                               START DATE, TD
                               DATE, PLUGBACK
                               DATE, FINAL MD, AND
                               FINAL TVD] and
                               Items 12 through
                               15,
(8) BSEE-0133S Open Hole      Boxes 7 and 8,        When the well goes
 Data Report,                                        on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(9) [Reserved]
(10) [Reserved]
------------------------------------------------------------------------

    (b) BSEE will release lease and permit data and information that you 
submit and BSEE retains, but that are not normally submitted on BSEE 
forms, according to the following table:

------------------------------------------------------------------------
                                                             Special
     If . . .      BSEE will release   At this time . .   provisions . .
                         . . .                .                 .
------------------------------------------------------------------------
(1) The Director   Geophysical data,  At any time,       BSEE will
 determines that    Geological data                       release data
 data and           Interpreted G&G                       and
 information are    information,                          information
 needed for         Processed G&G                         only if
 specific           information,                          release would
 scientific or      Analyzed                              further the
 research           geological                            National
 purposes for the   information,                          interest
 Government,                                              without unduly
                                                          damaging the
                                                          competitive
                                                          position of
                                                          the lessee.
(2) Data or        Geophysical data,  60 days after      BSEE will
 information is     Geological data,   BSEE receives      release the
 collected with     Interpreted G&G    the data or        data and
 high-resolution    information,       information, if    information
 systems (e.g.,     Processed          the Regional       earlier than
 bathymetry, side-  geological         Supervisor deems   60 days if the
 scan sonar,        information,       it necessary,      Regional
 subbottom          Analyzed                              Supervisor
 profiler, and      geological                            determines it
 magnetometer) to   information,                          is needed by
 comply with                                              affected
 safety or                                                States to make
 environmental                                            decisions
 protection                                               under 30 CFR
 requirements,                                            550, subpart
                                                          B. The
                                                          Regional
                                                          Supervisor
                                                          will
                                                          reconsider
                                                          earlier
                                                          release if you
                                                          satisfy him/
                                                          her that it
                                                          would unduly
                                                          damage your
                                                          competitive
                                                          position.

[[Page 78]]

 
(3) Your lease is  Geophysical data,  When your lease    This release
 no longer in       Geological data,   terminates,        time applies
 effect,            Processed G&G                         only if the
                    information                           provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                    Analyzed                              resolution
                    geological                            systems and
                    information,                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. The
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(4) Your lease is  Geophysical data,  10 years after     This release
 still in effect,   Processed          you submit the     time applies
                    geophysical        data and           only if the
                    information,       information,       provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                                                          resolution
                                                          systems and
                                                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. This
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(5) Your lease is  Geological data,   2 years after the  These release
 still in effect    Analyzed           required           times apply
 and within the     geological         submittal date     only if the
 primary term       information,       or 60 days after   provisions in
 specified in the                      a lease sale if    this table
 lease,                                any portion of     governing high-
                                       an offered lease   resolution
                                       is within 50       systems and
                                       miles of a well,   the provisions
                                       whichever is       in 30 CFR
                                       later,             552.7 do not
                                                          apply. If the
                                                          primary term
                                                          specified in
                                                          the lease is
                                                          extended under
                                                          the heading of
                                                          ``Suspensions'
                                                          ' in this
                                                          subpart, the
                                                          extension
                                                          applies to
                                                          this
                                                          provision.
(6) Your lease is  Geological data,   2 years after the  None.
 in effect and      Analyzed           required
 beyond the         geological         submittal date,
 primary term       information,
 specified in the
 lease,
(7) Data or        Descriptions of    When the well      Directional
 information is     downhole           goes on            survey data
 submitted on       locations,         production or      may be
 well operations,   operations, and    when geological    released
                    equipment,         data is released   earlier to the
                                       according to       owner of an
                                       Sec.  Sec.         adjacent lease
                                       250.197(b)(5)      according to
                                       and (b)(6),        Subpart D of
                                       whichever occurs   this part.
                                       earlier,
(8) Data and       Any data or        At any time,       None.
 information are    information
 obtained from      obtained,
 beneath unleased
 land as a result
 of a well
 deviation that
 has not been
 approved by the
 District Manager
 or Regional
 Supervisor,
(9) Except for     G&G data,          Geological data    None.
 high-resolution    analyzed           and information:
 data and           geological         10 years after
 information        information,       BOEM issues the
 released under     processed and      permit;
 paragraph (b)(2)   interpreted G&G    Geophysical
 of this section    information,       data: 50 years
 data and                              after BOEM
 information                           issues the
 acquired by a                         permit;
 permit under 30                       Geophysical
 CFR part 551 are                      information: 25
 submitted by a                        years after BOEM
 lessee under 30                       issues the
 CFR part 203, 30                      permit,
 CFR part 250, or
 30 CFR part 550,
------------------------------------------------------------------------

    (c) BSEE may allow limited inspection, but only by persons with a 
direct interest in related BSEE decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part or 30 CFR part 203 
that BSEE uses to:
    (1) Make unitization determinations on two or more leases;
    (2) Make competitive reservoir determinations;
    (3) Ensure proper plans of development for competitive reservoirs;
    (4) Promote operational safety;
    (5) Protect the environment;
    (6) [Reserved]; or

[[Page 79]]

    (7) Determine eligibility for royalty relief.

                               References



Sec.  250.198  Documents incorporated by reference.

    (a) The BSEE is incorporating by reference the documents listed in 
paragraphs (e) through (k) of this section. Paragraphs (e) through (k) 
identify the publishing organization of the documents, the address and 
phone number where you may obtain these documents, and the documents 
incorporated by reference. The Director of the Federal Register has 
approved the incorporations by reference according to 5 U.S.C. 552(a) 
and 1 CFR part 51.
    (1) Incorporation by reference of a document is limited to the 
edition of the publication that is cited in this section. Future 
amendments or revisions of the document are not included. The BSEE will 
publish any changes to a document in the Federal Register and amend this 
section.
    (2) The BSEE may make the rule amending the document effective 
without prior opportunity for public comment when BSEE determines:
    (i) That the revisions to a document result in safety improvements 
or represent new industry standard technology and do not impose undue 
costs on the affected parties; and
    (ii) The BSEE meets the requirements for making a rule immediately 
effective under 5 U.S.C. 553.
    (3) The effect of incorporation by reference of a document into the 
regulations in this part is that the incorporated document is a 
requirement. When a section in this part incorporates all of a document, 
you are responsible for complying with the provisions of that entire 
document, except to the extent that the section which incorporates the 
document by reference provides otherwise. When a section in this part 
incorporates part of a document, you are responsible for complying with 
that part of the document as provided in that section.
    (b) The BSEE incorporated each document or specific portion by 
reference in the sections noted. The entire document is incorporated by 
reference, unless the text of the corresponding sections in this part 
calls for compliance with specific portions of the listed documents. In 
each instance, the applicable document is the specific edition or 
specific edition and supplement or addendum cited in this section.
    (c) Under Sec. Sec.  250.141 and 250.142, you may comply with a 
later edition of a specific document incorporated by reference, 
provided:
    (1) You show that complying with the later edition provides a degree 
of protection, safety, or performance equal to or better than would be 
achieved by compliance with the listed edition; and
    (2) You obtain the prior written approval for alternative compliance 
from the authorized BSEE official.
    (d) You may inspect these documents at the Bureau of Safety and 
Environmental Enforcement, 45600 Woodland Rd, Sterling, VA 20166; phone: 
1-844-259-4779; or at the National Archives and Records Administration 
(NARA). For information on the availability of this material at NARA, 
call 202-741-6030, or go to: http://www.archives.gov/federal_register/
code_of_federal_regulations/ibr_locations.html.
    (e) American Concrete Institute (ACI), ACI Standards, 38800 Country 
Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org; 
phone: 248-848-3700:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95), incorporated by reference at Sec.  250.901.
    (2) ACI 318R-95, Commentary on Building Code Requirements for 
Reinforced Concrete, incorporated by reference at Sec.  250.901.
    (3) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec.  250.901.
    (f) American Institute of Steel Construction, Inc. (AISC), AISC 
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; 
http://www.aisc.org; phone: 312-670-2400:
    (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings 
incorporated by reference at Sec.  250.901.
    (2) [Reserved]
    (g) American Society of Mechanical Engineers (ASME), 22 Law Drive, 
P.O.

[[Page 80]]

Box 2900, Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-800-
843-2763:
    (1) 2017 ASME Boiler and Pressure Vessel Code (BPVC), Section I, 
Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017 
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules for 
Construction of Heating Boilers, 2017 Edition, July 1, 2017 incorporated 
by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (3) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Division 1, 2017 Edition; July 1, 
2017 incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (4) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Division 2: Alternative Rules, 
2017 Edition, July 1, 2017 incorporated by reference at Sec. Sec.  
250.851(a) and 250.1629(b).
    (5) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction Pressure Vessels; Division 3: Alternative Rules for 
Construction of High Pressure Vessels, 2017 Edition, July 1, 2017 
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (6) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings 
incorporated by reference at Sec.  250.1002.
    (7) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems incorporated by reference at Sec.  250.1002.
    (h) American Petroleum Institute (API), API Recommended Practices 
(RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) 
chapters, 1220 L Street, NW., Washington, DC 20005-4070; http://
www.api.org; phone: 202-682-8000:
    (1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, 
Rating, Repair, and Alteration, Tenth Edition, May 2014; Addendum 1, May 
2017; incorporated by reference at Sec. Sec.  250.851(a) and 
250.1629(b);
    (2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007; incorporated by reference 
at Sec.  250.901;
    (3) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007; 
incorporated by reference at Sec.  250.901;
    (4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007; incorporated by reference at Sec.  
250.901;
    (5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994; 
incorporated by reference at Sec.  250.1201;
    (6) API MPMS, Chapter 2--Tank Calibration, Section 2A--Measurement 
and Calibration of Upright Cylindrical Tanks by the Manual Tank 
Strapping Method, First Edition, February 1995; reaffirmed February 
2007; incorporated by reference at Sec.  250.1202;
    (7) API MPMS, Chapter 2--Tank Calibration, Section 2B--Calibration 
of Upright Cylindrical Tanks Using the Optical Reference Line Method, 
First Edition, March 1989; reaffirmed, December 2007; incorporated by 
reference at Sec.  250.1202;
    (8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice 
for the Manual Gauging of Petroleum and Petroleum Products, Second 
Edition, August 2005; incorporated by reference at Sec.  250.1202;
    (9) API MPMS, Chapter 3--Tank Gauging, Section 1B--Standard Practice 
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, October 
2006; incorporated by reference at Sec.  250.1202;
    (10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005; incorporated by reference at Sec.  
250.1202;
    (11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003; incorporated by reference at 
Sec.  250.1202;
    (12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005; incorporated by 
reference at Sec.  250.1202;
    (13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter 
Provers, Second Edition, May 2000, reaffirmed: August 2005; incorporated 
by reference at Sec.  250.1202;

[[Page 81]]

    (14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated 
by reference at Sec.  250.1202;
    (15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard 
Test Measures, Second Edition, December 1998; reaffirmed 2003; 
incorporated by reference at Sec.  250.1202;
    (16) API MPMS, Chapter 5--Metering, Section 1--General 
Considerations for Measurement by Meters, Fourth Edition, September 
2005; incorporated by reference at Sec.  250.1202;
    (17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid 
Hydrocarbons by Displacement Meters, Third Edition, September 2005; 
incorporated by reference at Sec.  250.1202;
    (18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005; 
incorporated by reference at Sec.  250.1202;
    (19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005; incorporated by 
reference at Sec.  250.1202;
    (20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security 
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, 
August 2005; incorporated by reference at Sec.  250.1202;
    (21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007; incorporated by reference at Sec.  250.1202;
    (22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007; 
incorporated by reference at Sec.  250.1202;
    (23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007; 
incorporated by reference at Sec.  250.1202;
    (24) API MPMS, Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.  
250.1202;
    (25) API MPMS, Chapter 8--Sampling, Section 1--Standard Practice for 
Manual Sampling of Petroleum and Petroleum Products, Third Edition, 
October 1995; reaffirmed, March 2006; incorporated by reference at Sec.  
250.1202;
    (26) API MPMS, Chapter 8--Sampling, Section 2--Standard Practice for 
Automatic Sampling of Liquid Petroleum and Petroleum Products, Second 
Edition, October 1995; reaffirmed, June 2005; incorporated by reference 
at Sec.  250.1202;
    (27) API MPMS, Chapter 9--Density Determination, Section 1--Standard 
Test Method for Density, Relative Density (Specific Gravity), or API 
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer 
Method, Second Edition, December 2002; reaffirmed October 2005; 
incorporated by reference at Sec.  250.1202(a)(3) and (l)(4);
    (28) API MPMS, Chapter 9--Density Determination, Section 2--Standard 
Test Method for Density or Relative Density of Light Hydrocarbons by 
Pressure Hydrometer, Second Edition, March 2003; incorporated by 
reference at Sec.  250.1202;
    (29) API MPMS, Chapter 10--Sediment and Water, Section 1--Standard 
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction 
Method, Third Edition, November 2007; incorporated by reference at Sec.  
250.1202;
    (30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007; incorporated by reference at Sec.  250.1202;
    (31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in Crude Oil by the Centrifuge Method 
(Laboratory Procedure), Third Edition, May 2008; incorporated by 
reference at Sec.  250.1202;
    (32) API MPMS, Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge 
Method (Field Procedure), Third Edition, December 1999; incorporated by 
reference at Sec.  250.1202;
    (33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard 
Test Method for Water in Crude Oils by Coulometric Karl Fischer 
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated 
by reference at Sec.  250.1202;

[[Page 82]]

    (34) API MPMS, Chapter 11.1--Volume Correction Factors, Volume 1, 
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API 
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude 
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at 
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed 
March 1997; incorporated by reference at Sec.  250.1202;
    (35) API MPMS, Chapter 11.2.2--Compressibility Factors for 
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -50 
[deg]F to 140 [deg]F Metering Temperature, Second Edition, October 1986; 
reaffirmed: December 2007; incorporated by reference at Sec.  250.1202;
    (36) API MPMS, Chapter 11--Physical Properties Data, Addendum to 
Section 2, Part 2--Compressibility Factors for Hydrocarbons, Correlation 
of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, 
December 1994; reaffirmed, December 2002; incorporated by reference at 
Sec.  250.1202;
    (37) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 1--Introduction, Second 
Edition, May 1995; reaffirmed March 2002; incorporated by reference at 
Sec.  250.1202;
    (38) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 2--Measurement Tickets, 
Third Edition, June 2003; incorporated by reference at Sec.  250.1202;
    (39) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations 
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed 
January 2003; incorporated by reference at Sec.  250.1203;
    (40) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and 
Installation Requirements, Fourth Edition, April 2000; reaffirmed March 
2006; incorporated by reference at Sec.  250.1203;
    (41) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas 
Applications; Third Edition, August 1992; Errata March 1994, reaffirmed, 
February 2009; incorporated by reference at Sec.  250.1203;
    (42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of 
Gross Heating Value, Relative Density, Compressibility and Theoretical 
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 
Transfer; Third Edition, January 2009; incorporated by reference at 
Sec.  250.1203;
    (43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006; incorporated by reference at Sec.  250.1203;
    (44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006; incorporated by reference at Sec.  250.1203;
    (45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006; incorporated by 
reference at Sec.  250.1202;
    (46) API MPMS, Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 1--Electronic Gas Measurement, First Edition, 
August 1993; reaffirmed, July 2005; incorporated by reference at Sec.  
250.1203;
    (47) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms--Working Stress Design, Twenty-
first Edition, December 2000; Errata and Supplement 1, December 2002; 
Errata and Supplement 2, September 2005; Errata and Supplement 3, 
October 2007; incorporated by reference at Sec. Sec.  250.901, 250.908, 
250.919, and 250.920;
    (48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007; incorporated by reference at Sec.  250.108;
    (49) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001; incorporated by 
reference at Sec.  250.901;
    (50) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008;

[[Page 83]]

incorporated by reference at Sec.  250.901(a) and (d);
    (51) API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; 
incorporated by reference at Sec. Sec.  250.292, 250.733, 250.800(c), 
250.901(a), (d), and 250.1002(b);
    (52) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008, 
Reaffirmed June 2015; incorporated by reference at Sec. Sec.  250.800(c) 
and 250.901(a) and (d);
    (53) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by 
reference at Sec. Sec.  250.800(c) and 250.901;
    (54) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997; 
incorporated by reference at Sec.  250.901;
    (55) ANSI/API RP 14B, Design, Installation, Operation, Test, and 
Redress of Subsurface Safety Valve Systems, Sixth Edition, September 
2015; incorporated by reference at Sec. Sec.  250.802(b), 250.803(a), 
250.814(d), 250.828(c), and 250.880(c);
    (56) API RP 14C, Recommended Practice for Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms, Seventh Edition, March 2001, Reaffirmed: March 
2007; incorporated by reference at Sec. Sec.  250.125(a), 250.292(j), 
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a), 
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c), 
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d), 
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
    (57) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; Reaffirmed, January 2013; incorporated by reference at Sec. Sec.  
250.841(b), 250.842(a), and 250.1628(b) and (d);
    (58) API RP 14F, Recommended Practice for Design, Installation, and 
Maintenance of Electrical Systems for Fixed and Floating Offshore 
Petroleum Facilities for Unclassified and Class 1, Division 1 and 
Division 2 Locations, Upstream Segment, Fifth Edition, July 2008, 
Reaffirmed: April 2013; incorporated by reference at Sec. Sec.  
250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (59) API RP 14FZ, Recommended Practice for Design, Installation, and 
Maintenance of Electrical Systems for Fixed and Floating Offshore 
Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and 
Zone 2 Locations, Second Edition, May 2013; incorporated by reference at 
Sec. Sec.  250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007: Reaffirmed, January 2013; incorporated by reference 
at Sec. Sec.  250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
    (61) API STD 6AV2, Installation, Maintenance, and Repair of Surface 
Safety Valves and Underwater Safety Valves Offshore; First Edition, 
March 2014; Errata 1, August 2014; incorporated by reference at 
Sec. Sec.  250.820, 250.834, 250.836, and 250.880(c);
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
Reaffirmed: January 2013; incorporated by reference at Sec. Sec.  
250.800(b) and (c), 250.842(c), and 250.901(a);
    (63) API Standard 53, Blowout Prevention Equipment Systems for 
Drilling Wells, Fourth Edition, November 2012, incorporated by reference 
at Sec. Sec.  250.730, 250.735, 250.737, and 250.739;
    (64) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002; 
incorporated by reference at Sec.  250.415;
    (65) API RP 500, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Division 1 and Division 2, Third Edition, 
December 2012; Errata January 2014; incorporated by reference at 
Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 
250.872(a), 250.1628(b) and (d), and 250.1629(b);
    (66) API RP 505, Recommended Practice for Classification of 
Locations for

[[Page 84]]

Electrical Installations at Petroleum Facilities Classified as Class I, 
Zone 0, Zone 1, and Zone 2, First Edition, November 1997; Reaffirmed, 
August 2013; incorporated by reference at Sec. Sec.  250.114(a), 
250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 250.1628(b) and 
(d), and 250.1629(b);
    (67) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 2003; 
incorporated by reference at Sec.  250.1202;
    (68) ANSI/API Spec. Q1, Specification for Quality Management System 
Requirements for Manufacturing Organizations for the Petroleum and 
Natural Gas Industry, Ninth Edition, June 2013; Errata, February 2014; 
Errata 2, March 2014; Addendum 1, June 2016; incorporated by reference 
at Sec. Sec.  250.730 and 250.801(b) and (c);
    (69) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004; 
incorporated by reference at Sec.  250.108;
    (70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas 
Tree Equipment, Twentieth Edition, October 2010; Addendum 1, November 
2011; Errata 2, November 2011; Addendum 2, November 2012; Addendum 3, 
March 2013; Errata 3, June 2013; Errata 4, August 2013; Errata 5, 
November 2013; Errata 6, March 2014; Errata 7, December 2014; Errata 8, 
February 2016; Addendum 4, June 2016; Errata 9, June 2016; Errata 10, 
August 2016; incorporated by reference at Sec. Sec.  250.730, 
250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and 
250.1002(b);
    (71) API Spec. 6AV1, Specification for Verification Test of Wellhead 
Surface Safety Valves and Underwater Safety Valves for Offshore Service, 
Second Edition, February 2013; incorporated by reference at Sec. Sec.  
250.802(a), 250.833, 250.873(b), and 250.874(g);
    (72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, 
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1, 
October 2009; Contains API Monogram Annex as Part of U.S. National 
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas 
industries--Pipeline transportation systems--Pipeline valves; 
incorporated by reference at Sec.  250.1002;
    (73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October 2005, Reaffirmed, June 2012; 
incorporated by reference at Sec. Sec.  250.802(c) and 250.803(a);
    (74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008, incorporated by reference at Sec. Sec.  
250.852(e), 250.1002(b), and 250.1007(a).
    (75) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007; incorporated by reference at Sec.  250.1202;
    (76) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; incorporated by 
reference at Sec.  250.1202;
    (77) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006, incorporated by reference at Sec.  
250.518;
    (78) API Standard 65--Part 2, Isolating Potential Flow Zones During 
Well Construction; Second Edition, December 2010; incorporated by 
reference at Sec.  250.415(f);
    (79) API RP 75, Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and Facilities, 
Third Edition, May 2004, Reaffirmed May 2008; incorporated by reference 
at Sec. Sec.  250.1900, 250.1902, 250.1903, 250.1909, 250.1920;
    (80) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
4--Proving Systems, Section 8--Operation of Proving Systems; First 
Edition, reaffirmed March 2007; incorporated by reference at Sec.  
250.1202(a)(2), (a)(3), (f)(1), and (g);
    (81) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
5--Metering, Section 6--Measurement of Liquid Hydrocarbons by Coriolis 
Meters; First Edition, reaffirmed March 2008; incorporated by reference 
at Sec.  250.1202(a)(2) and (3);
    (82) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
5--Metering, Section 8--Measurement of Liquid Hydrocarbons by Ultrasonic

[[Page 85]]

Flow Meters Using Transit Time Technology; First Edition, February 2005; 
incorporated by reference at Sec.  250.1202(a)(2) and (3);
    (83) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
11--Physical Properties Data, Section 1--Temperature and Pressure Volume 
Correction Factors for Generalized Crude Oils, Refined Products, and 
Lubricating Oils; May 2004, (incorporating Addendum 1, September 2007); 
incorporated by reference at Sec.  250.1202(a)(2), (a)(3), (g), and 
(l)(4);
    (84) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
12--Calculation of Petroleum Quantities, Section 2--Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, Part 3--Proving Reports; First Edition, reaffirmed 
2009; incorporated by reference at Sec.  250.1202(a)(2), (a)(3), and 
(g);
    (85) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
12--Calculation of Petroleum Quantities, Section 2--Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, Part 4--Calculation of Base Prover Volumes by the 
Waterdraw Method, First Edition, reaffirmed 2009; incorporated by 
reference at Sec.  250.1202(a)(2), (a)(3), (f)(1), and (g);
    (86) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
21--Flow Measurement Using Electronic Metering Systems, Section 2--
Electronic Liquid Volume Measurement Using Positive Displacement and 
Turbine Meters; First Edition, June 1998; incorporated by reference at 
Sec.  250.1202(a)(2);
    (87) API Manual of Petroleum Measurement Standards Chapter 21--Flow 
Measurement Using Electronic Metering Systems, Addendum to Section 2--
Flow Measurement Using Electronic Metering Systems, Inferred Mass; First 
Edition, reaffirmed February 2006; incorporated by reference at Sec.  
250.1202(a)(2);
    (88) API RP 86, API Recommended Practice for Measurement of 
Multiphase Flow; First Edition, September 2005; incorporated by 
reference at Sec.  250.1202(a)(2), (a)(3), and Sec.  250.1203(b)(2);
    (89) ANSI/API Specification 11D1, Packers and Bridge Plugs, Second 
Edition, July 2009, incorporated by reference at Sec. Sec.  250.518, 
250.619, and 250.1703;
    (90) ANSI/API Specification 16A, Specification for Drill-through 
Equipment, Third Edition, June 2004, Reaffirmed August 2010, 
incorporated by reference at Sec.  250.730;
    (91) ANSI/API Specification 16C, Specification for Choke and Kill 
Systems, First Edition, January 1993, Reaffirmed July 2010; incorporated 
by reference at Sec.  250.730;
    (92) API Specification 16D, Specification for Control Systems for 
Drilling Well Control Equipment and Control Systems for Diverter 
Equipment, Second Edition, July 2004, Reaffirmed August 2013, 
incorporated by reference at Sec.  250.730;
    (93) ANSI/API Specification 17D, Design and Operation of Subsea 
Production Systems--Subsea Wellhead and Tree Equipment, Second Edition, 
May 2011, incorporated by reference at Sec.  250.730;
    (94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle 
Interfaces on Subsea Production Systems, First Edition, July 2004, 
Reaffirmed January 2009, incorporated by reference at Sec.  250.734;
    (95) ANSI/API RP 2N, Third Edition, ``Recommended Practice for 
Planning, Designing, and Constructing Structures and Pipelines for 
Arctic Conditions'', Third Edition, April 2015; incorporated by 
reference at Sec.  250.470(g); and
    (96) API 570, Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Fourth Edition, February 2016; 
Addendum, May 2017; incorporated by reference at Sec.  250.841(b).
    (i) American Society for Testing and Materials (ASTM), ASTM 
Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA 
19428-2959; http://www.astm.org; phone: 1-877-909-2786:
    (1) ASTM Standard C 33-07, approved December 15, 2007, Standard 
Specification for Concrete Aggregates; incorporated by reference at 
Sec.  250.901;
    (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete; incorporated by reference at 
Sec.  250.901;

[[Page 86]]

    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at Sec.  
250.901;
    (4) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete; 
incorporated by reference at Sec.  250.901;
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec.  250.901;
    (j) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street, 
130, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition, 
October 18, 1999; incorporated by reference at Sec.  250.901;
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998 
Edition; incorporated by reference at Sec.  250.901;
    (3) AWS D3.6M:1999, Specification for Underwater Welding (1999); 
incorporated by reference at Sec.  250.901.
    (k) National Association of Corrosion Engineers (NACE) 
International, NACE Standards, Park Ten Place, Houston, TX 77084; http:/
/www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Standard Material Requirements, 
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking 
Resistance in Sour Oilfield Environments, Revised January 17, 2003; 
incorporated by reference at Sec. Sec.  250.901 and 250.490;
    (2) NACE Standard RP0176-2003, Standard Recommended Practice, 
Corrosion Control of Steel Fixed Offshore Structures Associated with 
Petroleum Production; incorporated by reference at Sec.  250.901.
    (l) American Gas Association (AGA Reports), 400 North Capitol 
Street, NW., Suite 450, Washington, DC 20001, http://www.aga.org; phone: 
202-824-7000;
    (1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters; 
Revised February 2006; incorporated by reference at Sec.  
250.1203(b)(2);
    (2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic 
Meters; Second Edition, April 2007; incorporated by reference at Sec.  
250.1203(b)(2);
    (3) AGA Report No. 10--Speed of Sound in Natural Gas and Other 
Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at 
Sec.  250.1203(b)(2).
    (m) International Organization for Standardization (ISO), 1, ch. de 
la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org; 
phone: 41-22-749-01-11:
    (1) ISO/IEC (International Electrotechnical Commission) 17011, 
Conformity assessment--General requirements for accreditation bodies 
accrediting conformity assessment bodies, First edition 2004-09-01; 
Corrected version 2005-02-15; incorporated by reference at Sec. Sec.  
250.1900, 250.1903, 250.1904, and 250.1922.
    (2) [Reserved]
    (n) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite 
1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
495-4925.
    (1) COS Safety Publication COS-2-01, Qualification and Competence 
Requirements for Audit Teams and Auditors Performing Third-party SEMS 
Audits of Deepwater Operations, First Edition, Effective Date October 
2012; incorporated by reference at Sec. Sec.  250.1900, 250.1903, 
250.1904, and 250.1921.
    (2) COS Safety Publication COS-2-03, Requirements for Third-party 
SEMS Auditing and Certification of Deepwater Operations, First Edition, 
Effective Date October 2012; incorporated by reference at Sec. Sec.  
250.1900, 250.1903, 250.1904, and 250.1920.
    (3) COS Safety Publication COS-2-04, Requirements for Accreditation 
of Audit Service Providers Performing SEMS Audits and Certification of 
Deepwater Operations, First Edition, Effective Date October 2012; 
incorporated by reference at Sec. Sec.  250.1900, 250.1903, 250.1904, 
and 250.1922.
    (o) American National Standards Institute (ANSI), http://
www.webstore.ansi.org; phone: 212-642-4900.
    (1) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at Sec.  250.490.

[[Page 87]]

    (2) [Reserved]

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012; 
77 FR 50891, Aug. 22, 2012; 78 FR 20440, Apr. 5, 2013; 81 FR 26015, Apr. 
29, 2016; 81 FR 36149, June 6, 2016; 81 FR 46560, July 15, 2016; 81 FR 
61917, Sept. 7, 2016; 83 FR 49255, Sept. 28, 2018]

    Effective Date Note: At 84 FR 21969, May 15, 2019, Sec.  250.198 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.198  Documents incorporated by reference.

    Certain material is incorporated by reference into this part with 
the approval of the Director of the Federal Register under 5 U.S.C. 
552(a) and 1 CFR part 51. All incorporated material is available for 
inspection at the Houston BSEE office at 1919 Smith Street Suite 14042, 
Houston, Texas 77002 and is available from the sources indicated in this 
section. It is also available for inspection at the National Archives 
and Records Administration (NARA). To make an appointment to inspect 
incorporated material at the Houston BSEE office, call 1-844-259-4779. 
For information on the availability of this material at NARA, call 202-
741-6030 or go to http://www.archives.gov/federal-register/cfr/ibr-
locations.html.
    (a) American Concrete Institute (ACI), ACI Standards, 38800 Country 
Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org; 
phone: 248-848-3700:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete, 1995; incorporated by reference at Sec.  250.901.
    (2) ACI 318R-95, Commentary on Building Code Requirements for 
Reinforced Concrete, 1995; incorporated by reference at Sec.  250.901.
    (3) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec.  250.901.
    (b) American Gas Association (AGA Reports), 400 North Capitol Street 
NW, Suite 450, Washington, DC 20001, http://www.aga.org; phone: 202-824-
7000;
    (1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters; 
Revised February 2006; incorporated by reference at Sec.  250.1203(b);
    (2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic 
Meters; Second Edition, April 2007; incorporated by reference at Sec.  
250.1203(b);
    (3) AGA Report No. 10--Speed of Sound in Natural Gas and Other 
Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at 
Sec.  250.1203(b).
    (c) American Institute of Steel Construction, Inc. (AISC), AISC 
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; 
http://www.aisc.org; phone: 312-670-2400:
    (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings, 
incorporated by reference at Sec.  250.901.
    (2) [Reserved]
    (d) American National Standards Institute (ANSI), http.www./
webstore.ansi.org/; phone: 212-642-4900:
    (1) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings, 
incorporated by reference at Sec.  250.1002;
    (2) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems, incorporated by reference at Sec.  250.1002;
    (3) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at Sec.  250.490.
    (e) American Petroleum Institute (API), API Recommended Practices 
(RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) 
chapters, 1220 L Street, NW, Washington, DC 20005-4070; http://
www.api.org; phone: 202-682-8000:
    (1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, 
Rating, Repair, and Alteration, Tenth Edition, May 2014; Addendum 1, May 
2017; incorporated by reference at Sec. Sec.  250.851(a) and 
250.1629(b);
    (2) API 570, Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Fourth Edition, February 2016; 
Addendum 1, May 2017; incorporated by reference at Sec.  250.841(b).
    (3) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007; incorporated by reference 
at Sec.  250.901;
    (4) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007; 
incorporated by reference at Sec.  250.901;
    (5) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007; incorporated by reference at Sec.  
250.901;
    (6) API Bulletin 92L, Drilling Ahead Safely with Lost Circulation in 
the Gulf of Mexico, First Edition, August 2015; incorporated by 
reference at Sec.  250.427(b);
    (7) API MPMS Chapter 1--Vocabulary, Second Edition, July 1994; 
incorporated by reference at Sec.  250.1201;
    (8) API MPMS Chapter 2--Tank Calibration, Section 2A--Measurement 
and Calibration of Upright Cylindrical Tanks by the Manual Tank 
Strapping Method, First Edition, February 1995; reaffirmed February 
2007; incorporated by reference at Sec.  250.1202;
    (9) API MPMS Chapter 2--Tank Calibration, Section 2B--Calibration of 
Upright Cylindrical Tanks Using the Optical Reference Line Method, First 
Edition, March 1989; reaffirmed, December 2007; incorporated by 
reference at Sec.  250.1202;
    (10) API MPMS Chapter 3--Tank Gauging, Section 1A--Standard Practice 
for the Manual Gauging of Petroleum and Petroleum

[[Page 88]]

Products, Second Edition, August 2005; incorporated by reference at 
Sec.  250.1202;
    (11) API MPMS Chapter 3--Tank Gauging, Section 1B--Standard Practice 
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging, Second Edition, June 2001; reaffirmed, October 
2006; incorporated by reference at Sec.  250.1202;
    (12) API MPMS Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005; incorporated by reference at Sec.  
250.1202;
    (13) API MPMS Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003; incorporated by reference at 
Sec.  250.1202;
    (14) API MPMS Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005; incorporated by 
reference at Sec.  250.1202;
    (15) API MPMS Chapter 4--Proving Systems, Section 5--Master-Meter 
Provers, Second Edition, May 2000, reaffirmed, August 2005; incorporated 
by reference at Sec.  250.1202;
    (16) API MPMS Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated 
by reference at Sec.  250.1202;
    (17) API MPMS Chapter 4--Proving Systems, Section 7--Field Standard 
Test Measures, Second Edition, December 1998; reaffirmed 2003; 
incorporated by reference at Sec.  250.1202;
    (18) API MPMS Chapter 4--Proving Systems, Section 8--Operation of 
Proving Systems; First Edition, reaffirmed March 2007; incorporated by 
reference at Sec.  250.1202(a), (f), and (g);
    (19) API MPMS Chapter 5--Metering, Section 1--General Considerations 
for Measurement by Meters, Fourth Edition, September 2005; incorporated 
by reference at Sec.  250.1202;
    (20) API MPMS Chapter 5--Metering, Section 2--Measurement of Liquid 
Hydrocarbons by Displacement Meters, Third Edition, September 2005; 
incorporated by reference at Sec.  250.1202;
    (21) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005; 
incorporated by reference at Sec.  250.1202;
    (22) API MPMS Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005; incorporated by 
reference at Sec.  250.1202;
    (23) API MPMS Chapter 5--Metering, Section 5--Fidelity and Security 
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, 
August 2005; incorporated by reference at Sec.  250.1202;
    (24) API MPMS Chapter 5--Metering, Section 6--Measurement of Liquid 
Hydrocarbons by Coriolis Meters; First Edition, reaffirmed, March 2008; 
incorporated by reference at Sec.  250.1202(a);
    (25) API MPMS Chapter 5--Metering, Section 8--Measurement of Liquid 
Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology; 
First Edition, February 2005; incorporated by reference at Sec.  
250.1202(a);
    (26) API MPMS Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007; incorporated by reference at Sec.  250.1202;
    (27) API MPMS Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007; 
incorporated by reference at Sec.  250.1202;
    (28) API MPMS Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007; 
incorporated by reference at Sec.  250.1202;
    (29) API MPMS Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.  
250.1202;
    (30) API MPMS Chapter 8--Sampling, Section 1--Standard Practice for 
Manual Sampling of Petroleum and Petroleum Products, Third Edition, 
October 1995; reaffirmed, March 2006; incorporated by reference at Sec.  
250.1202;
    (31) API MPMS Chapter 8--Sampling, Section 2--Standard Practice for 
Automatic Sampling of Liquid Petroleum and Petroleum Products, Second 
Edition, October 1995; reaffirmed, June 2005; incorporated by reference 
at Sec.  250.1202;
    (32) API MPMS Chapter 9--Density Determination, Section 1--Standard 
Test Method for Density, Relative Density (Specific Gravity), or API 
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer 
Method, Second Edition, December 2002; reaffirmed October 2005; 
incorporated by reference at Sec.  250.1202(a) and (l);
    (33) API MPMS Chapter 9--Density Determination, Section 2--Standard 
Test Method for Density or Relative Density of Light Hydrocarbons by 
Pressure Hydrometer, Second Edition, March 2003; incorporated by 
reference at Sec.  250.1202;
    (34) API MPMS Chapter 10--Sediment and Water, Section 1--Standard 
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction 
Method, Third Edition, November 2007; incorporated by reference at Sec.  
250.1202;
    (35) API MPMS Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007; incorporated by reference at Sec.  250.1202;
    (36) API MPMS Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in Crude Oil by the Centrifuge Method 
(Laboratory Procedure), Third Edition, May 2008; incorporated by 
reference at Sec.  250.1202;

[[Page 89]]

    (37) API MPMS Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge 
Method (Field Procedure), Third Edition, December 1999; incorporated by 
reference at Sec.  250.1202;
    (38) API MPMS Chapter 10--Sediment and Water, Section 9--Standard 
Test Method for Water in Crude Oils by Coulometric Karl Fischer 
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated 
by reference at Sec.  250.1202;
    (39) API MPMS Chapter 11.1--Volume Correction Factors, Volume 1, 
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API 
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude 
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at 
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed 
March 1997; incorporated by reference at Sec.  250.1202;
    (40) API MPMS Chapter 11.2.2--Compressibility Factors for 
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -50 
[deg]F to 140 [deg]F Metering Temperature, Second Edition, October 1986; 
reaffirmed: December 2007; incorporated by reference at Sec.  250.1202;
    (41) API MPMS Chapter 11--Physical Properties Data, Section 1--
Temperature and Pressure Volume Correction Factors for Generalized Crude 
Oils, Refined Products, and Lubricating Oils; May 2004 (incorporating 
Addendum 1, September 2007); incorporated by reference at Sec.  
250.1202(a), (g), and (l);
    (42) API MPMS Chapter 11--Physical Properties Data, Addendum to 
Section 2, Part 2--Compressibility Factors for Hydrocarbons, Correlation 
of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, 
December 1994; reaffirmed, December 2002; incorporated by reference at 
Sec.  250.1202;
    (43) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 1--Introduction, Second 
Edition, May 1995; reaffirmed March 2002; incorporated by reference at 
Sec.  250.1202;
    (44) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 2--Measurement Tickets, 
Third Edition, June 2003; incorporated by reference at Sec.  250.1202;
    (45) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 3--Proving Reports; 
First Edition, reaffirmed 2009; incorporated by reference at Sec.  
250.1202(a) and (g);
    (46) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 4--Calculation of Base 
Prover Volumes by the Waterdraw Method, First Edition, December 1997; 
reaffirmed, 2009; incorporated by reference at Sec.  250.1202(a), (f), 
and (g);
    (47) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations 
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed, 
January 2003; incorporated by reference at Sec.  250.1203;
    (48) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and 
Installation Requirements, Fourth Edition, April 2000; reaffirmed March 
2006; incorporated by reference at Sec.  250.1203;
    (49) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas 
Applications; Third Edition, August 1992; Errata March 1994, reaffirmed, 
February 2009; incorporated by reference at Sec.  250.1203;
    (50) API MPMS Chapter 14.5/GPA Standard 2172-09; Calculation of 
Gross Heating Value, Relative Density, Compressibility and Theoretical 
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 
Transfer; Third Edition, January 2009; incorporated by reference at 
Sec.  250.1203;
    (51) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006; incorporated by reference at Sec.  250.1203;
    (52) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006; incorporated by reference at Sec.  250.1203;
    (53) API MPMS Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006; incorporated by 
reference at Sec.  250.1202;
    (54) API MPMS Chapter 21--Flow Measurement Using Electronic Metering 
Systems, Section 1--Electronic Gas Measurement, First Edition, August 
1993; reaffirmed, July 2005; incorporated by reference at Sec.  
250.1203;
    (55) API MPMS Chapter 21--Flow Measurement Using Electronic Metering 
Systems, Section 2--Electronic Liquid Volume Measurement Using Positive 
Displacement and Turbine Meters; First Edition, June 1998; incorporated 
by reference at Sec.  250.1202(a);
    (56) API MPMS Chapter 21--Flow Measurement Using Electronic Metering 
Systems, Addendum to Section 2--Flow Measurement Using Electronic 
Metering Systems, Inferred Mass; First Edition, reaffirmed February 
2006; incorporated by reference at Sec.  250.1202(a);

[[Page 90]]

    (57) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms--Working Stress Design, Twenty-
first Edition, December 2000; Errata and Supplement 1, December 2002; 
Errata and Supplement 2, September 2005; Errata and Supplement 3, 
October 2007; incorporated by reference at Sec. Sec.  250.901, 250.908, 
250.919, and 250.920;
    (58) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007; incorporated by reference at Sec.  250.108;
    (59) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001; incorporated by 
reference at Sec.  250.901;
    (60) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008; incorporated by 
reference at Sec.  250.901(a) and (d);
    (61) ANSI/API RP 2N, Third Edition, ``Recommended Practice for 
Planning, Designing, and Constructing Structures and Pipelines for 
Arctic Conditions'', Third Edition, April 2015; incorporated by 
reference at Sec.  250.470(g);
    (62) API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; 
incorporated by reference at Sec. Sec.  250.733, 250.800(c), 250.901(a), 
(d), and 250.1002(b);
    (63) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008, 
reaffirmed June 2015; incorporated by reference at Sec. Sec.  250.800(c) 
and 250.901(a) and (d);
    (64) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by 
reference at Sec. Sec.  250.800(c) and 250.901(a) and (d);
    (65) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997; 
incorporated by reference at Sec.  250.901(a) and (d);
    (66) ANSI/API RP 14B, Design, Installation, Operation, Test, and 
Redress of Subsurface Safety Valve Systems, Sixth Edition, September 
2015; incorporated by reference at Sec. Sec.  250.802(b), 250.803(a), 
250.814(d), 250.828(c), and 250.880(c);
    (67) API RP 14C, Recommended Practice for Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms, Seventh Edition, March 2001, reaffirmed: March 
2007; incorporated by reference at Sec. Sec.  250.125(a), 250.292(j), 
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a), 
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c), 
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d), 
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
    (68) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; reaffirmed, January 2013; incorporated by reference at Sec. Sec.  
250.841(b), 250.842(a), and 250.1628(b) and (d);
    (69) API RP 14F, Recommended Practice for Design, Installation, and 
Maintenance of Electrical Systems for Fixed and Floating Offshore 
Petroleum Facilities for Unclassified and Class 1, Division 1 and 
Division 2 Locations, Upstream Segment, Fifth Edition, July 2008, 
reaffirmed: April 2013; incorporated by reference at Sec. Sec.  
250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (70) API RP 14FZ, Recommended Practice for Design, Installation, and 
Maintenance of Electrical Systems for Fixed and Floating Offshore 
Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and 
Zone 2 Locations, Second Edition, May 2013; incorporated by reference at 
Sec. Sec.  250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (71) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; Reaffirmed, January 2013; incorporated by reference 
at Sec. Sec.  250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
    (72) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
reaffirmed: January 2013; incorporated by reference at Sec. Sec.  
250.800(b) and (c), 250.842(c), and 250.901(a) and (d);
    (73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea 
Production Systems, Second Edition, June 2013; Errata, January 2014; 
incorporated by reference at Sec.  250.734(a);
    (74) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002; 
incorporated by reference at Sec.  250.415;
    (75) API RP 75, Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and Facilities, 
Third Edition, May 2004, reaffirmed May 2008; incorporated by reference 
at Sec. Sec.  250.1900, 250.1902, 250.1903, 250.1909, 250.1920;
    (76) API RP 86, API Recommended Practice for Measurement of 
Multiphase Flow; First Edition, September 2005; incorporated by 
reference at Sec. Sec.  250.1202(a) and 250.1203(b);
    (77) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006; incorporated by reference at Sec.  
250.519;
    (78) API RP 500, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Division 1 and Division 2, Third Edition, 
December 2012; Errata January 2014, incorporated by reference at 
Sec. Sec.  250.114(a),

[[Page 91]]

250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 250.1628(b) and 
(d), and 250.1629(b);
    (79) API RP 505, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, 
November 1997; reaffirmed, August 2013; incorporated by reference at 
Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 
250.872(a), 250.1628(b) and (d), and 250.1629(b);
    (80) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 2003; 
incorporated by reference at Sec.  250.1202;
    (81) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004; 
incorporated by reference at Sec.  250.108;
    (82) ANSI/API Spec. 6A, Specification for Wellhead and Christmas 
Tree Equipment, Twentieth Edition, October 2010; Addendum 1, November 
2011; Errata 2, November 2011; Addendum 2, November 2012; Addendum 3, 
March 2013; Errata 3, June 2013; Errata 4, August 2013; Errata 5, 
November 2013; Errata 6, March 2014; Errata 7, December 2014; Errata 8, 
February 2016; Addendum 4, June 2016; Errata 9, June 2016; Errata 10, 
August 2016; incorporated by reference at Sec. Sec.  250.730, 
250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and 
250.1002(b);
    (83) API Spec. 6AV1, Specification for Verification Test of Wellhead 
Surface Safety Valves and Underwater Safety Valves for Offshore Service, 
Second Edition, February 2013; incorporated by reference at Sec. Sec.  
250.802(a), 250.833, 250.873(b), and 250.874(g);
    (84) API STD 6AV2, Installation, Maintenance, and Repair of Surface 
Safety Valves and Underwater Safety Valves Offshore; First Edition, 
March 2014; Errata 1, August 2014; incorporated by reference at 
Sec. Sec.  250.820, 250.834, 250.836, and 250.880(c)
    (85) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, 
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1, 
October 2009; Contains API Monogram Annex as Part of U.S. National 
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas 
industries--Pipeline transportation systems--Pipeline valves; 
incorporated by reference at Sec.  250.1002(b);
    (86) ANSI/API Spec. 11D1, Packers and Bridge Plugs, Second Edition, 
July 2009; incorporated by reference at Sec. Sec.  250.518, 250.619, and 
250.1703;
    (87) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October 2005, reaffirmed, June 2012; 
incorporated by reference at Sec. Sec.  250.802 and 250.803(a);
    (88) ANSI/API Spec. 16A, Specification for Drill-through Equipment, 
Third Edition, June 2004, reaffirmed August 2010; incorporated by 
reference at Sec.  250.730;
    (89) ANSI/API Spec. 16C, Specification for Choke and Kill Systems, 
First Edition, January 1993, reaffirmed July 2010; incorporated by 
reference at Sec.  250.730;
    (90) API Spec. 16D, Specification for Control Systems for Drilling 
Well Control Equipment and Control Systems for Diverter Equipment, 
Second Edition, July 2004, reaffirmed August 2013; incorporated by 
reference at Sec.  250.730;
    (91) ANSI/API Spec. 17D, Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment, Second Edition, May 2011; 
incorporated by reference at Sec.  250.730;
    (92) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008, incorporated by reference at Sec. Sec.  
250.852(e), 250.1002(b), and 250.1007(a).
    (93) ANSI/API Spec. Q1, Specification for Quality Management System 
Requirements for Manufacturing Organizations for the Petroleum and 
Natural Gas Industry, Ninth Edition, June 2013; Errata, February 2014; 
Errata 2, March 2014; Addendum 1, June 2016; incorporated by reference 
at Sec. Sec.  250.730 and 250.801(b) and (c);
    (94) API Standard 53, Blowout Prevention Equipment Systems for 
Drilling Wells, Fourth Edition, November 2012, Addendum 1, July 2016, 
incorporated by reference at Sec. Sec.  250.730, 250.734, 250.735, 
250.736, 250.737, and 250.739;
    (95) API Standard 65--Part 2, Isolating Potential Flow Zones During 
Well Construction; Second Edition, December 2010; incorporated by 
reference at Sec. Sec.  250.415(f) and 250.420(a);
    (96) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007; incorporated by reference at Sec.  250.1202;
    (97) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; incorporated by 
reference at Sec.  250.1202;
    (f) American Society of Mechanical Engineers (ASME), 22 Law Drive, 
P.O. Box 2900, Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-
800-843-2763.
    (1) 2017 ASME Boiler and Pressure Vessel Code (BPVC), Section I, 
Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017, 
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules for 
Construction of Heating Boilers, 2017 Edition, July 1, 2017, 
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (3) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Division 1, 2017 Edition;

[[Page 92]]

July 1, 2017, incorporated by reference at Sec. Sec.  250.851(a) and 
250.1629(b).
    (4) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Division 2: Alternative Rules, 
2017 Edition, July 1, 2017, incorporated by reference at Sec. Sec.  
250.851(a) and 250.1629(b).
    (5) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Division 3: Alternative Rules for 
Construction of High Pressure Vessels, 2017 Edition, July 1, 2017, 
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (g) American Society for Testing and Materials (ASTM), ASTM 
Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA 
19428-2959; http://www.astm.org; phone: 1-877-909-2786:
    (1) ASTM Standard C 33-07, approved December 15, 2007, Standard 
Specification for Concrete Aggregates; incorporated by reference at 
Sec.  250.901;
    (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete; incorporated by reference at 
Sec.  250.901;
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at Sec.  
250.901;
    (4) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete; 
incorporated by reference at Sec.  250.901;
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec.  250.901;
    (h) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street, 
130, Miami, FL 33126; http://www.aws.org;phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition, 
October 18, 1999; incorporated by reference at Sec.  250.901;
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998 
Edition; incorporated by reference at Sec.  250.901;
    (3) AWS D3.6M:1999, Specification for Underwater Welding (1999); 
incorporated by reference at Sec.  250.901.
    (i) National Association of Corrosion Engineers (NACE) 
International, NACE Standards, Park Ten Place, Houston, TX 77084; http:/
/www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Standard Material Requirements, 
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking 
Resistance in Sour Oilfield Environments, Revised January 17, 2003; 
incorporated by reference at Sec. Sec.  250.490 and 250.901;
    (2) NACE Standard RP0176-2003, Standard Recommended Practice, 
Corrosion Control of Steel Fixed Offshore Structures Associated with 
Petroleum Production; incorporated by reference at Sec.  250.901.
    (j) International Organization for Standardization (ISO), 1, ch. de 
la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org; 
phone: 41-22-749-01-11:
    (1) ISO/IEC (International Electrotechnical Commission) 17011, 
Conformity assessment--General requirements for accreditation bodies 
accrediting conformity assessment bodies, First edition 2004-09-01; 
Corrected version 2005-02-15; incorporated by reference at Sec. Sec.  
250.1900, 250.1903, 250.1904, and 250.1922.
    (2) ISO/IEC 17021-1, Conformity assessment--Requirements for bodies 
providing audit and certification of management systems--Part 1: 
Requirements, First Edition, June 2015, incorporated by reference at 
Sec.  250.730(d).
    (3) [Reserved]
    (k) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite 
1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
495-4925.
    (1) COS Safety Publication COS-2-01, Qualification and Competence 
Requirements for Audit Teams and Auditors Performing Third-party SEMS 
Audits of Deepwater Operations, First Edition, Effective Date October 
2012; incorporated by reference at Sec. Sec.  250.1900, 250.1903, 
250.1904, and 250.1921.
    (2) COS Safety Publication COS-2-03, Requirements for Third-party 
SEMS Auditing and Certification of Deepwater Operations, First Edition, 
Effective Date October 2012; incorporated by reference at Sec. Sec.  
250.1900, 250.1903, 250.1904, and 250.1920.
    (3) COS Safety Publication COS-2-04, Requirements for Accreditation 
of Audit Service Providers Performing SEMS Audits and Certification of 
Deepwater Operations, First Edition, Effective Date October 2012; 
incorporated by reference at Sec. Sec.  250.1900, 250.1903, 250.1904, 
and 250.1922.



Sec.  250.199  Paperwork Reduction Act statements--information collection.

    (a) OMB has approved the information collection requirements in part 
250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this 
section lists the subpart in the rule requiring the information and its 
title, provides the OMB control number, and summarizes the reasons for 
collecting the information and how BSEE uses the information. The 
associated BSEE forms required by this part are listed at the end of 
this table with the relevant information.
    (b) Respondents are OCS oil, gas, and sulphur lessees and operators. 
The requirement to respond to the information collections in this part 
is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's 
Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses

[[Page 93]]

are also required to obtain or retain a benefit or may be voluntary. 
Proprietary information will be protected under Sec.  250.197, Data and 
information to be made available to the public or for limited 
inspection; parts 30 CFR Parts 251, 252; and the Freedom of Information 
Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.
    (e) BSEE is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR Subpart, title and/or BSEE Form   BSEE collects this information
            (OMB Control No.)                     and uses it to:
------------------------------------------------------------------------
(1) Subpart A, General (1014-0022),       (i) Determine that activities
 including Forms BSEE-0011, iSEE; BSEE-    on the OCS comply with
 0132, Evacuation Statistics; BSEE-0143,   statutory and regulatory
 Facility/Equipment Damage Report; BSEE-   requirements; are safe and
 1832, Notification of Incidents of        protect the environment; and
 Noncompliance.                            result in diligent
                                           development and production on
                                           OCS leases.
                                          (ii) Support the unproved and
                                           proved reserve estimation,
                                           resource assessment, and fair
                                           market value determinations.
                                          (iii) Assess damage and
                                           project any disruption of oil
                                           and gas production from the
                                           OCS after a major natural
                                           occurrence.
(2) Subpart B, Plans and Information      Evaluate Deepwater Operations
 (1014-0024).                              Plans for compliance with
                                           statutory and regulatory
                                           requirements
(3) Subpart C, Pollution Prevention and   (i) Evaluate measures to
 Control (1014-0023).                      prevent unauthorized
                                           discharge of pollutants into
                                           the offshore waters.
                                          (ii) Ensure action is taken to
                                           control pollution.
(4) Subpart D, Oil and Gas and Drilling   (i) Evaluate the equipment and
 Operations (1014-0018), including Forms   procedures to be used in
 BSEE-0125, End of Operations Report;      drilling operations on the
 BSEE-0133, Well Activity Report; and      OCS.
 BSEE-0133S, Open Hole Data Report.
                                          (ii) Ensure that drilling
                                           operations meet statutory and
                                           regulatory requirements.
(5) Subpart E, Oil and Gas Well-          (i) Evaluate the equipment and
 Completion Operations (1014-0004).        procedures to be used in well-
                                           completion operations on the
                                           OCS.
                                          (ii) Ensure that well-
                                           completion operations meet
                                           statutory and regulatory
                                           requirements.
(6) Subpart F, Oil and Gas Well Workover  (i) Evaluate the equipment and
 Operations (1014-0001).                   procedures to be used during
                                           well-workover operations on
                                           the OCS.
                                          (ii) Ensure that well-workover
                                           operations meet statutory and
                                           regulatory requirements.
(7) Subpart G, Blowout Preventer Systems  (i) Evaluate the equipment and
 (1014-0028), including Form BSEE-0144,    procedures to be used during
 Rig Movement Notification Report.         well drilling, completion,
                                           workover, and abandonment
                                           operations on the OCS.
                                          (ii) Ensure that well
                                           operations meet statutory and
                                           regulatory requirements.
(8) Subpart H, Oil and Gas Production     (i) Evaluate the equipment and
 Safety Systems (1014-0003).               procedures that will be used
                                           during production operations
                                           on the OCS.
                                          (ii) Ensure that production
                                           operations meet statutory and
                                           regulatory requirements.
(9) Subpart I, Platforms and Structures   (i) Evaluate the design,
 (1014-0011).                              fabrication, and installation
                                           of platforms on the OCS.
                                          (ii) Ensure the structural
                                           integrity of platforms
                                           installed on the OCS.
(10) Subpart J, Pipelines and Pipeline    (i) Evaluate the design,
 Rights-of-Way (1014-0016), including      installation, and operation
 Form BSEE-0149, Assignment of Federal     of pipelines on the OCS.
 OCS Pipeline Right-of-Way Grant.
                                          (ii) Ensure that pipeline
                                           operations meet statutory and
                                           regulatory requirements.
(11) Subpart K, Oil and Gas Production    (i) Evaluate production rates
 Rates (1014-0019), including Forms BSEE-  for hydrocarbons produced on
 0126, Well Potential Test Report and      the OCS.
 BSEE-0128, Semiannual Well Test Report.
                                          (ii) Ensure economic
                                           maximization of ultimate
                                           hydrocarbon recovery.

[[Page 94]]

 
(12) Subpart L, Oil and Gas Production    (i) Evaluate the measurement
 Measurement, Surface Commingling, and     of production, commingling of
 Security (1014-0002).                     hydrocarbons, and site
                                           security plans.
                                          (ii) Ensure that produced
                                           hydrocarbons are measured and
                                           commingled to provide for
                                           accurate royalty payments and
                                           security.
(13) Subpart M, Unitization (1014-0015).  (i) Evaluate the unitization
                                           of leases.
                                          (ii) Ensure that unitization
                                           prevents waste, conserves
                                           natural resources, and
                                           protects correlative rights.
(14) Subpart N, Remedies and Penalties..  (The requirements in subpart N
                                           are exempt from the Paperwork
                                           Reduction Act of 1995
                                           according to 5 CFR 1320.4).
(15) Subpart O, Well Control and          (i) Evaluate training program
 Production Safety Training (1014-0008).   curricula for OCS workers,
                                           course schedules, and
                                           attendance.
                                          (ii) Ensure that training
                                           programs are technically
                                           accurate and sufficient to
                                           meet statutory and regulatory
                                           requirements, and that
                                           workers are properly trained.
(16) Subpart P, Sulfur Operations (1014-  (i) Evaluate sulfur
 0006).                                    exploration and development
                                           operations on the OCS.
                                          (ii) Ensure that OCS sulfur
                                           operations meet statutory and
                                           regulatory requirements and
                                           will result in diligent
                                           development and production of
                                           sulfur leases.
(17) Subpart Q, Decommissioning           Ensure that decommissioning
 Activities (1014-0010).                   activities, site clearance,
                                           and platform or pipeline
                                           removal are properly
                                           performed to meet statutory
                                           and regulatory requirements
                                           and do not conflict with
                                           other users of the OCS.
(18) Subpart S, Safety and Environmental  (i) Evaluate operators'
 Management Systems (1014-0017),           policies and procedures to
 including Form BSEE-0131, Performance     assure safety and
 Measures Data.                            environmental protection
                                           while conducting OCS
                                           operations (including those
                                           operations conducted by
                                           contractor and subcontractor
                                           personnel).
                                          (ii) Evaluate Performance
                                           Measures Data relating to
                                           risk and number of accidents,
                                           injuries, and oil spills
                                           during OCS activities.
(19) Application for Permit to Drill      (i) Evaluate and approve the
 (APD, Revised APD), Form BSEE-0123; and   adequacy of the equipment,
 Supplemental APD Information Sheet,       materials, and/or procedures
 Form BSEE-0123S, and all supporting       that the lessee or operator
 documentation (1014-0025).                plans to use during drilling.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.
(20) Application for Permit to Modify     (i) Evaluate and approve the
 (APM), Form BSEE-0124, and supporting     adequacy of the equipment,
 documentation (1014-0026).                materials, and/or procedures
                                           that the lessee or operator
                                           plans to use during drilling
                                           and to evaluate well plan
                                           modifications and changes in
                                           major equipment.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26015, Apr. 29, 2016; 
81 FR 36149, June 6, 2016]



                     Subpart B_Plans and Information

                           General Information



Sec.  250.200  Definitions.

    Acronyms and terms used in this subpart have the following meanings:
    (a) Acronyms used frequently in this subpart are listed 
alphabetically below:
    BOEM means Bureau of Ocean Energy Management of the Department of 
the Interior.
    BSEE means Bureau of Safety and Environmental Enforcement of the 
Department of the Interior.
    CID means Conservation Information Document.
    CZMA means Coastal Zone Management Act.
    DOCD means Development Operations Coordination Document.
    DPP means Development and Production Plan.

[[Page 95]]

    DWOP means Deepwater Operations Plan.
    EIA means Environmental Impact Analysis.
    EP means Exploration Plan.
    NPDES means National Pollutant Discharge Elimination System.
    NTL means Notice to Lessees and Operators.
    OCS means Outer Continental Shelf.
    (b) Terms used in this subpart are listed alphabetically below:
    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before BOEM for a decision (see 30 CFR 550.232(d) and 
550.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see 30 CFR 550.233(b)(2) and 550.270(b)(2)) that is 
pending before BOEM for a decision because the OCS plan is inconsistent 
with applicable requirements.
    New or unusual technology means equipment or procedures that:
    (1) Have not been used previously or extensively in a BSEE OCS 
Region;
    (2) Have not been used previously under the anticipated operating 
conditions; or
    (3) Have operating characteristics that are outside the performance 
parameters established by this part.
    Non-conventional production or completion technology includes, but 
is not limited to, floating production systems, tension leg platforms, 
spars, floating production, storage, and offloading systems, guyed 
towers, compliant towers, subsea manifolds, and other subsea production 
components that rely on a remote site or host facility for utility and 
well control services.
    Offshore vehicle means a vehicle that is capable of being driven on 
ice.
    Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes 
you make to an OCS plan that BOEM has disapproved (see 30 CFR 
550.234(b), 550.272(a), and 550.273(b)).
    Revised OCS plan means an EP, DPP, or DOCD that proposes changes to 
an approved OCS plan, such as those in the location of a well or 
platform, type of drilling unit, or location of the onshore support base 
(see 30 CFR 550.283(a)).
    Supplemental OCS plan means an EP, DPP, or DOCD that proposes the 
addition to an approved OCS plan of an activity that requires approval 
of an application or permit (see 30 CFR 550.283(b)).



Sec.  250.201  What plans and information must I submit before I
 conduct any activities on my lease or unit?

    (a) Plans and documents. Before you conduct the activities on your 
lease or unit listed in the following table, you must submit, and BSEE 
must approve, the listed plans and documents. Your plans and documents 
may cover one or more leases or units.

------------------------------------------------------------------------
    You must submit a(n) . . .                Before you . . .
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) [Reserved]
(4) Deepwater Operations Plan      Conduct post-drilling installation
 (DWOP),                            activities in any water depth
                                    associated with a development
                                    project that will involve the use of
                                    a non-conventional production or
                                    completion technology.
(5) [Reserved]
(6) [Reserved]
------------------------------------------------------------------------

    (b) Submitting additional information. On a case-by-case basis, the 
Regional Supervisor may require you to submit additional information if 
the Regional Supervisor determines that it is necessary to evaluate your 
proposed plan or document.
    (c) Limiting information. The Regional Director may limit the amount 
of information or analyses that you otherwise must provide in your 
proposed plan or document under this subpart when:
    (1) Sufficient applicable information or analysis is readily 
available to BSEE;
    (2) Other coastal or marine resources are not present or affected;
    (3) Other factors such as technological advances affect information 
needs; or
    (4) Information is not necessary or required for a State to 
determine consistency with their CZMA Plan.
    (d) Referencing. In preparing your proposed plan or document, you 
may reference information and data discussed in other plans or documents 
you previously submitted or that are otherwise readily available to 
BSEE.

[[Page 96]]



Sec. Sec.  250.202-250.203  [Reserved]



Sec.  250.204  How must I protect the rights of the Federal government?

    (a) To protect the rights of the Federal government, you must 
either:
    (1) Drill and produce the wells that the Regional Supervisor 
determines are necessary to protect the Federal government from loss due 
to production on other leases or units or from adjacent lands under the 
jurisdiction of other entities (e.g., State and foreign governments); or
    (2) Pay a sum that the Regional Supervisor determines as adequate to 
compensate the Federal government for your failure to drill and produce 
any well.
    (b) Payment under paragraph (a)(2) of this section may constitute 
production in paying quantities for the purpose of extending the lease 
term.
    (c) You must complete and produce any penetrated hydrocarbon-bearing 
zone that the Regional Supervisor determines is necessary to conform to 
sound conservation practices.



Sec.  250.205  Are there special requirements if my well affects an
 adjacent property?

    For wells that could intersect or drain an adjacent property, the 
Regional Supervisor may require special measures to protect the rights 
of the Federal government and objecting lessees or operators of adjacent 
leases or units.

          Post-Approval Requirements for the EP, DPP, and DOCD



Sec.  250.282  Do I have to conduct post-approval monitoring?

    The Regional Supervisor may direct you to conduct monitoring 
programs. You must retain copies of all monitoring data obtained or 
derived from your monitoring programs and make them available to BSEE 
upon request. The Regional Supervisor may require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will specify requirements 
for preparing and submitting these reports.

                    Deepwater Operations Plan (DWOP)



Sec.  250.286  What is a DWOP?

    (a) A DWOP is a plan that provides sufficient information for BSEE 
to review a deepwater development project, and any other project that 
uses non-conventional production or completion technology, from a total 
system approach. The DWOP does not replace, but supplements other 
submittals required by the regulations such as BOEM Exploration Plans, 
Development and Production Plans, and Development Operations 
Coordination Documents. BSEE will use the information in your DWOP to 
determine whether the project will be developed in an acceptable manner, 
particularly with respect to operational safety and environmental 
protection issues involved with non-conventional production or 
completion technology.
    (b) The DWOP process consists of two parts: a Conceptual Plan and 
the DWOP. Section 250.289 prescribes what the Conceptual Plan must 
contain, and Sec.  250.292 prescribes what the DWOP must contain.



Sec.  250.287  For what development projects must I submit a DWOP?

    You must submit a DWOP for each development project in which you 
will use non-conventional production or completion technology, 
regardless of water depth. If you are unsure whether BSEE considers the 
technology of your project non-conventional, you must contact the 
Regional Supervisor for guidance.



Sec.  250.288  When and how must I submit the Conceptual Plan?

    You must submit four copies, or one hard copy and one electronic 
version, of the Conceptual Plan to the Regional Director after you have 
decided on the general concept(s) for development and before you begin 
engineering design of the well safety control system or subsea 
production systems to be used after well completion.

[[Page 97]]



Sec.  250.289  What must the Conceptual Plan contain?

    In the Conceptual Plan, you must explain the general design basis 
and philosophy that you will use to develop the field. You must include 
the following information:
    (a) An overview of the development concept(s);
    (b) A well location plat;
    (c) The system control type (i.e., direct hydraulic or electro-
hydraulic); and
    (d) The distance from each of the wells to the host platform.



Sec.  250.290  What operations require approval of the Conceptual Plan?

    You may not complete any production well or install the subsea 
wellhead and well safety control system (often called the tree) before 
BSEE has approved the Conceptual Plan.



Sec.  250.291  When and how must I submit the DWOP?

    You must submit four copies, or one hard copy and one electronic 
version, of the DWOP to the Regional Director after you have 
substantially completed safety system design and before you begin to 
procure or fabricate the safety and operational systems (other than the 
tree), production platforms, pipelines, or other parts of the production 
system.



Sec.  250.292  What must the DWOP contain?

    You must include the following information in your DWOP:
    (a) A description and schematic of the typical wellbore, casing, and 
completion;
    (b) Structural design, fabrication, and installation information for 
each surface system, including host facilities;
    (c) Design, fabrication, and installation information on the mooring 
systems for each surface system;
    (d) Information on any active stationkeeping system(s) involving 
thrusters or other means of propulsion used with a surface system;
    (e) Information concerning the drilling and completion systems;
    (f) Design and fabrication information for each riser system (e.g., 
drilling, workover, production, and injection);
    (g) Pipeline information;
    (h) Information about the design, fabrication, and operation of an 
offtake system for transferring produced hydrocarbons to a transport 
vessel;
    (i) Information about subsea wells and associated systems that 
constitute all or part of a single project development covered by the 
DWOP;
    (j) Flow schematics and Safety Analysis Function Evaluation (SAFE) 
charts (API RP 14C, subsection 4.3c, incorporated by reference in Sec.  
250.198) of the production system from the Surface Controlled Subsurface 
Safety Valve (SCSSV) downstream to the first item of separation 
equipment;
    (k) A description of the surface/subsea safety system and emergency 
support systems to include a table that depicts what valves will close, 
at what times, and for what events or reasons;
    (l) A general description of the operating procedures, including a 
table summarizing the curtailment of production and offloading based on 
operational considerations;
    (m) A description of the facility installation and commissioning 
procedure;
    (n) A discussion of any new technology that affects hydrocarbon 
recovery systems;
    (o) A list of any alternate compliance procedures or departures for 
which you anticipate requesting approval;
    (p) If you propose to use a pipeline free standing hybrid riser 
(FSHR) on a permanent installation that utilizes a critical chain, wire 
rope, or synthetic tether to connect the top of the riser to a buoyancy 
air can, provide the following information in your DWOP in the 
discussions required by paragraphs (f) and (g) of this section:
    (1) A detailed description and drawings of the FSHR, buoy and the 
tether system;
    (2) Detailed information on the design, fabrication, and 
installation of the FSHR, buoy and tether system, including pressure 
ratings, fatigue life, and yield strengths;

[[Page 98]]

    (3) A description of how you met the design requirements, load 
cases, and allowable stresses for each load case according to API RP 2RD 
(as incorporated by reference in Sec.  250.198);
    (4) Detailed information regarding the tether system used to connect 
the FSHR to a buoyancy air can;
    (5) Descriptions of your monitoring system and monitoring plan to 
monitor the pipeline FSHR and tether for fatigue, stress, and any other 
abnormal condition (e.g., corrosion) that may negatively impact the 
riser or tether; and
    (6) Documentation that the tether system and connection accessories 
for the pipeline FSHR have been certified by an approved classification 
society or equivalent and verified by the CVA required in subpart I of 
this part; and
    (q) Payment of the service fee listed in Sec.  250.125.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21973, May 15, 2019, Sec.  250.292 was 
amended by revising paragraph (p), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.292  What must the DWOP contain?

                                * * * * *

    (p) If you propose to use a pipeline free standing hybrid riser 
(FSHR) on a permanent installation that utilizes a buoyancy air can 
suspended from the top of the riser, you must provide the following 
information in your DWOP in the discussions required by paragraphs (f) 
and (g) of this section:
    (1) A detailed description and drawings of the FSHR, buoy, and the 
associated connection system;
    (2) Detailed information regarding the system used to connect the 
FSHR to the buoyancy air can, and associated redundancies; and
    (3) Descriptions of your monitoring system and monitoring plan to 
monitor the pipeline FSHR and the associated connection system for 
fatigue, stress, and any other abnormal condition (e.g., corrosion) that 
may negatively impact the riser system's integrity.

                                * * * * *



Sec.  250.293  What operations require approval of the DWOP?

    You may not begin production until BSEE approves your DWOP.



Sec.  250.294  May I combine the Conceptual Plan and the DWOP?

    If your development project meets the following criteria, you may 
submit a combined Conceptual Plan/DWOP on or before the deadline for 
submitting the Conceptual Plan.
    (a) The project is located in water depths of less than 400 meters 
(1,312 feet); and
    (b) The project is similar to projects involving non-conventional 
production or completion technology for which you have obtained approval 
previously.



Sec.  250.295  When must I revise my DWOP?

    You must revise either the Conceptual Plan or your DWOP to reflect 
changes in your development project that materially alter the 
facilities, equipment, and systems described in your plan. You must 
submit the revision within 60 days after any material change to the 
information required for that part of your plan.



               Subpart C_Pollution Prevention and Control



Sec.  250.300  Pollution prevention.

    (a) During the exploration, development, production, and 
transportation of oil and gas or sulphur, the lessee shall take measures 
to prevent unauthorized discharge of pollutants into the offshore 
waters. The lessee shall not create conditions that will pose 
unreasonable risk to public health, life, property, aquatic life, 
wildlife, recreation, navigation, commercial fishing, or other uses of 
the ocean.
    (1) When pollution occurs as a result of operations conducted by or 
on behalf of the lessee and the pollution damages or threatens to damage 
life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), or the marine, coastal, or 
human environment, the control and removal of the pollution to the 
satisfaction of the District Manager shall be at the expense of the 
lessee. Immediate corrective action shall be taken in all cases where 
pollution has occurred. Corrective action shall be subject to 
modification when directed by the District Manager.

[[Page 99]]

    (2) If the lessee fails to control and remove the pollution, the 
Director, in cooperation with other appropriate Agencies of Federal, 
State, and local governments, or in cooperation with the lessee, or 
both, shall have the right to control and remove the pollution at the 
lessee's expense. Such action shall not relieve the lessee of any 
responsibility provided for by law.
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components that could cause 
unreasonable degradation to the marine environment. No petroleum-based 
substances, including diesel fuel, may be added to the drilling mud 
system without prior approval of the District Manager. For Arctic OCS 
exploratory drilling, you must capture all petroleum-based mud to 
prevent its discharge into the marine environment. The Regional 
Supervisor may also require you to capture, during your Arctic OCS 
exploratory drilling operations, all water-based mud from operations 
after completion of the hole for the conductor casing to prevent its 
discharge into the marine environment, based on various factors 
including, but not limited to:
    (i) The proximity of your exploratory drilling operation to 
subsistence hunting and fishing locations;
    (ii) The extent to which discharged mud may cause marine mammals to 
alter their migratory patterns in a manner that impedes subsistence 
users' access to, or use of, those resources, or increases the risk of 
injury to subsistence users; or
    (iii) The extent to which discharged mud may adversely affect marine 
mammals, fish, or their habitat.
    (2) You must obtain approval from the District Manager of the method 
you plan to use to dispose of drill cuttings, sand, and other well 
solids. For Arctic OCS exploratory drilling, you must capture all 
cuttings from operations that utilize petroleum-based mud to prevent 
their discharge into the marine environment. The Regional Supervisor may 
also require you to capture, during your Arctic OCS exploratory drilling 
operations, all cuttings from operations that utilize water-based mud 
after completion of the hole for the conductor casing to prevent their 
discharge into the marine environment, based on various factors 
including, but not limited to:
    (i) The proximity of your exploratory drilling operation to 
subsistence hunting and fishing locations;
    (ii) The extent to which discharged cuttings may cause marine 
mammals to alter their migratory patterns in a manner that impedes 
subsistence users' access to, or use of, those resources, or increases 
the risk of injury to subsistence users; or
    (iii) The extent to which discharged cuttings may adversely affect 
marine mammals, fish, or their habitat.
    (3) All hydrocarbon-handling equipment for testing and production 
such as separators, tanks, and treaters shall be designed, installed, 
and operated to prevent pollution. Maintenance or repairs which are 
necessary to prevent pollution of offshore waters shall be undertaken 
immediately.
    (4) Curbs, gutters, drip pans, and drains shall be installed in deck 
areas in a manner necessary to collect all contaminants not authorized 
for discharge. Oil drainage shall be piped to a properly designed, 
operated, and maintained sump system which will automatically maintain 
the oil at a level sufficient to prevent discharge of oil into offshore 
waters. All gravity drains shall be equipped with a water trap or other 
means to prevent gas in the sump system from escaping through the 
drains. Sump piles shall not be used as processing devices to treat or 
skim liquids but may be used to collect treated-produced water, treated-
produced sand, or liquids from drip pans and deck drains and as a final 
trap for hydrocarbon liquids in the event of equipment upsets. 
Improperly designed, operated, or maintained sump piles which do not 
prevent the discharge of oil into offshore waters shall be replaced or 
repaired.
    (5) On artificial islands, all vessels containing hydrocarbons shall 
be placed inside an impervious berm or otherwise protected to contain 
spills. Drainage shall be directed away from the drilling rig to a sump. 
Drains and sumps shall be constructed to prevent seepage.

[[Page 100]]

    (6) Disposal of equipment, cables, chains, containers, or other 
materials into offshore waters is prohibited.
    (c) Materials, equipment, tools, containers, and other items used in 
the Outer Continental Shelf (OCS) which are of such shape or 
configuration that they are likely to snag or damage fishing devices 
shall be handled and marked as follows:
    (1) All loose material, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in use 
and in a marked container before transport over offshore waters;
    (2) All cable, chain, or wire segments shall be recovered after use 
and securely stored until suitable disposal is accomplished;
    (3) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over offshore waters; and
    (4) All markings must clearly identify the owner and must be durable 
enough to resist the effects of the environmental conditions to which 
they may be exposed.
    (d) Any of the items described in paragraph (c) of this section that 
are lost overboard shall be recorded on the facility's daily operations 
report, as appropriate, and reported to the District Manager.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]



Sec.  250.301  Inspection of facilities.

    Drilling and production facilities shall be inspected daily or at 
intervals approved or prescribed by the District Manager to determine if 
pollution is occurring. Necessary maintenance or repairs shall be made 
immediately. Records of such inspections and repairs shall be maintained 
at the facility or at a nearby manned facility for 2 years.



                Subpart D_Oil and Gas Drilling Operations

                          General Requirements



Sec.  250.400  General requirements.

    Drilling operations must be conducted in a safe manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS), 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must 
also follow the applicable requirements of subpart G of this part.

[81 FR 26017, Apr. 29, 2016]



Sec. Sec.  250.401-250.403  [Reserved]



Sec.  250.404  What are the requirements for the crown block?

    You must have a crown block safety device that prevents the 
traveling block from striking the crown block. You must check the device 
for proper operation at least once per week and after each drill-line 
slipping operation and record the results of this operational check in 
the driller's report.



Sec.  250.405  What are the safety requirements for diesel engines
 used on a drilling rig?

    You must equip each diesel engine with an air intake device to shut 
down the diesel engine in the event of a runaway.
    (a) For a diesel engine that is not continuously manned, you must 
equip the engine with an automatic shutdown device;
    (b) For a diesel engine that is continuously manned, you may equip 
the engine with either an automatic or remote manual air intake shutdown 
device;
    (c) You do not have to equip a diesel engine with an air intake 
device if it meets one of the following criteria:
    (1) Starts a larger engine;
    (2) Powers a firewater pump;
    (3) Powers an emergency generator;
    (4) Powers a BOP accumulator system;
    (5) Provides air supply to divers or confined entry personnel;
    (6) Powers temporary equipment on a nonproducing platform;
    (7) Powers an escape capsule; or
    (8) Powers a portable single-cylinder rig washer.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]

[[Page 101]]



Sec.  250.406  [Reserved]



Sec.  250.407  What tests must I conduct to determine reservoir
 characteristics?

    You must determine the presence, quantity, quality, and reservoir 
characteristics of oil, gas, sulphur, and water in the formations 
penetrated by logging, formation sampling, or well testing.



Sec.  250.408  May I use alternative procedures or equipment
 during drilling operations?

    You may use alternative procedures or equipment during drilling 
operations after receiving approval from the District Manager. You must 
identify and discuss your proposed alternative procedures or equipment 
in your Application for Permit to Drill (APD) (Form BSEE-0123) (see 
Sec.  250.414(h)). Procedures for obtaining approval are described in 
Sec.  250.141 of this part.



Sec.  250.409  May I obtain departures from these drilling requirements?

    The District Manager may approve departures from the drilling 
requirements specified in this subpart. You may apply for a departure 
from drilling requirements by writing to the District Manager. You 
should identify and discuss the departure you are requesting in your APD 
(see Sec.  250.414(h)).

                     Applying for a Permit To Drill



Sec.  250.410  How do I obtain approval to drill a well?

    You must obtain written approval from the District Manager before 
you begin drilling any well or before you sidetrack, bypass, or deepen a 
well. To obtain approval, you must:
    (a) Submit the information required by Sec. Sec.  250.411 through 
250.418;
    (b) Include the well in your approved Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD);
    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 553; and
    (d) Submit the following to the District Manager:
    (1) An original and two complete copies of Form BSEE-0123, 
Application for Permit to Drill (APD), and Form BSEE-0123S, Supplemental 
APD Information Sheet;
    (2) A separate public information copy of forms BSEE-0123 and BSEE-
0123S that meets the requirements of Sec.  250.186; and
    (3) Payment of the service fee listed in Sec.  250.125.



Sec.  250.411  What information must I submit with my application?

    In addition to forms BSEE-0123 and BSEE-0123S, you must include the 
information required in this subpart and subpart G of this part, 
including the following:

----------------------------------------------------------------------------------------------------------------
  Information that you must include with an APD                     Where to find a description
----------------------------------------------------------------------------------------------------------------
(a) Plat that shows locations of the proposed      Sec.   250.412.
 well,.
(b) Design criteria used for the proposed well,..  Sec.   250.413.
(c) Drilling prognosis,..........................  Sec.   250.414.
(d) Casing and cementing programs,...............  Sec.   250.415.
(e) Diverter systems descriptions,...............  Sec.   250.416.
(f) BOP system descriptions,.....................  Sec.   250.731.
(g) Requirements for using a MODU, and...........  Sec.   250.713.
(h) Additional information.......................  Sec.   250.418.
----------------------------------------------------------------------------------------------------------------


[81 FR 26017, Apr. 29, 2016]



Sec.  250.412  What requirements must the location plat meet?

    The location plat must:
    (a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
    (b) Show the surface and subsurface locations of the proposed well 
and all the wells in the vicinity;
    (c) Show the surface and subsurface locations of the proposed well 
in feet or meters from the block line;

[[Page 102]]

    (d) Contain the longitude and latitude coordinates, and either 
Universal Transverse Mercator grid-system coordinates or state plane 
coordinates in the Lambert or Transverse Mercator Projection system for 
the surface and subsurface locations of the proposed well; and
    (e) State the units and geodetic datum (including whether the datum 
is North American Datum 27 or 83) for these coordinates. If the datum 
was converted, you must state the method used for this conversion, since 
the various methods may produce different values.



Sec.  250.413  What must my description of well drilling design
 criteria address?

    Your description of well drilling design criteria must address:
    (a) Pore pressures;
    (b) Formation fracture gradients, adjusted for water depth;
    (c) Potential lost circulation zones;
    (d) Drilling fluid weights;
    (e) Casing setting depths;
    (f) Maximum anticipated surface pressures. For this section, maximum 
anticipated surface pressures are the pressures that you reasonably 
expect to be exerted upon a casing string and its related wellhead 
equipment. In calculating maximum anticipated surface pressures, you 
must consider: drilling, completion, and producing conditions; drilling 
fluid densities to be used below various casing strings; fracture 
gradients of the exposed formations; casing setting depths; total well 
depth; formation fluid types; safety margins; and other pertinent 
conditions. You must include the calculations used to determine the 
pressures for the drilling and the completion phases, including the 
anticipated surface pressure used for designing the production string;
    (g) A single plot containing curves for estimated pore pressures, 
formation fracture gradients, proposed drilling fluid weights, planned 
safe drilling margin, and casing setting depths in true vertical 
measurements;
    (h) A summary report of the shallow hazards site survey that 
describes the geological and manmade conditions if not previously 
submitted; and
    (i) Permafrost zones, if applicable.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21973, May 15, 2019, Sec.  250.413 was 
amended by revising paragraph (g), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.413  What must my description of well drilling design criteria 
          address?

                                * * * * *

    (g) A single plot containing curves for estimated pore pressures, 
formation fracture gradients, proposed drilling fluid weights (surface 
and downhole), planned safe drilling margin, and casing setting depths 
in true vertical measurements;

                                * * * * *



Sec.  250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures you will follow in drilling the well. This prognosis includes 
but is not limited to the following:
    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin that is between the estimated pore 
pressure and the lesser of estimated fracture gradients or casing shoe 
pressure integrity test and that is based on a risk assessment 
consistent with expected well conditions and operations.
    (1) Your safe drilling margin must also include use of equivalent 
downhole mud weight that is:
    (i) Greater than the estimated pore pressure; and
    (ii) Except as provided in paragraph (c)(2) of this section, a 
minimum of 0.5 pound per gallon below the lower of the casing shoe 
pressure integrity test or the lowest estimated fracture gradient.
    (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this 
section, you may use an equivalent downhole mud weight as specified in 
your APD, provided that you submit adequate documentation (such as risk 
modeling data, off-set well data, analog data, seismic data) to justify 
the alternative equivalent downhole mud weight.

[[Page 103]]

    (3) When determining the pore pressure and lowest estimated fracture 
gradient for a specific interval, you must consider related off-set well 
behavior observations.
    (d) Estimated depths to the top of significant marker formations;
    (e) Estimated depths to significant porous and permeable zones 
containing fresh water, oil, gas, or abnormally pressured formation 
fluids;
    (f) Estimated depths to major faults;
    (g) Estimated depths of permafrost, if applicable;
    (h) A list and description of all requests for using alternate 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternate procedures afford 
an equal or greater degree of protection, safety, or performance, or why 
the departures are requested;
    (i) Projected plans for well testing (refer to Sec.  250.460);
    (j) The type of wellhead system and liner hanger system to be 
installed and a descriptive schematic, which includes but is not limited 
to pressure ratings, dimensions, valves, load shoulders, and locking 
mechanisms, if applicable; and
    (k) Any additional information required by the District Manager 
needed to clarify or evaluate your drilling prognosis.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21973, May 15, 2019, Sec.  250.414 was 
amended by revising paragraphs (c)(2) and (c)(3), effective July 15, 
2019. For the convenience of the user, the revised text is set forth as 
follows:



Sec.  250.414  What must my drilling prognosis include?

                                * * * * *

    (c) * * *
    (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this 
section, you may use an equivalent downhole mud weight as specified in 
your APD, provided that you submit adequate documentation (such as risk 
modeling data, off-set well data, analog data, seismic data) to justify 
the alternative equivalent downhole mud weight. You may submit such 
justification in advance of your full APD, and BSEE may consider such 
justification for approval when submitted. Any such approval will be 
contingent upon your confirmation in the APD that your plans and the 
information underlying your approved justification have not changed.
    (3) When determining the pore pressure and lowest estimated fracture 
gradient for a specific interval, you must consider related off-set and 
analogous well behavior observations, if available.

                                * * * * *



Sec.  250.415  What must my casing and cementing programs include?

    Your casing and cementing programs must include:
    (a) The following well design information:
    (1) Hole sizes;
    (2) Bit depths (including measured and true vertical depth (TVD));
    (3) Casing information, including sizes, weights, grades, collapse 
and burst values, types of connection, and setting depths (measured and 
TVD) for all sections of each casing interval; and
    (4) Locations of any installed rupture disks (indicate if burst or 
collapse and rating);
    (b) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values;
    (c) Type and amount of cement (in cubic feet) planned for each 
casing string;
    (d) In areas containing permafrost, setting depths for conductor and 
surface casing based on the anticipated depth of the permafrost. Your 
program must provide protection from thaw subsidence and freezeback 
effect, proper anchorage, and well control;
    (e) A statement of how you evaluated the best practices included in 
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones 
in Deep Water Wells (as incorporated by reference in Sec.  250.198), if 
you drill a well in water depths greater than 500 feet and are in either 
of the following two areas:
    (1) An ``area with an unknown shallow water flow potential'' is a 
zone or geologic formation where neither the presence nor absence of 
potential for a shallow water flow has been confirmed.
    (2) An ``area known to contain a shallow water flow hazard'' is a 
zone or geologic formation for which drilling has confirmed the presence 
of shallow water flow; and

[[Page 104]]

    (f) A written description of how you evaluated the best practices 
included in API Standard 65--Part 2, Isolating Potential Flow Zones 
During Well Construction, Second Edition (as incorporated by reference 
in Sec.  250.198). Your written description must identify the mechanical 
barriers and cementing practices you will use for each casing string 
(reference API Standard 65--Part 2, Sections 4 and 5).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016]



Sec.  250.416  What must I include in the diverter description?

    You must include in the diverter description:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows:
    (1) The size of the element installed in the diverter housing;
    (2) Spool outlet internal diameter(s);
    (3) Diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) Valve type, size, working pressure rating, and location.

[81 FR 26018, Apr. 29, 2016]



Sec.  250.417  [Reserved]



Sec.  250.418  What additional information must I submit with my APD?

    You must include the following with the APD:
    (a) Rated capacities of the drilling rig and major drilling 
equipment, if not already on file with the appropriate District office;
    (b) A drilling fluids program that includes the minimum quantities 
of drilling fluids and drilling fluid materials, including weight 
materials, to be kept at the site;
    (c) A proposed directional plot if the well is to be directionally 
drilled;
    (d) A Hydrogen Sulfide Contingency Plan (see Sec.  250.490), if 
applicable, and not previously submitted;
    (e) A welding plan (see Sec. Sec.  250.109 to 250.113) if not 
previously submitted;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A request for approval, if you plan to wash out or displace 
cement to facilitate casing removal upon well abandonment. Your request 
must include a description of how far below the mudline you propose to 
displace cement and how you will visually monitor returns;
    (h) Certification of your casing and cementing program as required 
in Sec.  250.420(a)(7); and
    (i) Such other information as the District Manager may require.
    (j) For Arctic OCS exploratory drilling operations, you must provide 
the information required by Sec.  250.470.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016; 81 FR 46561, July 15, 2016]

                    Casing and Cementing Requirements



Sec.  250.420  What well casing and cementing requirements must I meet?

    You must case and cement all wells. Your casing and cementing 
programs must meet the applicable requirements of this subpart and of 
subpart G of this part.
    (a) Casing and cementing program requirements. Your casing and 
cementing programs must:
    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination;
    (5) Support unconsolidated sediments;
    (6) Provide adequate centralization to ensure proper cementation; 
and
    (7)(i) Include a certification signed by a registered professional 
engineer that the casing and cementing design is appropriate for the 
purpose for which it is intended under expected wellbore conditions, and 
is sufficient to satisfy the tests and requirements of this section and 
Sec.  250.423. Submit this certification with your APD (Form BSEE-0123).

[[Page 105]]

    (ii) You must have the registered professional engineer involved in 
the casing and cementing design process.
    (iii) The registered professional engineer must be registered in a 
state of the United States and have sufficient expertise and experience 
to perform the certification.
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the well.
    (3) On all wells that use subsea BOP stacks, you must include two 
independent barriers, including one mechanical barrier, in each annular 
flow path (examples of barriers include, but are not limited to, primary 
cement job and seal assembly). For the final casing string (or liner if 
it is your final string), you must install one mechanical barrier in 
addition to cement to prevent flow in the event of a failure in the 
cement. A dual float valve, by itself, is not considered a mechanical 
barrier. These barriers cannot be modified prior to or during completion 
or abandonment operations. The BSEE District Manager may approve 
alternative options under Sec.  250.141. You must submit documentation 
of this installation to BSEE in the End-of-Operations Report (Form BSEE-
0125).
    (4) If you need to substitute a different size, grade, or weight of 
casing than what was approved in your APD, you must contact the District 
Manager for approval prior to installing the casing.
    (c) Cementing requirements. (1) You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out the casing or before commencing completion operations. (If 
a liner is used refer to Sec.  250.421(f)).
    (2) You must use a weighted fluid during displacement to maintain an 
overbalanced hydrostatic pressure during the cement setting time, except 
when cementing casings or liners in riserless hole sections.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21973, May 15, 2019, Sec.  250.420 was 
amended by revising paragraph (a)(6), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.420  What well casing and cementing requirements must I meet?

                                * * * * *

    (a) * * *
    (6) Provide adequate centralization consistent with the guidelines 
of API Standard 65--Part 2 (as incorporated by reference in Sec.  
250.198); and

                                * * * * *



Sec.  250.421  What are the casing and cementing requirements by
 type of casing string?

    The table in this section identifies specific design, setting, and 
cementing requirements for casing strings and liners. For the purposes 
of subpart D, the casing strings in order of normal installation are as 
follows: drive or structural, conductor, surface, intermediate, and 
production casings (including liners). The District Manager may approve 
or prescribe other casing and cementing requirements where appropriate.

------------------------------------------------------------------------
                                                          Cementing
         Casing type           Casing requirements      requirements
------------------------------------------------------------------------
(a) Drive or Structural.....  Set by driving,       If you drilled a
                               jetting, or           portion of this
                               drilling to the       hole, you must use
                               minimum depth as      enough cement to
                               approved or           fill the annular
                               prescribed by the     space back to the
                               District Manager.     mudline.

[[Page 106]]

 
(b) Conductor...............  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space back
                               relevant              to the mudline.
                               engineering and      Verify annular fill
                               geologic factors.     by observing cement
                               These factors         returns. If you
                               include the           cannot observe
                               presence or absence   cement returns, use
                               of hydrocarbons,      additional cement
                               potential hazards,    to ensure fill-back
                               and water depths.     to the mudline.
                              Set casing            For drilling on an
                               immediately before    artificial island
                               drilling into         or when using a
                               formations known to   well cellar, you
                               contain oil or gas.   must discuss the
                               If you encounter      cement fill level
                               oil or gas or         with the District
                               unexpected            Manager.
                               formation pressure
                               before the planned
                               casing point, you
                               must set casing
                               immediately and set
                               it above the
                               encountered zone.
(c) Surface.................  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space to at
                               relevant              least 200 feet
                               engineering and       inside the
                               geologic factors.     conductor casing.
                               These factors        When geologic
                               include the           conditions such as
                               presence or absence   near-surface
                               of hydrocarbons,      fractures and
                               potential hazards,    faulting exist, you
                               and water depths.     must use enough
                                                     cement to fill the
                                                     calculated annular
                                                     space to the
                                                     mudline.
(d) Intermediate............  Design casing and     Use enough cement to
                               select setting        cover and isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones and
                               encountered           isolate abnormal
                               geologic              pressure intervals
                               characteristics or    from normal
                               wellbore conditions.  pressure intervals
                                                     in the well.
                                                    As a minimum, you
                                                     must cement the
                                                     annular space 500
                                                     feet above the
                                                     casing shoe and 500
                                                     feet above each
                                                     zone to be
                                                     isolated.
(e) Production..............  Design casing and     Use enough cement to
                               select setting        cover or isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones above
                               encountered           the shoe.
                               geologic             As a minimum, you
                               characteristics or    must cement the
                               wellbore conditions.  annular space at
                                                     least 500 feet
                                                     above the casing
                                                     shoe and 500 feet
                                                     above the uppermost
                                                     hydrocarbon-bearing
                                                     zone.
(f) Liners..................  If you use a liner    Same as cementing
                               as surface casing,    requirements for
                               you must set the      specific casing
                               top of the liner at   types. For example,
                               least 200 feet        a liner used as
                               above the previous    intermediate casing
                               casing/liner shoe.    must be cemented
                              If you use a liner     according to the
                               as an intermediate    cementing
                               string below a        requirements for
                               surface string or     intermediate
                               production casing     casing. If you have
                               below an              a liner lap and are
                               intermediate          unable to cement
                               string, you must      500 feet above the
                               set the top of the    previous shoe, as
                               liner at least 100    provided by
                               feet above the        paragraphs (d) and
                               previous casing       (e) of this
                               shoe.                 section, you must
                              You may not use a      submit and receive
                               liner as conductor    approval from the
                               casing.               District Manager on
                              A subsea well casing   a case-by-case
                               string whose top is   basis.
                               above the mudline
                               and that has been
                               cemented back to
                               the mudline will
                               not be considered a
                               liner.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26018, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21974, May 15, 2019, Sec.  421 was 
amended by revising paragraphs (c), (d), (e), and (f), effective July 
15, 2019. For the convenience of the user, the revised text is set forth 
as follows:



Sec.  250.421  What are the casing and cementing requirements by type of 
          casing string?

                                * * * * *

------------------------------------------------------------------------
                                                          Cementing
         Casing type           Casing requirements      requirements
------------------------------------------------------------------------
 
                              * * * * * * *
(c) Surface.................  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space to at
                               relevant              least 200 feet
                               engineering and       measured depth (MD)
                               geologic factors.     inside the
                               These factors         conductor casing.
                               include the          When geologic
                               presence or absence   conditions such as
                               of hydrocarbons,      near-surface
                               potential hazards,    fractures and
                               and water depths.     faulting exist, you
                                                     must use enough
                                                     cement to fill the
                                                     calculated annular
                                                     space to the
                                                     mudline.

[[Page 107]]

 
(d) Intermediate............  Design casing and     Use enough cement to
                               select setting        cover and isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones and
                               encountered           isolate abnormal
                               geologic              pressure intervals
                               characteristics or    from normal
                               wellbore conditions.  pressure intervals
                                                     in the well.
                                                    As a minimum, you
                                                     must cement the
                                                     annular space 500
                                                     feet MD above the
                                                     casing shoe and 500
                                                     feet MD above each
                                                     zone to be
                                                     isolated.
(e) Production..............  Design casing and     Use enough cement to
                               select setting        cover or isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones above
                               encountered           the shoe.
                               geologic             As a minimum, you
                               characteristics or    must cement the
                               wellbore conditions.  annular space at
                                                     least 500 feet MD
                                                     above the casing
                                                     shoe and 500 feet
                                                     MD above the
                                                     uppermost
                                                     hydrocarbon-bearing
                                                     zone.
(f) Liners..................  If you use a liner    Same as cementing
                               as surface casing,    requirements for
                               you must set the      specific casing
                               top of the liner at   types. For example,
                               least 200 feet MD     a liner used as
                               above the previous    intermediate casing
                               casing/liner shoe..   must be cemented
                              If you use a liner     according to the
                               as an intermediate    cementing
                               string below a        requirements for
                               surface string or     intermediate
                               production casing     casing.
                               below an
                               intermediate
                               string, you must
                               set the top of the
                               liner at least 100
                               feet MD above the
                               previous casing
                               shoe..
                              You may not use a
                               liner as conductor
                               casing.
                              A subsea well casing
                               string whose top is
                               above the mudline
                               and that has been
                               cemented back to
                               the mudline will
                               not be considered a
                               liner.
------------------------------------------------------------------------



Sec.  250.422  When may I resume drilling after cementing?

    (a) After cementing surface, intermediate, or production casing (or 
liners), you may resume drilling after the cement has been held under 
pressure for 12 hours. For conductor casing, you may resume drilling 
after the cement has been held under pressure for 8 hours. One 
acceptable method of holding cement under pressure is to use float 
valves to hold the cement in place.
    (b) If you plan to nipple down your diverter or BOP stack during the 
8- or 12-hour waiting time, you must determine, before nippling down, 
when it will be safe to do so. You must base your determination on a 
knowledge of formation conditions, cement composition, effects of 
nippling down, presence of potential drilling hazards, well conditions 
during drilling, cementing, and post cementing, as well as past 
experience.



Sec.  250.423  What are the requirements for casing and liner installation?

    You must ensure proper installation of casing in the subsea wellhead 
or liner in the liner hanger.
    (a) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing and cementing the 
casing string. If there is an indication of an inadequate cement job, 
you must comply with Sec.  250.428(c).
    (b) If you run a liner that has a latching mechanism or lock down 
mechanism, you must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing and cementing the 
liner. If there is an indication of an inadequate cement job, you must 
comply with Sec.  250.428(c).
    (c) You must perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner. You must perform this 
test for the intermediate and production casing strings or liners.
    (1) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (2) You must document all your test results and make them available 
to BSEE upon request.

[81 FR 26019, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21974, May 15, 2019, Sec.  423 was 
amended by revising paragraphs (a) and (b), effective July 15, 2019. For 
the convenience of the user, the revised text is set forth as follows:

[[Page 108]]



Sec.  250.423  What are the requirements for casing and liner 
          installation?

                                * * * * *

    (a) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing the casing string.
    (b) If you run a liner that has a latching mechanism or lock down 
mechanism, you must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing the liner.

                                * * * * *



Sec. Sec.  250.424-250.426  [Reserved]



Sec.  250.427  What are the requirements for pressure integrity tests?

    You must conduct a pressure integrity test below the surface casing 
or liner and all intermediate casings or liners. The District Manager 
may require you to run a pressure-integrity test at the conductor casing 
shoe if warranted by local geologic conditions or the planned casing 
setting depth. You must conduct each pressure integrity test after 
drilling at least 10 feet but no more than 50 feet of new hole below the 
casing shoe. You must test to either the formation leak-off pressure or 
to an equivalent drilling fluid weight if identified in an approved APD.
    (a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut 
drilling fluid, and well kicks to adjust the drilling fluid program and 
the setting depth of the next casing string. You must record all test 
results and hole-behavior observations made during the course of 
drilling related to formation integrity and pore pressure in the 
driller's report.
    (b) While drilling, you must maintain the safe drilling margins 
identified in Sec.  250.414. When you cannot maintain the safe margins, 
you must suspend drilling operations and remedy the situation.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26019, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21974, May 15, 2019, Sec.  250.427 was 
amended by revising paragraph (b), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.427  What are the requirements for pressure integrity tests?

                                * * * * *

    (b) While drilling, you must maintain the safe drilling margin 
identified in Sec.  250.414. When you cannot maintain the safe drilling 
margin, you must:
    (1) Suspend drilling operations and submit proposed remedial actions 
to the District Manager. The District Manager must review and approve 
your proposed remedial actions, which may include limited drilling 
through a lost circulation zone; or
    (2) Notify the District Manager and take further action in 
accordance with API Bulletin 92L (as incorporated by reference in Sec.  
250.198), if appropriate. You must submit a revised permit documenting 
any responsive actions taken.



Sec.  250.428  What must I do in certain cementing and casing situations?

    The table in this section describes actions that lessees must take 
when certain situations occur during casing and cementing activities.

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation pressures or  Submit a revised casing
 conditions that warrant revising your       program to the District
 casing design,                              Manager for approval.
(b) Need to change casing setting depths    Submit those changes to the
 or hole interval drilling depth (for a      District Manager for
 BHA with an under-reamer, this means bit    approval and include a
 depth) more than 100 feet true vertical     certification by a
 depth (TVD) from the approved APD due to    professional engineer (PE)
 conditions encountered during drilling      that he or she reviewed and
 operations,                                 approved the proposed
                                             changes.
(c) Have indication of inadequate cement    (1) Locate the top of cement
 job (such as lost returns, no cement        by:
 returns to mudline or expected height,     (i) Running a temperature
 cement channeling, or failure of            survey;
 equipment),                                (ii) Running a cement
                                             evaluation log; or
                                            (iii) Using a combination of
                                             these techniques.
                                            (2) Determine if your cement
                                             job is inadequate. If your
                                             cement job is determined to
                                             be inadequate, refer to
                                             paragraph (d) of this
                                             section.
                                            (3) If your cement job is
                                             determined to be adequate,
                                             report the results to the
                                             District Manager in your
                                             submitted WAR.

[[Page 109]]

 
(d) Inadequate cement job,                  Take remedial actions. The
                                             District Manager must
                                             review and approve all
                                             remedial actions before you
                                             may take them, unless
                                             immediate actions must be
                                             taken to ensure the safety
                                             of the crew or to prevent a
                                             well-control event. If you
                                             complete any immediate
                                             action to ensure the safety
                                             of the crew or to prevent a
                                             well-control event, submit
                                             a description of the action
                                             to the District Manager
                                             when that action is
                                             complete. Any changes to
                                             the well program will
                                             require submittal of a
                                             certification by a
                                             professional engineer (PE)
                                             certifying that he or she
                                             reviewed and approved the
                                             proposed changes, and must
                                             meet any other requirements
                                             of the District Manager.
(e) Primary cement job that did not         Isolate those intervals from
 isolate abnormal pressure intervals,        normal pressures by squeeze
                                             cementing before you
                                             complete; suspend
                                             operations; or abandon the
                                             well, whichever occurs
                                             first.
(f) Decide to produce a well that was not   Have at least two cemented
 originally contemplated for production,     casing strings (does not
                                             include liners) in the
                                             well. Note: All producing
                                             wells must have at least
                                             two cemented casing
                                             strings.
(g) Want to drill a well without setting    Submit geologic data and
 conductor casing,                           information to the District
                                             Manager that demonstrates
                                             the absence of shallow
                                             hydrocarbons or hazards.
                                             This information must
                                             include logging and
                                             drilling fluid-monitoring
                                             from wells previously
                                             drilled within 500 feet of
                                             the proposed well path down
                                             to the next casing point.
(h) Need to use less than required cement   Submit information to the
 for the surface casing during floating      District Manager that
 drilling operations to provide protection   demonstrates the use of
 from burst and collapse pressures,          less cement is necessary.
(i) Cement across a permafrost zone,        Use cement that sets before
                                             it freezes and has a low
                                             heat of hydration.
(j) Leave the annulus opposite a            Fill the annulus with a
 permafrost zone uncemented,                 liquid that has a freezing
                                             point below the minimum
                                             permafrost temperature and
                                             minimizes opposite a
                                             corrosion.
(k) Plan to use a valve(s) on the drive     Include a description of the
 pipe during cementing operations for the    plan in your APD. Your
 conductor casing, surface casing, or        description must include a
 liner,                                      schematic of the valve and
                                             height above the water
                                             line. The valve must be
                                             remotely operated and full
                                             opening with visual
                                             observation while taking
                                             returns. The person in
                                             charge of observing returns
                                             must be in communication
                                             with the drill floor. You
                                             must record in your daily
                                             report and in the WAR if
                                             cement returns were
                                             observed. If cement returns
                                             are not observed, you must
                                             contact the District
                                             Manager and obtain approval
                                             of proposed plans to locate
                                             the top of cement before
                                             continuing with operations.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26019, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21974, May 15, 2019, Sec.  250.428 was 
amended by revising paragraphs (c) and (d), effective July 15, 2019. For 
the convenience of the user, the revised text is set forth as follows:



Sec.  250.428  What must I do in certain cementing and casing 
          situations?

                                * * * * *

------------------------------------------------------------------------
     If you encounter the following
               situation:                      Then you must . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(c) Have indication of inadequate        (1) Locate the top of cement
 cement job (such as unplanned lost       by:
 returns, no cement returns to mudline      (i) Running a temperature
 or expected height, cement channeling,      survey;
 or failure of equipment),                  (ii) Running a cement
                                             evaluation log;
                                            (iii) Using tracers in the
                                             cement and logging them
                                             prior to drill out; or
                                            (iv) Using a combination of
                                             these techniques.
                                         (2) Determine if your cement
                                          job is inadequate. If your
                                          cement job is determined to be
                                          inadequate, refer to paragraph
                                          (d) of this section.
                                         (3) If your cement job is
                                          determined to be adequate,
                                          report the results to the
                                          District Manager in your
                                          submitted WAR.

[[Page 110]]

 
(d) Inadequate cement job,.............  Comply with Sec.
                                          250.428(c)(1) and take
                                          remedial actions. The District
                                          Manager must review and
                                          approve all remedial actions
                                          either through a previously
                                          approved contingency plan
                                          within the permit or remedial
                                          actions included in a revised
                                          permit before you may take
                                          them, unless immediate actions
                                          must be taken to ensure the
                                          safety of the crew or to
                                          prevent a well-control event.
                                          If you complete any immediate
                                          action to ensure the safety of
                                          the crew or to prevent a well-
                                          control event, submit a
                                          description of the action to
                                          the District Manager when that
                                          action is complete. Any
                                          changes to the well program,
                                          that are not included in the
                                          approved permit, will require
                                          submittal of a certification
                                          by a professional engineer
                                          (PE) certifying that they have
                                          reviewed and approved the
                                          proposed changes. You must
                                          also meet any other
                                          requirements of the District
                                          Manager for remedial actions.
 
                              * * * * * * *
------------------------------------------------------------------------

                      Diverter System Requirements



Sec.  250.430  When must I install a diverter system?

    You must install a diverter system before you drill a conductor or 
surface hole. The diverter system consists of a diverter sealing 
element, diverter lines, and control systems. You must design, install, 
use, maintain, and test the diverter system to ensure proper diversion 
of gases, water, drilling fluid, and other materials away from 
facilities and personnel.



Sec.  250.431  What are the diverter design and installation
 requirements?

    You must design and install your diverter system to:
    (a) Use diverter spool outlets and diverter lines that have a 
nominal diameter of at least 10 inches for surface wellhead 
configurations and at least 12 inches for floating drilling operations;
    (b) Use dual diverter lines arranged to provide for downwind 
diversion capability;
    (c) Use at least two diverter control stations. One station must be 
on the drilling floor. The other station must be in a readily accessible 
location away from the drilling floor;
    (d) Use only remote-controlled valves in the diverter lines. All 
valves in the diverter system must be full-opening. You may not install 
manual or butterfly valves in any part of the diverter system;
    (e) Minimize the number of turns (only one 90-degree turn allowed 
for each line for bottom-founded drilling units) in the diverter lines, 
maximize the radius of curvature of turns, and target all right angles 
and sharp turns;
    (f) Anchor and support the entire diverter system to prevent 
whipping and vibration; and
    (g) Protect all diverter-control instruments and lines from possible 
damage by thrown or falling objects.



Sec.  250.432  How do I obtain a departure to diverter design and
 installation requirements?

    The table below describes possible departures from the diverter 
requirements and the conditions required for each departure. To obtain 
one of these departures, you must have discussed the departure in your 
APD and received approval from the District Manager.

------------------------------------------------------------------------
        If you want a departure to:              Then you must . . .
------------------------------------------------------------------------
(a) Use flexible hose for diverter lines    Use flexible hose that has
 instead of rigid pipe,                      integral end couplings.
(b) Use only one spool outlet for your      (1) Have branch lines that
 diverter system,                            meet the minimum internal
                                             diameter requirements; and
                                             (2) Provide downwind
                                             diversion capability.
(c) Use a spool with an outlet with an      Use a spool that has dual
 internal diameter of less than 10 inches    outlets with an internal
 on a surface wellhead,                      diameter of at least 8
                                             inches.
(d) Use a single diverter line for          Maintain an appropriate
 floating drilling operations on a           vessel heading to provide
 dynamically positioned drillship,           for downwind diversion.
------------------------------------------------------------------------


[[Page 111]]



Sec.  250.433  What are the diverter actuation and testing requirements?

    When you install the diverter system, you must actuate the diverter 
sealing element, diverter valves, and diverter-control systems and 
control stations. You must also flow-test the vent lines.
    (a) For drilling operations with a surface wellhead configuration, 
you must actuate the diverter system at least once every 24-hour period 
after the initial test. After you have nippled up on conductor casing, 
you must pressure-test the diverter-sealing element and diverter valves 
to a minimum of 200 psi. While the diverter is installed, you must 
conduct subsequent pressure tests within 7 days after the previous test.
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation.
    (c) You must alternate actuations and tests between control 
stations.

    Effective Date Note: At 84 FR 21975, May 13, 2019, Sec.  250.433 was 
amended by revising paragraph (b), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.433  What are the diverter actuation and testing requirements?

                                * * * * *

    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation. For subsequent testing, you may partially actuate the 
diverter element and a flow test is not required.

                                * * * * *



Sec.  250.434  What are the recordkeeping requirements for diverter
 actuations and tests?

    You must record the time, date, and results of all diverter 
actuations and tests in the driller's report. In addition, you must:
    (a) Record the diverter pressure test on a pressure chart;
    (b) Require your onsite representative to sign and date the pressure 
test chart;
    (c) Identify the control station used during the test or actuation;
    (d) Identify problems or irregularities observed during the testing 
or actuations and record actions taken to remedy the problems or 
irregularities; and
    (e) Retain all pressure charts and reports pertaining to the 
diverter tests and actuations at the facility for the duration of 
drilling the well.



Sec. Sec.  250.440-250.451  [Reserved]



Sec.  250.452  What are the real-time monitoring requirements for
 Arctic OCS exploratory drilling operations?

    (a) When conducting exploratory drilling operations on the Arctic 
OCS, you must gather and monitor real-time data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's fluid handling systems on the rig; and
    (3) The well's downhole conditions as monitored by a downhole 
sensing system, when such a system is installed.
    (b) During well operations, you must transmit the data identified in 
paragraph (a) of this section as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and have 
the capability to monitor the data onshore, using qualified personnel. 
Onshore personnel who monitor real-time data must have the capability to 
contact rig personnel during operations. After well operations, you must 
store the data at a designated location for recordkeeping purposes as 
required in Sec. Sec.  250.740 and 250.741. You must provide BSEE with 
access to your real-time monitoring data onshore upon request.

[81 FR 46561, July 15, 2016]

                       Drilling Fluid Requirements



Sec.  250.455  What are the general requirements for a drilling
 fluid program?

    You must design and implement your drilling fluid program to prevent 
the loss of well control. This program must address drilling fluid safe 
practices, testing and monitoring equipment, drilling fluid quantities, 
and drilling fluid-handling areas.

[[Page 112]]



Sec.  250.456  What safe practices must the drilling fluid
 program follow?

    Your drilling fluid program must include the following safe 
practices:
    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just off-
bottom. You may omit this practice if documentation in the driller's 
report shows:
    (1) No indication of formation fluid influx before starting to pull 
the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in the 
driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases by 
75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you must 
fill the hole. You must also calculate the equivalent drilling fluid 
volume needed to fill the hole. Both sets of numbers must be posted near 
the driller's station. You must use a mechanical, volumetric, or 
electronic device to measure the drilling fluid required to fill the 
hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You must 
circulate and condition the well, on or near-bottom, unless well or 
drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break down, the rated 
working pressure of the BOP stack, and 70 percent of casing burst (or 
casing test as approved by the District Manager). As a minimum, you must 
post the following two pressures:
    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the hole; 
and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the District 
Manager);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid;
    (i) When circulating, you must test the drilling fluid at least once 
each tour, or more frequently if conditions warrant. Your tests must 
conform to industry-accepted practices and include density, viscosity, 
and gel strength; hydrogenion concentration; filtration; and any other 
tests the District Manager requires for monitoring and maintaining 
drilling fluid quality, prevention of downhole equipment problems and 
for kick detection. You must record the results of these tests in the 
drilling fluid report; and
    (j) In areas where permafrost and/or hydrate zones are present or 
may be present, you must control drilling fluid temperatures to drill 
safely through those zones.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26020, Apr. 29, 2016]



Sec.  250.457  What equipment is required to monitor drilling fluids?

    Once you establish drilling fluid returns, you must install and 
maintain the following drilling fluid-system

[[Page 113]]

monitoring equipment throughout subsequent drilling operations. This 
equipment must have the following indicators on the rig floor:
    (a) Pit level indicator to determine drilling fluid-pit volume gains 
and losses. This indicator must include both a visual and an audible 
warning device;
    (b) Volume measuring device to accurately determine drilling fluid 
volumes required to fill the hole on trips;
    (c) Return indicator devices that indicate the relationship between 
drilling fluid-return flow rate and pump discharge rate. This indicator 
must include both a visual and an audible warning device; and
    (d) Gas-detecting equipment to monitor the drilling fluid returns. 
The indicator may be located in the drilling fluid-logging compartment 
or on the rig floor. If the indicators are only in the logging 
compartment, you must continually man the equipment and have a means of 
immediate communication with the rig floor. If the indicators are on the 
rig floor only, you must install an audible alarm.



Sec.  250.458  What quantities of drilling fluids are required?

    (a) You must use, maintain, and replenish quantities of drilling 
fluid and drilling fluid materials at the drill site as necessary to 
ensure well control. You must determine those quantities based on known 
or anticipated drilling conditions, rig storage capacity, weather 
conditions, and estimated time for delivery.
    (b) You must record the daily inventories of drilling fluid and 
drilling fluid materials, including weight materials and additives in 
the drilling fluid report.
    (c) If you do not have sufficient quantities of drilling fluid and 
drilling fluid material to maintain well control, you must suspend 
drilling operations.



Sec.  250.459  What are the safety requirements for drilling
 fluid-handling areas?

    You must classify drilling fluid-handling areas according to API RP 
500, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities, Classified as Class I, Division 1 
and Division 2 (as incorporated by reference in Sec.  250.198); or API 
RP 505, Recommended Practice for Classification of Locations for 
Electrical Installations at Petroleum Facilities, Classified as Class 1, 
Zone 0, Zone 1, and Zone 2 (as incorporated by reference in Sec.  
250.198). In areas where dangerous concentrations of combustible gas may 
accumulate, you must install and maintain a ventilation system and gas 
monitors. Drilling fluid-handling areas must have the following safety 
equipment:
    (a) A ventilation system capable of replacing the air once every 5 
minutes or 1.0 cubic feet of air-volume flow per minute, per square foot 
of area, whichever is greater. In addition:
    (1) If natural means provide adequate ventilation, then a mechanical 
ventilation system is not necessary;
    (2) If a mechanical system does not run continuously, then it must 
activate when gas detectors indicate the presence of 1 percent or more 
of combustible gas by volume; and
    (3) If discharges from a mechanical ventilation system may be 
hazardous, then you must maintain the drilling fluid-handling area at a 
negative pressure. You must protect the negative pressure area by using 
at least one of the following: a pressure-sensitive alarm, open-door 
alarms on each access to the area, automatic door-closing devices, air 
locks, or other devices approved by the District Manager;
    (b) Gas detectors and alarms except in open areas where adequate 
ventilation is provided by natural means. You must test and recalibrate 
gas detectors quarterly. No more than 90 days may elapse between tests;
    (c) Explosion-proof or pressurized electrical equipment to prevent 
the ignition of explosive gases. Where you use air for pressuring 
equipment, you must locate the air intake outside of and as far as 
practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

[[Page 114]]

                       Other Drilling Requirements



Sec.  250.460  What are the requirements for conducting a well test?

    (a) If you intend to conduct a well test, you must include your 
projected plans for the test with your APD (form BSEE-0123) or in an 
Application for Permit to Modify (APM) (form BSEE-0124). Your plans must 
include at least the following information:
    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (b) You must give the District Manager at least 24-hours notice 
before starting a well test.



Sec.  250.461  What are the requirements for directional and
 inclination surveys?

    For this subpart, BSEE classifies a well as vertical if the 
calculated average of inclination readings does not exceed 3 degrees 
from the vertical.
    (a) Survey requirements for a vertical well. (1) You must conduct 
inclination surveys on each vertical well and record the results. Survey 
intervals may not exceed 1,000 feet during the normal course of 
drilling;
    (2) You must also conduct a directional survey that provides both 
inclination and azimuth, and digitally record the results in electronic 
format:
    (i) Within 500 feet of setting surface or intermediate casing;
    (ii) Within 500 feet of setting any liner; and
    (iii) When you reach total depth.
    (b) Survey requirements for directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals not 
to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 100 feet.
    (c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
    (d) Composite survey requirements. (1) Your composite directional 
survey must show the interval from the bottom of the conductor casing to 
total depth. In the absence of conductor casing, the survey must show 
the interval from the bottom of the drive or structural casing to total 
depth; and
    (2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-north 
correction. Surveys must show the magnetic and grid corrections used and 
include a listing of the directionally computed inclinations and 
azimuths.
    (e) If you drill within 500 feet of an adjacent lease, the Regional 
Supervisor may require you to furnish a copy of the well's directional 
survey to the affected leaseholder. This could occur when the adjoining 
leaseholder requests a copy of the survey for the protection of 
correlative rights.

    Effective Date Note: At 84 FR 21975, May 15, 2019, Sec.  250.461 was 
amended by revising paragraph (b), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.461  What are the requirements for directional and inclination 
          surveys?

                                * * * * *

    (b) Survey requirements for a directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals not 
to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 180 feet.

                                * * * * *



Sec.  250.462  What are the source control, containment, and 
collocated equipment requirements?

    For drilling operations using a subsea BOP or surface BOP on a 
floating facility, you must have the ability

[[Page 115]]

to control or contain a blowout event at the sea floor.
    (a) To determine your required source control and containment 
capabilities you must do the following:
    (1) Consider a scenario of the wellbore fully evacuated to reservoir 
fluids, with no restrictions in the well.
    (2) Evaluate the performance of the well as designed to determine if 
a full shut-in can be achieved without having reservoir fluids broach to 
the sea floor. If your evaluation indicates that the well can only be 
partially shut-in, then you must determine your ability to flow and 
capture the residual fluids to a surface production and storage system.
    (b) You must have access to and the ability to deploy Source Control 
and Containment Equipment (SCCE) and all other necessary supporting and 
collocated equipment to regain control of the well. SCCE means the 
capping stack, cap-and-flow system, containment dome, and/or other 
subsea and surface devices, equipment, and vessels, which have the 
collective purpose to control a spill source and stop the flow of fluids 
into the environment or to contain fluids escaping into the environment. 
This SCCE, supporting equipment, and collocated equipment must include, 
but is not limited to, the following:
    (1) Subsea containment and capture equipment, including containment 
domes and capping stacks;
    (2) Subsea utility equipment including hydraulic power sources and 
hydrate control equipment;
    (3) Collocated equipment including dispersant injection equipment;
    (4) Riser systems;
    (5) Remotely operated vehicles (ROVs);
    (6) Capture vessels;
    (7) Support vessels; and
    (8) Storage facilities.
    (c) You must submit a description of your source control and 
containment capabilities to the Regional Supervisor and receive approval 
before BSEE will approve your APD, Form BSEE-0123. The description of 
your containment capabilities must contain the following:
    (1) Your source control and containment capabilities for controlling 
and containing a blowout event at the seafloor;
    (2) A discussion of the determination required in paragraph (a) of 
this section; and
    (3) Information showing that you have access to and the ability to 
deploy all equipment required by paragraph (b) of this section.
    (d) You must contact the District Manager and Regional Supervisor 
for reevaluation of your source control and containment capabilities if 
your:
    (1) Well design changes; or
    (2) Approved source control and containment equipment is out of 
service.
    (e) You must maintain, test, and inspect the source control, 
containment, and collocated equipment identified in the following table 
according to these requirements:

------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) Capping stacks,.........  (i) Function test     Pressure containing
                               all pressure          critical components
                               containing critical   are those
                               components on a       components that
                               quarterly frequency   will experience
                               (not to exceed 104    wellbore pressure
                               days between          during a shut-in
                               tests),               after being
                                                     functioned.
                              (ii) Pressure test    Pressure containing
                               pressure containing   critical components
                               critical components   are those
                               on a bi-annual        components that
                               basis, but not        will experience
                               later than 210 days   wellbore pressure
                               from the last         during a shut-in.
                               pressure test. All    These components
                               pressure testing      include, but are
                               must be witnessed     not limited to: All
                               by BSEE (if           blind rams,
                               available) and a      wellhead
                               BSEE-approved         connectors, and
                               verification          outlet valves.
                               organization.
                              (iii) Notify BSEE at
                               least 21 days prior
                               to commencing any
                               pressure testing.
(2) Production safety         (i) Meet or exceed
 systems used for flow and     the requirements
 capture operations,           set forth in Sec.
                               Sec.   250.800
                               through 250.808,
                               excluding required
                               equipment that
                               would be installed
                               below the wellhead
                               or that is not
                               applicable to the
                               cap and flow
                               system.
                              (ii) Have all
                               equipment unique to
                               containment
                               operations
                               available for
                               inspection at all
                               times.

[[Page 116]]

 
(3) Subsea utility            Have all referenced   Subsea utility
 equipment,.                   containment           equipment includes,
                               equipment available   but is not limited
                               for inspection at     to: Hydraulic power
                               all times.            sources, debris
                                                     removal, and
                                                     hydrate control
                                                     equipment.
(4) Collocated equipment,...  Have equipment        Collocated equipment
                               available for         includes, but is
                               inspection at all     not limited to,
                               times.                dispersant
                                                     injection equipment
                                                     and other subsea
                                                     control equipment.
------------------------------------------------------------------------


[81 FR 26020, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21975, May 15, 2019, Sec.  250.462 was 
amended by revising paragraphs (b) introductory text, (e)(1)(ii), 
(e)(2)(i), (e)(3), and (e)(4), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.462  What are the source control, containment, and collocated 
          equipment requirements?

                                * * * * *

    (b) You must have access to and the ability to deploy Source Control 
and Containment Equipment (SCCE) and all other necessary supporting and 
collocated equipment to regain control of the well. SCCE means the 
capping stack, cap-and-flow system, containment dome, and/or other 
subsea and surface devices, equipment, and vessels, which have the 
collective purpose to control a spill source and stop the flow of fluids 
into the environment or to contain fluids escaping into the environment 
based on the determinations outlined in paragraph (a) of this section. 
This SCCE, supporting equipment, and collocated equipment may include, 
but is not limited to, the following:

                                * * * * *

    (e) * * *

------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) * * *
                              (ii) Pressure test    Pressure containing
                               pressure containing   critical components
                               critical components   are those
                               on a bi-annual        components that
                               basis, but not        will experience
                               later than 210 days   wellbore pressure
                               from the last         during a shut-in.
                               pressure test. All    These components
                               pressure testing      include, but are
                               must be witnessed     not limited to: All
                               by BSEE (if           blind rams,
                               available) and an     wellhead
                               independent third     connectors, and
                               party.                outlet valves.
 
                              * * * * * * *
(2) Production safety         (i) Meet or exceed
 systems used for flow and     the requirements
 capture operations.           set forth in
                               Subpart H,
                               excluding required
                               equipment that
                               would be installed
                               below the wellhead
                               or that is not
                               applicable to the
                               cap and flow
                               system.
 
                              * * * * * * *
(3) Subsea utility            Have all equipment    Subsea utility
 equipment,.                   utilized solely for   equipment includes,
                               containment           but is not limited
                               operations            to: Hydraulic power
                               available for         sources, debris
                               inspection at all     removal, and
                               times.                hydrate control
                                                     equipment.
(4) Collocated equipment      Have equipment        Collocated equipment
 designated by the operator    available for         includes, but is
 in the Regional Containment   inspection at all     not limited to,
 Demonstration (RCD) or Well   times.                dispersant
 Containment Plan (WCP),                             injection equipment
                                                     and other subsea
                                                     control equipment.
------------------------------------------------------------------------



Sec.  250.463  Who establishes field drilling rules?

    (a) The District Manager may establish field drilling rules 
different from the requirements of this subpart when geological and 
engineering information shows that specific operating requirements are 
appropriate. You must comply with field drilling rules and 
nonconflicting requirements of this subpart. The District Manager may 
amend or cancel field drilling rules at any time.
    (b) You may request the District Manager to establish, amend, or 
cancel field drilling rules.

[[Page 117]]

            Applying for a Permit To Modify and Well Records



Sec.  250.465  When must I submit an Application for Permit to
 Modify (APM) or an End of Operations Report to BSEE?

    (a) You must submit an APM (form BSEE-0124) or an End of Operations 
Report (form BSEE-0125) and other materials to the Regional Supervisor 
as shown in the following table. You must also submit a public 
information copy of each form.

------------------------------------------------------------------------
    When you . . .       Then you must . . .           And . . .
------------------------------------------------------------------------
(1) Intend to revise    Submit form BSEE-0124  Receive written or oral
 your drilling plan,     or request oral        approval from the
 change major drilling   approval,              District Manager before
 equipment, or                                  you begin the intended
 plugback,                                      operation. If you get an
                                                approval, you must
                                                submit form BSEE-0124 no
                                                later than the end of
                                                the 3rd business day
                                                following the oral
                                                approval. In all cases,
                                                or you must meet the
                                                additional requirements
                                                in paragraph (b) of this
                                                section.
(2) Determine a well's  Immediately Submit a   Submit a plat certified
 final surface           form BSEE-0124,        by a registered land
 location, water                                surveyor that meets the
 depth, and the rotary                          requirements of Sec.
 kelly bushing                                  250.412.
 elevation,
(3) Move a drilling     Submit forms BSEE-     Submit appropriate copies
 unit from a wellbore    0124 and BSEE-0125     of the well records.
 before completing a     within 30 days after
 well,                   the suspension of
                         wellbore operations,
------------------------------------------------------------------------

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following additional 
requirements:
    (1) Your APM (Form BSEE-0124) must contain a detailed statement of 
the proposed work that would materially change from the approved APD. 
The submission of your APM must be accompanied by payment of the service 
fee listed in Sec.  250.125;
    (2) Your form BSEE-0124 must include the present status of the well, 
depth of all casing strings set to date, well depth, present production 
zones and productive capability, and all other information specified; 
and
    (3) Within 30 days after completing this work, you must submit an 
End of Operations Report (EOR), Form BSEE-0125, as required under Sec.  
250.744.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26021, Apr. 29, 2016]



Sec. Sec.  250.466-250.469  [Reserved]

                   Additional Arctic OCS Requirements

    Source: 81 FR 46561, July 15, 2016, unless otherwise noted.



Sec.  250.470  What additional information must I submit with my
 APD for Arctic OCS exploratory drilling operations?

    In addition to complying with all other applicable requirements 
included in this part, you must provide with your APD all of the 
following information pertaining to your proposed Arctic OCS exploratory 
drilling:
    (a) A detailed description of:
    (1) The environmental, meteorological, and oceanic conditions you 
expect to encounter at the well site(s);
    (2) How you will prepare your equipment, materials, and drilling 
unit for service in the conditions identified in paragraph (a)(1) of 
this section, and how your drilling unit will be in compliance with the 
requirements of Sec.  250.713.
    (b) A detailed description of all operations necessary in Arctic OCS 
conditions to transition the rig from being under way to conducting 
drilling operations and from ending drilling operations to being under 
way, as well as any anticipated repair and maintenance plans for the 
drilling unit and equipment. You should include, among other things, a 
description of how you plan to:
    (1) Recover the subsea equipment, including the marine riser and the 
lower marine riser package;

[[Page 118]]

    (2) Recover the BOP;
    (3) Recover the auxiliary sub-sea controls and template;
    (4) Lay down the drill pipe and secure the drill pipe and marine 
riser;
    (5) Secure the drilling equipment;
    (6) Transfer the fluids for transport or disposal;
    (7) Secure ancillary equipment like the draw works and lines;
    (8) Refuel or transfer fuel;
    (9) Offload waste;
    (10) Recover the Remotely Operated Vehicles;
    (11) Pick up the oil spill prevention booms and equipment; and
    (12) Offload the drilling crew.
    (c) A description of well-specific drilling objectives, timelines, 
and updated contingency plans for temporary abandonment of the well, 
including but not limited to the following:
    (1) When you will spud the particular well (i.e., begin drilling 
operations at the well site) identified in the APD;
    (2) How long you will take to drill the well;
    (3) Anticipated depths and geologic targets, with timelines;
    (4) When you expect to set and cement each string of casing;
    (5) When and how you would log the well;
    (6) Your plans to test the well;
    (7) When and how you intend to abandon the well, including 
specifically addressing your plans for how to move the rig off location 
and how you will meet the requirements of Sec.  250.720(c);
    (8) A description of what equipment and vessels will be involved in 
the process of temporarily abandoning the well due to ice; and
    (9) An explanation of how you will integrate these elements into 
your overall program.
    (d) A detailed description of your weather and ice forecasting 
capability for all phases of the drilling operation, including:
    (1) How you will ensure your continuous awareness of potential 
weather and ice hazards at, and during transition between, wells;
    (2) Your plans for managing ice hazards and responding to weather 
events; and
    (3) Verification that you have the capabilities described in your 
BOEM-approved EP.
    (e) A detailed description of how you will comply with the 
requirements of Sec.  250.472.
    (f) A statement that you own, or have a contract with a provider 
for, source control and containment equipment (SCCE), which is capable 
of controlling and/or containing a worst case discharge, as described in 
your BOEM-approved EP, when proposing to use a MODU to conduct 
exploratory drilling operations on the Arctic OCS. The following 
information must be included in your SCCE submittal:
    (1) A detailed description of your or your contractor's SCCE 
capability to stop or contain flow from an out-of-control well, 
including your operating assumptions and limitations; your access to and 
ability to deploy, in accordance with Sec.  250.471, all necessary SCCE; 
and your ability to evaluate the performance of the well design to 
determine how you can achieve a full shut-in without having reservoir 
fluids discharged into the environment;
    (2) An inventory of the local and regional SCCE, supplies, and 
services that you own or for which you have a contract with a provider. 
You must identify each supplier of such equipment and services and 
provide their locations and telephone numbers;
    (3) Where applicable, proof of contracts or membership agreements 
with cooperatives, service providers, or other contractors who will 
provide you with the necessary SCCE or related supplies and services if 
you do not possess them. The contract or membership agreement must 
include provisions for ensuring the availability of the personnel and/or 
equipment on a 24-hour per day basis while you are drilling below or 
working below the surface casing;
    (4) A detailed description of the procedures you plan to use to 
inspect, test, and maintain your SCCE; and
    (5) A detailed description of your plan to ensure that all members 
of your operating team, who are responsible for operating the SCCE, have 
received the necessary training to deploy and operate such equipment in 
Arctic

[[Page 119]]

OCS conditions and demonstrate ongoing proficiency in source control 
operations. You must also identify and include the dates of prior and 
planned training.
    (g) Where it does not conflict with other requirements of this 
subpart, and except as provided in paragraphs (g)(1) through (11) of 
this section, you must comply with the requirements of API RP 2N, Third 
Edition ``Planning, Designing, and Constructing Structures and Pipelines 
for Arctic Conditions'' (incorporated by reference as specified in Sec.  
250.198), and provide a detailed description of how you will utilize the 
best practices included in API RP 2N during your exploratory drilling 
operations. You are not required to incorporate the following sections 
of API RP 2N into your drilling operations:
    (1) Sections 6.6.3 through 6.6.4;
    (2) The foundation recommendations in Section 8.4;
    (3) Section 9.6;
    (4) The recommendations for permanently moored systems in Section 
9.7;
    (5) The recommendations for pile foundations in Section 9.10;
    (6) Section 12;
    (7) Section 13.2.1;
    (8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through 
13.8.2.7;
    (9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
    (10) Sections 14 through 16; and
    (11) Section 18.



Sec.  250.471  What are the requirements for Arctic OCS source
 control and containment?

    You must meet the following requirements for all exploration wells 
drilled on the Arctic OCS:
    (a) If you use a MODU when drilling below or working below the 
surface casing, you must have access to the following SCCE capable of 
stopping or capturing the flow of an out-of-control well:
    (1) A capping stack, positioned to ensure that it will arrive at the 
well location within 24 hours after a loss of well control and can be 
deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section;
    (2) A cap and flow system, positioned to ensure that it will arrive 
at the well location within 7 days after a loss of well control and can 
be deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section. The cap and flow system must be designed to capture 
at least the amount of hydrocarbons equivalent to the calculated worst 
case discharge rate referenced in your BOEM-approved EP; and
    (3) A containment dome, positioned to ensure that it will arrive at 
the well location within 7 days after a loss of well control and can be 
deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section. The containment dome must have the capacity to pump 
fluids without relying on buoyancy.
    (b) You must conduct a monthly stump test of dry-stored capping 
stacks. If you use a pre-positioned capping stack, you must conduct a 
stump test prior to each installation on each well.
    (c) As required by Sec.  250.465(a), if you propose to change your 
well design, you must submit an APM. For Arctic OCS operations, your APM 
must include a reevaluation of your SCCE capabilities for any new Worst 
Case Discharge (WCD) rate, and a demonstration that your SCCE 
capabilities will meet the criteria in Sec.  250.470(f) under the 
changed well design.
    (d) You must conduct tests or exercises of your SCCE, including 
deployment of your SCCE, when directed by the Regional Supervisor.
    (e) You must maintain records pertaining to testing, inspection, and 
maintenance of your SCCE for at least 10 years and make the records 
available to any authorized BSEE representative upon request.
    (f) You must maintain records pertaining to the use of your SCCE 
during testing, training, and deployment activities for at least 3 years 
and make the records available to any authorized BSEE representative 
upon request.
    (g) Upon a loss of well control, you must initiate transit of all 
SCCE identified in paragraph (a) of this section to the well.
    (h) You must deploy and use SCCE when directed by the Regional 
Supervisor.
    (i) Operators may request approval of alternate procedures or 
equipment to

[[Page 120]]

the SCCE requirements of subparagraph (a) of this section in accordance 
with Sec.  250.141. The operator must show and document that the 
alternate procedures or equipment will provide a level of safety and 
environmental protection that will meet or exceed the level of safety 
and environmental protection required by BSEE regulations, including 
demonstrating that the alternate procedures or equipment will be capable 
of stopping or capturing the flow of an out-of-control well.



Sec.  250.472  What are the relief rig requirements for the Arctic OCS?

    (a) In the event of a loss of well control, the Regional Supervisor 
may direct you to drill a relief well using the relief rig able to kill 
and permanently plug an out-of-control well as described in your APD. 
Your relief rig must comply with all other requirements of this part 
pertaining to drill rig characteristics and capabilities, and it must be 
able to drill a relief well under anticipated Arctic OCS conditions.
    (b) When you are drilling below or working below the surface casing 
during Arctic OCS exploratory drilling operations, you must have access 
to a relief rig, different from your primary drilling rig, staged in a 
location such that it can arrive on site, drill a relief well, kill and 
abandon the original well, and abandon the relief well prior to expected 
seasonal ice encroachment at the drill site, but no later than 45 days 
after the loss of well control.
    (c) Operators may request approval of alternative compliance 
measures to the relief rig requirement in accordance with Sec.  250.141. 
The operator must show and document that the alternate compliance 
measure will meet or exceed the level of safety and environmental 
protection required by BSEE regulations, including demonstrating that 
the alternate compliance measure will be able to kill and permanently 
plug an out-of-control well.



Sec.  250.473  What must I do to protect health, safety, property,
 and theenvironment while operating on the Arctic OCS?

    In addition to the requirements set forth in Sec.  250.107, when 
conducting exploratory drilling operations on the Arctic OCS, you must 
protect health, safety, property, and the environment by using the 
following:
    (a) Equipment and materials that are rated or de-rated for service 
under conditions that can be reasonably expected during your operations; 
and
    (b) Measures to address human factors associated with weather 
conditions that can be reasonably expected during your operations 
including, but not limited to, provision of proper attire and equipment, 
construction of protected work spaces, and management of shifts.

                            Hydrogen Sulfide



Sec.  250.490  Hydrogen sulfide.

    (a) What precautions must I take when operating in an H2S area? You 
must:
    (1) Take all necessary and feasible precautions and measures to 
protect personnel from the toxic effects of H2S and to 
mitigate damage to property and the environment caused by 
H2S. You must follow the requirements of this section when 
conducting drilling, well-completion/well-workover, and production 
operations in zones with H2S present and when conducting 
operations in zones where the presence of H2S is unknown. You 
do not need to follow these requirements when operating in zones where 
the absence of H2S has been confirmed; and
    (2) Follow your approved contingency plan.
    (b) Definitions. Terms used in this section have the following 
meanings:
    Facility means a vessel, a structure, or an artificial island used 
for drilling, well-completion, well-workover, and/or production 
operations.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means that drilling, logging, coring, testing, or 
producing operations have confirmed the presence

[[Page 121]]

of H2S in concentrations and volumes that could potentially 
result in atmospheric concentrations of 20 ppm or more of 
H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Well-control fluid means drilling mud and completion or workover 
fluid as appropriate to the particular operation being conducted.
    (c) Classifying an area for the presence of H2S. You must:
    (1) Request and obtain an approved classification for the area from 
the Regional Supervisor before you begin operations. Classifications are 
``H2S absent,'' H2S present,'' or ``H2S 
unknown'';
    (2) Submit your request with your application for permit to drill;
    (3) Support your request with available information such as geologic 
and geophysical data and correlations, well logs, formation tests, cores 
and analysis of formation fluids; and
    (4) Submit a request for reclassification of a zone when additional 
data indicate a different classification is needed.
    (d) What do I do if conditions change? If you encounter 
H2S that could potentially result in atmospheric 
concentrations of 20 ppm or more in areas not previously classified as 
having H2S present, you must immediately notify BSEE and 
begin to follow requirements for areas with H2S present.
    (e) What are the requirements for conducting simultaneous 
operations? When conducting any combination of drilling, well-
completion, well-workover, and production operations simultaneously, you 
must follow the requirements in the section applicable to each 
individual operation.
    (f) Requirements for submitting an H2S Contingency Plan. Before you 
begin operations, you must submit an H2S Contingency Plan to 
the District Manager for approval. Do not begin operations before the 
District Manager approves your plan. You must keep a copy of the 
approved plan in the field, and you must follow the plan at all times. 
Your plan must include:
    (1) Safety procedures and rules that you will follow concerning 
equipment, drills, and smoking;
    (2) Training you provide for employees, contractors, and visitors;
    (3) Job position and title of the person responsible for the overall 
safety of personnel;
    (4) Other key positions, how these positions fit into your 
organization, and what the functions, duties, and responsibilities of 
those job positions are;
    (5) Actions that you will take when the concentration of 
H2S in the atmosphere reaches 20 ppm, who will be responsible 
for those actions, and a description of the audible and visual alarms to 
be activated;
    (6) Briefing areas where personnel will assemble during an H2S 
alert. You must have at least two briefing areas on each facility and 
use the briefing area that is upwind of the H2S source at any 
given time;
    (7) Criteria you will use to decide when to evacuate the facility 
and procedures you will use to safely evacuate all personnel from the 
facility by vessel, capsule, or lifeboat. If you use helicopters during 
H2S alerts, describe the types of H2S emergencies 
during which you consider the risk of helicopter activity to be 
acceptable and the precautions you will take during the flights;
    (8) Procedures you will use to safely position all vessels attendant 
to the facility. Indicate where you will locate the vessels with respect 
to wind direction. Include the distance from the facility and what 
procedures you will use to safely relocate the vessels in an emergency;
    (9) How you will provide protective-breathing equipment for all 
personnel, including contractors and visitors;
    (10) The agencies and facilities you will notify in case of a 
release of H2S (that constitutes an emergency), how you will 
notify them, and their telephone numbers. Include all facilities that 
might be exposed to atmospheric concentrations of 20 ppm or more of 
H2S;
    (11) The medical personnel and facilities you will use if needed, 
their addresses, and telephone numbers;
    (12) H2S detector locations in production facilities 
producing gas containing

[[Page 122]]

20 ppm or more of H2S. Include an ``H2S Detector 
Location Drawing'' showing:
    (i) All vessels, flare outlets, wellheads, and other equipment 
handling production containing H2S;
    (ii) Approximate maximum concentration of H2S in the gas 
stream; and
    (iii) Location of all H2S sensors included in your 
contingency plan;
    (13) Operational conditions when you expect to flare gas containing 
H2S including the estimated maximum gas flow rate, 
H2S concentration, and duration of flaring;
    (14) Your assessment of the risks to personnel during flaring and 
what precautionary measures you will take;
    (15) Primary and alternate methods to ignite the flare and 
procedures for sustaining ignition and monitoring the status of the 
flare (i.e., ignited or extinguished);
    (16) Procedures to shut off the gas to the flare in the event the 
flare is extinguished;
    (17) Portable or fixed sulphur dioxide (SO2)-detection 
system(s) you will use to determine SO2 concentration and 
exposure hazard when H2S is burned;
    (18) Increased monitoring and warning procedures you will take when 
the SO2 concentration in the atmosphere reaches 2 ppm;
    (19) Personnel protection measures or evacuation procedures you will 
initiate when the SO2 concentration in the atmosphere reaches 
5 ppm;
    (20) Engineering controls to protect personnel from SO2; 
and
    (21) Any special equipment, procedures, or precautions you will use 
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
    (g) Training program: (1) When and how often do employees need to be 
trained? All operators and contract personnel must complete an 
H2S training program to meet the requirements of this 
section:
    (i) Before beginning work at the facility; and
    (ii) Each year, within 1 year after completion of the previous 
class.
    (2) What training documentation do I need? For each individual 
working on the platform, either:
    (i) You must have documentation of this training at the facility 
where the individual is employed; or
    (ii) The employee must carry a training completion card.
    (3) What training do I need to give to visitors and employees 
previously trained on another facility?
    (i) Trained employees or contractors transferred from another 
facility must attend a supplemental briefing on your H2S 
equipment and procedures before beginning duty at your facility;
    (ii) Visitors who will remain on your facility more than 24 hours 
must receive the training required for employees by paragraph (g)(4) of 
this section; and
    (iii) Visitors who will depart before spending 24 hours on the 
facility are exempt from the training required for employees, but they 
must, upon arrival, complete a briefing that includes:
    (A) Information on the location and use of an assigned respirator; 
practice in donning and adjusting the assigned respirator; information 
on the safe briefing areas, alarm system, and hazards of H2S 
and SO2; and
    (B) Instructions on their responsibilities in the event of an 
H2S release.
    (4) What training must I provide to all other employees? You must 
train all individuals on your facility on the:
    (i) Hazards of H2S and of SO2 and the 
provisions for personnel safety contained in the H2S 
Contingency Plan;
    (ii) Proper use of safety equipment which the employee may be 
required to use;
    (iii) Location of protective breathing equipment, H2S 
detectors and alarms, ventilation equipment, briefing areas, warning 
systems, evacuation procedures, and the direction of prevailing winds;
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (as specified in Sec.  
250.198);
    (v) Basic first-aid procedures applicable to victims of 
H2S exposure. During all drills and training sessions, you 
must address procedures for rescue and first aid for H2S 
victims;
    (vi) Location of:

[[Page 123]]

    (A) The first-aid kit on the facility;
    (B) Resuscitators; and
    (C) Litter or other device on the facility.
    (vii) Meaning of all warning signals.
    (5) Do I need to post safety information? You must prominently post 
safety information on the facility and on vessels serving the facility 
(i.e., basic first-aid, escape routes, instructions for use of life 
boats, etc.).
    (h) Drills. (1) When and how often do I need to conduct drills on 
H2S safety discussions on the facility? You must:
    (i) Conduct a drill for each person at the facility during normal 
duty hours at least once every 7-day period. The drills must consist of 
a dry-run performance of personnel activities related to assigned jobs.
    (ii) At a safety meeting or other meetings of all personnel, discuss 
drill performance, new H2S considerations at the facility, 
and other updated H2S information at least monthly.
    (2) What documentation do I need? You must keep records of 
attendance for:
    (i) Drilling, well-completion, and well-workover operations at the 
facility until operations are completed; and
    (ii) Production operations at the facility or at the nearest field 
office for 1 year.
    (i) Visual and audible warning systems: (1) How must I install wind 
direction equipment? You must install wind-direction equipment in a 
location visible at all times to individuals on or in the immediate 
vicinity of the facility.
    (2) When do I need to display operational danger signs, display 
flags, or activate visual or audible alarms?
    (i) You must display warning signs at all times on facilities with 
wells capable of producing H2S and on facilities that process 
gas containing H2S in concentrations of 20 ppm or more.
    (ii) In addition to the signs, you must activate audible alarms and 
display flags or activate flashing red lights when atmospheric 
concentration of H2S reaches 20 ppm.
    (3) What are the requirements for signs? Each sign must be a high-
visibility yellow color with black lettering as follows:

------------------------------------------------------------------------
               Letter height                           Wording
------------------------------------------------------------------------
12 inches.................................  Danger.
                                            Poisonous Gas.
                                            Hydrogen Sulfide.
7 inches..................................  Do not approach if red flag
                                             is flying.
(Use appropriate wording at right)........  Do not approach if red
                                             lights are flashing.
------------------------------------------------------------------------

    (4) May I use existing signs? You may use existing signs containing 
the words ``Danger-Hydrogen Sulfide-H2S,'' provided the words 
``Poisonous Gas. Do Not Approach if Red Flag is Flying'' or ``Red Lights 
are Flashing'' in lettering of a minimum of 7 inches in height are 
displayed on a sign immediately adjacent to the existing sign.
    (5) What are the requirements for flashing lights or flags? You must 
activate a sufficient number of lights or hoist a sufficient number of 
flags to be visible to vessels and aircraft. Each light must be of 
sufficient intensity to be seen by approaching vessels or aircraft any 
time it is activated (day or night). Each flag must be red, rectangular, 
a minimum width of 3 feet, and a minimum height of 2 feet.
    (6) What is an audible warning system? An audible warning system is 
a public address system or siren, horn, or other similar warning device 
with a unique sound used only for H2S.
    (7) Are there any other requirements for visual or audible warning 
devices? Yes, you must:
    (i) Illuminate all signs and flags at night and under conditions of 
poor visibility; and
    (ii) Use warning devices that are suitable for the electrical 
classification of the area.
    (8) What actions must I take when the alarms are activated? When the 
warning devices are activated, the designated responsible persons must 
inform personnel of the level of danger and issue instructions on the 
initiation of appropriate protective measures.
    (j) H2S-detection and H2S monitoring 
equipment: (1) What are the requirements for an H2S detection 
system? An H2S detection system must:
    (i) Be capable of sensing a minimum of 10 ppm of H2S in 
the atmosphere; and
    (ii) Activate audible and visual alarms when the concentration of 
H2S in the atmosphere reaches 20 ppm.

[[Page 124]]

    (2) Where must I have sensors for drilling, well-completion, and 
well-workover operations? You must locate sensors at the:
    (i) Bell nipple;
    (ii) Mud-return line receiver tank (possum belly);
    (iii) Pipe-trip tank;
    (iv) Shale shaker;
    (v) Well-control fluid pit area;
    (vi) Driller's station;
    (vii) Living quarters; and
    (viii) All other areas where H2S may accumulate.
    (3) Do I need mud sensors? The District Manager may require mud 
sensors in the possum belly in cases where the ambient air sensors in 
the mud-return system do not consistently detect the presence of 
H2S.
    (4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe 
the H2S levels indicated by the monitors in the work areas 
during the following operations:
    (i) When you pull a wet string of drill pipe or workover string;
    (ii) When circulating bottoms-up after a drilling break;
    (iii) During cementing operations;
    (iv) During logging operations; and
    (v) When circulating to condition mud or other well-control fluid.
    (5) Where must I have sensors for production operations? On a 
platform where gas containing H2S of 20 ppm or greater is 
produced, processed, or otherwise handled:
    (i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this 
section, where atmospheric concentrations of H2S could reach 
20 ppm or more. You must have at least one sensor per 400 square feet of 
deck area or fractional part of 400 square feet;
    (ii) You must have a sensor in buildings where personnel have their 
living quarters;
    (iii) You must have a sensor within 10 feet of each vessel, 
compressor, wellhead, manifold, or pump, which could release enough 
H2S to result in atmospheric concentrations of 20 ppm at a 
distance of 10 feet from the component;
    (iv) You may use one sensor to detect H2S around multiple 
pieces of equipment, provided the sensor is located no more than 10 feet 
from each piece, except that you need to use at least two sensors to 
monitor compressors exceeding 50 horsepower;
    (v) You do not need to have sensors near wells that are shut in at 
the master valve and sealed closed;
    (vi) When you determine where to place sensors, you must consider:
    (A) The location of system fittings, flanges, valves, and other 
devices subject to leaks to the atmosphere; and
    (B) Design factors, such as the type of decking and the location of 
fire walls; and
    (vii) The District Manager may require additional sensors or other 
monitoring capabilities, if warranted by site specific conditions.
    (6) How must I functionally test the H2S Detectors? (i) Personnel 
trained to calibrate the particular H2S detector equipment 
being used must test detectors by exposing them to a known concentration 
in the range of 10 to 30 ppm of H2S.
    (ii) If the results of any functional test are not within 2 ppm or 
10 percent, whichever is greater, of the applied concentration, 
recalibrate the instrument.
    (7) How often must I test my detectors? (i) When conducting 
drilling, drill stem testing, well-completion, or well-workover 
operations in areas classified as H2S present or 
H2S unknown, test all detectors at least once every 24 hours. 
When drilling, begin functional testing before the bit is 1,500 feet 
(vertically) above the potential H2S zone.
    (ii) When conducting production operations, test all detectors at 
least every 14 days between tests.
    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Manager may require that 
H2S-detection and H2S-monitoring equipment be 
functionally tested and calibrated more frequently.
    (8) What documentation must I keep? (i) You must maintain records of 
testing and calibrations (in the drilling or production operations 
report, as applicable) at the facility to show the present status and 
history of each device, including dates and details concerning:

[[Page 125]]

    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by BSEE personnel.
    (9) What are the requirements for nearby vessels? If vessels are 
stationed overnight alongside facilities in areas of H2S 
present or H2S unknown, you must equip vessels with an 
H2S-detection system that activates audible and visual alarms 
when the concentration of H2S in the atmosphere reaches 20 
ppm. This requirement does not apply to vessels positioned upwind and at 
a safe distance from the facility in accordance with the positioning 
procedure described in the approved H2S Contingency Plan.
    (10) What are the requirements for nearby facilities? The District 
Manager may require you to equip nearby facilities with portable or 
fixed H2S detector(s) and to test and calibrate those 
detectors. To invoke this requirement, the District Manager will 
consider dispersion modeling results from a possible release to 
determine if 20 ppm H2S concentration levels could be 
exceeded at nearby facilities.
    (11) What must I do to protect against SO2 if I burn gas containing 
H2S? You must:
    (i) Monitor the SO2concentration in the air with portable 
or strategically placed fixed devices capable of detecting a minimum of 
2 ppm of SO2;
    (ii) Take readings at least hourly and at any time personnel detect 
SO2 odor or nasal irritation;
    (iii) Implement the personnel protective measures specified in the 
H2S Contingency Plan if the SO2 concentration in 
the work area reaches 2 ppm; and
    (iv) Calibrate devices every 3 months if you use fixed or portable 
electronic sensing devices to detect SO2.
    (12) May I use alternative measures? You may follow alternative 
measures instead of those in paragraph (j)(11) of this section if you 
propose and the Regional Supervisor approves the alternative measures.
    (13) What are the requirements for protective-breathing equipment? 
In an area classified as H2S present or H2S 
unknown, you must:
    (i) Provide all personnel, including contractors and visitors on a 
facility, with immediate access to self-contained pressure-demand-type 
respirators with hoseline capability and breathing time of at least 15 
minutes.
    (ii) Design, select, use, and maintain respirators in conformance 
with ANSI Z88.2 (as specified in Sec.  250.198).
    (iii) Make available at least two voice-transmission devices, which 
can be used while wearing a respirator, for use by designated personnel.
    (iv) Make spectacle kits available as needed.
    (v) Store protective-breathing equipment in a location that is 
quickly and easily accessible to all personnel.
    (vi) Label all breathing-air bottles as containing breathing-quality 
air for human use.
    (vii) Ensure that vessels attendant to facilities carry appropriate 
protective-breathing equipment for each crew member. The District 
Manager may require additional protective-breathing equipment on certain 
vessels attendant to the facility.
    (viii) During H2S alerts, limit helicopter flights to and 
from facilities to the conditions specified in the H2S 
Contingency Plan. During authorized flights, the flight crew and 
passengers must use pressure-demand-type respirators. You must train all 
members of flight crews in the use of the particular type(s) of 
respirator equipment made available.
    (ix) As appropriate to the particular operation(s), (production, 
drilling, well-completion or well-workover operations, or any 
combination of them), provide a system of breathing-air manifolds, 
hoses, and masks at the facility and the briefing areas. You must 
provide a cascade air-bottle system for the breathing-air manifolds to 
refill individual protective-breathing apparatus bottles. The cascade 
air-bottle system may be recharged by a high-pressure compressor 
suitable for providing breathing-quality air, provided the compressor 
suction is located in an uncontaminated atmosphere.
    (k) Personnel safety equipment: (1) What additional personnel-safety

[[Page 126]]

equipment do I need? You must ensure that your facility has:
    (i) Portable H2S detectors capable of detecting a 10 ppm 
concentration of H2S in the air available for use by all 
personnel;
    (ii) Retrieval ropes with safety harnesses to retrieve incapacitated 
personnel from contaminated areas;
    (iii) Chalkboards and/or note pads for communication purposes 
located on the rig floor, shale-shaker area, the cement-pump rooms, 
well-bay areas, production processing equipment area, gas compressor 
area, and pipeline-pump area;
    (iv) Bull horns and flashing lights; and
    (v) At least three resuscitators on manned facilities, and a number 
equal to the personnel on board, not to exceed three, on normally 
unmanned facilities, complete with face masks, oxygen bottles, and spare 
oxygen bottles.
    (2) What are the requirements for ventilation equipment? You must:
    (i) Use only explosion-proof ventilation devices;
    (ii) Install ventilation devices in areas where H2S or 
SO2 may accumulate; and
    (iii) Provide movable ventilation devices in work areas. The movable 
ventilation devices must be multidirectional and capable of dispersing 
H2S or SO2 vapors away from working personnel.
    (3) What other personnel safety equipment do I need? You must have 
the following equipment readily available on each facility:
    (i) A first-aid kit of appropriate size and content for the number 
of personnel on the facility; and
    (ii) At least one litter or an equivalent device.
    (l) Do I need to notify BSEE in the event of an H2S release? You 
must notify BSEE without delay in the event of a gas release which 
results in a 15-minute time-weighted average atmospheric concentration 
of H2S of 20 ppm or more anywhere on the OCS facility. You 
must report these gas releases to the District Manager immediately by 
oral communication, with a written follow-up report within 15 days, 
pursuant to Sec. Sec.  250.188 through 250.190.
    (m) Do I need to use special drilling, completion and workover 
fluids or procedures? When working in an area classified as 
H2S present or H2S unknown:
    (1) You may use either water- or oil-base muds in accordance with 
Sec.  250.300(b)(1).
    (2) If you use water-base well-control fluids, and if ambient air 
sensors detect H2S, you must immediately conduct either the 
Garrett-Gas-Train test or a comparable test for soluble sulfides to 
confirm the presence of H2S.
    (3) If the concentration detected by air sensors in over 20 ppm, 
personnel conducting the tests must don protective-breathing equipment 
conforming to paragraph (j)(13) of this section.
    (4) You must maintain on the facility sufficient quantities of 
additives for the control of H2S, well-control fluid pH, and 
corrosion equipment.
    (i) Scavengers. You must have scavengers for control of 
H2S available on the facility. When H2S is 
detected, you must add scavengers as needed. You must suspend drilling 
until the scavenger is circulated throughout the system.
    (ii) Control pH. You must add additives for the control of pH to 
water-base well-control fluids in sufficient quantities to maintain pH 
of at least 10.0.
    (iii) Corrosion inhibitors. You must add additives to the well-
control fluid system as needed for the control of corrosion.
    (5) You must degas well-control fluids containing H2S at 
the optimum location for the particular facility. You must collect the 
gases removed and burn them in a closed flare system conforming to 
paragraph (q)(6) of this section.
    (n) What must I do in the event of a kick? In the event of a kick, 
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible 
environmental damage, and possible facility well-equipment damage:
    (1) Contain the well-fluid influx by shutting in the well and 
pumping the fluids back into the formation.
    (2) Control the kick by using appropriate well-control techniques to 
prevent formation fracturing in an open hole within the pressure limits 
of the

[[Page 127]]

well equipment (drill pipe, work string, casing, wellhead, BOP system, 
and related equipment). The disposal of H2S and other gases 
must be through pressurized or atmospheric mud-separator equipment 
depending on volume, pressure and concentration of H2S. The 
equipment must be designed to recover well-control fluids and burn the 
gases separated from the well-control fluid. The well-control fluid must 
be treated to neutralize H2S and restore and maintain the 
proper quality.
    (o) Well testing in a zone known to contain H2S. When testing a well 
in a zone with H2S present, you must do all of the following:
    (1) Before starting a well test, conduct safety meetings for all 
personnel who will be on the facility during the test. At the meetings, 
emphasize the use of protective-breathing equipment, first-aid 
procedures, and the Contingency Plan. Only competent personnel who are 
trained and are knowledgeable of the hazardous effects of H2S 
must be engaged in these tests.
    (2) Perform well testing with the minimum number of personnel in the 
immediate vicinity of the rig floor and with the appropriate test 
equipment to safely and adequately perform the test. During the test, 
you must continuously monitor H2S levels.
    (3) Not burn produced gases except through a flare which meets the 
requirements of paragraph (q)(6) of this section. Before flaring gas 
containing H2S, you must activate SO2 monitoring 
equipment in accordance with paragraph (j)(11) of this section. If you 
detect SO2 in excess of 2 ppm, you must implement the 
personnel protective measures in your H2S Contingency Plan, 
required by paragraph (f) of this section. You must also follow the 
requirements of Sec.  250.1164. You must pipe gases from stored test 
fluids into the flare outlet and burn them.
    (4) Use downhole test tools and wellhead equipment suitable for 
H2S service.
    (5) Use tubulars suitable for H2S service. You must not 
use drill pipe for well testing without the prior approval of the 
District Manager. Water cushions must be thoroughly inhibited in order 
to prevent H2S attack on metals. You must flush the test 
string fluid treated for this purpose after completion of the test.
    (6) Use surface test units and related equipment that is designed 
for H2S service.
    (p) Metallurgical properties of equipment. When operating in a zone 
with H2S present, you must use equipment that is constructed 
of materials with metallurgical properties that resist or prevent 
sulfide stress cracking (also known as hydrogen embrittlement, stress 
corrosion cracking, or H2S embrittlement), chloride-stress 
cracking, hydrogen-induced cracking, and other failure modes. You must 
do all of the following:
    (1) Use tubulars and other equipment, casing, tubing, drill pipe, 
couplings, flanges, and related equipment that is designed for 
H2S service.
    (2) Use BOP system components, wellhead, pressure-control equipment, 
and related equipment exposed to H2S-bearing fluids in 
conformance with NACE Standard MR0175-03 (as specified in Sec.  
250.198).
    (3) Use temporary downhole well-security devices such as retrievable 
packers and bridge plugs that are designed for H2S service.
    (4) When producing in zones bearing H2S, use equipment 
constructed of materials capable of resisting or preventing sulfide 
stress cracking.
    (5) Keep the use of welding to a minimum during the installation or 
modification of a production facility. Welding must be done in a manner 
that ensures resistance to sulfide stress cracking.
    (q) General requirements when operating in an H2S zone: (1) Coring 
operations. When you conduct coring operations in H2S-bearing 
zones, all personnel in the working area must wear protective-breathing 
equipment at least 10 stands in advance of retrieving the core barrel. 
Cores to be transported must be sealed and marked for the presence of 
H2S.
    (2) Logging operations. You must treat and condition well-control 
fluid in use for logging operations to minimize the effects of 
H2S on the logging equipment.
    (3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-

[[Page 128]]

breathing equipment in the working area when the atmospheric 
concentration of H2S reaches 20 ppm or if the well is under 
pressure.
    (4) Gas-cut well-control fluid or well kick from H2S-bearing zone. 
If you decide to circulate out a kick, personnel in the working area 
during bottoms-up and extended-kill operations must wear protective-
breathing equipment.
    (5) Drill- and workover-string design and precautions. Drill- and 
workover-strings must be designed consistent with the anticipated depth, 
conditions of the hole, and reservoir environment to be encountered. You 
must minimize exposure of the drill- or workover-string to high stresses 
as much as practical and consistent with well conditions. Proper 
handling techniques must be taken to minimize notching and stress 
concentrations. Precautions must be taken to minimize stresses caused by 
doglegs, improper stiffness ratios, improper torque, whip, abrasive wear 
on tool joints, and joint imbalance.
    (6) Flare system. The flare outlet must be of a diameter that allows 
easy nonrestricted flow of gas. You must locate flare line outlets on 
the downside of the facility and as far from the facility as is 
feasible, taking into account the prevailing wind directions, the wake 
effects caused by the facility and adjacent structure(s), and the height 
of all such facilities and structures. You must equip the flare outlet 
with an automatic ignition system including a pilot-light gas source or 
an equivalent system. You must have alternate methods for igniting the 
flare. You must pipe to the flare system used for H2S all 
vents from production process equipment, tanks, relief valves, burst 
plates, and similar devices.
    (7) Corrosion mitigation. You must use effective means of monitoring 
and controlling corrosion caused by acid gases (H2S and 
CO2) in both the downhole and surface portions of a 
production system. You must take specific corrosion monitoring and 
mitigating measures in areas of unusually severe corrosion where 
accumulation of water and/or higher concentration of H2S 
exists.
    (8) Wireline lubricators. Lubricators which may be exposed to fluids 
containing H2S must be of H2S-resistant materials.
    (9) Fuel and/or instrument gas. You must not use gas containing 
H2S for instrument gas. You must not use gas containing 
H2S for fuel gas without the prior approval of the District 
Manager.
    (10) Sensing lines and devices. Metals used for sensing line and 
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion resistant 
materials or coated so as to resist H2S corrosion.
    (11) Elastomer seals. You must use H2S-resistant 
materials for all seals which may be exposed to fluids containing 
H2S.
    (12) Water disposal. If you dispose of produced water by means other 
than subsurface injection, you must submit to the District Manager an 
analysis of the anticipated H2S content of the water at the 
final treatment vessel and at the discharge point. The District Manager 
may require that the water be treated for removal of H2S. The 
District Manager may require the submittal of an updated analysis if the 
water disposal rate or the potential H2S content increases.
    (13) Deck drains. You must equip open deck drains with traps or 
similar devices to prevent the escape of H2S gas into the 
atmosphere.
    (14) Sealed voids. You must take precautions to eliminate sealed 
spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which 
can be invaded by atomic hydrogen when H2S is present.



            Subpart E_Oil and Gas Well-Completion Operations



Sec.  250.500  General requirements.

    Well-completion operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the OCS, including any mineral deposits 
(in areas leased and not leased), the National security or defense, or 
the marine, coastal, or human environment. In addition to the 
requirements of this subpart,

[[Page 129]]

you must also follow the applicable requirements of subpart G of this 
part.

[81 FR 26021, Apr. 29, 2016]



Sec.  250.501  Definition.

    When used in this subpart, the following term shall have the meaning 
given below:
    Well-completion operations means the work conducted to establish the 
production of a well after the production-casing string has been set, 
cemented, and pressure-tested.



Sec.  250.502  [Reserved]



Sec.  250.503  Emergency shutdown system.

    When well-completion operations are conducted on a platform where 
there are other hydrocarbon-producing wells or other hydrocarbon flow, 
an emergency shutdown system (ESD) manually controlled station shall be 
installed near the driller's console or well-servicing unit operator's 
work station.



Sec.  250.504  Hydrogen sulfide.

    When a well-completion operation is conducted in zones known to 
contain hydrogen sulfide (H2S) or in zones where the presence 
of H2S is unknown (as defined in Sec.  250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or completion unit, including, but not limited 
to operations such as blowing the well down, dismantling wellhead 
equipment and flow lines, circulating the well, swabbing, and pulling 
tubing, pumps, and packers. The lessee shall comply with the 
requirements in Sec.  250.490 of this part as well as the appropriate 
requirements of this subpart.



Sec.  250.505  Subsea completions.

    No subsea well completion shall be commenced until the lessee 
obtains written approval from the District Manager in accordance with 
Sec.  250.513 of this part. That approval shall be based upon a case-by-
case determination that the proposed equipment and procedures will 
adequately control the well and permit safe production operations.



Sec. Sec.  250.506-250.508  [Reserved]



Sec.  250.509  Well-completion structures on fixed platforms.

    Derricks, masts, substructures, and related equipment shall be 
selected, designed, installed, used, and maintained so as to be adequate 
for the potential loads and conditions of loading that may be 
encountered during the proposed operations. Prior to moving a well-
completion rig or equipment onto a platform, the lessee shall determine 
the structural capability of the platform to safely support the 
equipment and proposed operations, taking into consideration the 
corrosion protection, age of platform, and previous stresses to the 
platform.



Sec.  250.510  Diesel engine air intakes.

    Diesel engine air intakes must be equipped with a device to shut 
down the diesel engine in the event of runaway. Diesel engines that are 
continuously attended must be equipped with either remote operated 
manual or automatic-shutdown devices. Diesel engines that are not 
continuously attended must be equipped with automatic-shutdown devices.



Sec.  250.511  Traveling-block safety device.

    All units being used for well-completion operations that have both a 
traveling block and a crown block must be equipped with a safety device 
that is designed to prevent the traveling block from striking the crown 
block. The device must be checked for proper operation weekly and after 
each drill-line slipping operation. The results of the operational check 
must be entered in the operations log.



Sec.  250.512  Field well-completion rules.

    When geological and engineering information available in a field 
enables the District Manager to determine specific operating 
requirements, field well-completion rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-completion rules have been established, well-completion 
operations in the field shall be conducted in

[[Page 130]]

accordance with such rules and other requirements of this subpart. Field 
well-completion rules may be amended or canceled for cause at any time 
upon the initiative of the District Manager or upon the request of a 
lessee.



Sec.  250.513  Approval and reporting of well-completion operations.

    (a) No well-completion operation may begin until the lessee receives 
written approval from the District Manager. If completion is planned and 
the data are available at the time you submit the Application for Permit 
to Drill and Supplemental APD Information Sheet (Forms BSEE-0123 and 
BSEE-0123S), you may request approval for a well-completion on those 
forms (see Sec. Sec.  250.410 through 250.418 of this part). If the 
District Manager has not approved the completion or if the completion 
objective or plans have significantly changed, you must submit an 
Application for Permit to Modify (Form BSEE-0124) for approval of such 
operations.
    (b) You must submit the following with Form BSEE-0124 (or with Form 
BSEE-0123; Form BSEE-0123S):
    (1) A brief description of the well-completion procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of completion fluids;
    (2) A schematic drawing of the well showing the proposed producing 
zone(s) and the subsurface well-completion equipment to be used;
    (3) For multiple completions, a partial electric log showing the 
zones proposed for completion, if logs have not been previously 
submitted;
    (4) All applicable information required in Sec.  250.731.
    (5) When the well-completion is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown, information pursuant to Sec.  250.490 of this part; and
    (6) Payment of the service fee listed in Sec.  250.125.
    (c) Within 30 days after completion, you must submit to the District 
Manager an End of Operations Report (Form BSEE-0125), including a 
schematic of the tubing and subsurface equipment.
    (d) You must submit public information copies of Form BSEE-0125 
according to Sec.  250.186.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]



Sec.  250.514  Well-control fluids, equipment, and operations.

    (a) Well-control fluids, equipment, and operations shall be 
designed, utilized, maintained, and/or tested as necessary to control 
the well in foreseeable conditions and circumstances, including 
subfreezing conditions. The well shall be continuously monitored during 
well-completion operations and shall not be left unattended at any time 
unless the well is shut in and secured.
    (b) The following well-control-fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP;
    (2) A well-control, fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips; and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.
    (c) When coming out of the hole with drill pipe, the annulus shall 
be filled with well-control fluid before the change in such fluid level 
decreases the hydrostatic pressure 75 pounds per square inch (psi) or 
every five stands of drill pipe, whichever gives a lower decrease in 
hydrostatic pressure. The number of stands of drill pipe and drill 
collars that may be pulled prior to filling the hole and the equivalent 
well-control fluid volume shall be calculated and posted near the 
operator's station. A mechanical, volumetric, or electronic device for 
measuring the amount of well-control fluid required to fill the hole 
shall be utilized.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]

[[Page 131]]



Sec. Sec.  250.515-250.517  [Reserved]



Sec.  250.518  Tubing and wellhead equipment.

    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) When the tree is installed, you must equip wells to monitor for 
casing pressure according to the following chart:

------------------------------------------------------------------------
     If you . . .        you must equip . . .   so you can monitor . . .
------------------------------------------------------------------------
(1) fixed platform      the wellhead,          all annuli (A, B, C, D,
 wells,                                         etc., annuli).
(2) subsea wells,       the tubing head,       the production casing
                                                annulus (A annulus).
(3) hybrid * wells,     the surface wellhead,  all annuli at the surface
                                                (A and B riser annuli).
                                                If the production casing
                                                below the mudline and
                                                the production casing
                                                riser above the mudline
                                                are pressure isolated
                                                from each other,
                                                provisions must be made
                                                to monitor the
                                                production casing below
                                                the mudline for casing
                                                pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
  with a surface casing head, a surface tubing head, a surface tubing
  hanger, and a surface christmas tree.

    (c) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. New wells completed as flowing or gas-lift wells shall 
be equipped with a minimum of one master valve and one surface safety 
valve, installed above the master valve, in the vertical run of the 
tree.
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839.
    (e) When installed, packers and bridge plugs must meet the 
following:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec.  250.198);
    (2) The production packer must be set at a depth that will allow for 
a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and
    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.
    (f) Your APM must include a description and calculations for how you 
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.518 was 
amended by revising paragraph (e)(1) and adding new paragraph (g), 
effective July 15, 2019. For the convenience of the user, the added and 
revised text is set forth as follows:



Sec.  250.518  Tubing and wellhead equipment.

                                * * * * *

    (e) * * *
    (1) The uppermost permanently installed packer and all permanently 
installed bridge plugs qualified as mechanical barriers must comply with 
ANSI/API Spec. 11D1 (as incorporated by reference in Sec.  250.198);

                                * * * * *

    (g) You must have two independent barriers, one being mechanical, in 
the exposed center wellbore prior to removing the tree and/or well 
control equipment.

                       Casing Pressure Management



Sec.  250.519  What are the requirements for casing pressure management?

    Once you install your wellhead, you must meet the casing pressure 
management requirements of API RP 90 (as incorporated by reference in 
Sec.  250.198) and the requirements of Sec. Sec.  250.519 through 
250.530. If there is a conflict between API RP 90 and the casing 
pressure requirements of this subpart, you must

[[Page 132]]

follow the requirements of this subpart.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.519 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.519  What are the requirements for casing pressure management?

    Once you install your wellhead, you must meet the casing pressure 
management requirements of API RP 90 (as incorporated by reference in 
Sec.  250.198) and the requirements of Sec. Sec.  250.519 through 
250.531. If there is a conflict between API RP 90 and the casing 
pressure requirements of this subpart, you must follow the requirements 
of this subpart.



Sec.  250.520  How often do I have to monitor for casing pressure?

    You must monitor for casing pressure in your well according to the 
following table:

----------------------------------------------------------------------------------------------------------------
                                                                                with a minimum one pressure data
               If you have . . .                    you must monitor . . .          point recorded per . . .
----------------------------------------------------------------------------------------------------------------
(a) fixed platform wells,                       monthly,                       month for each casing.
(b) subsea wells,                               continuously,                  day for the production casing.
(c) hybrid wells,                               continuously,                  day for each riser and/or the
                                                                                production casing.
(d) wells operating under a casing pressure     daily,                         day for each casing.
 request on a manned fixed platform,
(e) wells operating under a casing pressure     weekly,                        week for each casing.
 request on an unmanned fixed platform,
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.521  When do I have to perform a casing diagnostic test?

    (a) You must perform a casing diagnostic test within 30 days after 
first observing or imposing casing pressure according to the following 
table:

------------------------------------------------------------------------
                                              you must perform a casing
            If you have a . . .               diagnostic test if . . .
------------------------------------------------------------------------
(1) fixed platform well,                    the casing pressure is
                                             greater than 100 psig.
(2) subsea well,                            the measurable casing
                                             pressure is greater than
                                             the external hydrostatic
                                             pressure plus 100 psig
                                             measured at the subsea
                                             wellhead.
(3) hybrid well,                            a riser or the production
                                             casing pressure is greater
                                             than 100 psig measured at
                                             the surface.
------------------------------------------------------------------------

    (b) You are exempt from performing a diagnostic pressure test for 
the production casing on a well operating under active gas lift.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.522  How do I manage the thermal effects caused by initial production on a newly completed or recompleted well?

    A newly completed or recompleted well often has thermal casing 
pressure during initial startup. Bleeding casing pressure during the 
startup process is considered a normal and necessary operation to manage 
thermal casing pressure; therefore, you do not need to evaluate these 
operations as a casing diagnostic test. After 30 days of continuous 
production, the initial production startup operation is complete and you 
must perform casing diagnostic testing as required in Sec. Sec.  250.520 
and 250.522.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.522 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.522  How do I manage the thermal effects caused by initial 
          production on a newly completed or recompleted well?

    A newly completed or recompleted well often has thermal casing 
pressure during initial startup. Bleeding casing pressure during

[[Page 133]]

the startup process is considered a normal and necessary operation to 
manage thermal casing pressure; therefore, you do not need to evaluate 
these operations as a casing diagnostic test. After 30 days of 
continuous production, the initial production startup operation is 
complete and you must perform casing diagnostic testing as required in 
Sec. Sec.  250.521 and 250.523.



Sec.  250.523  When do I have to repeat casing diagnostic testing?

    Casing diagnostic testing must be repeated according to the 
following table:

------------------------------------------------------------------------
                                             you must repeat diagnostic
                When . . .                          testing . . .
------------------------------------------------------------------------
(a) your casing pressure request approved   immediately.
 term has expired,
(b) your well, previously on gas lift, has  immediately on the
 been shut-in or returned to flowing         production casing (A
 status without gas lift for more than 180   annulus). The production
 days,                                       casing (A annulus) of wells
                                             on active gas lift are
                                             exempt from diagnostic
                                             testing.
(c) your casing pressure request becomes    within 30 days.
 invalid,
(d) a casing or riser has an increase in    within 30 days.
 pressure greater than 200 psig over the
 previous casing diagnostic test,
(e) after any corrective action has been    within 30 days.
 taken to remediate undesirable casing
 pressure, either as a result of a casing
 pressure request denial or any other
 action,
(f) your fixed platform well production     once per year, not to exceed
 casing (A annulus) has pressure exceeding   12 months between tests.
 10 percent of its minimum internal yield
 pressure (MIYP), except for production
 casings on active gas lift,
(g) your fixed platform well's outer        once every 5 years, at a
 casing (B, C, D, etc., annuli) has a        minimum.
 pressure exceeding 20 percent of its
 MIYP,
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.524  How long do I keep records of casing pressure
 and diagnostic tests?

    Records of casing pressure and diagnostic tests must be kept at the 
field office nearest the well for a minimum of 2 years. The last casing 
diagnostic test for each casing or riser must be retained at the field 
office nearest the well until the well is abandoned.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.525  When am I required to take action from my casing
diagnostic test?

    You must take action if you have any of the following conditions:
    (a) Any fixed platform well with a casing pressure exceeding its 
maximum allowable wellhead operating pressure (MAWOP);
    (b) Any fixed platform well with a casing pressure that is greater 
than 100 psig and that cannot bleed to 0 psig through a \1/2\-inch 
needle valve within 24 hours, or is not bled to 0 psig during a casing 
diagnostic test;
    (c) Any well that has demonstrated tubing/casing, tubing/riser, 
casing/casing, riser/casing, or riser/riser communication;
    (d) Any well that has sustained casing pressure (SCP) and is bled 
down to prevent it from exceeding its MAWOP, except during initial 
startup operations described in Sec.  250.521;
    (e) Any hybrid well with casing or riser pressure exceeding 100 
psig; or
    (f) Any subsea well with a casing pressure 100 psig greater than the 
external hydrostatic pressure at the subsea wellhead.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.525 was 
amended by revising paragraph (d), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.525  When am I required to take action from my casing 
          diagnostic test?

                                * * * * *

    (d) Any well that has sustained casing pressure (SCP) and is bled 
down to prevent it from exceeding its MAWOP, except during

[[Page 134]]

initial startup operations described in Sec.  250.522;

                                * * * * *



Sec.  250.526  What do I submit if my casing diagnostic test 
requires action?

    Within 14 days after you perform a casing diagnostic test requiring 
action under Sec.  250.524:

----------------------------------------------------------------------------------------------------------------
You must submit either . .                              and it must include . . .
             .               to the appropriate . . .                                   You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of       District Manager and copy   requirements under Sec.    submit an Application for
 corrective action; or,      the Regional Supervisor,    250.526,                   Permit to Modify or
                             Field Operations,                                      Corrective Action Plan
                                                                                    within 30 days of the
                                                                                    diagnostic test.
(b) a casing pressure       Regional Supervisor, Field  requirements under Sec.    .............................
 request,                    Operations,                 250.527.
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.526 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.526  What do I submit if my casing diagnostic test requires action?

    Within 14 days after you perform a casing diagnostic test requiring 
action under Sec.  250.525:

----------------------------------------------------------------------------------------------------------------
You must submit either . .                              and it must include . . .
             .               to the appropriate . . .                                   You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of       District Manager and copy   requirements under Sec.    submit an Application for
 corrective action; or,      the Regional Supervisor,    250.527,                   Permit to Modify or
                             Field Operations,                                      Corrective Action Plan
                                                                                    within 30 days of the
                                                                                    diagnostic test.
(b) a casing pressure       Regional Supervisor, Field  requirements under Sec.    .............................
 request,                    Operations,                 250.528.
----------------------------------------------------------------------------------------------------------------



Sec.  250.527  What must I include in my notification of corrective action?

    The following information must be included in the notification of 
corrective action:
    (a) Lessee or Operator name;
    (b) Area name and OCS block number;
    (c) Well name and API number; and
    (d) Casing diagnostic test data.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.528  What must I include in my casing pressure request?

    The following information must be included in the casing pressure 
request:
    (a) API number;
    (b) Lease number;
    (c) Area name and OCS block number;
    (d) Well number;
    (e) Company name and mailing address;
    (f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
    (g) All casing/riser calculated MAWOPs;
    (h) All casing/riser pre-bleed down pressures;
    (i) Shut-in tubing pressure;
    (j) Flowing tubing pressure;
    (k) Date and the calculated daily production rate during last well 
test (oil, gas, basic sediment, and water);
    (l) Well status (shut-in, temporarily abandoned, producing, 
injecting, or gas lift);
    (m) Well type (dry tree, hybrid, or subsea);
    (n) Date of diagnostic test;
    (o) Well schematic;
    (p) Water depth;
    (q) Volumes and types of fluid bled from each casing or riser 
evaluated;

[[Page 135]]

    (r) Type of diagnostic test performed:
    (1) Bleed down/buildup test;
    (2) Shut-in the well and monitor the pressure drop test;
    (3) Constant production rate and decrease the annular pressure test;
    (4) Constant production rate and increase the annular pressure test;
    (5) Change the production rate and monitor the casing pressure test; 
and
    (6) Casing pressure and tubing pressure history plot;
    (s) The casing diagnostic test data for all casing exceeding 100 
psig;
    (t) Associated shoe strengths for casing shoes exposed to annular 
fluids;
    (u) Concentration of any H2S that may be present;
    (v) Whether the structure on which the well is located is manned or 
unmanned;
    (w) Additional comments; and
    (x) Request date.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.529  What are the terms of my casing pressure request?

    Casing pressure requests are approved by the Regional Supervisor, 
Field Operations, for a term to be determined by the Regional Supervisor 
on a case-by-case basis. The Regional Supervisor may impose additional 
restrictions or requirements to allow continued operation of the well.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec.  250.530  What if my casing pressure request is denied?

    (a) If your casing pressure request is denied, then the operating 
company must submit plans for corrective action to the respective 
District Manager within 30 days of receiving the denial. The District 
Manager will establish a specific time period in which this corrective 
action will be taken. You must notify the respective District Manager 
within 30 days after completion of your corrected action.
    (b) You must submit the casing diagnostic test data to the 
appropriate Regional Supervisor, Field Operations, within 14 days of 
completion of the diagnostic test required under Sec.  250.522(e).

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.530 was 
amended by revising paragraph (b), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.530  What if my casing pressure request is denied?

                                * * * * *

    (b) You must submit the casing diagnostic test data to the 
appropriate Regional Supervisor, Field Operations, within 14 days of 
completion of the diagnostic test required under Sec.  250.523(e).



Sec.  250.531  When does my casing pressure request approval
 become invalid?

    A casing pressure request becomes invalid when:
    (a) The casing or riser pressure increases by 200 psig over the 
approved casing pressure request pressure;
    (b) The approved term ends;
    (c) The well is worked-over, side-tracked, redrilled, recompleted, 
or acid stimulated;
    (d) A different casing or riser on the same well requires a casing 
pressure request; or
    (e) A well has more than one casing operating under a casing 
pressure request and one of the casing pressure requests become invalid, 
then all casing pressure requests for that well become invalid.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



             Subpart F_Oil and Gas Well-Workover Operations



Sec.  250.600  General requirements.

    Well-workover operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS) 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must

[[Page 136]]

also follow the applicable requirements of subpart G of this part.

[81 FR 26021, Apr. 29, 2016]



Sec.  250.601  Definitions.

    When used in this subpart, the following terms shall have the 
meanings given below:
    Expected surface pressure means the highest pressure predicted to be 
exerted upon the surface of a well. In calculating expected surface 
pressure, you must consider reservoir pressure as well as applied 
surface pressure.
    Routine operations mean any of the following operations conducted on 
a well with the tree installed:
    (a) Cutting paraffin;
    (b) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves which can be removed by wireline 
operations;
    (c) Bailing sand;
    (d) Pressure surveys;
    (e) Swabbing;
    (f) Scale or corrosion treatment;
    (g) Caliper and gauge surveys;
    (h) Corrosion inhibitor treatment;
    (i) Removing or replacing subsurface pumps;
    (j) Through-tubing logging (diagnostics);
    (k) Wireline fishing; and
    (l) Setting and retrieving other subsurface flow-control devices.
    Workover operations mean the work conducted on wells after the 
initial completion for the purpose of maintaining or restoring the 
productivity of a well.

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.601 was 
amended by adding paragraph (m) to the definition of routine 
operations, effective July 15, 2019. For the convenience of 
the user, the added text is set forth as follows:



Sec.  250.601  Definitions.

                                * * * * *

    (m) Acid treatments.

                                * * * * *



Sec.  250.602  [Reserved]



Sec.  250.603  Emergency shutdown system.

    When well-workover operations are conducted on a well with the tree 
removed, an emergency shutdown system (ESD) manually controlled station 
shall be installed near the driller's console or well-servicing unit 
operator's work station, except when there is no other hydrocarbon-
producing well or other hydrocarbon flow on the platform.



Sec.  250.604  Hydrogen sulfide.

    When a well-workover operation is conducted in zones known to 
contain hydrogen sulfide (H2S) or in zones where the presence 
of H2S is unknown (as defined in Sec.  250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or rig, including but not limited to operations 
such as blowing the well down, dismantling wellhead equipment and flow 
lines, circulating the well, swabbing, and pulling tubing, pumps and 
packers. The lessee shall comply with the requirements in Sec.  250.490 
of this part as well as the appropriate requirements of this subpart.



Sec.  250.605  Subsea workovers.

    No subsea well-workover operation including routine operations shall 
be commenced until the lessee obtains written approval from the District 
Manager in accordance with Sec.  250.613 of this part. That approval 
shall be based upon a case-by-case determination that the proposed 
equipment and procedures will maintain adequate control of the well and 
permit continued safe production operations.



Sec. Sec.  250.606-250.608  [Reserved]



Sec.  250.609  Well-workover structures on fixed platforms.

    Derricks, masts, substructures, and related equipment shall be 
selected, designed, installed, used, and maintained so as to be adequate 
for the potential loads and conditions of loading that may be 
encountered during the operations proposed. Prior to moving a well-
workover rig or well-servicing equipment onto a platform, the lessee

[[Page 137]]

shall determine the structural capability of the platform to safely 
support the equipment and proposed operations, taking into consideration 
the corrosion protection, age of the platform, and previous stresses to 
the platform.



Sec.  250.610  Diesel engine air intakes.

    You must equip diesel engine air intakes with a device to shut down 
the diesel engine in the event of runaway. Diesel engines that are 
continuously attended must be equipped with remotely operated, manual, 
or automatic shutdown devices. Diesel engines that are not continuously 
attended must be equipped with automatic shutdown devices.

[81 FR 36149, June 6, 2016]



Sec.  250.611  Traveling-block safety device.

    You must equip all units being used for well-workover operations 
that have both a traveling block and a crown block with a safety device 
that is designed to prevent the traveling block from striking the crown 
block. You must check the device for proper operation weekly and after 
each drill-line slipping operation. You must enter the results of the 
operational check in the operations log.

[81 FR 36149, June 6, 2016]



Sec.  250.612  Field well-workover rules.

    When geological and engineering information available in a field 
enables the District Manager to determine specific operating 
requirements, field well-workover rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-workover rules have been established, well-workover 
operations in the field shall be conducted in accordance with such rules 
and other requirements of this subpart. Field well-workover rules may be 
amended or canceled for cause at any time upon the initiative of the 
District Manager or upon the request of a lessee.



Sec.  250.613  Approval and reporting for well-workover operations.

    (a) No well-workover operation except routine ones, as defined in 
Sec.  250.601 of this part, shall begin until the lessee receives 
written approval from the District Manager. Approval for these 
operations must be requested on Form BSEE-0124, Application for Permit 
to Modify.
    (b) You must submit the following with Form BSEE-0124:
    (1) A brief description of the well-workover procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of workover fluids;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing of the well showing the zone proposed for workover and 
the workover equipment to be used;
    (3) All information required in Sec.  250.731.
    (4) Where the well-workover is in a zone known to contain 
H2S or a zone where the presence of H2S is unknown, 
information pursuant to Sec.  250.490 of this part; and
    (5) Payment of the service fee listed in Sec.  250.125.
    (c) The following additional information shall be submitted with 
Form BSEE-0124 if completing to a new zone is proposed:
    (1) Reason for abandonment of present producing zone including 
supportive well test data, and
    (2) A statement of anticipated or known pressure data for the new 
zone.
    (d) Within 30 days after completing the well-workover operation, 
except routine operations, Form BSEE-0124, Application for Permit to 
Modify, shall be submitted to the District Manager, showing the work as 
performed. In the case of a well-workover operation resulting in the 
initial recompletion of a well into a new zone, a Form BSEE-0125, End of 
Operations Report, shall be submitted to the District Manager and shall 
include a new schematic of the tubing subsurface equipment if any 
subsurface equipment has been changed.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]

[[Page 138]]



Sec.  250.614  Well-control fluids, equipment, and operations.

    The following requirements apply during all well-workover operations 
with the tree removed:
    (a) Well-control fluids, equipment, and operations shall be 
designed, utilized, maintained, and/or tested as necessary to control 
the well in foreseeable conditions and circumstances, including 
subfreezing conditions. The well shall be continuously monitored during 
well-workover operations and shall not be left unattended at anytime 
unless the well is shut in and secured.
    (b) When coming out of the hole with drill pipe or a workover 
string, the annulus shall be filled with well-control fluid before the 
change in such fluid level decreases the hydrostatic pressure 75 pounds 
per square inch (psi) or every five stands of drill pipe or workover 
string, whichever gives a lower decrease in hydrostatic pressure. The 
number of stands of drill pipe or workover string and drill collars that 
may be pulled prior to filling the hole and the equivalent well-control 
fluid volume shall be calculated and posted near the operator's station. 
A mechanical, volumetric, or electronic device for measuring the amount 
of well-control fluid required to fill the hold shall be utilized.
    (c) The following well-control-fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP;
    (2) A well-control, fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips; and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]



Sec.  250.615  [Reserved]



Sec.  250.616  Coiled tubing and snubbing operations.

    (a) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

------------------------------------------------------------------------
                                 BOP system when
  BOP system when expected      expected surface    BOP system for wells
 surface pressures are less       pressures are      with returns taken
 than or equal to 3,500 psi    greater than 3,500   through an outlet on
                                       psi              the BOP stack
------------------------------------------------------------------------
Stripper or annular-type      Stripper or annular-  Stripper or annular-
 well control component.       type well control     type well control
                               component.            component.
Hydraulically-operated blind  Hydraulically-        Hydraulically-
 rams.                         operated blind rams.  operated blind rams
Hydraulically-operated shear  Hydraulically-        Hydraulically-
 rams.                         operated shear rams.  operated shear
                                                     rams.
Kill line inlet.............  Kill line inlet.....  Kill line inlet.
Hydraulically-operated two-   Hydraulically-        Hydraulically-
 way slip rams.                operated two-way      operated two-way
                               slip rams.            slip rams.
                                                    Hydraulically-
                                                     operated pipe rams.
Hydraulically-operated pipe   Hydraulically-        A flow tee or cross.
 rams.                         operated pipe rams.  Hydraulically-
                              Hydraulically-         operated pipe rams.
                               operated blind-      Hydraulically-
                               shear rams. These     operated blind-
                               rams should be        shear rams on wells
                               located as close to   with surface
                               the tree as           pressures 3,500 psi. As an
                                                     option, the pipe
                                                     rams can be placed
                                                     below the blind-
                                                     shear rams. The
                                                     blind-shear rams
                                                     should be located
                                                     as close to the
                                                     tree as practical.
------------------------------------------------------------------------

    (2) You may use a set of hydraulically-operated combination rams for 
the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams for 
the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled tubing 
connector at the downhole end of the coiled tubing string for all coiled 
tubing well-workover operations. If you plan to conduct operations 
without

[[Page 139]]

downhole check valves, you must describe alternate procedures and 
equipment in Form BSEE-0124, Application for Permit to Modify and have 
it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (b) The minimum BOP-system components for well-workover operations 
with the tree in place and performed by moving tubing or drill pipe in 
or out of a well under pressure utilizing equipment specifically 
designed for that purpose, i.e., snubbing operations, shall include the 
following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (c) An inside BOP or a spring-loaded, back-pressure safety valve and 
an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover 
operations with the tree installed and using small tubing as the work 
string. A wrench to fit the work-string safety valve shall be readily 
available. Proper connections shall be readily available for inserting 
valves in the work string. The full-opening safety valve is not required 
for coiled tubing or snubbing operations.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012, 
as amended at 81 FR 26021, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.616 was 
removed and reserved, effective July 15, 2019.



Sec. Sec.  250.617-250.618  [Reserved]



Sec.  250.619  Tubing and wellhead equipment.

    The lessee shall comply with the following requirements during well-
workover operations with the tree removed:
    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) When reinstalling the tree, you must:
    (1) Equip wells to monitor for casing pressure according to the 
following chart:

------------------------------------------------------------------------
   If you have . . .     you must equip . . .   so you can monitor . . .
------------------------------------------------------------------------
(i) fixed platform      the wellhead,          all annuli (A, B, C, D,
 wells,                                         etc., annuli).
(ii) subsea wells,      the tubing head,       the production casing
                                                annulus (A annulus).
(iii) hybrid* wells,    the surface wellhead,  all annuli at the surface
                                                (A and B riser annuli).
                                                If the production casing
                                                below the mudline and
                                                the production casing
                                                riser above the mudline
                                                are pressure isolated
                                                from each other,
                                                provisions must be made
                                                to monitor the
                                                production casing below
                                                the mudline for casing
                                                pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
  with a surface casing head, a surface tubing head, a surface tubing
  hanger, and a surface christmas tree.


[[Page 140]]

    (2) Follow the casing pressure management requirements in subpart E 
of this part.
    (c) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. The tree shall be equipped with a minimum of one 
master valve and one surface safety valve in the vertical run of the 
tree when it is reinstalled.
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839.
    (e) If you pull and reinstall packers and bridge plugs, you must 
meet the following requirements:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec.  250.198);
    (2) The production packer must be set at a depth that will allow for 
a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and
    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.
    (f) Your APM must include a description and calculations for how you 
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012, 
as amended at 81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.619 was 
amended by revising paragraph (e)(1) and adding new paragraph (g), 
effective July 15, 2019. For the convenience of the user, the added and 
revised text is set forth as follows:



Sec.  250.619  Tubing and wellhead equipment.

                                * * * * *

    (e) * * *
    (1) The uppermost permanently installed packer and all permanently 
installed bridge plugs qualified as mechanical barriers must comply with 
ANSI/API Spec. 11D1 (as incorporated by reference in Sec.  250.198).

                                * * * * *

    (g) You must have two independent barriers, one being mechanical, in 
the exposed center wellbore prior to removing the tree and/or well 
control equipment.



Sec.  250.620  Wireline operations.

    The lessee shall comply with the following requirements during 
routine, as defined in Sec.  250.601 of this part, and nonroutine 
wireline workover operations:
    (a) Wireline operations shall be conducted so as to minimize leakage 
of well fluids. Any leakage that does occur shall be contained to 
prevent pollution.
    (b) All wireline perforating operations and all other wireline 
operations where communication exists between the completed hydrocarbon-
bearing zone(s) and the wellbore shall use a lubricator assembly 
containing at least one wireline valve.
    (c) When the lubricator is initially installed on the well, it shall 
be successfully pressure tested to the expected shut-in surface 
pressure.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]



                 Subpart G_Well Operations and Equipment

    Source: 81 FR 26022, Apr. 29, 2016, unless otherwise noted.

                          General Requirements



Sec.  250.700  What operations and equipment does this subpart cover?

    This subpart covers operations and equipment associated with 
drilling, completion, workover, and decommissioning activities. This 
subpart includes regulations applicable to drilling, completion, 
workover, and decommissioning activities in addition to applicable 
regulations contained in subparts D, E, F, and Q of this part unless 
explicitly stated otherwise.

[[Page 141]]



Sec.  250.701  May I use alternate procedures or equipment during
 operations?

    You may use alternate procedures or equipment during operations 
after receiving approval as described in Sec.  250.141. You must 
identify and discuss your proposed alternate procedures or equipment in 
your Application for Permit to Drill (APD) (Form BSEE-0123) (see Sec.  
250.414(h)) or your Application for Permit to Modify (APM) (Form BSEE-
0124). Procedures for obtaining approval of alternate procedures or 
equipment are described in Sec.  250.141.



Sec.  250.702  May I obtain departures from these requirements?

    You may apply for a departure from these requirements as described 
in Sec.  250.142. Your request must include a justification showing why 
the departure is necessary. You must identify and discuss the departure 
you are requesting in your APD (see Sec.  250.414(h)) or your APM.



Sec.  250.703  What must I do to keep wells under control?

    You must take the necessary precautions to keep wells under control 
at all times, including:
    (a) Use recognized engineering practices to reduce risks to the 
lowest level practicable when monitoring and evaluating well conditions 
and to minimize the potential for the well to flow or kick;
    (b) Have a person onsite during operations who represents your 
interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the rig crew maintains continuous surveillance on the rig 
floor from the beginning of operations until the well is completed or 
abandoned, unless you have secured the well with blowout preventers 
(BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subparts O 
and S of this part;
    (e) Use and maintain equipment and materials necessary to ensure the 
safety and protection of personnel, equipment, natural resources, and 
the environment; and
    (f) Use equipment that has been designed, tested, and rated for the 
maximum environmental and operational conditions to which it may be 
exposed while in service.

                            Rig Requirements



Sec.  250.710  What instructions must be given to personnel engaged 
in well operations?

    Prior to engaging in well operations, personnel must be instructed 
in:
    (a) Hazards and safety requirements. You must instruct your 
personnel regarding the safety requirements for the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment as 
required by subpart S of this part. The date and time of safety meetings 
must be recorded and available at the facility for review by BSEE 
representatives.
    (b) Well control. You must prepare a well-control plan for each 
well. Each well-control plan must contain instructions for personnel 
about the use of each well-control component of your BOP, procedures 
that describe how personnel will seal the wellbore and shear pipe before 
maximum anticipated surface pressure (MASP) conditions are exceeded, 
assignments for each crew member, and a schedule for completion of each 
assignment. You must keep a copy of your well-control plan on the rig at 
all times, and make it available to BSEE upon request. You must post a 
copy of the well-control plan on the rig floor.



Sec.  250.711  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with all personnel 
engaged in well operations. Your drill must familiarize personnel 
engaged in well operations with their roles and functions so that they 
can perform their duties promptly and efficiently as outlined in the 
well-control plan required by Sec.  250.710.
    (a) Timing of drills. You must conduct each drill during a period of 
activity that minimizes the risk to operations. The timing of your 
drills must cover a range of different operations, including drilling 
with a diverter, on-bottom

[[Page 142]]

drilling, and tripping. The same drill may not be repeated consecutively 
with the same crew.
    (b) Recordkeeping requirements. For each drill, you must record the 
following in the daily report:
    (1) Date, time, and type of drill conducted;
    (2) The amount of time it took to be ready to close the diverter or 
use each well-control component of BOP system; and
    (3) The total time to complete the entire drill.
    (c) A BSEE ordered drill. A BSEE representative may require you to 
conduct a well-control drill during a BSEE inspection. The BSEE 
representative will consult with your onsite representative before 
requiring the drill.



Sec.  250.712  What rig unit movements must I report?

    (a) You must report the movement of all rig units on and off 
locations to the District Manager using Form BSEE-0144, Rig Movement 
Notification Report. Rig units include MODUs, platform rigs, snubbing 
units, wire-line units used for non-routine operations, and coiled 
tubing units. You must inform the District Manager 24 hours before:
    (1) The arrival of a rig unit on location;
    (2) The movement of a rig unit to another slot. For movements that 
will occur less than 24 hours after initially moving onto location 
(e.g., coiled tubing and batch operations), you may include your 
anticipated movement schedule on Form BSEE-0144; or
    (3) The departure of a rig unit from the location.
    (b) You must provide the District Manager with the rig name, lease 
number, well number, and expected time of arrival or departure.
    (c) If a MODU or platform rig is to be warm or cold stacked, you 
must inform the District Manager:
    (1) Where the MODU or platform rig is coming from;
    (2) The location where the MODU or platform rig will be positioned;
    (3) Whether the MODU or platform rig will be manned or unmanned; and
    (4) If the location for stacking the MODU or platform rig changes.
    (d) Prior to resuming operations after stacking, you must notify the 
appropriate District Manager of any construction, repairs, or 
modifications associated with the drilling package made to the MODU or 
platform rig.
    (e) If a drilling rig is entering OCS waters, you must inform the 
District Manager where the drilling rig is coming from.
    (f) If you change your anticipated date for initially moving on or 
off location by more than 24 hours, you must submit an updated Form 
BSEE-0144, Rig Movement Notification Report.

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.712 was 
amended by adding paragraphs (g) and (h), effective July 15, 2019. For 
the convenience of the user, the added text is set forth as follows:



Sec.  250.712  What rig unit movements must I report?

                                * * * * *

    (g) You are not required to report rig unit movements to and from 
the safe zone during the course of permitted operations.
    (h) If a rig unit is already on a well, you are not required to 
report any additional rig unit movements on that well.



Sec.  250.713  What must I provide if I plan to use a mobile
 offshore drilling unit (MODU) for well operations?

    If you plan to use a MODU for well operations, you must provide:
    (a) Fitness requirements. Information and data to demonstrate the 
MODU's capability to perform at the proposed location. This information 
must include the maximum environmental and operational conditions that 
the MODU is designed to withstand, including the minimum air gap 
necessary for both hurricane and non-hurricane seasons. If sufficient 
environmental information and data are not available at the time you 
submit your APD or APM, the District Manager may approve your APD or 
APM, but require you to collect and report this information during 
operations. Under this circumstance, the District Manager may revoke the 
approval of the APD or APM if information collected during operations 
shows that the MODU is not capable of performing at the proposed 
location.
    (b) Foundation requirements. Information to show that site-specific 
soil and

[[Page 143]]

oceanographic conditions are capable of supporting the proposed bottom-
founded MODU. If you provided sufficient site-specific information in 
your EP, DPP, or DOCD submitted to BOEM for that well location and 
conditions, you may reference that information. The District Manager may 
require you to conduct additional surveys and soil borings before 
approving the APD or APM if additional information is needed to make a 
determination that the conditions are capable of supporting the MODU, or 
equipment installed on a subsea wellhead. For a moored rig, you must 
submit a plat of the rig's anchor pattern approved in your EP, DPP, or 
DOCD in your APD or APM.
    (c) For frontier areas. (1) If the design of the MODU you plan to 
use in a frontier area is unique or has not been proven for use in the 
proposed environment, the District Manager may require you to submit a 
third-party review of the MODU design. If required, you must obtain a 
third-party review of your MODU similar to the process outlined in 
Sec. Sec.  250.915 through 250.918. You may submit this information 
before submitting an APD or APM.
    (2) If you plan to conduct operations in a frontier area, you must 
have a contingency plan that addresses design and operating limitations 
of the MODU. Your plan must identify the actions necessary to maintain 
safety and prevent damage to the environment. Actions must include the 
suspension, curtailment, or modification of operations to remedy various 
operational or environmental situations (e.g., vessel motion, riser 
offset, anchor tensions, wind speed, wave height, currents, icing or 
ice-loading, settling, tilt or lateral movement, resupply capability).
    (d) Additional documentation. You must provide the current 
Certificate of Inspection (for U.S.-flag vessels) or Certificate of 
Compliance (for foreign-flag vessels) from the USCG and Certificate of 
Classification. You must also provide current documentation of any 
operational limitations imposed by an appropriate classification 
society.
    (e) Dynamically positioned MODU. If you use a dynamically positioned 
MODU, you must include in your APD or APM your contingency plan for 
moving off location in an emergency situation. At a minimum, your plan 
must address emergency events caused by storms, currents, station-
keeping failures, power failures, and losses of well control. The 
District Manager may require your plan to include additional events that 
may require movement of the MODU and other information needed to clarify 
or further address how the MODU will respond to emergencies or other 
events.
    (f) Inspection of MODU. The MODU must be available for inspection by 
the District Manager before commencing operations and at any time during 
operations.
    (g) Current monitoring. For water depths greater than 400 meters 
(1,312 feet), you must include in your APD or APM:
    (1) A description of the specific current speeds that will cause you 
to implement rig shutdown, move-off procedures, or both; and
    (2) A discussion of the specific measures you will take to curtail 
rig operations and move off location when such currents are encountered. 
You may use criteria, such as current velocities, riser angles, watch 
circles, and remaining rig power to describe when these procedures or 
measures will be implemented.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.714  Do I have to develop a dropped objects plan?

    If you use a floating rig unit in an area with subsea 
infrastructure, you must develop a dropped objects plan and make it 
available to BSEE upon request. This plan must be updated as the 
infrastructure on the seafloor changes. Your plan must include:
    (a) A description and plot of the path the rig will take while 
running and pulling the riser;
    (b) A plat showing the location of any subsea wells, production 
equipment, pipelines, and any other identified debris;
    (c) Modeling of a dropped object's path with consideration given to 
metocean conditions for various material forms, such as a tubular (e.g., 
riser or casing) and box (e.g., BOP or tree);

[[Page 144]]

    (d) Communications, procedures, and delegated authorities 
established with the production host facility to shut-in any active 
subsea wells, equipment, or pipelines in the event of a dropped object; 
and
    (e) Any additional information required by the District Manager as 
appropriate to clarify, update, or evaluate your dropped objects plan.



Sec.  250.715  Do I need a global positioning system (GPS) for all MODUs?

    All MODUs must have a minimum of two functioning GPS transponders at 
all times, and you must provide to BSEE real-time access to the GPS data 
prior to and during each hurricane season.
    (a) The GPS must be capable of monitoring the position and tracking 
the path in real-time if the MODU moves from its location during a 
severe storm.
    (b) You must install and protect the tracking system's equipment to 
minimize the risk of the system being disabled.
    (c) You must place the GPS transponders in different locations for 
redundancy to minimize risk of system failure.
    (d) Each GPS transponder must be capable of transmitting data for at 
least 7 days after a storm has passed.
    (e) If the MODU is moved off location in the event of a storm, you 
must immediately begin to record the GPS location data.
    (f) You must contact the Regional Office and allow real-time access 
to the MODU location data. When you contact the Regional Office, provide 
the following:
    (1) Name of the lessee and operator with contact information;
    (2) MODU name;
    (3) Initial date and time; and
    (4) How you will provide GPS real-time access.

                             Well Operations



Sec.  250.720  When and how must I secure a well?

    (a) Whenever you interrupt operations, you must notify the District 
Manager. Before moving off the well, you must have two independent 
barriers installed, at least one of which must be a mechanical barrier, 
as approved by the District Manager. You must install the barriers at 
appropriate depths within a properly cemented casing string or liner. 
Before removing a subsea BOP stack or surface BOP stack on a mudline 
suspension well, you must conduct a negative pressure test in accordance 
with Sec.  250.721.
    (1) The events that would cause you to interrupt operations and 
notify the District Manager include, but are not limited to, the 
following:
    (i) Evacuation of the rig crew;
    (ii) Inability to keep the rig on location;
    (iii) Repair to major rig or well-control equipment; or
    (iv) Observed flow outside the well's casing (e.g., shallow water 
flow or bubbling).
    (2) The District Manager may approve alternate procedures or 
barriers, in accordance with Sec.  250.141, if you do not have time to 
install the required barriers or if special circumstances occur.
    (b) Before you displace kill-weight fluid from the wellbore and/or 
riser, thereby creating an underbalanced state, you must obtain approval 
from the District Manager. To obtain approval, you must submit with your 
APD or APM your reasons for displacing the kill-weight fluid and provide 
detailed step-by-step written procedures describing how you will safely 
displace these fluids. The step-by-step displacement procedures must 
address the following:
    (1) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers;
    (2) Tests you will conduct to ensure integrity of independent 
barriers;
    (3) BOP procedures you will use while displacing kill-weight fluids; 
and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.
    (c) For Arctic OCS exploratory drilling operations, in addition to 
the requirements of paragraphs (a) and (b) of this section:
    (1) If you move your drilling rig off a well prior to completion or 
permanent abandonment, you must ensure that

[[Page 145]]

any equipment left on, near, or in a wellbore that has penetrated below 
the surface casing is positioned in a manner to:
    (i) Protect the well head; and
    (ii) Prevent or minimize the likelihood of compromising the down-
hole integrity of the well or the effectiveness of the well plugs.
    (2) In areas of ice scour you must use a well mudline cellar or an 
equivalent means of minimizing the risk of damage to the well head and 
wellbore. BSEE may approve an equivalent means that will meet or exceed 
the level of safety and environmental protection provided by a mudline 
cellar if the operator can show that utilizing a mudline cellar would 
compromise the stability of the rig, impede access to the well head 
during a well control event, or otherwise create operational risks.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 46563, July 15, 2016]

    Effective Date Note: At 84 FR 21976, May 15, 2019, Sec.  250.720 was 
amended by revising paragraph (a)(1) and adding paragraphs (a)(3) and 
(d), effective July 15, 2019. For the convenience of the user, the added 
and revised text is set forth as follows:



Sec.  250.720  When and how must I secure a well?

    (a) * * *
    (1) The events that would cause you to interrupt operations and 
notify the District Manager include, but are not limited to, the 
following:
    (i) Evacuation of the rig crew;
    (ii) Inability to keep the rig on location;
    (iii) Repair to major rig or well-control equipment;
    (iv) Observed flow outside the well's casing (e.g., shallow water 
flow or bubbling); or
    (v) Impending National Weather Service-named tropical storm or 
hurricane.

                                * * * * *

    (3) If you unlatch the BOP or LMRP:
    (i) Upon relatch of the BOP, you must test according to Sec.  
250.734(b)(2), or
    (ii) Upon relatch of the LMRP, you must test according to Sec.  
250.734(b)(3); and
    (iii) You must submit a revised permit with a written statement from 
an independent third party certifying that the previous certification 
under Sec.  250.731(c) remains valid and receive District Manager 
approval before resuming operations.

                                * * * * *

    (d) You must have the equipment used solely for intervention 
operations (e.g., tree interface tools) identified, readily available, 
properly maintained, and available for BSEE inspection upon request. 
This equipment is required for subsea completed wells with a tree 
installed, that meet the following conditions:
    (1) Have a shut-in tubing pressure that is greater than the 
hydrostatic pressure of the water column, or
    (2) Are not capable of having the annulus monitored.



Sec.  250.721  What are the requirements for pressure testing 
casing and liners?

    (a) You must test each casing string that extends to the wellhead 
according to the following table:

------------------------------------------------------------------------
              Casing type                     Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural,...............  Not required.
(2) Conductor, excluding subsea          250 psi.
 wellheads,.
(3) Surface, Intermediate, and           70 percent of its minimum
 Production,.                             internal yield.
------------------------------------------------------------------------

    (b) You must test each drilling liner and liner-top to a pressure at 
least equal to the anticipated leak-off pressure of the formation below 
that liner shoe, or subsequent liner shoes if set. You must conduct this 
test before you continue operations in the well.
    (c) You must test each production liner and liner-top to a minimum 
of 500 psi above the formation fracture pressure at the casing shoe into 
which the liner is lapped.
    (d) The District Manager may approve or require other casing test 
pressures as appropriate under the circumstances to ensure casing 
integrity.
    (e) If you plan to produce a well, you must:
    (1) For a well that is fully cased and cemented, pressure test the 
entire well to maximum anticipated shut-in tubing pressure, not to 
exceed 70% of the

[[Page 146]]

burst rating limit of the weakest component before perforating the 
casing or liner; or
    (2) For an open-hole completion, pressure test the entire well to 
maximum anticipated shut-in tubing pressure, not to exceed 70% of the 
burst rating limit of the weakest component before you drill the open-
hole section.
    (f) You may not resume operations until you obtain a satisfactory 
pressure test. If the pressure declines more than 10 percent in a 30-
minute test, or if there is another indication of a leak, you must 
submit to the District Manager for approval your proposed plans to re-
cement, repair the casing or liner, or run additional casing/liner to 
provide a proper seal. Your submittal must include a PE certification of 
your proposed plans.
    (g) You must perform a negative pressure test on all wells that use 
a subsea BOP stack or wells with mudline suspension systems.
    (1) You must perform a negative pressure test on your final casing 
string or liner. This test must be conducted after setting your second 
barrier just above the shoe track, but prior to conducting any 
completion operations.
    (2) You must perform a negative pressure test prior to unlatching 
the BOP at any point in the well. The negative pressure test must be 
performed on those components, at a minimum, that will be exposed to the 
negative differential pressure that will occur when the BOP is 
disconnected.
    (3) The District Manager may require you to perform additional 
negative pressure tests on other casing strings or liners (e.g., 
intermediate casing string or liner) or on wells with a surface BOP 
stack as appropriate to demonstrate casing or liner integrity.
    (4) You must submit for approval with your APD or APM, test 
procedures and criteria for a successful negative pressure test. If any 
of your test procedures or criteria for a successful test change, you 
must submit for approval the changes in a revised APD or APM.
    (5) You must document all your test results and make them available 
to BSEE upon request.
    (6) If you have any indication of a failed negative pressure test, 
such as, but not limited to, pressure buildup or observed flow, you must 
immediately investigate the cause. If your investigation confirms that a 
failure occurred during the negative pressure test, you must:
    (i) Correct the problem and immediately notify the appropriate 
District Manager; and
    (ii) Submit a description of the corrective action taken and receive 
approval from the appropriate District Manager for the retest.
    (7) You must have two barriers in place, as described in Sec.  
250.420(b)(3), at any time and for any well, prior to performing the 
negative pressure test.
    (8) You must include documentation of the successful negative 
pressure test in the End-of-Operations Report (Form BSEE-0125).



Sec.  250.722  What are the requirements for prolonged operations
 in a well?

    If wellbore operations continue within a casing or liner for more 
than 30 days from the previous pressure test of the well's casing or 
liner, you must:
    (a) Stop operations as soon as practicable, and evaluate the effects 
of the prolonged operations on continued operations and the life of the 
well. At a minimum, you must:
    (1) Evaluate the well casing with a pressure test, caliper tool, or 
imaging tool. On a case-by-case basis, the District Manager may require 
a specific method of evaluation of the effects on the well casing of 
prolonged operations; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations. Your 
report must include calculations that show the well's integrity is above 
the minimum safety factors, if an imaging tool or caliper is used.
    (b) If well integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Obtain approval from the District Manager to begin repairs or 
install additional casing. To obtain approval, you must also provide a 
PE certification showing that he or she reviewed and approved the 
proposed changes;
    (2) Repair the casing or run another casing string; and

[[Page 147]]

    (3) Perform a pressure test after the repairs are made or additional 
casing is installed and report the results to the District Manager as 
specified in Sec.  250.721.

    Effective Date Note: At 84 FR 21977, May 15, 2019, Sec.  250.722 was 
amended by revising paragraph (a)(2), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.722  What are the requirements for prolonged operations in a 
          well?

                                * * * * *

    (a) * * *
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations. Your 
report must include calculations that indicate the well's integrity is 
above the minimum safety factors, if an imaging tool or caliper is used. 
District Manager approval is not required to resume operations if you 
conducted a successful pressure test as approved in your permit. You 
must document the successful pressure test in the WAR.

                                * * * * *



Sec.  250.723  What additional safety measures must I take when I
 conduct operations on a platform that has producing wells or has
 other hydrocarbon flow?

    You must take the following safety measures when you conduct 
operations with a rig unit or lift boat on or jacked-up over a platform 
with producing wells or that has other hydrocarbon flow:
    (a) The movement of rig units and related equipment on and off a 
platform or from well to well on the same platform, including rigging up 
and rigging down, must be conducted in a safe manner;
    (b) You must install an emergency shutdown station for the 
production system near the rig operator's console;
    (c) You must shut-in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a rig unit or related equipment on and off a platform. 
This includes rigging up and rigging down activities within 500 feet of 
the affected platform;
    (2) You move or skid a rig unit between wells on a platform; or
    (3) A MODU or lift boat moves within 500 feet of a platform. You may 
resume production once the MODU or lift boat is in place, secured, and 
ready to begin operations.
    (d) All wells in the same well-bay which are capable of producing 
hydrocarbons must be shut-in below the surface with a pump-through-type 
tubing plug and at the surface with a closed master valve prior to 
moving rig units and related equipment, unless otherwise approved by the 
District Manager.
    (1) A closed surface-controlled subsurface safety valve of the pump-
through-type may be used in lieu of the pump-through-type tubing plug 
provided that the surface control has been locked out of operation.
    (2) The well to which a rig unit or related equipment is to be moved 
must be equipped with a back-pressure valve prior to removing the tree 
and installing and testing the BOP system.
    (3) The well from which a rig unit or related equipment is to be 
moved must be equipped with a back pressure valve prior to removing the 
BOP system and installing the production tree.
    (e) Coiled tubing units, snubbing units, or wireline units may be 
moved onto and off of a platform without shutting in wells.

    Effective Date Note: At 84 FR 21977, May 15, 2019, Sec.  250.723 was 
amended by revising the introductory text and paragraph (c)(3), 
effective July 15, 2019. For the convenience of the user, the added and 
revised text is set forth as follows:



Sec.  250.723  What additional safety measures must I take when I 
          conduct operations on a platform that has producing wells or 
          has other hydrocarbon flow?

    You must take the following safety measures when you conduct 
operations with a rig unit on or jacked-up over a platform with 
producing wells or that has other hydrocarbon flow:

                                * * * * *

    (c) * * *
    (3) A MODU moves within 500 feet of a platform. You may resume 
production once the MODU is in place, secured, and ready to begin 
operations.

                                * * * * *

[[Page 148]]



Sec.  250.724  What are the real-time monitoring requirements?

    (a) No later than April 29, 2019, when conducting well operations 
with a subsea BOP or with a surface BOP on a floating facility, or when 
operating in an high pressure high temperature (HPHT) environment, you 
must gather and monitor real-time well data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's fluid handling system on the rig; and
    (3) The well's downhole conditions with the bottom hole assembly 
tools (if any tools are installed).
    (b) You must transmit these data as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and have 
the capability to monitor the data onshore, using qualified personnel in 
accordance with a real-time monitoring plan, as provided in paragraph 
(c) of this section. Onshore personnel who monitor real-time data must 
have the capability to contact rig personnel during operations. After 
operations, you must preserve and store these data onshore for 
recordkeeping purposes as required in Sec. Sec.  250.740 and 250.741. 
You must provide BSEE with access to your designated real-time 
monitoring data onshore upon request. You must include in your APD a 
certification that you have a real-time monitoring plan that meets the 
criteria in paragraph (c) of this section.
    (c) You must develop and implement a real-time monitoring plan. Your 
real-time monitoring plan, and all real-time monitoring data, must be 
made available to BSEE upon request. Your real-time monitoring plan must 
include the following:
    (1) A description of your real-time monitoring capabilities, 
including the types of the data collected;
    (2) A description of how your real-time monitoring data will be 
transmitted onshore during operations, how the data will be labeled and 
monitored by qualified onshore personnel, and how it will be stored 
onshore;
    (3) A description of your procedures for providing BSEE access, upon 
request, to your real-time monitoring data including, if applicable, the 
location of any onshore data monitoring or data storage facilities;
    (4) The qualifications of the onshore personnel monitoring the data;
    (5) Your procedures for, and methods of, communication between rig 
personnel and the onshore monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring 
capabilities or communications between rig and onshore personnel, and a 
protocol for how you will respond to any significant and/or prolonged 
interruption of monitoring or onshore-offshore communications, including 
your protocol for notifying BSEE of any significant and/or prolonged 
interruptions.

    Effective Date Note: At 84 FR 21977, May 15, 2019, Sec.  250.724 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.724  What are the real-time monitoring requirements?

    (a) When conducting well operations with a subsea BOP or with a 
surface BOP on a floating facility, or when operating in an high 
pressure high temperature (HPHT) environment, you must gather and 
monitor real-time well data using an independent, automatic, and 
continuous monitoring system capable of recording, storing, and 
transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's active fluid circulating system; and
    (3) The well's downhole conditions with the bottom hole assembly 
tools (if any tools are installed).
    (b) You must transmit these data as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and have 
the capability to monitor the data, using qualified personnel in 
accordance with a real-time monitoring plan, as provided in paragraph 
(c) of this section.
    (c) You must develop and implement a real-time monitoring plan. Your 
real-time monitoring plan, and all real-time monitoring data, must be 
made available to BSEE upon request. Your real-time monitoring plan must 
include the following:
    (1) A description of your real-time monitoring capabilities, 
including the types of the data collected;
    (2) A description of how your real-time monitoring data will be 
transmitted during operations, how the data will be labeled and 
monitored by qualified personnel, and how the data will be stored as 
required in Sec. Sec.  250.740 and 250.741;

[[Page 149]]

    (3) A description of your procedures for providing BSEE access, upon 
request, to your real-time monitoring data;
    (4) The qualifications of the personnel monitoring the data;
    (5) Your procedures for, and methods of, communication between rig 
personnel and the monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring 
capabilities or communications between rig personnel and monitoring 
personnel, and a protocol for how you will respond to any significant 
and/or prolonged interruption of monitoring capabilities or 
communications, including your protocol for notifying BSEE of any 
significant and/or prolonged interruptions.

               Blowout Preventer (BOP) System Requirements



Sec.  250.730  What are the general requirements for BOP systems
 and system components?

    (a) You must ensure that the BOP system and system components are 
designed, installed, maintained, inspected, tested, and used properly to 
ensure well control. The working-pressure rating of each BOP component 
(excluding annular(s)) must exceed MASP as defined for the operation. 
For a subsea BOP, the MASP must be taken at the mudline. The BOP system 
includes the BOP stack, control system, and any other associated 
system(s) and equipment. The BOP system and individual components must 
be able to perform their expected functions and be compatible with each 
other. Your BOP system (excluding casing shear) must be capable of 
closing and sealing the wellbore at all times, including under 
anticipated flowing conditions for the specific well conditions, without 
losing ram closure time and sealing integrity due to the corrosiveness, 
volume, and abrasiveness of any fluids in the wellbore that the BOP 
system may encounter. Your BOP system must meet the following 
requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by 
reference in Sec.  250.198) and the requirements of Sec. Sec.  250.733 
through 250.739. If there is a conflict between API Standard 53, and the 
requirements of this subpart, you must follow the requirements of this 
subpart.
    (2) Those provisions of the following industry standards (all 
incorporated by reference in Sec.  250.198) that apply to BOP systems:
    (i) ANSI/API Spec. 6A;
    (ii) ANSI/API Spec. 16A;
    (iii) ANSI/API Spec. 16C;
    (iv) API Spec. 16D; and
    (v) ANSI/API Spec. 17D.
    (3) For surface and subsea BOPs, the pipe and variable bore rams 
installed in the BOP stack must be capable of effectively closing and 
sealing on the tubular body of any drill pipe, workstring, and tubing 
(excluding tubing with exterior control lines and flat packs) in the 
hole under MASP, as defined for the operation, with the proposed 
regulator settings of the BOP control system.
    (4) The current set of approved schematic drawings must be available 
on the rig and at an onshore location. If you make any modifications to 
the BOP or control system that will change your BSEE-approved schematic 
drawings, you must suspend operations until you obtain approval from the 
District Manager.
    (b) You must ensure that the design, fabrication, maintenance, and 
repair of your BOP system is in accordance with the requirements 
contained in this part, Original Equipment Manufacturers (OEM) 
recommendations unless otherwise directed by BSEE, and recognized 
engineering practices. The training and qualification of repair and 
maintenance personnel must meet or exceed any OEM training 
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in 
API Standard 53, ANSI/API Spec. 6A, and ANSI/API Spec 16A (all 
incorporated by reference in Sec.  250.198), and:
    (1) You must provide a written notice of equipment failure to the 
Chief, Office of Offshore Regulatory Programs, and the manufacturer of 
such equipment within 30 days after the discovery and identification of 
the failure. A failure is any condition that prevents the equipment from 
meeting the functional specification.
    (2) You must ensure that an investigation and a failure analysis are 
performed within 120 days of the failure to

[[Page 150]]

determine the cause of the failure. You must also ensure that the 
results and any corrective action are documented. If the investigation 
and analysis are performed by an entity other than the manufacturer, you 
must ensure that the Chief, Office of Offshore Regulatory Programs and 
the manufacturer receive a copy of the analysis report.
    (3) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed operating 
or repair procedures as a result of a failure, then you must, within 30 
days of such changes, report the design change or modified procedures in 
writing to the Chief, Office of Offshore Regulatory Programs.
    (4) You must send the reports required in this paragraph to: Chief, 
Office of Offshore Regulatory Programs; Bureau of Safety and 
Environmental Enforcement; 45600 Woodland Road, Sterling, VA 20166.
    (d) If you plan to use a BOP stack manufactured after the effective 
date of this regulation, you must use one manufactured pursuant to an 
API Spec. Q1 (as incorporated by reference in Sec.  250.198) quality 
management system. Such quality management system must be certified by 
an entity that meets the requirements of ISO 17011.
    (1) BSEE may consider accepting equipment manufactured under quality 
assurance programs other than API Spec. Q1, provided you submit a 
request to the Chief, Office of Offshore Regulatory Programs for 
approval, containing relevant information about the alternative program.
    (2) You must submit this request to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
45600 Woodland Road, Sterling, Virginia 20166.

    Effective Date Note: At 84 FR 21977, May 15, 2019, Sec.  250.730 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.730  What are the general requirements for BOP systems and 
          system components?

    (a) You must ensure that the BOP system and system components are 
designed, installed, maintained, inspected, tested, and used properly to 
ensure well control. The working-pressure rating of each BOP component 
(excluding annular(s)) must exceed MASP as defined for the operation. 
For a subsea BOP, the MASP must be determined at the mudline. The BOP 
system includes the BOP stack, control system, and any other associated 
system(s) and equipment. The BOP system and individual components must 
be able to perform their expected functions and be compatible with each 
other. Your BOP system must be capable of closing and sealing the 
wellbore in the event of flow due to a kick, including under anticipated 
flowing conditions for the specific well conditions, without losing ram 
closure time and sealing integrity due to the corrosiveness, volume, and 
abrasiveness of any fluids in the wellbore that the BOP system may 
encounter. Your BOP system must meet the following requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by 
reference in Sec.  250.198) and the requirements of Sec. Sec.  250.733 
through 250.739. If there is a conflict between API Standard 53 and the 
requirements of this subpart, you must follow the requirements of this 
subpart.
    (2) The provisions of the following industry standards (all 
incorporated by reference in Sec.  250.198) that apply to BOP systems:
    (i) ANSI/API Spec. 6A;
    (ii) ANSI/API Spec. 16A;
    (iii) ANSI/API Spec. 16C;
    (iv) API Spec. 16D; and
    (v) ANSI/API Spec. 17D.
    (3) For surface and subsea BOPs, the pipe and variable bore rams 
installed in the BOP stack must be capable of effectively closing and 
sealing on the tubular body of any drill pipe, workstring, and tubing 
(excluding tubing with exterior control lines and flat packs) in the 
hole under MASP, as defined for the operation, at the proposed regulator 
settings of the BOP control system.
    (4) The current set of approved schematic drawings must be available 
on the rig and at an onshore location. If you make any modifications to 
the BOP or control system that will require changes to your BSEE-
approved schematic drawings, you must suspend operations until you 
obtain approval from the District Manager.
    (b) You must ensure that the design, fabrication, maintenance, and 
repair of your BOP system is in accordance with the requirements 
contained in this part, applicable Original Equipment Manufacturer's 
(OEM) recommendations unless otherwise directed by BSEE, and recognized 
engineering practices. The training and qualification of repair and 
maintenance personnel must meet or exceed applicable OEM training 
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in 
API Standard 53, (incorporated by reference in Sec.  250.198), and:

[[Page 151]]

    (1) You must provide a written notice of equipment failure to the 
Chief, Office of Offshore Regulatory Programs (OORP), unless BSEE has 
designated a third party as provided in paragraph (c)(4) of this 
section, and the manufacturer of such equipment within 30 days after the 
discovery and identification of the failure. A failure is any condition 
that prevents the equipment from meeting the functional specification.
    (2) You must ensure that an investigation and a failure analysis are 
started within 120 days of the failure to determine the cause of the 
failure, and are completed within 120 days upon starting the 
investigation and failure analysis. You must also ensure that the 
results and any corrective action are documented. You must ensure that 
the analysis report is submitted to the Chief OORP, unless BSEE has 
designated a third party as provided in paragraph (c)(4) of this 
section, as well as the manufacturer. If you cannot complete the 
investigation and analysis within the specified time, you must submit an 
extension request detailing how you will complete the investigation and 
analysis to BSEE for approval. You must submit the extension request to 
the Chief, OORP.
    (3) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed operating 
or repair procedures as a result of a failure, then you must, within 30 
days of such changes, report the design change or modified procedures in 
writing to the Chief OORP, unless BSEE has designated a third party as 
provided in paragraph (c)(4) of this section.
    (4) Submit notices and reports to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
45600 Woodland Road, Sterling, Virginia 20166. BSEE may designate a 
third party to receive the data and reports on behalf of BSEE. If BSEE 
designates a third party, you must submit the data and reports to the 
designated third party.
    (d) If you plan to use a BOP stack manufactured after the effective 
date of this regulation, you must use one manufactured pursuant to an 
ANSI/API Spec. Q1 (as incorporated by reference in Sec.  250.198) 
quality management system. Such quality management system must be 
certified by an entity that meets the requirements of ISO/IEC 17021-1 
(as incorporated by reference in Sec.  250.198).
    (1) BSEE may consider accepting equipment manufactured under quality 
assurance programs other than ANSI/API Spec. Q1, provided you submit a 
request to the Chief, OORP for approval, containing relevant information 
about the alternative program.
    (2) You must submit this request to the Chief, OORP; Bureau of 
Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, 
Virginia 20166.



Sec.  250.731  What information must I submit for BOP systems
 and system components?

    For any operation that requires the use of a BOP, you must include 
the information listed in this section with your applicable APD, APM, or 
other submittal. You are required to submit this information only once 
for each well, unless the information changes from what you provided in 
an earlier approved submission or you have moved off location from the 
well. After you have submitted this information for a particular well, 
subsequent APMs or other submittals for the well should reference the 
approved submittal containing the information required by this section 
and confirm that the information remains accurate and that you have not 
moved off location from that well. If the information changes or you 
have moved off location from the well, you must submit updated 
information in your next submission.

------------------------------------------------------------------------
         You must submit:                        Including:
------------------------------------------------------------------------
(a) A complete description of the   (1) Pressure ratings of BOP
 BOP system and system components,   equipment;
                                    (2) Proposed BOP test pressures (for
                                     subsea BOPs, include both surface
                                     and corresponding subsea
                                     pressures);
                                    (3) Rated capacities for liquid and
                                     gas for the fluid-gas separator
                                     system;
                                    (4) Control fluid volumes needed to
                                     close, seal, and open each
                                     component;
                                    (5) Control system pressure and
                                     regulator settings needed to
                                     achieve an effective seal of each
                                     ram BOP under MASP as defined for
                                     the operation;
                                    (6) Number and volume of accumulator
                                     bottles and bottle banks (for
                                     subsea BOP, include both surface
                                     and subsea bottles);
                                    (7) Accumulator pre-charge
                                     calculations (for subsea BOP,
                                     include both surface and subsea
                                     calculations);
                                    (8) All locking devices; and
                                    (9) Control fluid volume
                                     calculations for the accumulator
                                     system (for a subsea BOP system,
                                     include both the surface and subsea
                                     volumes).
(b) Schematic drawings,...........  (1) The inside diameter of the BOP
                                     stack;

[[Page 152]]

 
                                    (2) Number and type of preventers
                                     (including blade type for shear
                                     ram(s));
                                    (3) All locking devices;
                                    (4) Size range for variable bore
                                     ram(s);
                                    (5) Size of fixed ram(s);
                                    (6) All control systems with all
                                     alarms and set points labeled,
                                     including pods;
                                    (7) Location and size of choke and
                                     kill lines (and gas bleed line(s)
                                     for subsea BOP);
                                    (8) Associated valves of the BOP
                                     system;
                                    (9) Control station locations; and
                                    (10) A cross-section of the riser
                                     for a subsea BOP system showing
                                     number, size, and labeling of all
                                     control, supply, choke, and kill
                                     lines down to the BOP.
(c) Certification by a BSEE-        Verification that:
 approved verification              (1) Test data demonstrate the shear
 organization (BAVO),                ram(s) will shear the drill pipe at
                                     the water depth as required in Sec.
                                       250.732;
                                    (2) The BOP was designed, tested,
                                     and maintained to perform under the
                                     maximum environmental and
                                     operational conditions anticipated
                                     to occur at the well; and
                                    (3) The accumulator system has
                                     sufficient fluid to operate the BOP
                                     system without assistance from the
                                     charging system.
(d) Additional certification by a   Verification that:
 BAVO, if you use a subsea BOP, a   (1) The BOP stack is designed and
 BOP in an HPHT environment as       suitable for the specific equipment
 defined in Sec.   250.807, or a     on the rig and for the specific
 surface BOP on a floating           well design;
 facility,                          (2) The BOP stack has not been
                                     compromised or damaged from
                                     previous service; and
                                    (3) The BOP stack will operate in
                                     the conditions in which it will be
                                     used.
(e) If you are using a subsea BOP,  A listing of the functions with
 descriptions of autoshear,          their sequences and timing.
 deadman, and emergency disconnect
 sequence (EDS) systems,
(f) Certification stating that the  ....................................
 MIA Report required in Sec.
 250.732(d) has been submitted
 within the past 12 months for a
 subsea BOP, a BOP being used in
 an HPHT environment as defined in
 Sec.   250.807, or a surface BOP
 on a floating facility.
------------------------------------------------------------------------


    Effective Date Note: At 84 FR 21978, May 15, 2019, Sec.  250.731 was 
amended by removing paragraphs (d) and (f); redesignating paragraph (e) 
as (d), and revising paragraphs (a)(5) and (c), effective July 15, 2019. 
For the convenience of the user, the revised text is set forth as 
follows:



Sec.  250.731  What information must I submit for BOP systems and system 
          components?

                                * * * * *

------------------------------------------------------------------------
         You must submit:                        Including:
------------------------------------------------------------------------
(a) * * *.........................  (5) Control system pressure and
                                     regulator settings needed to close
                                     each ram BOP under MASP as defined
                                     for the operation;
 
                              * * * * * * *
(c) Certification by an             Verification that:
 independent third party,           (1) Test data demonstrate the shear
                                     ram(s) will shear the drill pipe at
                                     the water depth as required in Sec.
                                       250.732;
                                    (2) The BOP was designed, tested,
                                     and maintained to perform under the
                                     maximum environmental and
                                     operational conditions anticipated
                                     to occur at the well;
                                    (3) The accumulator system has
                                     sufficient fluid to operate the BOP
                                     system without assistance from the
                                     charging system; and
                                    (4) If using a subsea BOP, a BOP in
                                     an HPHT environment as defined in
                                     Sec.   250.804(b), or a surface BOP
                                     on a floating facility, the BOP has
                                     not been compromised or damaged
                                     from previous service.
 
                              * * * * * * *
------------------------------------------------------------------------


[[Page 153]]



Sec.  250.732  What are the BSEE-approved verification organization
 (BAVO) requirements for BOP systems and system components?

    (a) BSEE will maintain a list of BSEE-approved verification 
organizations (BAVOs) on its public website that you must use to satisfy 
any provision in this subpart that requires a BAVO certification, 
verification, report, or review. You must comply with all requirements 
in this subpart for BAVO certification, verification, or reporting no 
later than 1 year from the date BSEE publishes a list of BAVOs.
    (1) Until such time as you use a BAVO to perform the actions that 
this subpart requires to be performed by a BAVO, but not after 1 year 
from the date BSEE publishes a list of BAVOs, you must use an 
independent third-party meeting the criteria specified in paragraph 
(a)(2) of this section to prepare certifications, verifications, and 
reports as required by Sec. Sec.  250.731(c) and (d), 250.732 (b) and 
(c), 250.734(b)(1), 250.738(b)(4), and 250.739(b).
    (2) The independent third-party must be a technical classification 
society, or a licensed professional engineering firm, or a registered 
professional engineer capable of providing the certifications, 
verifications, and reports required under paragraph (a)(1) of this 
section.
    (3) For an organization to become a BAVO, it must submit the 
following information to the Chief, Office of Offshore Regulatory 
Programs; Bureau of Safety and Environmental Enforcement; 45600 Woodland 
Road, Sterling, Virginia, 20166, for BSEE review and approval:
    (i) Previous experience in verification or in the design, 
fabrication, installation, repair, or major modification of BOPs and 
related systems and equipment;
    (ii) Technical capabilities;
    (iii) Size and type of organization;
    (iv) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (v) Ability to perform the verification functions for projects 
considering current commitments;
    (vi) Previous experience with BSEE requirements and procedures; and
    (vii) Any additional information that may be relevant to BSEE's 
review.
    (b) Prior to beginning any operation requiring the use of any BOP, 
you must submit verification by a BAVO and supporting documentation as 
required by this paragraph to the appropriate District Manager and 
Regional Supervisor.

------------------------------------------------------------------------
 You must submit verification and
     documentation related to:                      That:
------------------------------------------------------------------------
(1) Shear testing,................  (i) Demonstrates that the BOP will
                                     shear the drill pipe and any
                                     electric-, wire-, and slick-line to
                                     be used in the well, no later than
                                     April 30, 2018;
                                    (ii) Demonstrates the use of test
                                     protocols and analysis that
                                     represent recognized engineering
                                     practices for ensuring the
                                     repeatability and reproducibility
                                     of the tests, and that the testing
                                     was performed by a facility that
                                     meets generally accepted quality
                                     assurance standards;
                                    (iii) Provides a reasonable
                                     representation of field
                                     applications, taking into
                                     consideration the physical and
                                     mechanical properties of the drill
                                     pipe;
                                    (iv) Ensures testing was performed
                                     on the outermost edges of the
                                     shearing blades of the shear ram
                                     positioning mechanism as required
                                     in Sec.   250.734(a)(16);
                                    (v) Demonstrates the shearing
                                     capacity of the BOP equipment to
                                     the physical and mechanical
                                     properties of the drill pipe; and
                                    (vi) Includes relevant testing
                                     results.
(2) Pressure integrity testing,     (i) Shows that testing is conducted
 and.                                immediately after the shearing
                                     tests;
                                    (ii) Demonstrates that the equipment
                                     will seal at the rated working
                                     pressures (RWP) of the BOP for 30
                                     minutes; and
                                    (iii) Includes all relevant test
                                     results.
(3) Calculations..................  Include shearing and sealing
                                     pressures for all pipe to be used
                                     in the well including corrections
                                     for MASP.
------------------------------------------------------------------------

    (c) For wells in an HPHT environment, as defined by Sec.  
250.807(b), you must submit verification by a BAVO that the verification 
organization conducted a comprehensive review of the BOP system and 
related equipment you

[[Page 154]]

propose to use. You must provide the BAVO access to any facility 
associated with the BOP system or related equipment during the review 
process. You must submit the verifications required by this paragraph 
(c) to the appropriate District Manager and Regional Supervisor before 
you begin any operations in an HPHT environment with the proposed 
equipment.

------------------------------------------------------------------------
           You must submit:                        Including:
------------------------------------------------------------------------
(1) Verification that the
 verification organization conducted
 a detailed review of the design
 package to ensure that all critical
 components and systems meet
 recognized engineering practices,
(2) Verification that the designs of   (i) Identification of all
 individual components and the          reasonable potential modes of
 overall system have been proven in a   failure; and
 testing process that demonstrates     (ii) Evaluation of the design
 the performance and reliability of     verification tests. The design
 the equipment in a manner that is      verification tests must assess
 repeatable and reproducible,           the equipment for the identified
                                        potential modes of failure.
(3) Verification that the BOP
 equipment will perform as designed
 in the temperature, pressure, and
 environment that will be
 encountered, and
(4) Verification that the              For the quality control and
 fabrication, manufacture, and          assurance mechanisms, complete
 assembly of individual components      material and quality controls
 and the overall system uses            over all contractors,
 recognized engineering practices and   subcontractors, distributors,
 quality control and assurance          and suppliers at every stage in
 mechanisms.                            the fabrication, manufacture,
                                        and assembly process.
------------------------------------------------------------------------

    (d) Once every 12 months, you must submit a Mechanical Integrity 
Assessment Report for a subsea BOP, a BOP being used in an HPHT 
environment as defined in Sec.  250.807, or a surface BOP on a floating 
facility. This report must be completed by a BAVO. You must submit this 
report to the Chief, Office of Offshore Regulatory Programs; Bureau of 
Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, VA 
20166. This report must include:
    (1) A determination that the BOP stack and system meets or exceeds 
all BSEE regulatory requirements, industry standards incorporated into 
this subpart, and recognized engineering practices.
    (2) Verification that complete documentation of the equipment's 
service life exists that demonstrates that the BOP stack has not been 
compromised or damaged during previous service.
    (3) A description of all inspection, repair and maintenance records 
reviewed, and verification that all repairs, replacement parts, and 
maintenance meet regulatory requirements, recognized engineering 
practices, and OEM specifications.
    (4) A description of records reviewed related to any modifications 
to the equipment and verification that any such changes do not adversely 
affect the equipment's capability to perform as designed or invalidate 
test results.
    (5) A description of the Safety and Environmental Management Systems 
(SEMS) plans reviewed related to assurance of quality and mechanical 
integrity of critical equipment and verification that the plans are 
comprehensive and fully implemented.
    (6) Verification that the qualification and training of inspection, 
repair, and maintenance personnel for the BOP systems meet recognized 
engineering practices and any applicable OEM requirements.
    (7) A description of all records reviewed covering OEM safety 
alerts, all failure reports, and verification that any design or 
maintenance issues have been completely identified and corrected.
    (8) A comprehensive assessment of the overall system and 
verification that all components (including mechanical, hydraulic, 
electrical, and software) are compatible.
    (9) Verification that documentation exists concerning the 
traceability of the fabrication, repair, and maintenance of all critical 
components.
    (10) Verification of use of a formal maintenance tracking system to 
ensure that corrective maintenance and scheduled maintenance is 
implemented in a timely manner.
    (11) Identification of gaps or deficiencies related to inspection 
and

[[Page 155]]

maintenance procedures and documentation, documentation of any deferred 
maintenance, and verification of the completion of corrective action 
plans.
    (12) Verification that any inspection, maintenance, or repair work 
meets the manufacturer's design and material specifications.
    (13) Verification of written procedures for operating the BOP stack 
and Lower Marine Riser Package (LMRP) (including proper techniques to 
prevent accidental disconnection of these components) and minimum 
knowledge requirements for personnel authorized to operate and maintain 
BOP components.
    (14) Recommendations, if any, for how to improve the fabrication, 
installation, operation, maintenance, inspection, and repair of the 
equipment.
    (e) You must make all documentation that supports the requirements 
of this section available to BSEE upon request.

    Effective Date Note: At 84 FR 21978, May 15, 2019, Sec.  250.732 was 
revised, effective July 15, 2019. For the convenience of the user, the 
revised text is set forth as follows:



Sec.  250.732  What are the independent third party requirements for BOP 
          systems and system components?

    (a) Prior to beginning any operation requiring the use of any BOP, 
you must submit verification by an independent third party and 
supporting documentation as required by this paragraph to the 
appropriate District Manager and Regional Supervisor.

------------------------------------------------------------------------
 You must submit verification and
     documentation related to:                      That:
------------------------------------------------------------------------
(1) Shear testing,................  (i) Demonstrates that the BOP will
                                     shear the tubular body of any drill
                                     pipe (excluding tool joints, bottom-
                                     hole tools, and bottom hole
                                     assemblies such as heavy-weight
                                     pipe or collars), workstring,
                                     tubing and associated exterior
                                     control lines and any electric-,
                                     wire-, and slick-line to be used in
                                     the well;
                                    (ii) Demonstrates the use of test
                                     protocols and analysis that
                                     represent recognized engineering
                                     practices for ensuring the
                                     repeatability and reproducibility
                                     of the tests, and that the testing
                                     was performed by a facility that
                                     meets generally accepted quality
                                     assurance standards;
                                    (iii) Provides a reasonable
                                     representation of field
                                     applications, taking into
                                     consideration the physical and
                                     mechanical properties of the
                                     tubular body of any drill pipe
                                     (excluding tool joints, bottom-hole
                                     tools, and bottom hole assemblies
                                     such as heavy-weight pipe or
                                     collars), workstring, tubing and
                                     associated exterior control lines
                                     and any electric-, wire-, and slick-
                                     line to be used in the well;
                                    (iv) Ensures testing was performed
                                     on the outermost edges of the
                                     shearing blades of the shear ram;
                                    (v) Demonstrates the shearing
                                     capacity of the BOP equipment to
                                     the physical and mechanical
                                     properties of the tubular body of
                                     any drill pipe (excluding tool
                                     joints, bottom-hole tools, and
                                     bottom hole assemblies such as
                                     heavy-weight pipe or collars),
                                     workstring, tubing and associated
                                     exterior control lines and any
                                     electric-, wire-, and slick-line to
                                     be used in the well; and
                                    (vi) Includes relevant testing
                                     results.
(2) Pressure integrity testing for  (i) Shows that testing is conducted
 sealing components, and             after the shearing is completed and
                                     prior to opening the component;
                                    (ii) Demonstrates that the equipment
                                     will seal at the rated working
                                     pressures (RWP) of the BOP for 5
                                     minutes; and
                                    (iii) Includes all relevant test
                                     results.
(3) Calculations                    Include shearing and sealing
                                     pressures for all pipe to be used
                                     in the well including corrections
                                     for MASP.
------------------------------------------------------------------------

    (b) The independent third-party must be a technical classification 
society, a licensed professional engineering firm, or a registered 
professional engineer capable of providing the required certifications 
and verifications.
    (c) For wells in an HPHT environment, as defined by Sec.  
250.804(b), you must submit verification by an independent third party 
that it conducted a comprehensive review of the BOP system and related 
equipment you propose to use. You must provide the independent third 
party access to any facility associated with the BOP system or related 
equipment during the review process. You must submit the verifications 
required by this paragraph (c) to the appropriate District Manager and 
Regional Supervisor before you begin any operations in an HPHT 
environment with the proposed equipment.

[[Page 156]]



------------------------------------------------------------------------
            You must submit:                        Including:
------------------------------------------------------------------------
(1) Verification that the independent
 third party conducted a detailed
 review of the design package to ensure
 that all critical components and
 systems meet recognized engineering
 practices,
(2) Verification that the designs of     (i) Identification of all
 individual components and the overall    reasonable potential modes of
 system have been proven in a testing     failure; and
 process that demonstrates the           (ii) Evaluation of the design
 performance and reliability of the       verification tests. The design
 equipment in a manner that is            verification tests must assess
 repeatable and reproducible,             the equipment for the
                                          identified potential modes of
                                          failure.
(3) Verification that the BOP equipment
 will perform as designed in the
 temperature, pressure, and environment
 that will be encountered, and
(4) Verification that the fabrication,   For the quality control and
 manufacture, and assembly of             assurance mechanisms, complete
 individual components and the overall    material and quality controls
 system uses recognized engineering       over all contractors,
 practices and quality control and        subcontractors, distributors,
 assurance mechanisms.                    and suppliers at every stage
                                          in the fabrication,
                                          manufacture, and assembly
                                          process.
------------------------------------------------------------------------

    (d) You must make all documentation that demonstrates compliance 
with the requirements of this section available to BSEE upon request.



Sec.  250.733  What are the requirements for a surface BOP stack?

    (a) When you drill or conduct operations with a surface BOP stack, 
you must install the BOP system before drilling or conducting operations 
to deepen the well below the surface casing and after the well is 
deepened below the surface casing point. The surface BOP stack must 
include at least four remote-controlled, hydraulically operated BOPs, 
consisting of one annular BOP, one BOP equipped with blind shear rams, 
and two BOPs equipped with pipe rams.
    (1) The blind shear rams must be capable of shearing at any point 
along the tubular body of any drill pipe (excluding tool joints, bottom-
hole tools, and bottom hole assemblies that include heavy-weight pipe or 
collars), workstring, tubing provided that the capability to shear 
tubing with exterior control lines is not required prior to April 30, 
2018, and any electric-, wire-, and slick-line that is in the hole and 
sealing the wellbore after shearing. If your blind shear rams are unable 
to cut any electric-, wire-, or slick-line under MASP as defined for the 
operation and seal the wellbore, you must use an alternative cutting 
device capable of shearing the lines before closing the BOP. This device 
must be available on the rig floor during operations that require their 
use.
    (2) The two BOPs equipped with pipe rams must be capable of closing 
and sealing on the tubular body of any drill pipe, workstring, and 
tubing under MASP, as defined for the operation, except for tubing with 
exterior control lines and flat packs, a bottom hole assembly that 
includes heavy-weight pipe or collars, and bottom-hole tools.
    (b) If you plan to use a surface BOP on a floating production 
facility you must:
    (1) For BOPs installed after April 29, 2019, follow the BOP 
requirements in Sec.  250.734(a)(1).
    (2) For risers installed after July 28, 2016, use a dual bore riser 
configuration before drilling or operating in any hole section or 
interval where hydrocarbons are, or may be, exposed to the well. The 
dual bore riser must meet the design requirements of API RP 2RD (as 
incorporated by reference in Sec.  250.198), including appropriate 
design for the maximum anticipated operating and environmental 
conditions.
    (i) For a dual bore riser configuration, the annulus between the 
risers must be monitored for pressure during operations. You must 
describe in your APD or APM your annulus monitoring plan and how you 
will secure the well in the event a leak is detected.
    (ii) The inner riser for a dual riser configuration is subject to 
the requirements at Sec.  250.721 for testing the casing or liner.
    (c) You must install separate side outlets on the BOP stack for the 
kill and choke lines. If your stack does not have side outlets, you must 
install a drilling spool with side outlets. The outlet valves must hold 
pressure from both directions.

[[Page 157]]

    (d) You must install a choke and a kill line on the BOP stack. You 
must equip each line with two full-bore, full-opening valves, one of 
which must be remote-controlled. On the kill line, you may install a 
check valve and a manual valve instead of the remote-controlled valve. 
To use this configuration, both manual valves must be readily accessible 
and you must install the check valve between the manual valves and the 
pump.

    Effective Date Note: At 84 FR 21979, May 15, 2019, Sec.  250.733 was 
amended by revising paragraphs (a)(1) and (b)(1), and adding paragraph 
(e), effective July 15, 2019. For the convenience of the user, the added 
and revised text is set forth as follows:



Sec.  250.733  What are the requirements for a surface BOP stack?

    (a) * * *
    (1) The blind shear rams must be capable of shearing at any point 
along the tubular body of any drill pipe (excluding tool joints, bottom-
hole tools, and bottom hole assemblies that include heavy-weight pipe or 
collars), workstring, tubing and associated exterior control lines, and 
any electric-, wire-, and slick-line that is in the hole and sealing the 
wellbore after shearing. Prior to April 29, 2021, if your blind shear 
rams are unable to cut any electric-, wire-, or slick-line under MASP as 
defined for the operation and seal the wellbore, you must use an 
alternative cutting device capable of shearing the lines before closing 
the BOP. This device must be available on the rig floor during 
operations that require their use.

                                * * * * *

    (b) * * *
    (1) On new floating production facilities installed after April 29, 
2021, that include a surface BOP, follow the BOP requirements in Sec.  
250.734(a)(1).

                                * * * * *

    (e) Additional requirements for surface BOP systems used in well-
completion, workover, and decommissioning operations. The minimum BOP 
system for well-completion, workover, and decommissioning operations 
must meet the appropriate standards from the following table:

------------------------------------------------------------------------
                                    The minimum BOP stack must include .
            When . . .                               . .
------------------------------------------------------------------------
(1) The expected pressure is less   Three BOPs consisting of an annular,
 than 5,000 psi,                     one set of pipe rams, and one set
                                     of blind-shear rams.
(2) The expected pressure is 5,000  Four BOPs consisting of an annular,
 psi or greater or you use           two sets of pipe rams, and one set
 multiple tubing strings,            of blind-shear rams.
(3) You handle multiple tubing      Four BOPs consisting of an annular,
 strings simultaneously,             one set of pipe rams, one set of
                                     dual pipe rams, and one set of
                                     blind-shear rams.
(4) You use a tapered drill pipe,   At least one set of pipe rams that
 work string, or tubing,             are capable of sealing around each
                                     size of drill pipe, work string, or
                                     tubing. If the expected pressure is
                                     greater than 5,000 psi, then you
                                     must have at least two sets of pipe
                                     rams that are capable of sealing
                                     around the larger size drill pipe,
                                     work string, or tubing. You may
                                     substitute one set of variable bore
                                     rams for two sets of pipe rams.
(5) You use a surface BOP on a      The elements required by Sec.
 floating facility,                  250.733(b)(1) of this part.
------------------------------------------------------------------------



Sec.  250.734  What are the requirements for a subsea BOP system?

    (a) When you drill or conduct operations with a subsea BOP system, 
you must install the BOP system before drilling to deepen the well below 
the surface casing or before conducting operations if the well is 
already deepened beyond the surface casing point. The District Manager 
may require you to install a subsea BOP system before drilling or 
conducting operations below the conductor casing if proposed casing 
setting depths or local geology indicate the need. The following table 
outlines your requirements.

------------------------------------------------------------------------
 When operating with a subsea BOP system,
                 you must:                    Additional requirements:
------------------------------------------------------------------------
(1) Have at least five remote-controlled,   You must have at least one
 hydraulically operated BOPs;                annular BOP, two BOPs
                                             equipped with pipe rams,
                                             and two BOPs equipped with
                                             shear rams. For the dual
                                             ram requirement, you must
                                             comply with this
                                             requirement no later than
                                             April 29, 2021.

[[Page 158]]

 
                                            (i) Both BOPs equipped with
                                             pipe rams must be capable
                                             of closing and sealing on
                                             the tubular body of any
                                             drill pipe, workstring, and
                                             tubing under MASP, as
                                             defined for the operation,
                                             except tubing with exterior
                                             control lines and flat
                                             packs, a bottom hole
                                             assembly that includes
                                             heavy-weight pipe or
                                             collars, and bottom-hole
                                             tools.
                                            (ii) Both shear rams must be
                                             capable of shearing at any
                                             point along the tubular
                                             body of any drill pipe
                                             (excluding tool joints,
                                             bottom-hole tools, and
                                             bottom hole assemblies such
                                             as heavy-weight pipe or
                                             collars), workstring,
                                             tubing provided that the
                                             capability to shear tubing
                                             with exterior control lines
                                             is not required prior to
                                             April 30, 2018, appropriate
                                             area for the liner or
                                             casing landing string,
                                             shear sub on subsea test
                                             tree, and any electric-,
                                             wire-, slick-line in the
                                             hole no later than April
                                             30, 2018; under MASP. At
                                             least one shear ram must be
                                             capable of sealing the
                                             wellbore after shearing
                                             under MASP conditions as
                                             defined for the operation.
                                             Any non-sealing shear
                                             ram(s) must be installed
                                             below a sealing shear
                                             ram(s).
(2) Have an operable redundant pod control
 system to ensure proper and independent
 operation of the BOP system;
(3) Have the accumulator capacity located   The accumulator capacity
 subsea, to provide fast closure of the      must:
 BOP components and to operate all          (i) Operate each required
 critical functions in case of a loss of     shear ram, ram locks, one
 the power fluid connection to the           pipe ram, and disconnect
 surface;                                    the LMRP.
                                            (ii) Have the capability of
                                             delivering fluid to each
                                             ROV function i.e., flying
                                             leads.
                                            (iii) No later than April
                                             29, 2021, have bottles for
                                             the autoshear, and deadman
                                             that are dedicated to, but
                                             may be shared between,
                                             those functions.
                                            (iv) Perform under MASP
                                             conditions as defined for
                                             the operation.
(4) Have a subsea BOP stack equipped with   The ROV must be capable of
 remotely operated vehicle (ROV)             opening and closing each
 intervention capability;                    shear ram, ram locks, one
                                             pipe ram, and LMRP
                                             disconnect under MASP
                                             conditions as defined for
                                             the operation. The ROV
                                             panels on the BOP and LMRP
                                             must be compliant with API
                                             RP 17H (as incorporated by
                                             reference in Sec.
                                             250.198).
(5) Maintain an ROV and have a trained ROV  The crew must be trained in
 crew on each rig unit on a continuous       the operation of the ROV.
 basis once BOP deployment has been          The training must include
 initiated from the rig until recovered to   simulator training on
 the surface. The ROV crew must examine      stabbing into an ROV
 all ROV-related well-control equipment      intervention panel on a
 (both surface and subsea) to ensure that    subsea BOP stack. The ROV
 it is properly maintained and capable of    crew must be in
 carrying out appropriate tasks during       communication with
 emergency operations;                       designated rig personnel
                                             who are knowledgeable about
                                             the BOP's capabilities.
(6) Provide autoshear, deadman, and EDS     (i) Autoshear system means a
 systems for dynamically positioned rigs;    safety system that is
 provide autoshear and deadman systems for   designed to automatically
 moored rigs;                                shut-in the wellbore in the
                                             event of a disconnect of
                                             the LMRP. This is
                                             considered a rapid
                                             discharge system.
                                            (ii) Deadman system means a
                                             safety system that is
                                             designed to automatically
                                             shut-in the wellbore in the
                                             event of a simultaneous
                                             absence of hydraulic supply
                                             and signal transmission
                                             capacity in both subsea
                                             control pods. This is
                                             considered a rapid
                                             discharge system.
                                            (iii) Emergency Disconnect
                                             Sequence (EDS) system means
                                             a safety system that is
                                             designed to be manually
                                             activated to shut-in the
                                             wellbore and disconnect the
                                             LMRP in the event of an
                                             emergency situation. This
                                             is considered a rapid
                                             discharge system.
                                            (iv) Each emergency function
                                             must close at a minimum,
                                             two shear rams in sequence
                                             and be capable of
                                             performing its expected
                                             shearing and sealing action
                                             under MASP conditions as
                                             defined for the operation.
                                            (v) Your sequencing must
                                             allow a sufficient delay
                                             for closing the upper shear
                                             ram after beginning closure
                                             of the lower shear ram to
                                             provide for maximum sealing
                                             efficiency.
                                            (vi) The control system for
                                             the emergency functions
                                             must be a fail-safe design
                                             once activated.

[[Page 159]]

 
(7) Demonstrate that any acoustic control   If you choose to use an
 system will function in the proposed        acoustic control system in
 environment and conditions;                 addition to the autoshear,
                                             deadman, and EDS
                                             requirements, you must
                                             demonstrate to the District
                                             Manager, as part of the
                                             information submitted under
                                             Sec.   250.731, that the
                                             acoustic control system
                                             will function in the
                                             proposed environment and
                                             conditions. The District
                                             Manager may require
                                             additional information as
                                             appropriate to clarify or
                                             evaluate the acoustic
                                             control system information
                                             provided in your
                                             demonstration.
(8) Have operational or physical            You must incorporate enable
 barrier(s) on BOP control panels to         buttons, or a similar
 prevent accidental disconnect functions;    feature, on control panels
                                             to ensure two-handed
                                             operation for all critical
                                             functions.
(9) Clearly label all control panels for    Label other BOP control
 the subsea BOP system;                      panels, such as hydraulic
                                             control panel.
(10) Develop and use a management system    The management system must
 for operating the BOP system, including     include written procedures
 the prevention of accidental or unplanned   for operating the BOP stack
 disconnects of the system;                  and LMRP (including proper
                                             techniques to prevent
                                             accidental disconnection of
                                             these components) and
                                             minimum knowledge
                                             requirements for personnel
                                             authorized to operate and
                                             maintain BOP components.
(11) Establish minimum requirements for     Personnel must have:
 personnel authorized to operate critical   (i) Training in deepwater
 BOP equipment;                              well-control theory and
                                             practice according to the
                                             requirements of Subparts O
                                             and S; and
                                            (ii) A comprehensive
                                             knowledge of BOP hardware
                                             and control systems.
(12) Before removing the marine riser,      You must maintain sufficient
 displace the fluid in the riser with        hydrostatic pressure or
 seawater;                                   take other suitable
                                             precautions to compensate
                                             for the reduction in
                                             pressure and to maintain a
                                             safe and controlled well
                                             condition. You must follow
                                             the requirements of Sec.
                                             250.720(b).
(13) Install the BOP stack in a well        Your well cellar must be
 cellar when in an ice-scour area;           deep enough to ensure that
                                             the top of the stack is
                                             below the deepest probable
                                             ice-scour depth.
(14) Install at least two side outlets for  (i) If your stack does not
 a choke line and two side outlets for a     have side outlets, you must
 kill line;                                  install a drilling spool
                                             with side outlets.
                                            (ii) Each side outlet must
                                             have two full-bore, full-
                                             opening valves.
                                            (iii) The valves must hold
                                             pressure from both
                                             directions and must be
                                             remote-controlled.
                                            (iv) You must install a side
                                             outlet below the lowest
                                             sealing shear ram. You may
                                             have a pipe ram or rams
                                             between the shearing ram
                                             and side outlet.
(15) Install a gas bleed line with two      (i) The valves must hold
 valves for the annular preventer no later   pressure from both
 than April 30, 2018;                        directions;
                                            (ii) If you have dual
                                             annulars, you must install
                                             the gas bleed line below
                                             the upper annular.
(16) Use a BOP system that has the          (i) A mechanism coupled with
 following mechanisms and capabilities;      each shear ram to position
                                             the entire pipe, completely
                                             within the area of the
                                             shearing blade and ensure
                                             shearing will occur any
                                             time the shear rams are
                                             activated. This mechanism
                                             cannot be another ram BOP
                                             or annular preventer, but
                                             you may use those during a
                                             planned shear. You must
                                             install this mechanism no
                                             later than May 1, 2023;
                                            (ii) The ability to mitigate
                                             compression of the pipe
                                             stub between the shearing
                                             rams when both shear rams
                                             are closed;
                                            (iii) If your control pods
                                             contain a subsea electronic
                                             module with batteries, a
                                             mechanism for personnel on
                                             the rig to monitor the
                                             state of charge of the
                                             subsea electronic module
                                             batteries in the BOP
                                             control pods.
------------------------------------------------------------------------

    (b) If operations are suspended to make repairs to any part of the 
subsea BOP system, you must stop operations at a safe downhole location. 
Before resuming operations you must:
    (1) Submit a revised permit with a verification report from a BAVO 
documenting the repairs and that the BOP is fit for service;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in 
accordance with Sec.  250.737(d)(4), including deadman. If repairs take 
longer than 30days, once the BOP is on deck, you must test in accordance 
with the requirements of Sec.  250.737; and
    (3) Receive approval from the District Manager.
    (c) If you plan to drill a new well with a subsea BOP, you do not 
need to submit with your APD the verifications required by this subpart 
for the open water drilling operation. Before drilling out the surface 
casing, you must submit for approval a revised

[[Page 160]]

APD, including the verifications required in this subpart.

    Effective Date Note: At 84 FR 21980, May 15, 2019, Sec.  250.734 was 
amended by removing paragraph (a)(6)(vi) and revising paragraphs 
(a)(1)(ii), (a)(3), (a)(4), (a)(6)(iv), (a)(6)(v), (a)(16), and (b), 
effective July 15, 2019. For the convenience of the user, the revised 
text is set forth as follows:



Sec.  250.734  What are the requirements for a subsea BOP system?

    (a) * * *

------------------------------------------------------------------------
 When operating with a subsea
    BOP system, you must:               Additional requirements
------------------------------------------------------------------------
(1) * * *....................  (ii) Both shear rams must be capable of
                                shearing at any point along the tubular
                                body of any drill pipe (excluding tool
                                joints, bottom-hole tools, and bottom
                                hole assemblies such as heavy-weight
                                pipe or collars), workstring, tubing and
                                associated exterior control lines,
                                appropriate area for the liner or casing
                                landing string, shear sub on subsea test
                                tree, and any electric-, wire-, slick-
                                line in the hole; under MASP. At least
                                one shear ram must be capable of sealing
                                the wellbore after shearing under MASP
                                conditions as defined for the operation.
                                Any non-sealing shear ram(s) must be
                                installed below a sealing shear ram(s).
 
                              * * * * * * *
(3) Have the accumulator       The accumulator capacity must:
 capacity, to provide fast     (i) Close each required shear ram, ram
 closure of the BOP             locks, one pipe ram, and disconnect the
 components and to operate      LMRP.
 all critical functions;       (ii) Have the capability to perform ROV
                                functions within the required times
                                outlined in API Standard 53 with ROV or
                                flying leads.
                               (iii) Have bottles located subsea for the
                                autoshear and deadman (which may be
                                shared between those two systems) to
                                secure the wellbore. These bottles may
                                also be utilized to perform the
                                secondary control system functions
                                (e.g., ROV or acoustic functions).
                               (iv) Perform under MASP conditions as
                                defined for the operation.
(4) * * *....................  You must have the ROV intervention
                                capability to close each shear ram, ram
                                locks, one pipe ram, and disconnect the
                                LMRP under MASP conditions as defined
                                for the operation. You must be capable
                                of performing these functions in the
                                response times outlined in API Standard
                                53 (as incorporated by reference in Sec.
                                  250.198). The ROV panels on the BOP
                                and LMRP must be compliant with API RP
                                17H (as incorporated by reference in
                                Sec.   250.198).
 
                              * * * * * * *
(6) * * *....................  (iv) Autoshear/deadman functions and an
                                EDS mode must close, at a minimum, two
                                shear rams in sequence and be capable of
                                performing their expected shearing and
                                sealing action under MASP conditions as
                                defined for the operation.
                               (v) Your sequencing must allow a
                                sufficient delay when closing your two
                                shear rams in order to provide maximum
                                sealing efficiency.
 
                              * * * * * * *
(16) Use a BOP system that     (i) No later than May 1, 2023, you must
 has the following mechanisms   have the capability to position the
 and capabilities;              entire pipe completely within the area
                                of the shearing blade. This capability
                                cannot be a separate ram BOP or annular
                                preventer, but you may use those during
                                a planned shear.
                               (ii) If your control pods contain a
                                subsea electronic module with batteries,
                                a mechanism for personnel on the rig to
                                monitor the state of charge of the
                                subsea electronic module batteries in
                                the BOP control pods.
------------------------------------------------------------------------

    (b) If you suspend operations to make repairs to any part of the 
subsea BOP system, you must stop operations at a safe downhole location. 
Before resuming operations you must:
    (1) Submit a revised permit with a written statement from an 
independent third party documenting the repairs and certifying that the 
previous certification in Sec.  250.731(c) remains valid;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in 
accordance with Sec.  250.737(d)(4), including deadman in accordance 
with Sec.  250.737(d)(12)(vi). If repairs take longer than 30 days, once 
the BOP is on deck, you must test in accordance with the requirements of 
Sec.  250.737;
    (3) Upon relatch of the LMRP, you must test according to the 
following:
    (i) Pressure test riser connector/gasket in accordance with Sec.  
250.737(b) and (c);
    (ii) Pressure test choke and kill stabs at LMRP/BOP interface in 
accordance with Sec.  250.737(b) and (c);
    (iii) Full function test of both pods and both control panels;
    (iv) Verify acoustic pod communication (if equipped); and
    (v) Deadman test with pressure test in accordance with Sec.  
250.737(d)(12)(vi).
    (4) Receive approval from the District Manager.

                                * * * * *

[[Page 161]]



Sec.  250.735  What associated systems and related equipment must
 all BOP systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An accumulator system (as specified in API Standard 53, and 
incorporated by reference in Sec.  250.198) that provides the volume of 
fluid capacity (as specified in API Standard 53, Annex C) necessary to 
close and hold closed all BOP components against MASP. The system must 
operate under MASP conditions as defined for the operation. You must be 
able to operate the BOP functions as defined in API Standard 53, without 
assistance from a charging system, and still have a minimum pressure of 
200 psi remaining on the bottles above the pre-charge pressure. If you 
supply the accumulator regulators by rig air and do not have a secondary 
source of pneumatic supply, you must equip the regulators with manual 
overrides or other devices to ensure capability of hydraulic operations 
if rig air is lost;
    (b) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components under MASP conditions as defined for the operation;
    (c) At least two full BOP control stations. One station must be on 
the rig floor. You must locate the other station in a readily accessible 
location away from the rig floor;
    (d) The choke line(s) installed above the bottom well-control ram;
    (e) The kill line must be installed beneath at least one well-
control ram, and may be installed below the bottom ram;
    (f) A fill-up line above the uppermost BOP;
    (g) Locking devices for all BOP sealing rams (i.e., blind shear 
rams, pipe rams and variable bore rams), as follows:
    (1) For subsea BOPs, hydraulic locking devices must be installed on 
all sealing rams;
    (2) For surface BOPs:
    (i) Remotely-operated locking devices must be installed on blind 
shear rams no later than April 29, 2019;
    (ii) Manual or remotely-operated locking devices must be installed 
on pipe rams and variable bore rams; and
    (h) A wellhead assembly with a RWP that exceeds the maximum 
anticipated wellhead pressure.

    Effective Date Note: At 84 FR 21981, May 15, 2019, Sec.  250.735 was 
amended by revising paragraph (a), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.735  What associated systems and related equipment must all 
          BOP systems include?

                                * * * * *

    (a) An accumulator system (as specified in API Standard 53, 
incorporated by reference in Sec.  250.198). Your accumulator system 
must have the fluid volume capacity and appropriate pre-charge pressures 
in accordance with API Standard 53. If you supply the accumulator 
regulators by rig air and do not have a secondary source of pneumatic 
supply, you must equip the regulators with manual overrides or other 
devices to ensure capability of hydraulic operations if rig air is lost;

                                * * * * *



Sec.  250.736  What are the requirements for choke manifolds,
 kelly-type valves inside BOPs, and drill string safety valves?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, and 
abrasiveness of drilling fluids and well fluids that you may encounter.
    (b) Choke manifold components must have a RWP at least as great as 
the RWP of the ram BOPs. If your choke manifold has buffer tanks 
downstream of choke assemblies, you must install isolation valves on any 
bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings upstream 
of the choke manifold must have a RWP at least as great as the RWP of 
the ram BOPs.
    (d) You must use the following BOP equipment with a RWP and 
temperature of at least as great as the working

[[Page 162]]

pressure and temperature of the ram BOP during all operations:
    (1) The applicable kelly-type valves as described in API Standard 53 
(incorporated by reference in Sec.  250.198);
    (2) On a top-drive system equipped with a remote-controlled valve, a 
strippable kelly-type valve must be installed below the remote-
controlled valve;
    (3) An inside BOP in the open position located on the rig floor. You 
must be able to install an inside BOP for each size connection in the 
pipe;
    (4) A drill string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the pipe;
    (5) When running casing, a safety valve in the open position 
available on the rig floor to fit the casing string being run in the 
hole;
    (6) All required manual and remote- controlled kelly-type valves, 
drill-string safety valves, and comparable-type valves (i.e., kelly-type 
valve in a top-drive system) that are essentially full opening; and
    (7) A wrench to fit each manual valve. Each wrench must be readily 
accessible to the drilling crew.

    Effective Date Note: At 84 FR 21981, May 15, 2019, Sec.  250.736 was 
amended by revising paragraph (d)(5), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.736  What are the requirements for choke manifolds, kelly-type 
          valves inside BOPs, and drill string safety valves?

                                * * * * *

    (d) * * *
    (5) When running casing, a safety valve in the open position 
available on the rig floor to fit the casing string being run in the 
hole. For subsea BOPs, the safety valve must be available on the rig 
floor if the length of casing being run exceeds the water depth, which 
would result in the casing being across the BOP stack and the rig floor 
prior to crossing over to the drill pipe running string;

                                * * * * *



Sec.  250.737  What are the BOP system testing requirements?

    Your BOP system (this includes the choke manifold, kelly-type 
valves, inside BOP, and drill string safety valve) must meet the 
following testing requirements:
    (a) Pressure test frequency. You must pressure test your BOP system:
    (1) When installed;
    (2) Before 14 days have elapsed since your last BOP pressure test, 
or 30 days since your last blind shear ram BOP pressure test. You must 
begin to test your BOP system before midnight on the 14th day (or 30th 
day for your blind shear rams) following the conclusion of the previous 
test;
    (3) Before drilling out each string of casing or a liner. You may 
omit this pressure test requirement if you did not remove the BOP stack 
to run the casing string or liner, the required BOP test pressures for 
the next section of the hole are not greater than the test pressures for 
the previous BOP test, and the time elapsed between tests has not 
exceeded 14 days (or 30 days for blind shear rams). You must indicate in 
your APD which casing strings and liners meet these criteria;
    (4) The District Manager may require more frequent testing if 
conditions or your BOP performance warrant.
    (b) Pressure test procedures. When you pressure test the BOP system, 
you must conduct a low-pressure test and a high-pressure test for each 
BOP component. You must begin each test by conducting the low-pressure 
test then transition to the high-pressure test. Each individual pressure 
test must hold pressure long enough to demonstrate the tested 
component(s) holds the required pressure. The table in this paragraph 
(b) outlines your pressure test requirements.

------------------------------------------------------------------------
                                         According to the following
     You must conduct a . . .                 procedures . . .
------------------------------------------------------------------------
(1) Low-pressure test.............  All low-pressure tests must be
                                     between 250 and 350 psi. Any
                                     initial pressure above 350 psi must
                                     be bled back to a pressure between
                                     250 and 350 psi before starting the
                                     test. If the initial pressure
                                     exceeds 500 psi, you must bleed
                                     back to zero and reinitiate the
                                     test.

[[Page 163]]

 
(2) High-pressure test for blind    The high-pressure test must equal
 shear ram-type BOPs, ram-type       the RWP of the equipment or be 500
 BOPs, the choke manifold, outside   psi greater than your calculated
 of all choke and kill side outlet   MASP, as defined for the operation
 valves (and annular gas bleed       for the applicable section of hole.
 valves for subsea BOP), inside of   Before you may test BOP equipment
 all choke and kill side outlet      to the MASP plus 500 psi, the
 valves below uppermost ram, and     District Manager must have approved
 other BOP components.               those test pressures in your APD.
(3) High-pressure test for annular- The high pressure test must equal 70
 type BOPs, inside of choke or       percent of the RWP of the equipment
 kill valves (and annular gas        or be 500 psi greater than your
 bleed valves for subsea BOP)        calculated MASP, as defined for the
 above the uppermost ram BOP.        operation for the applicable
                                     section of hole. Before you may
                                     test BOP equipment to the MASP plus
                                     500 psi, the District Manager must
                                     have approved those test pressures
                                     in your APD.
------------------------------------------------------------------------

    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes, which must be recorded on a chart not exceeding 
4 hours. However, for surface BOP systems and surface equipment of a 
subsea BOP system, a 3-minute test duration is acceptable if recorded on 
a chart not exceeding 4 hours, or on a digital recorder. The recorded 
test pressures must be within the middle half of the chart range, i.e., 
cannot be within the lower or upper one-fourth of the chart range. If 
the equipment does not hold the required pressure during a test, you 
must correct the problem and retest the affected component(s).
    (d) Additional test requirements. You must meet the following 
additional BOP testing requirements:

------------------------------------------------------------------------
          You must . . .                Additional requirements . . .
------------------------------------------------------------------------
(1) Follow the testing              If there is a conflict between API
 requirements of API Standard 53     Standard 53, testing requirements
 (as incorporated in Sec.            and this section, you must follow
 250.198).                           the requirements of this section.
(2) Use water to test a surface     (i) You must submit test procedures
 BOP system on the initial test.     with your APD or APM for District
 You may use drilling/completion/    Manager approval.
 workover fluids to conduct         (ii) Contact the District Manager at
 subsequent tests of a surface BOP   least 72 hours prior to beginning
 system.                             the initial test to allow BSEE
                                     representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the initial test
                                     results to the appropriate District
                                     Manager within 72 hours after
                                     completion of the tests.
(3) Stump test a subsea BOP system  (i) You must use water to conduct
 before installation.                this test. You may use drilling/
                                     completion/workover fluids to
                                     conduct subsequent tests of a
                                     subsea BOP system.
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval
                                    (iii) Contact the District Manager
                                     at least 72 hours prior to
                                     beginning the stump test to allow
                                     BSEE representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the test results to
                                     the appropriate District Manager
                                     within 72 hours after completion of
                                     the tests.
                                    (iv) You must test and verify
                                     closure of all ROV intervention
                                     functions on your subsea BOP stack
                                     during the stump test.
                                    (v) You must follow paragraphs (b)
                                     and (c) of this section.
(4) Perform an initial subsea BOP   (i) You must perform the initial
 test.                               subsea BOP test on the seafloor
                                     within 30 days of the stump test.
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval.
                                    (iii) You must pressure test well-
                                     control rams according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (iv) You must notify the District
                                     Manager at least 72 hours prior to
                                     beginning the initial subsea test
                                     for the BOP system to allow BSEE
                                     representative(s) to witness
                                     testing.
                                    (v) You must test and verify closure
                                     of at least one set of rams during
                                     the initial subsea test through a
                                     ROV hot stab.
                                    (vi) You must pressure test the
                                     selected rams according to
                                     paragraphs (b) and (c) of this
                                     section.
(5) Alternate testing pods between  (i) For two complete BOP control
 control stations.                   stations:
                                    (A) Designate a primary and
                                     secondary station, and both
                                     stations must be function-tested
                                     weekly;
                                    (B) The control station used for the
                                     pressure test must be alternated
                                     between pressure tests; and
                                    (C) For a subsea BOP, the pods must
                                     be rotated between control stations
                                     during weekly function testing and
                                     14 day pressure testing.

[[Page 164]]

 
                                    (ii) Remote panels where all BOP
                                     functions are not included (e.g.,
                                     life boat panels) must be function-
                                     tested upon the initial BOP tests
                                     and monthly thereafter.
(6) Pressure test variable bore-
 pipe ram BOPs against pipe sizes
 according to API Standard 53,
 excluding the bottom hole
 assembly that includes heavy-
 weight pipe or collars and bottom-
 hole tools.
(7) Pressure test annular type
 BOPs against pipe sizes according
 to API Standard 53.
(8) Pressure test affected BOP
 components following the
 disconnection or repair of any
 well-pressure containment seal in
 the wellhead or BOP stack
 assembly.
(9) Function test annular and pipe/
 variable bore ram BOPs every 7
 days between pressure tests.
(10) Function test shear ram(s)
 BOPs every 14 days.
(11) Actuate safety valves
 assembled with proper casing
 connections before running casing.
(12) Function test autoshear/       (i) You must submit test procedures
 deadman, and EDS systems            with your APD or APM for District
 separately on your subsea BOP       Manager approval. The procedures
 stack during the stump test. The    for these function tests must
 District Manager may require        include the schematics of the
 additional testing of the           actual controls and circuitry of
 emergency systems. You must also    the system that will be used during
 test the deadman system and         an actual autoshear or deadman
 verify closure of the shearing      event.
 rams during the initial test on    (ii) The procedures must also
 the seafloor.                       include the actions and sequence of
                                     events that take place on the
                                     approved schematics of the BOP
                                     control system and describe
                                     specifically how the ROV will be
                                     utilized during this operation.
                                    (iii) When you conduct the initial
                                     deadman system test on the
                                     seafloor, you must ensure the well
                                     is secure and, if hydrocarbons have
                                     been present, appropriate barriers
                                     are in place to isolate
                                     hydrocarbons from the wellhead. You
                                     must also have an ROV on bottom
                                     during the test.
                                    (iv) The testing of the deadman
                                     system on the seafloor must
                                     indicate the discharge pressure of
                                     the subsea accumulator system
                                     throughout the test.
                                    (v) For the function test of the
                                     deadman system during the initial
                                     test on the seafloor, you must have
                                     the ability to quickly disconnect
                                     the LMRP should the rig experience
                                     a loss of station-keeping event.
                                     You must include your quick-
                                     disconnect procedures with your
                                     deadman test procedures.
                                    (vi) You must pressure test the
                                     blind shear ram(s) according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (vii) If a casing shear ram is
                                     installed, you must describe how
                                     you will verify closure of the ram.
                                    (viii) You must document all your
                                     test results and make them
                                     available to BSEE upon request.
------------------------------------------------------------------------

    (e) Prior to conducting any shear ram tests in which you will shear 
pipe, you must notify the District Manager at least 72 hours in advance, 
to ensure that a BSEE representative will have access to the location to 
witness any testing.

    Effective Date Note: At 84 FR 21981, May 15, 2019, Sec.  250.737 was 
amended by redesignating paragraph (a)(4) as (a)(5); adding new 
paragraph (a)(4); revising paragraphs (b) introductory text, (b)(2), 
(b)(3), (c), (d)(2)(ii), (d)(3)(iii), (d)(3)(iv), (d)(3)(v), (d)(4)(i), 
(d)(4)(iii),(d)(4)(v), (d)(5), (d)(10), (d)(12)(iv) and (d)(12)(vi); 
removing paragraph (d)(4)(vi); and adding paragraph (d)(13), effective 
July 15, 2019. For the convenience of the user, the added and revised 
text is set forth as follows:



Sec.  250.737  What are the BOP system testing requirements?

                                * * * * *

    (a) * * *
    (4) In lieu of meeting the schedule established in paragraph (a)(2) 
of this section, you may request that BSEE approve a 21-day BOP testing 
frequency. To obtain BSEE approval, you must submit a request to the 
appropriate BSEE Regional Supervisor, District Field Operations. Your 
request must demonstrate that you have developed a BOP health monitoring 
plan that includes certain system capabilities. As long as your plan is 
consistent with recognized engineering and industry practice, BSEE will 
approve your request if it includes the following:
    (i) Condition monitoring tools, including continuous surveillance of 
sensor readings

[[Page 165]]

from the BOP control system, real-time condition analysis and displays, 
functional pressure signal analysis, historical sensor data;
    (ii) Failure propagation analysis;
    (iii) A failure tracking and resolution system that includes 
detailed failure reports and identification of recurring problems; and
    (iv) Submission of quarterly reports of the data collected pursuant 
to paragraphs (a)(4)(i)(iii) to the BSEE Regional Supervisor, District 
Field Operations.

                                * * * * *

    (b) Pressure test procedures. When you pressure test the BOP system, 
you must conduct a low-pressure test and a high-pressure test for each 
BOP component (excluding test rams and non-sealing shear rams). You must 
begin each test by conducting the low-pressure test then transition to 
the high-pressure test. Each individual pressure test must hold pressure 
long enough to demonstrate the tested component(s) holds the required 
pressure. The table in this paragraph (b) outlines your pressure test 
requirements.

------------------------------------------------------------------------
                                            According to the following
        You must conduct a . . .                 procedures . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(2) High-pressure test for blind shear   (i) The high-pressure test must
 ram-type BOPs, ram-type BOPs, the        equal the RWP of the equipment
 choke manifold, outside of all choke     or be 500 psi greater than
 and kill side outlet valves (and         your calculated MASP, as
 annular gas bleed valves for subsea      defined for the operation for
 BOP), inside of all choke and kill       the applicable section of
 side outlet valves below uppermost       hole. Before you may test BOP
 ram, and other BOP components.           equipment to the MASP plus 500
                                          psi, the District Manager must
                                          have approved those test
                                          pressures in your permit.
                                         (ii) The blind shear ram (BSR)
                                          must be tested to:
                                            (A) MASP plus 500 psi for
                                             the hole section to which
                                             it is exposed; or
                                            (B) Full well MASP plus 500
                                             psi on initial latch up and
                                             all subsequent BSR pressure
                                             tests can be done to the
                                             casing/liner test pressure
                                             for the applicable hole
                                             section.
                                         (iii) The choke and kill side
                                          outlet valves must be tested
                                          to, except as provided in
                                          paragraph (d)(13) of this
                                          section:
                                            (A) MASP plus 500 psi for
                                             the hole section to which
                                             it is exposed; or
                                            (B) Full well MASP plus 500
                                             psi on initial latch up and
                                             all subsequent pressure
                                             tests can be done to the
                                             casing/liner test pressure
                                             for the applicable hole
                                             section.
(3) High-pressure test for annular-type  The high pressure test must
 BOPs, inside of choke or kill valves     equal 70 percent of the RWP of
 (and annular gas bleed valves for        the equipment or be 500 psi
 subsea BOP) above the uppermost ram      greater than your calculated
 BOP.                                     MASP, as defined for the
                                          operation for the applicable
                                          section of hole. Before you
                                          may test BOP equipment to the
                                          MASP plus 500 psi, the
                                          District Manager must have
                                          approved those test pressures
                                          in your APD or APM.
 
                              * * * * * * *
------------------------------------------------------------------------

    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes, which must be recorded on a chart not exceeding 
4 hours, or on a digital recorder. However, for surface BOP systems and 
surface equipment of a subsea BOP system, a 3-minute test duration is 
acceptable if recorded on a chart not exceeding 4 hours, or on a digital 
recorder. The recorded test pressures must be within the middle half of 
the chart range, i.e., cannot be within the lower or upper one-fourth of 
the chart range. If the equipment does not hold the required pressure 
during a test, you must correct the problem and retest the affected 
component(s).

                                * * * * *

    (d) * * *

------------------------------------------------------------------------
             You must . . .               Additional requirements . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(2) * * *..............................  (ii) Contact the District
                                          Manager at least 72 hours
                                          prior to beginning the initial
                                          test to allow BSEE
                                          representative(s) to witness
                                          testing.
(3) * * *..............................  (iii) Contact the District
                                          Manager at least 72 hours
                                          prior to beginning the stump
                                          test to allow BSEE
                                          representative(s) to witness
                                          testing.
                                         (iv) You must verify closure of
                                          all ROV intervention functions
                                          on your subsea BOP stack
                                          during the stump test.

[[Page 166]]

 
                                         (v) You must follow paragraphs
                                          (b) and (c) of this section.
                                          Pressure testing of each ram
                                          and annular component is only
                                          required once.
(4) * * *..............................  (i) You must begin the initial
                                          subsea BOP test on the
                                          seafloor within 30 days of the
                                          stump test.
 
                              * * * * * * *
                                         (iii) You must pressure test
                                          well-control rams and annulars
                                          according to paragraphs (b)
                                          and (c) of this section.
 
                              * * * * * * *
                                         (v) You must test and verify
                                          closure of at least one set of
                                          rams during the initial subsea
                                          test through a ROV hot stab.
                                          You must confirm closure of
                                          the selected ram through the
                                          ROV hot stab with a 1,000 psi
                                          pressure test for 5 minutes.
(5) Alternate tests between control      (i) For two complete BOP
 stations.                                control stations you must:
                                            (A) Designate a primary and
                                             secondary station;
                                            (B) Alternate testing
                                             between the primary and
                                             secondary control stations
                                             on a weekly basis; and
                                            (C) For a subsea BOP,
                                             develop an alternating
                                             testing schedule to ensure
                                             the primary and secondary
                                             control stations will
                                             function each pod.
                                         (ii) Remote panels where all
                                          BOP functions are not included
                                          (e.g., life boat panels) must
                                          be function-tested upon the
                                          initial BOP tests.
 
                              * * * * * * *
(10) * * *.............................  If BSEE approves your request
                                          to utilize a 21-day BOP test
                                          frequency pursuant to Sec.
                                          250.737(a)(4), you may
                                          function test shear ram(s)
                                          BOPs every 21 days in
                                          accordance with the terms of
                                          that approval.
 
                              * * * * * * *
(12) * * *.............................  (iv) Following the deadman
                                          system test on the seafloor
                                          you must document the final
                                          remaining pressure of the
                                          subsea accumulator system.
 
                              * * * * * * *
                                         (vi) You must confirm closure
                                          of the BSR(s) with a 1,000 psi
                                          pressure test for 5 minutes.
 
                              * * * * * * *
(13) Pressure test the choke and kill    According to paragraph (b) of
 side outlet valves.                      this section, except as
                                          follows:
                                         (i) Test the wellbore side of
                                          the choke and kill side outlet
                                          valves above the uppermost
                                          pipe ram to the approved
                                          annular test pressure. Choke
                                          and kill side outlet valves
                                          below the uppermost pipe ram
                                          must be tested to MASP plus
                                          500 psi for the applicable
                                          hole section.
                                         (ii) For the 30 day BSR
                                          testing, test the wellbore
                                          side of the choke and kill
                                          side outlet valves between the
                                          upper most pipe ram and the
                                          upper most ram, to the casing/
                                          liner test pressure or annular
                                          test pressure, whichever is
                                          greater.
                                         (iii) For BOPs with only one
                                          choke and kill side outlet
                                          valve, you are only required
                                          to pressure test the choke and
                                          kill side outlet valves from
                                          the wellbore side.
------------------------------------------------------------------------

                                * * * * *



Sec.  250.738  What must I do in certain situations involving BOP
 equipment or systems?

    The table in this section describes actions that you must take when 
certain situations occur with BOP systems.

------------------------------------------------------------------------
    If you encounter the following
              situation:                      Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the    Correct the problem and retest
 required pressure during a test;       the affected equipment. You must
                                        report any problems or
                                        irregularities, including any
                                        leaks, on the daily report as
                                        required in Sec.   250.746.
(b) Need to repair, replace, or        (1) First place the well in a
 reconfigure a surface or subsea BOP    safe, controlled condition as
 system;                                approved by the District Manager
                                        (e.g., before drilling out a
                                        casing shoe or after setting a
                                        cement plug, bridge plug, or a
                                        packer).

[[Page 167]]

 
                                       (2) Any repair or replacement
                                        parts must be manufactured under
                                        a quality assurance program and
                                        must meet or exceed the
                                        performance of the original part
                                        produced by the OEM.
                                       (3) You must receive approval
                                        from the District Manager prior
                                        to resuming operations with the
                                        new, repaired, or reconfigured
                                        BOP.
                                       (4) You must submit a report from
                                        a BAVO to the District Manager
                                        certifying that the BOP is fit
                                        for service.
(c) Need to postpone a BOP test due    Record the reason for postponing
 to well-control problems such as       the test in the daily report and
 lost circulation, formation fluid      conduct the required BOP test
 influx, or stuck pipe;                 after the first trip out of the
                                        hole.
(d) BOP control station or pod that    Suspend operations until that
 does not function properly;            station or pod is operable. You
                                        must report any problems or
                                        irregularities, including any
                                        leaks, to the District Manager.
(e) Plan to operate with a tapered     Install two or more sets of
 string;                                conventional or variable-bore
                                        pipe rams in the BOP stack to
                                        provide for the following: two
                                        sets of rams must be capable of
                                        sealing around the larger-size
                                        drill string and one set of pipe
                                        rams must be capable of sealing
                                        around the smaller size pipe,
                                        excluding the bottom hole
                                        assembly that includes heavy
                                        weight pipe or collars and
                                        bottom-hole tools.
(f) Plan to install casing rams or     Test the affected connections
 casing shear rams in a surface BOP     before running casing to the RWP
 stack;                                 or MASP plus 500 psi. If this
                                        installation was not included in
                                        your approved permit, and
                                        changes the BOP configuration
                                        approved in the APD or APM, you
                                        must notify and receive approval
                                        from the District Manager.
(g) Plan to use an annular BOP with a  Demonstrate that your well-
 RWP less than the anticipated          control procedures or the
 surface pressure;                      anticipated well conditions will
                                        not place demands above its RWP
                                        and obtain approval from the
                                        District Manager.
(h) Plan to use a subsea BOP system    Install the BOP stack in a well
 in an ice-scour area;                  cellar. The well cellar must be
                                        deep enough to ensure that the
                                        top of the stack is below the
                                        deepest probable ice-scour
                                        depth.
(i) You activate any shear ram and     Retrieve, physically inspect, and
 pipe or casing is sheared;             conduct a full pressure test of
                                        the BOP stack after the
                                        situation is fully controlled.
                                        You must submit to the District
                                        Manager a report from a BSEE-
                                        approved verification
                                        organization certifying that the
                                        BOP is fit to return to service.
(j) Need to remove the BOP stack;      Have a minimum of two barriers in
                                        place prior to BOP removal. You
                                        must obtain approval from the
                                        District Manager of the two
                                        barriers prior to removal and
                                        the District Manager may require
                                        additional barriers and test(s).
(k) In the event of a deadman or       Place the blind shear ram opening
 autoshear activation, if there is a    function in the block position
 possibility of the blind shear ram     prior to re-establishing power
 opening immediately upon re-           to the stack. Contact the
 establishing power to the BOP stack;   District Manager and receive
                                        approval of procedures for re-
                                        establishing power and functions
                                        prior to latching up the BOP
                                        stack or re-establishing power
                                        to the stack.
(l) If a test ram is to be used;       The wellhead/BOP connection must
                                        be tested to the MASP plus 500
                                        psi for the hole section to
                                        which it is exposed. This can be
                                        done by:
                                       (1) Testing wellhead/BOP
                                        connection to the MASP plus 500
                                        psi for the well upon
                                        installation;
                                       (2) Pressure testing each casing
                                        to the MASP plus 500 psi for the
                                        next hole section; or
                                       (3) Some combination of
                                        paragraphs (l)(1) and (2) of
                                        this section.
(m) Plan to utilize any other well-    Contact the District Manager and
 control equipment (e.g., but not       request approval in your APD or
 limited to, subsea isolation device,   APM. Your request must include a
 subsea accumulator module, or gas      report from a BAVO on the
 handler) that is in addition to the    equipment's design and
 equipment required in this subpart;    suitability for its intended use
                                        as well as any other information
                                        required by the District
                                        Manager. The District Manager
                                        may impose any conditions
                                        regarding the equipment's
                                        capabilities, operation, and
                                        testing.
(n) You have pipe/variable bore rams   Indicate in your APD or APM which
 that have no current utility or well-  pipe/variable bore rams meet
 control purposes;                      these criteria and clearly label
                                        them on all BOP control panels.
                                        You do not need to function test
                                        or pressure test pipe/variable
                                        bore rams having no current
                                        utility, and that will not be
                                        used for well-control purposes,
                                        until such time as they are
                                        intended to be used during
                                        operations.
(o) You install redundant components   Comply with all testing,
 for well control in your BOP system    maintenance, and inspection
 that are in addition to the required   requirements in this subpart
 components of this subpart (e.g.,      that are applicable to those
 pipe/variable bore rams, shear rams,   well-control components. If any
 annular preventers, gas bleed lines,   redundant component fails a
 and choke/kill side outlets or         test, you must submit a report
 lines);                                from a BAVO that describes the
                                        failure and confirms that there
                                        is no impact on the BOP that
                                        will make it unfit for well-
                                        control purposes. You must
                                        submit this report to the
                                        District Manager and receive
                                        approval before resuming
                                        operations. The District Manager
                                        may require you to provide
                                        additional information as needed
                                        to clarify or evaluate your
                                        report.
(p) Need to position the bottom hole   Ensure that the well is stable
 assembly, including heavy-weight       prior to positioning the bottom
 pipe or collars, and bottom-hole       hole assembly across the BOP.
 tools across the BOP for tripping or   You must have, as part of your
 any other operations.                  well-control plan required by
                                        Sec.   250.710, procedures that
                                        enable the removal of the bottom
                                        hole assembly from across the
                                        BOP in the event of a well-
                                        control or emergency situation
                                        (for dynamically positioned
                                        rigs, your plan must also
                                        include steps for when the EDS
                                        must be activated) before MASP
                                        conditions are reached as
                                        defined for the operation.
------------------------------------------------------------------------


[[Page 168]]


    Effective Date Note: At 84 FR 21983, May 15, 2019, Sec.  250.738 was 
amended by revising paragraphs (b) introductory text, (b)(3), (b)(4), 
(f), (i), (m), and (o), effective July 15, 2019. For the convenience of 
the user, the revised text is set forth as follows:

Sec.  250.738  What must I do in certain situations involving BOP 
          equipment or systems?

                                * * * * *

------------------------------------------------------------------------
     If you encounter the following
               situation:                      Then you must . . .
------------------------------------------------------------------------
(b) Need to repair, replace, or
 reconfigure a surface BOP or subsea
 BOP system;
 
                              * * * * * * *
                                         (3) Submit a revised permit
                                          with a written statement from
                                          an independent third party
                                          documenting the repairs,
                                          replacement, or
                                          reconfiguration and certifying
                                          that the previous
                                          certification under Sec.
                                          250.731(c) remains valid.
                                         (4) You must receive approval
                                          from the District Manager
                                          prior to resuming operations.
 
                              * * * * * * *
(f) Plan to install casing rams or       Before running casing, perform
 casing shear rams in a surface BOP       a shell test to the permit
 stack;                                   approved test pressure of the
                                          BOP component above the casing
                                          ram/casing shear. If this
                                          installation was not included
                                          in your approved permit, and
                                          changes the BOP configuration
                                          approved in the APD or APM,
                                          you must notify and receive
                                          approval from the District
                                          Manager.
 
                              * * * * * * *
(i) You activate any shear ram and pipe  Retrieve, physically inspect,
 or casing is sheared;.                   and conduct a full pressure
                                          test of the BOP stack after
                                          the situation is fully
                                          controlled. You must submit to
                                          the District Manager a report
                                          from an independent third
                                          party certifying that the BOP
                                          is fit to return to service.
 
                              * * * * * * *
(m) Plan to utilize any other            Contact the District Manager
 circulating or ancillary equipment       and request approval in your
 (e.g., but not limited to, subsea        APD or APM. Your request must
 isolation device, subsea accumulator     include a report from an
 module, or gas handler) that is in       independent third party on the
 addition to the equipment required in    equipment's design and
 this subpart;                            suitability for its intended
                                          use as well as any other
                                          information required by the
                                          District Manager. The District
                                          Manager may impose any
                                          conditions regarding the
                                          equipment's capabilities,
                                          operation, and testing.
 
                              * * * * * * *
(o) You install redundant components     Comply with all testing,
 for well control in your BOP system      maintenance, and inspection
 that are in addition to the required     requirements in this subpart
 components of this subpart (e.g., pipe/  that are applicable to those
 variable bore rams, shear rams,          well-control components. If
 annular preventers, gas bleed lines,     any redundant component fails
 and choke/kill side outlets or lines);   a test, you must submit a
                                          report from an independent
                                          third party that describes the
                                          failure and confirms that
                                          there is no impact on the BOP
                                          that will make it unfit for
                                          well-control purposes. You
                                          must submit this report to the
                                          District Manager and receive
                                          approval before resuming
                                          operations. The District
                                          Manager may require you to
                                          provide additional information
                                          as needed to clarify or
                                          evaluate your report.
 
                              * * * * * * *
------------------------------------------------------------------------



Sec.  250.739  What are the BOP maintenance and inspection requirements?

    (a) You must maintain and inspect your BOP system to ensure that the 
equipment functions as designed. The BOP maintenance and inspections 
must meet or exceed any OEM recommendations, recognized engineering 
practices, and industry standards incorporated by reference into the 
regulations of this subpart, including API Standard 53 (incorporated by 
reference in Sec.  250.198). You must document how you met or exceeded 
the provisions of API Standard 53, maintain complete records to ensure 
the traceability of BOP stack equipment beginning at fabrication, and 
record the results of your

[[Page 169]]

BOP inspections and maintenance actions. You must make all records 
available to BSEE upon request.
    (b) A complete breakdown and detailed physical inspection of the BOP 
and every associated system and component must be performed every 5 
years. This complete breakdown and inspection may be performed in phased 
intervals. You must track and document all system and component 
inspection dates. These records must be available on the rig. A BAVO is 
required to be present during each inspection and must compile a 
detailed report documenting the inspection, including descriptions of 
any problems and how they were corrected. You must make these reports 
available to BSEE upon request. This complete breakdown and inspection 
must be performed every 5 years from the following applicable dates, 
whichever is later:
    (1) The date the equipment owner accepts delivery of a new build 
drilling rig with a new BOP system;
    (2) The date the new, repaired, or remanufactured equipment is 
initially installed into the system; or
    (3) The date of the last 5 year inspection for the component.
    (c) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system, marine riser, 
and wellhead at least once every 3 days if weather and sea conditions 
permit. You may use cameras to inspect subsea equipment.
    (d) You must ensure that all personnel maintaining, inspecting, or 
repairing BOPs, or critical components of the BOP system, are trained in 
accordance with applicable training requirements in subpart S of this 
part, any applicable OEM criteria, recognized engineering practices, and 
industry standards incorporated by reference in this subpart.
    (e) You must make all records available to BSEE upon request. You 
must ensure that the rig unit owner maintains the BOP maintenance, 
inspection, and repair records on the rig unit for 2 years from the date 
the records are created or for a longer period if directed by BSEE. You 
must ensure that all equipment schematics, maintenance, inspection, and 
repair records are located at an onshore location for the service life 
of the equipment.

    Effective Date Note: At 84 FR 21983, May 15, 2019, Sec.  250.739 was 
amended by revising paragraph (b) introductory text, effective July 15, 
2019. For the convenience of the user, the revised text is set forth as 
follows:



Sec.  250.739  What are the BOP maintenance and inspection requirements?

                                * * * * *

    (b) A major, detailed inspection of the well control system 
components (including but not limited to riser, BOP, LMRP, and control 
pods) must be performed every 5 years. This major inspection may be 
performed in phased intervals. You must track and document all system 
and component inspection dates. These records must be available on the 
rig. An independent third party is required to review the inspection 
results and must compile a detailed report of the inspection results, 
including descriptions of any problems and how they were corrected. You 
must make these reports available to BSEE upon request. This major 
inspection must be performed every 5 years from the following applicable 
dates, whichever is later:

                                * * * * *

                          Records and Reporting



Sec.  250.740  What records must I keep?

    You must keep a daily report consisting of complete, legible, and 
accurate records for each well. You must keep records onsite while well 
operations continue. After completion of operations, you must keep all 
operation and other well records for the time periods shown in Sec.  
250.741 at a location of your choice, except as required in Sec.  
250.746. The records must contain complete information on all of the 
following:
    (a) Well operations, all testing conducted, and any real-time 
monitoring data as required by Sec.  250.724;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and

[[Page 170]]

    (g) All other information required by the District Manager as 
appropriate to ensure compliance with the requirements of this section 
and to enable BSEE to determine that the well operations are consistent 
with conservation of natural resources and protection of safety and the 
environment on the OCS.



Sec.  250.741  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
  You must keep records relating to . . .            Until . . .
------------------------------------------------------------------------
(a) Drilling;                               90 days after you complete
                                             operations.
(b) Casing and liner pressure tests,        2 years after the completion
 diverter tests, BOP tests, and real-time    of operations.
 monitoring data;
(c) Completion of a well or of any          You permanently plug and
 workover activity that materially alters    abandon the well or until
 the completion configuration or affects a   you assign the lease and
 hydrocarbon-bearing zone.                   forward the records to the
                                             assignee.
------------------------------------------------------------------------



Sec.  250.742  What well records am I required to submit?

    You must submit to BSEE copies of logs or charts of electrical, 
radioactive, sonic, and other well logging operations; directional and 
vertical well surveys; velocity profiles and surveys; and analysis of 
cores. Each Region will provide specific instructions for submitting 
well logs and surveys.



Sec.  250.743  What are the well activity reporting requirements?

    (a) For operations in the BSEE Gulf of Mexico (GOM) OCS Region, you 
must submit Form BSEE-0133, Well Activity Report (WAR), to the District 
Manager on a weekly basis. The reporting week is defined as beginning on 
Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). This 
reporting week corresponds to a week (Sunday through Saturday) on a 
standard calendar. Report any well operations that extend past the end 
of this weekly reporting period on the next weekly report. The reporting 
period for the weekly report is never longer than 7 days, but could be 
less than 7 days for the first reporting period and the last reporting 
period for a particular well operation. Submit each WAR and accompanying 
Form BSEE-0133S, Open Hole Data Report, to the BSEE GOM OCS Region no 
later than close of business on the Friday immediately after the closure 
of the reporting week. The District Manager may require more frequent 
submittal of the WAR on a case-by-case basis.
    (b) For operations in the Pacific or Alaska OCS Regions, you must 
submit Form BSEE-0133, WAR, to the District Manager on a daily basis.
    (c) The WAR must include a description of the operations conducted, 
any abnormal or significant events that affect the permitted operation 
each day within the report from the time you begin operations to the 
time you end operations, any verbal approval received, the well's as-
built drawings, casing, fluid weights, shoe tests, test pressures at 
surface conditions, and any other information concerning well activities 
required by the District Manager. For casing cementing operations, 
indicate type of returns (i.e., full, partial, or none). If partial or 
no returns are observed, you must indicate how you determined the top of 
cement. For each report, indicate the operation status for the well at 
the end of the reporting period. On the final WAR, indicate the status 
of the well (completed, temporarily abandoned, permanently abandoned, or 
drilling suspended) and the date you finished such operations.



Sec.  250.744  What are the end of operation reporting requirements?

    (a) Within 30 days after completing operations, except routine 
operations as defined in Sec.  250.601, you must submit Form BSEE-0125, 
End of Operations Report (EOR), to the District Manager. The EOR must 
include: a listing, with top and bottom depths, of all hydrocarbon zones 
and other zones of porosity encountered with any cored intervals; 
details on any drill-stem and formation tests conducted; documentation 
of successful negative pressure testing on wells that use a subsea BOP 
stack or wells with mudline suspension

[[Page 171]]

systems; and an updated schematic of the full wellbore configuration. 
The schematic must be clearly labeled and show all applicable top and 
bottom depths, locations and sizes of all casings, cut casing or stubs, 
casing perforations, casing rupture discs (indicate if burst or collapse 
and rating), cemented intervals, cement plugs, mechanical plugs, 
perforated zones, completion equipment, production and isolation 
packers, alternate completions, tubing, landing nipples, subsurface 
safety devices, and any other information required by the District 
Manager regarding the end of well operations. The EOR must indicate the 
status of the well (completed, temporarily abandoned, permanently 
abandoned, or drilling suspended) and the date of the well status 
designation. The well status date is subject to the following:
    (1) For surface well operations and riserless subsea operations, the 
operations end date is subject to the discretion of the District 
Manager; and
    (2) For subsea well operations, the operations end date is 
considered to be the date the BOP is disconnected from the wellhead 
unless otherwise specified by the District Manager.
    (b) You must submit public information copies of Form BSEE-0125 
according to Sec.  250.186(b).



Sec.  250.745  What other well records could I be required to submit?

    The District Manager or Regional Supervisor may require you to 
submit copies of any or all of the following well records:
    (a) Well records as specified in Sec.  250.740;
    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that sets forth the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.



Sec.  250.746  What are the recordkeeping requirements for casing, 
liner, and BOP tests, and inspections of BOP systems and marine
 risers?

    You must record the time, date, and results of all casing and liner 
pressure tests. You must also record pressure tests, actuations, and 
inspections of the BOP system, system components, and marine riser in 
the daily report described in Sec.  250.740. In addition, you must:
    (a) Record test pressures on pressure charts or digital recorders;
    (b) Require your onsite lessee representative, designated rig or 
contractor representative, and pump operator to sign and date the 
pressure charts or digital recordings and daily reports as correct;
    (c) Document on the daily report the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
For subsea BOP systems, you must also record the closing times for 
annular and ram BOPs. You may reference a BOP test plan if it is 
available at the facility;
    (d) Identify on the daily report the control station and pod used 
during the test (identifying the pod does not apply to coiled tubing and 
snubbing units);
    (e) Identify on the daily report any problems or irregularities 
observed during BOP system testing and record actions taken to remedy 
the problems or irregularities. Any leaks associated with the BOP or 
control system during testing must be documented in the WAR. If any 
problems that cannot be resolved promptly are observed during testing, 
operations must be suspended until the District Manager determines that 
you may continue; and
    (f) Retain all records, including pressure charts, daily reports, 
and referenced documents pertaining to tests, actuations, and 
inspections at the rig unit for the duration of the operation. After 
completion of the operation, you must retain all the records listed in 
this section for a period of 2 years at the rig unit. You must also 
retain the records at the lessee's field office nearest the facility or 
at another location available to BSEE. You must make all the records 
available to BSEE upon request.

[[Page 172]]

                        Coiled Tubing Operations



Sec.  250.750  What are the coiled tubing requirements?

    (a) For coiled tubing operations, you must follow the applicable 
requirements of this subpart and you must meet the following minimum 
requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

------------------------------------------------------------------------
                                 BOP system when
   BOP system when expected      expected surface   BOP system for wells
  surface pressures are less      pressures are      with returns taken
  than or equal to 3,500 psi       greater than     through an outlet on
                                    3,500 psi          the BOP stack
------------------------------------------------------------------------
(i) Stripper or annular-type    Stripper or        Stripper or annular-
 well control component.         annular-type       type well control
                                 well control       component.
                                 component.
(ii) Hydraulically-operated     Hydraulically-     Hydraulically-
 blind rams.                     operated blind     operated blind rams.
                                 rams.
(iii) Hydraulically-operated    Hydraulically-     Hydraulically-
 shear rams.                     operated shear     operated shear rams.
                                 rams.
(iv) Kill line inlet..........  Kill line inlet..  Kill line inlet.
(v) Hydraulically-operated two- Hydraulically-     Hydraulically-
 way slip rams.                  operated two-way   operated two-way
                                 slip rams.         slip rams.
                                                   Hydraulically-
                                                    operated pipe rams.
(vi) Hydraulically-operated     Hydraulically-     A flow tee or cross.
 pipe rams.                      operated pipe     Hydraulically-
                                 rams.              operated pipe rams.
                                Hydraulically-     Hydraulically-
                                 operated blind-    operated blind-shear
                                 shear rams.        rams on wells with
                                 These rams         surface pressures
                                 should be          3,500
                                 located as close   psi. As an option,
                                 to the tree as     the pipe rams can be
                                 practical.         placed below the
                                                    blind-shear rams.
                                                    The blind-shear rams
                                                    should be located as
                                                    close to the tree as
                                                    practical.
------------------------------------------------------------------------

    (2) You may use a set of hydraulically-operated combination rams for 
the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams for 
the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled tubing 
connector at the downhole end of the coiled tubing string for all coiled 
tubing operations. If you plan to conduct operations without downhole 
check valves, you must describe alternate procedures and equipment in 
Form BSEE-0124, Application for Permit to Modify and have it approved by 
the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (b) BSEE considers all coiled tubing operations to be non-routine.

[84 FR 21983, May 15, 2019]

    Effective Date Note: At 84 FR 21983, May 15, 2019, an undesignated 
center heading and Sec.  250.750 were added, effective July 15, 2019.



Sec.  250.751  Coiled tubing testing requirements.

    You must test the coiled tubing unit in accordance with Sec.  
250.737(a), (b), (c),

[[Page 173]]

(d)(9), and (d)(10). You must successfully pressure test the dual check 
valves to the rated working pressure of the connector, the rated working 
pressure of the dual check valve, expected surface pressure, or the 
collapse pressure of the coiled tubing, whichever is less. The test 
interval for coiled tubing operations must include a 10 minute high-
pressure test for the coiled tubing string.

[84 FR 21984, May 15, 2019]

    Effective Date Note: At 84 FR 21984, May 15, 2019, Sec.  250.751 was 
added, effective July 15, 2019.

                           Snubbing Operations



Sec.  250.760  What are the snubbing requirements?

    (a) For snubbing operations, you must follow the applicable 
requirements of this subpart and have the following minimum BOP-system 
components:
    (1) One set of pipe rams hydraulically operated,
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool,
    (3) An inside BOP or a spring-loaded, back-pressure safety valve in 
the open position located on the rig floor, and
    (4) An essentially full-opening, work-string safety valve in the 
open position must be maintained on the rig floor at all times and a 
wrench to fit the work-string safety valve must be readily available.
    (5) Proper connections must be readily available for inserting 
valves in the work string.
    (b) Test the snubbing unit in accordance with Sec.  250.737(a), (b), 
and (c).

    Effective Date Note: At 84 FR 21984, May 15, 2019, an undesignated 
center heading and Sec.  250.760 were added, effective July 15, 2019.



             Subpart H_Oil and Gas Production Safety Systems

    Source: 81 FR 60918, Sept. 7, 2016, unless otherwise noted.

                          General Requirements



Sec.  250.800  General.

    (a) You must design, install, use, maintain, and test production 
safety equipment in a manner to ensure the safety and protection of the 
human, marine, and coastal environments. For production safety systems 
operated in subfreezing climates, you must use equipment and procedures 
that account for floating ice, icing, and other extreme environmental 
conditions that may occur in the area. Before you commence production on 
a new production facility:
    (1) BSEE must approve your production safety system application, as 
required in Sec.  250.842.
    (2) You must request a preproduction inspection by notifying the 
District Manager at least 72 hours before you plan to commence initial 
production, as required under Sec.  250.880(a)(1).
    (b) For all new production systems on fixed leg platforms, you must 
comply with API RP 14J (incorporated by reference as specified in Sec.  
250.198);
    (c) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must:
    (1) Comply with API RP 14J;
    (2) Meet the production riser standards of API RP 2RD (incorporated 
by reference as specified in Sec.  250.198), provided that you may not 
install single bore production risers from floating production 
facilities;
    (3) Design all stationkeeping (i.e., anchoring and mooring) systems 
for floating production facilities to meet the standards of API RP 2SK 
and API RP 2SM (both incorporated by reference as specified in Sec.  
250.198); and
    (4) Design stationkeeping (i.e., anchoring and mooring) systems for 
floating facilities to meet the structural requirements of Sec. Sec.  
250.900 through 250.921.
    (d) If there are any conflicts between the documents incorporated by 
reference and the requirements of this subpart, you must follow the 
requirements of this subpart.
    (e) You may use alternate procedures or equipment during operations 
after

[[Page 174]]

receiving approval from the District Manager. You must present your 
proposed alternate procedures or equipment as required by Sec.  250.141.
    (f) You may apply for a departure from the operating requirements of 
this subpart as provided by Sec.  250.142. Your written request must 
include a justification showing why the departure is necessary and 
appropriate.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49256, Sept. 28, 2018]



Sec.  250.801  Safety and pollution prevention equipment (SPPE)
certification.

    (a) SPPE equipment. You must install only safety and pollution 
prevention equipment (SPPE) considered certified under paragraph (b) of 
this section or accepted under paragraph (c) of this section. BSEE 
considers the following equipment to be types of SPPE:
    (1) Surface safety valves (SSV) and actuators, including those 
installed on injection wells capable of natural flow;
    (2) Boarding shutdown valves (BSDV) and their actuators. For subsea 
wells, the BSDV is the surface equivalent of an SSV on a surface well;
    (3) Underwater safety valves (USV) and actuators;
    (4) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples; and
    (5) Gas lift shutdown valves (GLSDV) and their actuators associated 
with subsea systems.
    (b) Certification of SPPE. SPPE that is manufactured and marked 
pursuant to ANSI/API Spec. Q1 (incorporated by reference as specified in 
Sec.  250.198), is considered as certified SPPE under this part. All 
other SPPE is considered as not certified, unless approved in accordance 
with paragraph (c) of this section.
    (c) Accepting SPPE manufactured under other quality assurance 
programs. BSEE may exercise its discretion to accept SPPE manufactured 
under a quality assurance program other than ANSI/API Spec. Q1, provided 
that the alternative quality assurance program is verified as equivalent 
to API Spec. Q1 by an appropriately qualified entity and that the 
operator submits a request to BSEE containing relevant information about 
the alternative program and receives BSEE approval. In addition, an 
operator may request that BSEE accept SPPE that is marked with a third-
party certification mark other than the API monogram. All requests under 
this paragraph should be submitted to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
VAE-ORP; 45600 Woodland Road, Sterling, VA 20166.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49256, Sept. 28, 2018]



Sec.  250.802  Requirements for SPPE.

    (a) All SSVs, BSDVs, USVs, and GLSDVs and their actuators must meet 
all of the specifications contained in ANSI/API Spec. 6A and API Spec. 
6AV1 (both incorporated by reference in Sec.  250.198).
    (b) All SSSVs and their actuators must meet all of the 
specifications and recommended practices of ANSI/API Spec. 14A and ANSI/
API RP 14B, including all annexes (both incorporated by reference as 
specified in Sec.  250.198). Subsurface-controlled SSSVs are not allowed 
on subsea wells.
    (c) Requirements derived from the documents incorporated in this 
section for SSVs, BSDVs, SSSVs, USVs, GLSDVs, and their actuators, 
include, but are not limited to, the following:
    (1) You must ensure that each device is designed to function in the 
conditions to which it may be exposed; including temperature, pressure, 
flow rates, and environmental conditions.
    (i) The device design must be tested by an independent test agency 
according to the test requirements in the appropriate standard for that 
device (API Spec. 6AV1 or ANSI/API Spec. 14A), as identified in 
paragraphs (a) and (b) of this section.
    (ii) You must maintain a description of the process you used to 
ensure the device is designed to function as required in paragraphs (a) 
and (c)(1) of this section and provide that description to BSEE upon 
request.
    (iii) If you remove any SPPE from service and install the device at 
a different location, you must have a qualified third party review and 
certify that each device will function as designed under the conditions 
to which it may be exposed.

[[Page 175]]

    (2) All materials and parts must meet the original equipment 
manufacturer specifications and acceptance criteria.
    (3) The device must pass applicable validation tests and functional 
tests performed by an API-licensed test agency.
    (4) You must have requalification testing performed following 
manufacture design changes.
    (5) You must comply with and document all manufacturing, 
traceability, quality control, and inspection requirements.
    (6) You must follow specified installation, testing, and repair 
protocols.
    (7) You must use only qualified parts, procedures, and personnel to 
repair or redress equipment.
    (d) You must install and use SPPE according to the following table.

------------------------------------------------------------------------
                If . . .                            Then . . .
------------------------------------------------------------------------
(1) You need to install any SPPE.......  You must install SPPE that
                                          conforms to Sec.   250.801.
(2) A non-certified SPPE is already in   It may remain in service.
 service.
(3) A non-certified SPPE requires        You must replace it with SPPE
 offsite repair, re-manufacturing, or     that conforms to Sec.
 any hot work such as welding.            250.801.
------------------------------------------------------------------------

    (e) You must retain all documentation related to the manufacture, 
installation, testing, repair, redress, and performance of the SPPE 
until 1 year after the date of decommissioning of the equipment.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49256, Sept. 28, 2018]



Sec.  250.803  What SPPE failure reporting procedures must I follow?

    (a) You must follow the failure reporting requirements contained in 
section 10.20.7.4 of ANSI/API Spec. 6A for SSVs, BSDVs, GLSDVs and USVs. 
You must follow the failure reporting requirements contained in section 
7.10 of ANSI/API Spec. 14A and Annex F of ANSI/API RP 14B for SSSVs (all 
incorporated by reference in Sec.  250.198). Within 30 days after the 
discovery and identification of the failure, you must provide a written 
notice of equipment failure to the manufacturer of such equipment and to 
BSEE through the Chief, Office of Offshore Regulatory Programs, unless 
BSEE has designated a third party as provided in paragraph (d) of this 
section. A failure is any condition that prevents the equipment from 
meeting the functional specification or purpose.
    (b) You must ensure that an investigation and a failure analysis are 
performed within 120 days of the failure to determine the cause of the 
failure. If the investigation and analyses are performed by an entity 
other than the manufacturer, you must ensure that the analysis report is 
submitted to the manufacturer and to BSEE through the Chief, Office of 
Offshore Regulatory Programs, unless BSEE has designated a third party 
as provided in paragraph (d) of this section. You must also ensure that 
the results of the investigation and any corrective action are 
documented in the analysis report.
    (c) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed operating 
or repair procedures as a result of a failure, then you must, within 30 
days of such changes, report the design change or modified procedures in 
writing to BSEE through the Chief, Office of Offshore Regulatory 
Programs, unless BSEE has designated a third party as provided in 
paragraph (d) of this section.
    (d) BSEE may designate a third party to receive the data required by 
paragraphs (a) through (c) of this section on behalf of BSEE. If BSEE 
designates a third party, you must submit the information required in 
this section to the designated third party, as directed by BSEE.

[83 FR 49256, Sept. 28, 2018]

[[Page 176]]



Sec.  250.804  Additional requirements for subsurface safety
 valves (SSSVs) and related equipment installed in high pressure
 high temperature (HPHT) environments.

    (a) If you plan to install SSSVs and related equipment in an HPHT 
environment, you must submit detailed information with your Application 
for Permit to Drill (APD) or Application for Permit to Modify (APM), and 
Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related 
equipment are capable of performing in the applicable HPHT environment. 
Your detailed information must include the following:
    (1) A discussion of the SSSVs' and related equipment's design 
verification analyses;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing processes and procedures used; and
    (3) An explanation of why the analyses, processes, and procedures 
ensure that the SSSVs and related equipment are fit-for-service in the 
applicable HPHT environment.
    (b) For this section, HPHT environment means when one or more of the 
following well conditions exist:
    (1) The completion of the well requires completion equipment or well 
control equipment assigned a pressure rating greater than 15,000 psia or 
a temperature rating greater than 350 degrees Fahrenheit;
    (2) The maximum anticipated surface pressure or shut-in tubing 
pressure is greater than 15,000 psia on the seafloor for a well with a 
subsea wellhead or at the surface for a well with a surface wellhead; or
    (3) The flowing temperature is equal to or greater than 350 degrees 
Fahrenheit on the seafloor for a well with a subsea wellhead or at the 
surface for a well with a surface wellhead.
    (c) For this section, related equipment includes wellheads, tubing 
heads, tubulars, packers, threaded connections, seals, seal assemblies, 
production trees, chokes, well control equipment, and any other 
equipment that will be exposed to the HPHT environment.



Sec.  250.805  Hydrogen sulfide.

    (a) In zones known to contain hydrogen sulfide (H2S) or 
in zones where the presence of H2S is unknown, as defined in 
Sec.  250.490, you must conduct production operations in accordance with 
that section and other relevant requirements of this subpart.
    (b) You must receive approval through the DWOP process (Sec. Sec.  
250.286 through 250.295) for production operations in HPHT environments 
known to contain H2S or in HPHT environments where the 
presence of H2S is unknown.



Sec. Sec.  250.806-250.809  [Reserved]2

            Surface and Subsurface Safety Systems--Dry Trees



Sec.  250.810  Dry tree subsurface safety devices--general.

    For wells using dry trees or for which you intend to install dry 
trees, you must equip all tubing installations open to hydrocarbon-
bearing zones with subsurface safety devices that will shut off the flow 
from the well in the event of an emergency unless, after you submit a 
request containing a justification, the District Manager determines the 
well to be incapable of natural flow. You must install flow couplings 
above and below the subsurface safety devices. These subsurface safety 
devices include the following devices and any associated safety valve 
lock and landing nipple:
    (a) An SSSV, including either:
    (1) A surface-controlled SSSV; or
    (2) A subsurface-controlled SSSV.
    (b) An injection valve.
    (c) A tubing plug.
    (d) A tubing/annular subsurface safety device.



Sec.  250.811  Specifications for SSSVs--dry trees.

    All surface-controlled and subsurface-controlled SSSVs, safety valve 
locks, and landing nipples installed in the OCS must conform to the 
requirements specified in Sec. Sec.  250.801 through 250.803.

[[Page 177]]



Sec.  250.812  Surface-controlled SSSVs--dry trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Sec. Sec.  250.813, 250.815, and 250.816.
    (a) The surface controls must be located on the site or at a BSEE-
approved remote location. You may request District Manager approval to 
situate the surface controls at a remote location.
    (b) You must equip dry tree wells not previously equipped with a 
surface-controlled SSSV, and dry tree wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV, 
with a surface-controlled SSSV when the tubing is first removed and 
reinstalled.



Sec.  250.813  Subsurface-controlled SSSVs.

    You may submit an APM or a request to the District Manager for 
approval to equip a dry tree well with a subsurface-controlled SSSV in 
lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is 
installed in a well equipped with a surface-controlled SSSV that has 
become inoperable and cannot be repaired without removal and 
reinstallation of the tubing. If you remove and reinstall the tubing, 
you must equip the well with a surface-controlled SSSV.



Sec.  250.814  Design, installation, and operation of SSSVs--dry trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below the 
mudline within 2 days after production is established. When warranted by 
conditions such as permafrost, unstable bottom conditions, hydrate 
formation, or paraffin problems, the District Manager may approve an 
alternate setting depth on a case-by-case basis.
    (b) The well must not be open to flow while the SSSV is inoperable, 
except when flowing the well is necessary for a particular operation 
such as cutting paraffin or performing other routine operations as 
defined in Sec.  250.601.
    (c) Until the SSSV is installed, the well must be attended in the 
immediate vicinity so that any necessary emergency actions can be taken 
while the well is open to flow. During testing and inspection 
procedures, the well must not be left unattended while open to 
production unless you have installed a properly operating SSSV in the 
well.
    (d) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with ANSI/API RP 14B (incorporated by reference 
in Sec.  250.198). For additional SSSV testing requirements, refer to 
Sec.  250.880.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]



Sec.  250.815  Subsurface safety devices in shut-in wells--dry trees.

    (a) You must equip all new dry tree completions (perforated but not 
placed on production) and completions that are shut-in for a period of 6 
months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) A surface-controlled SSSV, provided the surface control has been 
rendered inoperative; or
    (3) An injection valve capable of preventing backflow.
    (b) When warranted by conditions such as permafrost, unstable bottom 
conditions, hydrate formation, and paraffin problems, the District 
Manager must approve the setting depth of the subsurface safety device 
for a shut-in well on a case-by-case basis.



Sec.  250.816  Subsurface safety devices in injection wells--dry
 trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.



Sec.  250.817  Temporary removal of subsurface safety devices for
 routine operations.

    (a) You may remove a wireline- or pumpdown-retrievable subsurface 
safety device without further authorization or notice, for a routine 
operation that does not require BSEE approval of a Form BSEE-0124, 
Application for

[[Page 178]]

Permit to Modify (APM). For a list of these routine operations, see 
Sec.  250.601. The removal period must not exceed 15 days.
    (b) Prior to removal, you must identify the well by placing a sign 
on the wellhead stating that the subsurface safety device was removed. 
You must note the removal of the subsurface safety device in the records 
required by Sec.  250.890. If the master valve is open, you must ensure 
that a trained person (see Sec.  250.891) is in the immediate vicinity 
to attend the well and take any necessary emergency actions.
    (c) You must monitor a platform well when a subsurface safety device 
has been removed, but a person does not need to remain in the well-bay 
area continuously if the master valve is closed. If the well is on a 
satellite structure, it must be attended by a support vessel, or a pump-
through plug must be installed in the tubing at least 100 feet below the 
mudline and the master valve must be closed, unless otherwise approved 
by the appropriate District Manager.
    (d) You must not allow the well to flow while the subsurface safety 
device is removed, except when it is necessary for the particular 
operation for which the SSSV is removed. The provisions of this 
paragraph are not applicable to the testing and inspection procedures 
specified in Sec.  250.880.



Sec.  250.818  Additional safety equipment--dry trees.

    (a) You must equip all tubing installations that have a wireline- or 
pumpdown-retrievable subsurface safety device with a landing nipple, 
with flow couplings or other protective equipment above and below it to 
provide for the setting of the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform emergency shutdown system (ESD).
    (c) In addition to the activation of the ESD by manual action on the 
platform, the system may be activated by a signal from a remote 
location. Surface-controlled SSSVs must close in response to shut-in 
signals from the ESD and in response to the fire loop or other fire 
detection devices.



Sec.  250.819  Specification for surface safety valves (SSVs).

    All wellhead SSVs and their actuators must conform to the 
requirements specified in Sec. Sec.  250.801 through 250.803.



Sec.  250.820  Use of SSVs.

    You must install, maintain, inspect, repair, and test all SSVs in 
accordance with API STD 6AV2 (incorporated by reference in Sec.  
250.198). If any SSV does not operate properly, or if any gas and/or 
liquid fluid flow is observed during the leakage test as described in 
Sec.  250.880, then you must shut-in all sources to the SSV and repair 
or replace the valve before resuming production.

[83 FR 49257, Sept. 28, 2018]



Sec.  250.821  Emergency action and safety system shutdown--dry trees.

    (a) If your facility is impacted or will potentially be impacted by 
an emergency situation (e.g., an impending National Weather Service-
named tropical storm or hurricane, ice events, or post-earthquake), you 
must:
    (1) Properly install a subsurface safety device on any well that is 
not yet equipped with a subsurface safety device and that is capable of 
natural flow, as soon as possible, with due consideration being given to 
personnel safety.
    (2) You must shut-in (by closing the SSV and the surface-controlled 
SSSV) the following types of wells:
    (i) All oil wells, and
    (ii) All gas wells requiring compression.
    (b) Closure of the SSV must not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV must close within 2 minutes after the shut-in signal has 
closed the SSV. The District Manager must approve any alternative 
design-delayed closure time of greater than 2 minutes based on the 
mechanical/production characteristics of the individual well.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]

[[Page 179]]



Sec. Sec.  250.822-250.824  [Reserved]

           Subsea and Subsurface Safety Systems--Subsea Trees



Sec.  250.825  Subsea tree subsurface safety devices--general.

    (a) For wells using subsea (wet) trees or for which you intend to 
install subsea trees, you must equip all tubing installations open to 
hydrocarbon-bearing zones with subsurface safety devices that will shut 
off the flow from the well in the event of an emergency. You must also 
install flow couplings above and below the subsurface safety devices. 
For instances where the well at issue is incapable of natural flow, you 
may seek District Manager approval for using alternative procedures or 
equipment, if you propose to use a subsea safety system that is not 
capable of shutting off the flow from the well in the event of an 
emergency. Subsurface safety devices include the following and any 
associated safety valve lock and landing nipple:
    (1) A surface-controlled SSSV;
    (2) An injection valve;
    (3) A tubing plug; and
    (4) A tubing/annular subsurface safety device.
    (b) After installing the subsea tree, but before the rig or 
installation vessel leaves the area, you must test all valves and 
sensors to ensure that they are operating as designed and meet all the 
conditions specified in this subpart.



Sec.  250.826  Specifications for SSSVs--subsea trees.

    All SSSVs, safety valve locks, and landing nipples installed on the 
OCS must conform to the requirements specified in Sec. Sec.  250.801 
through 250.803 and any Deepwater Operations Plan (DWOP) required by 
Sec. Sec.  250.286 through 250.295.



Sec.  250.827  Surface-controlled SSSVs--subsea trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Sec. Sec.  250.829 and 250.830. The surface 
controls must be located on the host facility.



Sec.  250.828  Design, installation, and operation of SSSVs--subsea trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below the 
mudline. When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, or paraffin problems, the 
District Manager may approve an alternate setting depth on a case-by-
case basis.
    (b) The well must not be open to flow while an SSSV is inoperable, 
unless specifically approved by the District Manager in an APM.
    (c) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and 
ANSI/API RP 14B (incorporated by reference in Sec.  250.198). For 
additional SSSV testing requirements, refer to Sec.  250.880.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]



Sec.  250.829  Subsurface safety devices in shut-in wells--subsea trees.

    (a) You must equip all new subsea tree completions (perforated but 
not placed on production) and completions shut-in for a period of 6 
months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) An injection valve capable of preventing backflow; or
    (3) A surface-controlled SSSV, provided the surface control has been 
rendered inoperative. For purposes of this section, a surface-controlled 
SSSV is considered inoperative if, for a direct hydraulic control 
system, you have bled the hydraulics from the control line and have 
isolated it from the hydraulic control pressure. If your controls employ 
an electro-hydraulic control umbilical and the hydraulic control 
pressure to the individual well cannot be isolated, a surface-controlled 
SSSV is considered inoperative if you perform the following:
    (i) Disable the control function of the surface-controlled SSSV 
within the logic of the programmable logic controller which controls the 
subsea well;

[[Page 180]]

    (ii) Place a pressure alarm high on the control line to the surface-
controlled SSSV of the subsea well; and
    (iii) Close the USV and at least one other tree valve on the subsea 
well.
    (b) When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, and paraffin problems, the 
District Manager must approve the setting depth of the subsurface safety 
device for a shut-in well on a case-by-case basis.



Sec.  250.830  Subsurface safety devices in injection wells--subsea trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.



Sec.  250.831  Alteration or disconnection of subsea pipeline or umbilical.

    If a necessary alteration or disconnection of the pipeline or 
umbilical of any subsea well would affect your ability to monitor casing 
pressure or to test any subsea valves or equipment, you must contact the 
appropriate District Office at least 48 hours in advance and submit a 
repair or replacement plan to conduct the required monitoring and 
testing. You must not alter or disconnect until the repair or 
replacement plan is approved.



Sec.  250.832  Additional safety equipment--subsea trees.

    (a) You must equip all tubing installations that have a wireline- or 
pump down-retrievable subsurface safety device installed after May 31, 
1988, with a landing nipple, with flow couplings, or other protective 
equipment above and below it to provide for the setting of the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform ESD.
    (c) In addition to the activation of the ESD by manual action on the 
platform, the system may be activated by a signal from a remote 
location.



Sec.  250.833  Specification for underwater safety valves (USVs).

    All USVs, including those designated as primary or secondary, and 
any alternate isolation valve (AIV) that acts as a USV, if applicable, 
and their actuators, must conform to the requirements specified in 
Sec. Sec.  250.801 through 250.803. A production master or wing valve 
may qualify as a USV under ANSI/API Spec. 6A and API Spec. 6AV1 (both 
incorporated by reference in Sec.  250.198).
    (a) Primary USV (USV1). You must install and designate one USV on a 
subsea tree as the USV1. The USV1 must be located upstream of the choke 
valve. As provided in paragraph (b) of this section, you must inform 
BSEE if the primary USV designation changes.
    (b) Secondary USV (USV2). You may equip your tree with two or more 
valves qualified to be designated as a USV, one of which may be 
designated as the USV2. If the USV1 fails to operate properly or 
exhibits a leakage rate greater than allowed in Sec.  250.880, you must 
notify the appropriate District Office and designate the USV2 or another 
qualified valve (e.g., an AIV) that meets all the requirements of this 
subpart for USVs as the USV1. The USV2 must be located upstream of the 
choke.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]



Sec.  250.834  Use of USVs.

    You must install, maintain, inspect, repair, and test any valve 
designated as the primary USV in accordance with this subpart, your DWOP 
(as specified in Sec. Sec.  250.286 through 250.295), and API STD 6AV2 
(incorporated by reference in Sec.  250.198). For additional USV testing 
requirements, refer to Sec.  250.880.

[83 FR 49257, Sept. 28, 2018]



Sec.  250.835  Specification for all boarding shutdown valves 
(BSDVs) associated with subsea systems.

    You must install a BSDV on the pipeline boarding riser. All new 
BSDVs and any BSDVs removed from service for remanufacturing or repair 
and their actuators installed on the OCS must meet the requirements 
specified in Sec. Sec.  250.801 through 250.803. In addition, you must:

[[Page 181]]

    (a) Ensure that the internal design pressure(s) of the pipeline(s), 
riser(s), and BSDV(s) is fully rated for the maximum pressure of any 
input source and complies with the design requirements set forth in 
subpart J, unless BSEE approves an alternate design.
    (b) Use a BSDV that is fire rated for 30 minutes, and is pressure 
rated for the maximum allowable operating pressure (MAOP) approved in 
your pipeline application.
    (c) Locate the BSDV within 10 feet of the first point of access to 
the boarding pipeline riser (i.e., within 10 feet of the edge of 
platform if the BSDV is horizontal, or within 10 feet above the first 
accessible working deck, excluding the boat landing and above the splash 
zone, if the BSDV is vertical).
    (d) Install a temperature safety element (TSE) and locate it within 
5 feet of each BSDV.



Sec.  250.836  Use of BSDVs.

    You must install, inspect, maintain, repair, and test all new BSDVs, 
as well as all BSDVs that you remove from service for remanufacturing or 
repair, in accordance with API STD 6AV2 (incorporated by reference in 
Sec.  250.198) for SSVs. If any BSDV does not operate properly or if any 
gas fluid and/or liquid fluid flow is observed during the leakage test, 
as described in Sec.  250.880, you must shut-in all sources to the BSDV 
and immediately repair or replace the valve.

[83 FR 49257, Sept. 28, 2018]



Sec.  250.837  Emergency action and safety system shutdown--subsea trees.

    (a) If your facility is impacted or will potentially be impacted by 
an emergency situation (e.g., an impending National Weather Service-
named tropical storm or hurricane, ice events, or post-earthquake), you 
must shut-in all subsea wells unless otherwise approved by the District 
Manager. A shut-in is defined as a closed BSDV, USV, GLSDV, and surface-
controlled SSSV.
    (b) When operating a mobile offshore drilling unit (MODU) or other 
type of workover or intervention vessel in an area with subsea 
infrastructure, you must:
    (1) Suspend production from all wells that could be affected by a 
dropped object, including upstream wells that flow through the same 
pipeline; or
    (2) Establish direct, real-time communications between the MODU or 
other type of workover or intervention vessel and the production 
facility control room and develop a dropped objects plan, as required in 
Sec.  250.714. If an object is dropped, you must immediately secure the 
well directly under the MODU or other type of workover or intervention 
vessel while simultaneously communicating with the platform to shut-in 
all affected wells. You must also maintain without disruption, and 
continuously verify, communication between the production facility and 
the MODU or other type of workover or intervention vessel. If 
communication is lost between the MODU or other type of workover or 
intervention vessel and the platform for 20 or more minutes, you must 
shut-in all wells that could be affected by a dropped object.
    (c) In the event of an emergency, you must operate your production 
system according to the valve closure times in the applicable tables in 
Sec. Sec.  250.838 and 250.839 for the following conditions:
    (1) Process upset. In the event an upset in the production process 
train occurs downstream of the BSDV, you must close the BSDV in 
accordance with the applicable tables in Sec. Sec.  250.838 and 250.839. 
You may reopen the BSDV to blow down the pipeline to prevent hydrates, 
provided you have secured the well(s) and ensured adequate protection.
    (2) Pipeline pressure safety high and low (PSHL) sensor. In the 
event that either a high or a low pressure condition is detected by a 
PSHL sensor located upstream of the BSDV, you must secure the affected 
well and pipeline, and all wells and pipelines associated with a dual or 
multi pipeline system, by closing the BSDVs, USVs, and surface-
controlled SSSVs in accordance with the applicable tables in Sec. Sec.  
250.838 and 250.839. You must obtain approval from the appropriate 
District Manager to resume production in the unaffected pipeline(s) of a 
dual or multi pipeline system. If the PSHL sensor activation was a false 
alarm, you may return the wells to production without contacting the 
appropriate District Manager.

[[Page 182]]

    (3) ESD/TSE (platform). In the event of an ESD activation that is 
initiated because of a platform ESD or platform TSE not associated with 
the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in 
accordance with the applicable tables in Sec. Sec.  250.838 and 250.839.
    (4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency 
shutdown activation that is initiated by the host platform due to an 
abnormal condition subsea, or a TSE associated with the BSDV, you must 
close the BSDV, USV, and surface-controlled SSSV in accordance with the 
applicable tables in Sec. Sec.  250.838 and 250.839.
    (5) Subsea ESD (MODU). In the event of an ESD activation that is 
initiated by a dropped object from a MODU or other type of workover or 
intervention vessel, you must secure all wells in the proximity of the 
MODU or other type of workover or intervention vessel by closing the 
USVs and surface-controlled SSSVs in accordance with the applicable 
tables in Sec. Sec.  250.838 and 250.839. You must notify the 
appropriate District Manager before resuming production.
    (d) Following an ESD or fire, you must bleed your low pressure (LP) 
and high pressure (HP) hydraulic systems in accordance with the 
applicable tables in Sec. Sec.  250.838 and 250.839 to ensure that the 
valves are locked out of service and cannot be reopened inadvertently.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]



Sec.  250.838  What are the maximum allowable valve closure times
 and hydraulic bleeding requirements for an electro-hydraulic control
 system?

    (a) If you have an electro-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure times 
listed in paragraphs (b) and (d) of this section or your approved DWOP; 
and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) through 
visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following table 
or your approved DWOP as long as communication is maintained with the 
platform or with the MODU or other type of workover vessel:

                                                 Valve Closure Timing, Electro-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.
(2) Pipeline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 60  [no              Initiate
                                seconds after     seconds after sensor activation. Close the            minutes after    requirements].   unrestricted
                                sensor            designated USV1 within 20 minutes after sensor        sensor                            bleed within
                                activation.       activation.                                           activation. If                    24 hours after
                                                                                                        you use a 60-                     sensor
                                                                                                        minute manual                     activation.
                                                                                                        resettable
                                                                                                        timer, you may
                                                                                                        continue to
                                                                                                        reset the time
                                                                                                        for closure up
                                                                                                        to a maximum
                                                                                                        of 24 hours
                                                                                                        total.

[[Page 183]]

 
(3) ESD/TSE (Platform).......  Close within 45   Close within 5    Close within 20 minutes after ESD   Close within 20  Initiate         Initiate
                                seconds after     minutes after     or sensor activation.               minutes after    unrestricted     unrestricted
                                ESD or sensor     ESD or sensor                                         ESD or sensor    bleed within     bleed within
                                activation.       activation. If                                        activation. If   60 minutes       60 minutes
                                                  you use a 5-                                          you use a 20-    after ESD or     after ESD or
                                                  minute                                                minute manual    sensor           sensor
                                                  resettable                                            resettable       activation. If   activation. If
                                                  timer, you may                                        timer, you may   you use a 60-    you use a 60-
                                                  continue to                                           continue to      minute manual    minute manual
                                                  reset the time                                        reset the time   resettable       resettable
                                                  for closure up                                        for closure up   timer you must   timer you must
                                                  to a maximum of                                       to a maximum     initiate         initiate
                                                  20 minutes                                            of 60 minutes    unrestricted     unrestricted
                                                  total.                                                total.           bleed within     bleed within
                                                                                                                         24 hours.        24 hours.
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Initiate         Initiate
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    unrestricted     unrestricted
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    bleed within     bleed within
                                activation.       activation                                            activation.      60 minutes       60 minutes
                                                                                                                         after ESD or     after ESD or
                                                                                                                         sensor           sensor
                                                                                                                         activation.      activation.
(5) Subsea ESD (MODU or other  [no               Initiate valve closure immediately. You may allow for closure of the   Initiate         Initiate
 type of workover vessel,       requirements].    tree valves immediately prior to closure of the surface-controlled     unrestricted    unrestricted
 Dropped object).                                 SSSV if desired.                                                       bleed            bleed within
                                                                                                                         immediately.     10 minutes
                                                                                                                                          after ESD
                                                                                                                                          activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) If you have an electro-hydraulic control system and experience a 
loss of communications (EH Loss of Comms), you must comply with the 
following:
    (1) If you can meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office within 12 hours of detecting 
the loss of communication.
    (2) If you cannot meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office immediately after detecting 
the loss of communication. You must shut-in production by initiating a 
bleed of the low pressure (LP) hydraulic system or the high pressure 
(HP) hydraulic system within 120 minutes after loss of communication. 
You must bleed the other hydraulic system within 180 minutes after loss 
of communication.
    (3) You must obtain approval from the appropriate District Manager 
before continuing to produce after loss of communication when you cannot 
meet the EH Loss of Comms valve closure times specified in the table in 
paragraph (d) of this section. In your request, include an alternate 
valve closure timing table that your system is able to achieve. The 
appropriate District Manager may also approve an alternate hydraulic 
bleed schedule to allow for hydrate mitigation and orderly shut-in.
    (d) If you experience a loss of communications, you must comply with 
the maximum allowable valve closure times and hydraulic system bleeding 
requirements listed in the following table or your approved DWOP:

[[Page 184]]



                                    Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.
(2) Pipeline PSHL............  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 5 minutes after sensor           closure when     unrestricted     unrestricted
                                sensor            activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   immediately,     24 hours after
                                                                                                        (close within    concurrent       sensor
                                                                                                        24 hours after   with sensor      activation.
                                                                                                        sensor           activation.
                                                                                                        activation).
(3) ESD/TSE (Platform).......  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 20 minutes after ESD or sensor   closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   concurrent       60 minutes
                                                                                                        (close within    with BSDV        after ESD or
                                                                                                        60 minutes       closure (bleed   sensor
                                                                                                        after ESD or     within 20        activation.
                                                                                                        sensor           minutes after
                                                                                                        activation).     ESD or sensor
                                                                                                                         activation).
(4) Subsea ESD (Platform) or   Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
 BSDV TSE.                      seconds after     (close valves within 5 minutes after ESD or sensor    closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed
                                activation.                                                             system is bled   immediately.     immediately,
                                                                                                        (close within                     allowing for
                                                                                                        20 minutes                        surface-
                                                                                                        after ESD or                      controlled
                                                                                                        sensor                            SSSV closure.
                                                                                                        activation).
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. You may allow for closure of the tree    Initiate         Initiate
 type of workover vessel),      requirements].    valves immediately prior to closure of the surface-controlled SSSV     unrestricted     unrestricted
 Dropped object.                                  if desired.                                                            bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------



Sec.  250.839  What are the maximum allowable valve closure times and hydraulic bleeding requirements for a direct-hydraulic control system?

    (a) If you have a direct-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure times 
listed in this section or your approved DWOP; and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) through 
visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following table 
or your approved DWOP:

[[Page 185]]



                                                  Valve Closure Timing, Direct-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements]
                                sensor
                                activation.
(2) Flowline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 24  Complete bleed   Complete bleed
                                seconds after     seconds after sensor activation. Close the            hours after      of USV1, USV2,   within 24
                                sensor            designated USV1 within 20 minutes after sensor        sensor           and the AIV      hours after
                                activation.       activation.                                           activation.      within 20        sensor
                                                                                                                         minutes after    activation.
                                                                                                                         sensor
                                                                                                                         activation.
(3) ESD/TSE (Platform).......  Close within 45   Close all valves within 20 minutes after ESD or       Close within 60  Complete bleed   Complete bleed
                                seconds after     sensor activation.                                    minutes after    of USV1, USV2,   within 60
                                ESD or sensor                                                           ESD or sensor    and the AIV      minutes after
                                activation.                                                             activation.      within 20        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Complete bleed   Complete bleed
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    of USV1, USV2,   within 10
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    and the AIV      minutes after
                                activation.       activation.                                           activation.      within 10        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. If desired, you may allow for closure    Initiate         Initiate
 type of workover vessel),      requirements].    of the tree valves immediately prior to closure of the surface-        unrestricted     unrestricted
 Dropped object.                                  controlled SSSV.                                                       bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                        PRODUCTION SAFETY SYSTEMS



Sec.  250.840  Design, installation, and maintenance--general.

    You must design, install, and maintain all production facilities and 
equipment including, but not limited to, separators, treaters, pumps, 
heat exchangers, fired components, wellhead injection lines, 
compressors, headers, and flowlines in a manner that is efficient, safe, 
and protects the environment.



Sec.  250.841  Platforms.

    (a) You must protect all platform production facilities with a basic 
and ancillary surface safety system designed, analyzed, installed, 
tested, and maintained in operating condition in accordance with the 
provisions of API RP 14C (incorporated by reference as specified in 
Sec.  250.198). If you use processing components other than those for 
which Safety Analysis Checklists are included in API RP 14C, you must 
utilize the analysis technique and documentation specified in API RP 14C 
to determine the effects and requirements of these components on the 
safety system. Safety device requirements for pipelines are contained in 
Sec.  250.1004.
    (b) You must design, install, inspect, repair, test, and maintain in 
operating condition all platform production process piping in accordance 
with API RP 14E and API 570 (both incorporated by

[[Page 186]]

reference as specified in Sec.  250.198). The District Manager may 
approve temporary repairs to facility piping on a case-by-case basis for 
a period not to exceed 30 days.
    (c) If you plan to make a modification to any production safety 
system that also involves a major modification to the platform 
structure, you must follow the requirements in Sec.  250.900(b)(2). A 
major modification to a platform structure is defined in Sec.  
250.900(b)(2).

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49257, Sept. 28, 2018]



Sec.  250.842  Approval of safety systems design and installation features.

    (a) Before you install or modify a production safety system, you 
must submit a production safety system application to the District 
Manager. The District Manager must approve your production safety system 
application before you commence production through or otherwise use the 
new or modified system. The application must include the design 
documentation prescribed as follows:

------------------------------------------------------------------------
                                          Details and/or additional
         You must submit:                       requirements:
------------------------------------------------------------------------
(1) Safety analysis flow diagram    Your safety analysis flow diagram
 (API RP 14C, Annex B) and Safety    must show the following:
 Analysis Function Evaluation          (i) Well shut-in tubing pressure;
 (SAFE) chart (API RP 14C, section     (ii) Pressure relieving device
 6.3.3) (incorporated by reference      set points;
 in Sec.   250.198)                    (iii) Size, capacity, and design
                                        working pressures of separators,
                                        flare scrubbers, heat
                                        exchangers, treaters, storage
                                        tanks, compressors, and metering
                                        devices;
                                       (iv) Size, capacity, design
                                        working pressures, and maximum
                                        discharge pressure of
                                        hydrocarbon-handling pumps;
                                       (v) Size, capacity, and design
                                        working pressures of hydrocarbon-
                                        handling vessels, and chemical
                                        injection systems handling a
                                        material having a flash point
                                        below 100 degrees Fahrenheit for
                                        a Class I flammable liquid as
                                        described in API RP 500 and API
                                        RP 505 (both incorporated by
                                        reference in Sec.   250.198);
                                        and
                                       (vi) Piping sizes and maximum
                                        allowable working pressures as
                                        determined in accordance with
                                        API RP 14E (incorporated by
                                        reference in Sec.   250.198),
                                        including the locations of
                                        piping specification breaks.
(2) Electrical one-line diagram;    Showing elements including
                                     generators, circuit breakers,
                                     transformers, bus bars, conductors,
                                     automatic transfer switches,
                                     uninterruptable power supply (UPS)
                                     and associated battery banks,
                                     dynamic (motor) loads, and static
                                     loads (e.g., electrostatic treater
                                     grid, lighting panels). You must
                                     also include a functional legend.
(3) Area classification diagram;    A plan for each platform deck and
                                     outlining all classified areas. You
                                     must classify areas according to
                                     API RP 500 or API RP 505 (both
                                     incorporated by reference in Sec.
                                     250.198). The plan must contain:
                                       (i) All major production
                                        equipment, wells, and other
                                        significant hydrocarbon and
                                        class 1 flammable sources, and a
                                        description of the type of
                                        decking, ceiling, walls (e.g.,
                                        grating or solid), and
                                        firewalls; and
                                       (ii) The location of generators
                                        and any buildings (e.g., control
                                        rooms and motor control center
                                        (MCC) buildings) or major
                                        structures on the platform.
(4) A piping and instrumentation    A detailed flow diagram which shows
 diagram, for new facilities;        the piping and vessels in the
                                     process flow, together with the
                                     instrumentation and control
                                     devices.
(5) The service fee listed in Sec.  The fee you must pay will be
   250.125;                          determined by the number of
                                     components involved in the review
                                     and approval process.
------------------------------------------------------------------------

    (b) You must develop and maintain the following design documents and 
make them available to BSEE upon request:

------------------------------------------------------------------------
                                          Details and/or additional
             Diagram:                           requirements:
------------------------------------------------------------------------
(1) Additional electrical system    (i) Cable tray/conduit routing plan
 information;                        that identifies the primary wiring
                                     method (e.g., type cable, cable
                                     schedule, conduit, wire); and
                                    (ii) Panel board/junction box
                                     location plan, if this information
                                     is not shown on the area
                                     classification diagram required in
                                     paragraph (a)(3) of this section.
(2) Schematics of the fire and gas- Showing a functional block diagram
 detection systems;                  of the detection system, including
                                     the electrical power supply and
                                     also including the type, location,
                                     and number of detection sensors;
                                     the type and kind of alarms,
                                     including emergency equipment to be
                                     activated; and the method used for
                                     detection.
(3) Revised piping and              A detailed flow diagram which shows
 instrumentation diagram for         the piping and vessels in the
 existing facilities;                process flow, together with the
                                     instrumentation and control
                                     devices.
------------------------------------------------------------------------


[[Page 187]]

    (c) In the production safety system application, you must also 
certify the following:
    (1) That all electrical systems were designed according to API RP 
14F or API RP 14FZ, as applicable (incorporated by reference in Sec.  
250.198);
    (2) That the design documents for the mechanical and electrical 
systems that you are required to submit under paragraph (a) of this 
section are sealed by a licensed professional engineer. For modified 
systems, only the modifications are required to be sealed by a licensed 
professional engineer(s). The professional engineer must be licensed in 
a State or Territory of the United States and have sufficient expertise 
and experience to perform the duties; and
    (3) That a hazards analysis was performed in accordance with Sec.  
250.1911 and API RP 14J (incorporated by reference in Sec.  250.198), 
and that you have a hazards analysis program in place to assess 
potential hazards during the operation of the facility.
    (d) Within 90 days after placing new or modified production safety 
systems in service, you must submit to the District Manager the as-built 
diagrams for the new or modified production safety systems outlined in 
paragraphs (a)(1), (2), and (3) of this section. You must certify in an 
accompanying letter that the as-built design documents have been 
reviewed for compliance with applicable regulations and accurately 
represent the new or modified system as installed. The drawings must be 
clearly marked ``as-built.''
    (e) You must maintain approved and supporting design documents 
required under paragraphs (a) and (b) of this section at your offshore 
field office nearest the OCS facility or at other locations conveniently 
available to the District Manager. These documents must be made 
available to BSEE upon request and must be retained for the life of the 
facility. All approved designs are subject to field verifications.

[84 FR 24705, May 29, 2019]



Sec. Sec.  250.843-250.849  [Reserved]

                Additional Production System Requirements



Sec.  250.850  Production system requirements--general.

    You must comply with the production safety system requirements in 
Sec. Sec.  250.851 through 250.872, in addition to the practices 
contained in API RP 14C (incorporated by reference as specified in Sec.  
250.198).



Sec.  250.851  Pressure vessels (including heat exchangers) and fired vessels.

    (a) Pressure vessels (including heat exchangers) and fired vessels 
supporting production operations must meet the requirements in the 
following table:

------------------------------------------------------------------------
                                               Applicable codes and
               Item name                           requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels.........  (i) Must be designed,
                                          fabricated, and code stamped
                                          according to applicable
                                          provisions of sections I, IV,
                                          and VIII of the ANSI/ASME
                                          Boiler and Pressure Vessel
                                          Code (incorporated by
                                          reference as specified in Sec.
                                            250.198).
                                         (ii) Must be repaired,
                                          maintained, and inspected in
                                          accordance with API 510
                                          (incorporated by reference as
                                          specified in Sec.   250.198).
(2) Existing uncoded pressure and fired  Must be justified and approval
 vessels:.                                obtained from the District
                                          Manager for their continued
                                          use.
    (i) With an operating pressure
     greater than 15 psig; and
   (ii) That are not code stamped in
    accordance with the ASME Boiler and
    Pressure Vessel Code.

[[Page 188]]

 
(3) Pressure relief valves.............  (i) Must be designed and
                                          installed according to
                                          applicable provisions of
                                          sections I, IV, and VIII of
                                          the ASME Boiler and Pressure
                                          Vessel Code (incorporated by
                                          reference as specified in Sec.
                                            250.198).
                                         (ii) Must conform to the valve
                                          sizing and pressure-relieving
                                          requirements specified in
                                          these documents, but must be
                                          set no higher than the maximum-
                                          allowable working pressure of
                                          the vessel (except for cases
                                          where staggered set pressures
                                          are required for
                                          configurations using multiple
                                          relief valves or redundant
                                          valves installed and
                                          designated for operator use
                                          only).
                                         (iii) Vents must be positioned
                                          in such a way as to prevent
                                          fluid from striking personnel
                                          or ignition sources.
(4) Steam generators operating at less   Must be equipped with a level
 than 15 psig.                            safety low (LSL) sensor which
                                          will shut off the fuel supply
                                          when the water level drops
                                          below the minimum safe level.
(5) Steam generators operating at 15     (i) Must be equipped with a
 psig or greater.                         level safety low (LSL) sensor
                                          which will shut off the fuel
                                          supply when the water level
                                          drops below the minimum safe
                                          level.
                                         (ii) Must be equipped with a
                                          water-feeding device that will
                                          automatically control the
                                          water level except when closed
                                          loop systems are used for
                                          steam generation.
------------------------------------------------------------------------

    (b) Operating pressure ranges. You must use pressure recording 
devices to establish the new operating pressure ranges of pressure 
vessels at any time that the normalized system pressure changes by 50 
psig or 5 percent. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must maintain the pressure recording 
information you used to determine current operating pressure ranges at 
your field office nearest the OCS facility or at another location 
conveniently available to the District Manager for as long as the 
information is valid.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

------------------------------------------------------------------------
                                                         Additional
        Type of sensor               Settings           requirements
------------------------------------------------------------------------
(1) High pressure shut-in       Must be set no     Must also be set
 sensor,.                        higher than 15     sufficiently below
                                 percent or 5 psi   (5 percent or 5 psi,
                                 (whichever is      whichever is
                                 greater) above     greater) the relief
                                 the highest        valve's set pressure
                                 operating          to assure that the
                                 pressure of the    pressure source is
                                 vessel.            shut-in before the
                                                    relief valve
                                                    activates.
(2) Low pressure shut-in        Must be set no     You must receive
 sensor,.                        lower than 15      specific approval
                                 percent or 5 psi   from the District
                                 (whichever is      Manager for
                                 greater) below     activation limits on
                                 the lowest         pressure vessels
                                 pressure in the    that have a pressure
                                 operating range.   safety low (PSL)
                                                    sensor set less than
                                                    5 psi.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 84 FR 24706, May 29, 2019]



Sec.  250.852  Flowlines/Headers.

    (a) You must:
    (1) Equip flowlines from wells with both PSH and PSL sensors. You 
must locate these sensors in accordance with section A.1 of API RP 14C 
(incorporated by reference as specified in Sec.  250.198).
    (2) Use pressure recording devices to establish the new operating 
pressure ranges of flowlines at any time when the normalized system 
pressure changes by 50 psig or 5 percent, whichever is higher. The 
pressure recording devices must document the pressure range over time 
intervals that are no less than 4 hours and no more than 30 days long.

[[Page 189]]

    (3) Maintain the most recent pressure recording information you used 
to determine operating pressure ranges at your field office nearest the 
OCS facility or at another location conveniently available to the 
District Manager for as long as the information is valid.
    (b) Flowline shut-in sensors must meet the requirements in the 
following table (initial set points for pressure sensors must be set 
using gauge readings and engineering design):

------------------------------------------------------------------------
        Type of flowline sensor                      Settings
------------------------------------------------------------------------
(1) PSH sensor,........................  Must be set no higher than 15
                                          percent or 5 psi (whichever is
                                          greater) above the highest
                                          operating pressure of the
                                          flowline. In all cases, the
                                          PSH must be set sufficiently
                                          below the maximum shut-in
                                          wellhead pressure or the gas-
                                          lift supply pressure to ensure
                                          actuation of the SSV. Do not
                                          set the PSH sensor above the
                                          maximum allowable working
                                          pressure of the flowline.
(2) PSL sensor,........................  Must be set no lower than 15
                                          percent or 5 psi (whichever is
                                          greater) below the lowest
                                          operating pressure of the
                                          flowline in which it is
                                          installed.
------------------------------------------------------------------------

    (c) If a well flows directly to a pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) must have a working pressure equal to or greater 
than the maximum shut-in pressure of the well unless the flowline is 
protected by one of the following:
    (1) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. You must design 
the platform flare scrubber to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of hydrocarbons 
that may be relieved to the vessel; or
    (2) Two SSVs with independent PSH sensors connected to separate 
relays and sensing points and installed with adequate volume upstream of 
any block valve to allow sufficient time for the SSVs to close before 
exceeding the maximum allowable working pressure. Each independent PSH 
sensor must close both SSVs along with any associated flowline PSL 
sensor. If the maximum shut-in pressure of a dry tree satellite well(s) 
is greater than 1\1/2\ times the maximum allowable pressure of the 
pipeline, a pressure safety valve (PSV) of sufficient size and relief 
capacity to protect against any SSV leakage or fluid hammer effect may 
be required by the District Manager. The PSV must be installed upstream 
of the host platform boarding valve and vent into the platform flare 
scrubber or some other location approved by the District Manager.
    (d) If a well flows directly to the pipeline from a header without 
prior separation, the header, the header inlet valves, and pipeline 
isolation valve must have a working pressure equal to or greater than 
the maximum shut-in pressure of the well unless the header is protected 
by the safety devices as outlined in paragraph (c) of this section.
    (e) If you are installing flowlines constructed of unbonded flexible 
pipe on a floating platform, you must:
    (1) Review the manufacturer's Design Methodology Verification Report 
and the independent verification agent's (IVA) certificate for the 
design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of ANSI/API Spec. 17J 
(incorporated by reference in Sec.  250.198);
    (2) Determine that the unbonded flexible pipe is suitable for its 
intended purpose;
    (3) Submit to the District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (4) Submit to the District Manager a statement certifying that the 
pipe is suitable for its intended use and that the manufacturer has 
complied with the IVA requirements of ANSI/API Spec. 17J (incorporated 
by reference in Sec.  250.198).

[[Page 190]]

    (f) Automatic pressure or flow regulating choking devices must not 
prevent the normal functionality of the process safety system that 
includes, but is not limited to, the flowline pressure safety devices 
and the SSV.
    (g) You may install a single flow safety valve (FSV) on the platform 
to protect multiple subsea pipelines or wells that tie into a single 
pipeline riser provided that you install an FSV for each riser on the 
platform and test it in accordance with the criteria prescribed in Sec.  
250.880(c)(2)(v).
    (h) You may install a single PSHL sensor on the platform to protect 
multiple subsea pipelines that tie into a single pipeline riser provided 
that you install a PSHL sensor for each riser on the platform and locate 
it upstream of the BSDV.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49259, Sept. 28, 2018]



Sec.  250.853  Safety sensors.

    You must ensure that:
    (a) All shutdown devices, valves, and pressure sensors function in a 
manual reset mode;
    (b) Sensors with integral automatic reset are equipped with an 
appropriate device to override the automatic reset mode;
    (c) All pressure sensors are equipped to permit testing with an 
external pressure source; and
    (d) All level sensors are equipped to permit testing through an 
external bridle on all new vessel installations where possible, 
depending on the type of vessel for which the level sensor is used.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49259, Sept. 28, 2018]



Sec.  250.854  Floating production units equipped with turrets and 
turret-mounted systems.

    (a) For floating production units equipped with an auto slew system, 
you must integrate the auto slew control system with your process safety 
system allowing for automatic shut-in of the production process, 
including the sources (subsea wells, subsea pumps, etc.) and releasing 
of the buoy. Your safety system must immediately initiate a process 
system shut-in according to Sec. Sec.  250.838 and 250.839 and release 
the buoy to prevent hydrocarbon discharge and damage to the subsea 
infrastructure when the following are encountered:
    (1) Your buoy is clamped,
    (2) Your auto slew mode is activated, and
    (3) You encounter a ship heading/position failure or an exceedance 
of the rotational tolerances of the clamped buoy.
    (b) For floating production units equipped with swivel stack 
arrangements, you must equip the portion of the swivel stack containing 
hydrocarbons with a leak detection system. Your leak detection system 
must be tied into your production process surface safety system allowing 
for automatic shut-in of the system. Upon seal system failure and 
detection of a hydrocarbon leak, your surface safety system must 
immediately initiate a process system shut-in according to Sec. Sec.  
250.838 and 250.839.



Sec.  250.855  Emergency shutdown (ESD) system.

    The ESD system must conform to the requirements of Appendix C, 
section C1, of API RP 14C (incorporated by reference as specified in 
Sec.  250.198), and the following:
    (a) The manually operated ESD valve(s) must be quick-opening and 
non-restricted to enable the rapid actuation of the shutdown system. 
Electronic ESD stations must be wired as de-energize to trip circuits or 
as supervised circuits. Because of the key role of the ESD system in the 
platform safety system, all ESD components must be of high quality and 
corrosion resistant and stations must be uniquely identified. Only ESD 
stations at the boat landing may utilize a loop of breakable synthetic 
tubing in lieu of a valve or electric switch. This breakable loop is not 
required to be physically located on the boat landing, but must be 
accessible from a vessel adjacent to or attached to the facility.
    (b) You must maintain a schematic of the ESD that indicates the 
control functions of all safety devices for the platforms on the 
platform, at your field office nearest the OCS facility, or

[[Page 191]]

at another location conveniently available to the District Manager, for 
the life of the facility.



Sec.  250.856  Engines.

    (a) Engine exhaust. You must equip all engine exhausts to comply 
with the insulation and personnel protection requirements of API RP 14C, 
section 4.2 (incorporated by reference as specified in Sec.  250.198). 
You must equip exhaust piping from diesel engines with spark arresters.
    (b) Diesel engine air intake. You must equip diesel engine air 
intakes with a device to shut down the diesel engine in the event of 
runaway (i.e., overspeed). You must equip diesel engines that are 
continuously attended with either remotely operated manual or automatic 
shutdown devices. You must equip diesel engines that are not 
continuously attended with automatic shutdown devices. The following 
diesel engines do not require a shutdown device: Engines for fire water 
pumps; engines on emergency generators; engines that power BOP 
accumulator systems; engines that power air supply for confined entry 
personnel; temporary equipment on non-producing platforms; booster 
engines whose purpose is to start larger engines; and engines that power 
portable single cylinder rig washers.



Sec.  250.857  Glycol dehydration units.

    (a) You must install a pressure relief system or an adequate vent on 
the glycol regenerator (reboiler) to prevent over pressurization. The 
discharge of the relief valve must be vented in a nonhazardous manner.
    (b) You must install the FSV on the dry glycol inlet to the glycol 
contact tower as near as practical to the glycol contact tower.
    (c) You must install the shutdown valve (SDV) on the wet glycol 
outlet from the glycol contact tower as near as practical to the glycol 
contact tower.



Sec.  250.858  Gas compressors.

    (a) You must equip compressor installations with the following 
protective equipment as required in API RP 14C, sections A.4 and A.8 
(incorporated by reference as specified in Sec.  250.198).
    (1) A pressure safety high (PSH) sensor, a pressure safety low (PSL) 
sensor, a pressure safety valve (PSV), a level safety high (LSH) sensor, 
and a level safety low (LSL) sensor to protect each interstage and 
suction scrubber.
    (2) A temperature safety high (TSH) sensor in the discharge piping 
of each compressor cylinder or case discharge.
    (3) You must design the PSH and PSL sensors and LSH controls 
protecting compressor suction and interstage scrubbers to actuate 
automatic SDVs located in each compressor suction and fuel gas line so 
that the compressor unit and the associated vessels can be isolated from 
all input sources. All automatic SDVs installed in compressor suction 
and fuel gas piping must also be actuated by the shutdown of the prime 
mover. Unless otherwise approved by the District Manager, gas-well gas 
affected by the closure of the automatic SDV on the suction side of a 
compressor must be diverted to the pipeline, diverted to a flare or vent 
in accordance with Sec. Sec.  250.1160 or 250.1161, or shut-in at the 
wellhead.
    (4) You must install a blowdown valve on the discharge line of all 
compressor installations that are 1,000 horsepower (746 kilowatts) or 
greater.
    (b) Once system pressure has stabilized, you must use pressure 
recording devices to establish the new operating pressure ranges for 
compressor discharge sensors whenever the normalized system pressure 
changes by 50 psig or 5 percent, whichever is higher. The pressure 
recording devices must document the pressure range over time intervals 
that are no less than 4 hours and no more than 30 days long. You must 
maintain the most recent pressure recording information that you used to 
determine operating pressure ranges at your field office nearest the OCS 
facility or at another location conveniently available to the District 
Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

[[Page 192]]



----------------------------------------------------------------------------------------------------------------
         Type of sensor                               Settings                         Additional requirements
----------------------------------------------------------------------------------------------------------------
(1) PSH sensor,                   Must be set no higher than 15 percent or 5 psi    Must also be set
                                   (whichever is greater) above the highest          sufficiently below (5
                                   operating pressure of the discharge line and      percent or 5 psi, whichever
                                   sufficiently below the maximum discharge          is greater) the set
                                   pressure to ensure actuation of the suction SDV.  pressure of the PSV to
                                                                                     assure that the pressure
                                                                                     source is shut-in before
                                                                                     the PSV activates.
(2) PSL sensor,                   Must be set no lower than 15 percent or 5 psi     ............................
                                   (whichever is greater) below the lowest
                                   operating pressure of the discharge line in
                                   which it is installed.
----------------------------------------------------------------------------------------------------------------


[[Page 193]]



Sec.  250.859  Firefighting systems.

    (a) On fixed facilities, to protect all areas where production-
handling equipment is located, you must install firefighting systems 
that meet the requirements of this paragraph. You must install a 
firewater system consisting of rigid pipe with fire hose stations and/or 
fixed firewater monitors to protect all areas where production-handling 
equipment is located. Your firewater system must include installation of 
a fixed water spray system in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (1) Your firewater system must conform to API RP 14G (incorporated 
by reference as specified in Sec.  250.198).
    (2) Fuel or power for firewater pump drivers must be available for 
at least 30 minutes of run time during a platform shut-in. If necessary, 
you must install an alternate fuel or power supply to provide for this 
pump operating time unless the District Manager has approved an 
alternate firefighting system. In addition:
    (i) As of September 7, 2017, you must have equipped all new 
firewater pump drivers with automatic starting capabilities upon 
activation of the ESD, fusible loop, or other fire detection system.
    (ii) For electric-driven firewater pump drivers, to provide for a 
potential loss of primary power, you must install an automatic transfer 
switch to cross over to an emergency power source in order to maintain 
at least 30 minutes of run time. The emergency power source must be 
reliable and have adequate capacity to carry the locked-rotor currents 
of the fire pump motor and accessory equipment.
    (iii) You must route power cables or conduits with wires installed 
between the fire water pump drivers and the automatic transfer switch 
away from hazardous-classified locations that can cause flame 
impingement. Power cables or conduits with wires that connect to the 
fire water pump drivers must be capable of maintaining circuit integrity 
for not less than 30 minutes of flame impingement.
    (3) You must post, in a prominent place on the facility, a diagram 
of the firefighting system showing the location of all firefighting 
equipment.
    (4) For operations in subfreezing climates, you must furnish 
evidence to the District Manager that the firefighting system is 
suitable for those conditions.
    (5) You must obtain approval from the District Manager before 
installing any firefighting system.
    (6) All firefighting equipment located on a facility must be in good 
working order whether approved as the primary, secondary, or ancillary 
firefighting system.
    (b) On floating facilities, to protect all areas where production-
handling equipment is located, you must install a firewater system 
consisting of rigid pipe with fire hose stations and/or fixed firewater 
monitors. You must install a fixed water spray system in enclosed well-
bay areas where hydrocarbon vapors may accumulate. Your firewater system 
must conform to the USCG requirements for firefighting systems on 
floating facilities.
    (c) Except as provided in paragraph (c)(1) and (2) of this section, 
on fixed and floating facilities, if you are required to maintain a 
firewater system and the system becomes inoperable, you must shut-in 
your production operations while making the necessary repairs. For fixed 
facilities only, you may continue your production operations on a 
temporary basis while you make the necessary repairs, provided that:
    (1) You request that the appropriate District Manager approve the 
use of a chemical firefighting system on a temporary basis (for a period 
up to 7 days) while you make the necessary repairs;
    (2) If you are unable to complete repairs during the approved time 
period because of circumstances beyond your control, the District 
Manager may grant multiple extensions to your previously approved 
request to use a chemical firefighting system for periods up to 7 days 
each.



Sec.  250.860  Chemical firefighting system.

    For fixed platforms:
    (a) On minor unmanned platforms, you may use a U.S. Coast Guard type 
and size rating ``B-II'' portable dry chemical unit (with a minimum UL 
Rating (US) of 60-B:C) or a 30-pound portable dry chemical unit, in lieu 
of a

[[Page 194]]

water system, as long as you ensure that the unit is available on the 
platform when personnel are on board.
    (1) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (2) An unmanned platform is one that is not attended 24 hours a day 
or one on which personnel are not quartered overnight.
    (b) On major platforms and minor manned platforms, you may use a 
firefighting system using chemicals-only in lieu of a water-based system 
if the District Manager determines that the use of a chemical system 
provides equivalent fire-protection control and would not increase the 
risk to human safety.
    (1) A major platform is a structure with either six or more 
completions or zero to five completions with more than one item of 
production processing equipment.
    (2) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (3) A manned platform is one that is attended 24 hours a day or one 
on which personnel are quartered overnight.
    (c) On major platforms and minor manned platforms, to obtain 
approval to use a chemical-only fire prevention and control system in 
lieu of a water system under paragraph (b) of this section, you must 
submit to the District Manager:
    (1) A justification for asserting that the use of a chemical system 
provides equivalent fire-protection control. The justification must 
address fire prevention, fire protection, fire control, and firefighting 
on the platform; and
    (2) A risk assessment demonstrating that a chemical-only system 
would not increase the risk to human safety. You must provide the 
following and any other important information in your risk assessment:

------------------------------------------------------------------------
     For the use of a chemical
 firefighting system on major and
 minor manned platforms, you must              Including . . .
provide the following in your risk
         assessment . . .
------------------------------------------------------------------------
(i) Platform description..........  (A) The type and quantity of
                                     hydrocarbons (i.e., natural gas,
                                     oil) that are produced, handled,
                                     stored, or processed at the
                                     facility.
                                    (B) The capacity of any tanks on the
                                     facility that you use to store
                                     either liquid hydrocarbons or other
                                     flammable liquids.
                                    (C) The total volume of flammable
                                     liquids (other than produced
                                     hydrocarbons) stored on the
                                     facility in containers other than
                                     bulk storage tanks. Include
                                     flammable liquids stored in paint
                                     lockers, storerooms, and drums.
                                    (D) If the facility is manned,
                                     provide the maximum number of
                                     personnel on board and the
                                     anticipated length of their stay.
                                    (E) If the facility is unmanned,
                                     provide the number of days per week
                                     the facility will be visited, the
                                     average length of time spent on the
                                     facility per visit, the mode of
                                     transportation, and whether or not
                                     transportation will be available at
                                     the facility while personnel are on
                                     board.
                                    (F) A diagram that depicts: quarters
                                     location, production equipment
                                     location, fire prevention and
                                     control equipment location,
                                     lifesaving appliances and equipment
                                     location, and evacuation plan
                                     escape routes from quarters and all
                                     manned working spaces to primary
                                     evacuation equipment.
(ii) Hazard assessment (facility    (A) Identification of all likely
 specific).                          fire initiation scenarios
                                     (including those resulting from
                                     maintenance and repair activities).
                                     For each scenario, discuss its
                                     potential severity and identify the
                                     ignition and fuel sources.
                                    (B) Estimates of the fire/radiant
                                     heat exposure that personnel could
                                     be subjected to. Show how you have
                                     considered designated muster areas
                                     and evacuation routes near fuel
                                     sources and have verified proper
                                     flare boom sizing for radiant heat
                                     exposure.
(iii) Human factors assessment      (A) Descriptions of the fire-related
 (not facility specific).            training your employees and
                                     contractors have received. Include
                                     details on the length of training,
                                     whether the training was hands-on
                                     or classroom, the training
                                     frequency, and the topics covered
                                     during the training.
                                    (B) Descriptions of the training
                                     your employees and contractors have
                                     received in fire prevention,
                                     control of ignition sources, and
                                     control of fuel sources when the
                                     facility is occupied.
                                    (C) Descriptions of the instructions
                                     and procedures you have given to
                                     your employees and contractors on
                                     the actions they should take if a
                                     fire occurs. Include those
                                     instructions and procedures
                                     specific to evacuation. State how
                                     you convey this information to your
                                     employees and contractors on the
                                     platform.
(iv) Evacuation assessment          (A) A general discussion of your
 (facility specific).                evacuation plan. Identify your
                                     muster areas (if applicable), both
                                     the primary and secondary
                                     evacuation routes, and the means of
                                     evacuation for both.

[[Page 195]]

 
                                    (B) Description of the type,
                                     quantity, and location of
                                     lifesaving appliances available on
                                     the facility. Show how you have
                                     ensured that lifesaving appliances
                                     are located in the near vicinity of
                                     the escape routes.
                                    (C) Description of the types and
                                     availability of support vessels,
                                     whether the support vessels are
                                     equipped with a fire monitor, and
                                     the time needed for support vessels
                                     to arrive at the facility.
                                    (D) Estimates of the worst case time
                                     needed for personnel to evacuate
                                     the facility should a fire occur.
(v) Alternative protection          (A) Discussion of the reasons you
 assessment.                         are proposing to use an alternative
                                     fire prevention and control system.
                                    (B) Lists of the specific standards
                                     used to design the system, locate
                                     the equipment, and operate the
                                     equipment/system.
                                    (C) Description of the proposed
                                     alternative fire prevention and
                                     control system/equipment. Provide
                                     details on the type, size, number,
                                     and location of the prevention and
                                     control equipment.
                                    (D) Description of the testing,
                                     inspection, and maintenance program
                                     you will use to maintain the fire
                                     prevention and control equipment in
                                     an operable condition. Provide
                                     specifics regarding the type of
                                     inspection, the personnel who
                                     conduct the inspections, the
                                     inspection procedures, and
                                     documentation and recordkeeping.
(vi) Conclusion...................  A summary of your technical
                                     evaluation showing that the
                                     alternative system provides an
                                     equivalent level of personnel
                                     protection for the specific hazards
                                     located on the facility.
------------------------------------------------------------------------

    (d) On major or minor platforms, if BSEE has approved your request 
to use a chemical-only fire suppressant system in lieu of a water system 
under paragraphs (b) and (c) of this section, and if you make an 
insignificant change to your platform subsequent to that approval, you 
must document the change and maintain the documentation for the life of 
the facility at either the facility or nearest field office for BSEE 
review and/or inspection. Do not submit this documentation to the 
District Manager. However, if you make a significant change to your 
platform (e.g., placing a storage vessel with a capacity of 100 barrels 
or more on the facility, adding production equipment), or if you plan to 
man an unmanned platform temporarily, you must submit a new request for 
approval, including an updated risk assessment if previously required, 
to the appropriate District Manager. You must maintain, for the life of 
the facility, the most recent documentation that you submitted to BSEE 
at the facility or nearest field office.



Sec.  250.861  Foam firefighting systems.

    When you install foam firefighting systems as part of a firefighting 
system that protects production handling areas, you must:
    (a) Annually conduct an inspection of the foam concentrates and 
their tanks or storage containers for evidence of excessive sludging or 
deterioration;
    (b) Annually send samples of the foam concentrate to the 
manufacturer or authorized representative for quality condition testing. 
You must have the sample tested to determine the specific gravity, pH, 
percentage of water dilution, and solid content. Based on these results, 
the foam must be certified by an authorized representative of the 
manufacturer as suitable firefighting foam consistent with the original 
manufacturer's specifications. The certification document must be 
readily accessible for field inspection. In lieu of sampling and 
certification, you may choose to replace the total inventory of foam 
with suitable new stock;
    (c) Ensure that the quantity of concentrate meets design 
requirements, and that tanks or containers are kept full, with space 
allowed for expansion.



Sec.  250.862  Fire and gas-detection systems.

    For production processing areas only:
    (a) You must install fire (flame, heat, or smoke) sensors in all 
enclosed classified areas. You must install gas sensors in all 
inadequately ventilated, enclosed classified areas.
    (1) Adequate ventilation is defined as ventilation that is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations

[[Page 196]]

over 25 percent of the lower explosive limit. An acceptable method of 
providing adequate ventilation is one that provides a change of air 
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per 
square foot of solid floor area, whichever is greater.
    (2) Enclosed areas (e.g., buildings, living quarters, or doghouses) 
are defined as those areas confined on more than 4 of their 6 possible 
sides by walls, floors, or ceilings more restrictive to air flow than 
grating or fixed open louvers and of sufficient size to allow entry of 
personnel.
    (3) A classified area is any area classified Class I, Group D, 
Division 1 or 2, following the guidelines of API RP 500 (incorporated by 
reference as specified in Sec.  250.198), or any area classified Class 
I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505 
(incorporated by reference as specified in Sec.  250.198).
    (b) All detection systems must be capable of continuous monitoring. 
Fire-detection systems and portions of combustible gas-detection systems 
related to the higher gas-concentration levels must be of the manual-
reset type. Combustible gas-detection systems related to the lower gas-
concentration level may be of the automatic-reset type.
    (c) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility which are provided with fuel gas. A gas detection system is not 
required for living quarters and doghouses that do not contain a gas 
source and that are not located in a classified area.
    (d) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (e) Fire- and gas-detection systems must be an approved type, and 
designed and installed in accordance with API RP 14C, API RP 14G, API RP 
14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by 
reference as specified in Sec.  250.198), provided that, if compliance 
with any provision of those standards would be in conflict with 
applicable regulations of the U.S. Coast Guard, compliance with the U.S. 
Coast Guard regulations controls.



Sec.  250.863  Electrical equipment.

    You must design, install, and maintain electrical equipment and 
systems in accordance with the requirements in Sec.  250.114.



Sec.  250.864  Erosion.

    You must have a program of erosion control in effect for wells or 
fields that have a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. You must maintain records for each 
lease that indicate the wells that have erosion-control programs in 
effect. You must also maintain the results of the programs for at least 
2 years and make them available to BSEE upon request.



Sec.  250.865  Surface pumps.

    (a) You must equip pump installations with the protective equipment 
required in API RP 14C, Appendix A--A.7, Pumps (incorporated by 
reference as specified in Sec.  250.198).
    (b) You must use pressure recording devices to establish the new 
operating pressure ranges for pump discharge sensors at any time when 
the normalized system pressure changes by 50 psig or 5 percent, 
whichever is higher. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must only maintain the most recent pressure 
recording information that you used to determine operating pressure 
ranges at your field office nearest the OCS facility or at another 
location conveniently available to the District Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

[[Page 197]]



------------------------------------------------------------------------
                                                         Additional
      Type of sensor               Settings             requirements
------------------------------------------------------------------------
(1) PSH sensor............  Must be no higher      Must be set
                             than 15 percent or 5   sufficiently below
                             psi (whichever is      the maximum
                             greater) above the     allowable working
                             highest operating      pressure of the
                             pressure of the        discharge piping.
                             discharge line.        The PSH must also be
                                                    set at least 5
                                                    percent or 5 psi
                                                    (whichever is
                                                    greater) below the
                                                    set pressure of the
                                                    PSV to assure that
                                                    the pressure source
                                                    is shut-in before
                                                    the PSV activates.
(2) PSL sensor............  Must be set no lower
                             than 15 percent or 5
                             psi (whichever is
                             greater) below the
                             lowest operating
                             pressure of the
                             discharge line in
                             which it is
                             installed.
------------------------------------------------------------------------

    (d) The PSL must be placed into service when the pump discharge 
pressure has risen above the PSL sensing point, or within 45 seconds of 
the pump coming into service, whichever is sooner.
    (e) You may exclude the PSH and PSL sensors on small, low-volume 
pumps such as chemical injection-type pumps. This is acceptable if such 
a pump is used as a sump pump or transfer pump, has a discharge rating 
of less than \1/2\ gallon per minute (gpm), discharges into piping that 
is 1 inch or less in diameter, and terminates in piping that is 2 inches 
or larger in diameter.
    (f) You must install a TSE in the immediate vicinity of all pumps in 
hydrocarbon service or those powered by platform fuel gas.
    (g) The pump maximum discharge pressure must be determined using the 
maximum possible suction pressure and the maximum power output of the 
driver as appropriate for the pump type and service.



Sec.  250.866  Personnel safety equipment.

    You must maintain all personnel safety equipment located on a 
facility, whether required or not, in good working condition.



Sec.  250.867  Temporary quarters and temporary equipment.

    (a) You must equip temporary quarters with all safety devices 
required by API RP 14C, Appendix C (incorporated by reference as 
specified in Sec.  250.198). The District Manager must approve the 
safety system/safety devices associated with the temporary quarters 
prior to installation.
    (b) The District Manager may require you to install a temporary 
firewater system for temporary quarters in production processing areas 
or other classified areas.
    (c) Temporary equipment associated with the production process 
system, including equipment used for well testing and/or well clean-up, 
must be approved by the District Manager.
    (d) The District Manager must approve temporary generators that 
would require a change to the electrical one-line diagram in Sec.  
250.842(a).

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49259, Sept. 28, 2018]



Sec.  250.868  Non-metallic piping.

    On fixed OCS facilities, you may use non-metallic piping (such as 
that made from polyvinyl chloride, chlorinated polyvinyl chloride, and 
reinforced fiberglass) only in accordance with the requirements of Sec.  
250.841(b).



Sec.  250.869  General platform operations.

    (a) Surface or subsurface safety devices must not be bypassed or 
blocked out of service unless they are temporarily out of service for 
startup, maintenance, or testing. You may take only the minimum number 
of safety devices out of service. Personnel must monitor the bypassed or 
blocked-out functions until the safety devices are placed back in 
service. Any surface or subsurface safety device which is temporarily 
out of service must be flagged. A designated visual indicator must be 
used to identify the bypassed safety device. You must follow the 
monitoring procedures as follows:
    (1) If you are using a non-computer-based system, meaning your 
safety system operates primarily with pneumatic supply or non-
programmable electrical systems, you must monitor bypassed safety 
devices by positioning monitoring personnel at either the control

[[Page 198]]

panel for the bypassed safety device, or at the bypassed safety device, 
or at the component that the bypassed safety device would be monitoring 
when in service. You must also ensure that monitoring personnel are able 
to view all relevant essential operating conditions until all bypassed 
safety devices are placed back in service and are able to initiate shut-
in action in the event of an abnormal condition.
    (2) If you are using a computer-based technology system, meaning a 
computer-controlled electronic safety system such as supervisory control 
and data acquisition and remote terminal units, you must monitor 
bypassed safety devices by maintaining instantaneous communications at 
all times among remote monitoring personnel and the personnel performing 
maintenance, testing, or startup. Until all bypassed safety devices are 
placed back in service, you must also position monitoring personnel at a 
designated control station that is capable of the following:
    (i) Displaying all relevant essential operating conditions that 
affect the bypassed safety device, well, pipeline, and process 
component. If electronic display of all relevant essential conditions is 
not possible, you must have field personnel monitoring the level gauges 
(sight glass) and pressure gauges in order to know the current operating 
conditions. You must be in communication with all field personnel 
monitoring the gauges;
    (ii) Controlling the production process equipment and the entire 
safety system;
    (iii) Displaying a visual indicator when safety devices are placed 
in the bypassed mode; and
    (iv) Upon command, overriding the bypassed safety device and 
initiating shut-in action in the event of an abnormal condition.
    (3) You must not bypass for startup any element of the emergency 
support system or other support system required by API RP 14C, Appendix 
C (incorporated by reference as specified in Sec.  250.198) without 
first receiving BSEE approval to depart from this operating procedure. 
These systems include, but are not limited to:
    (i) The ESD system to provide a method to manually initiate platform 
shutdown by personnel observing abnormal conditions or undesirable 
events. You do not have to receive approval from the District Manager 
for manual reset and/or initial charging of the system;
    (ii) The fire loop system to sense the heat of a fire and initiate 
platform shutdown, and other fire detection devices (flame, thermal, and 
smoke) that are used to enhance fire detection capability. You do not 
have to receive approval from the District Manager for manual reset and/
or initial charging of the system;
    (iii) The combustible gas detection system to sense the presence of 
hydrocarbons and initiate alarms and platform shutdown before gas 
concentrations reach the lower explosive limit;
    (iv) Adequate ventilation;
    (v) The containment system to collect escaped liquid hydrocarbons 
and initiate platform shutdown;
    (vi) Subsurface safety valves, including those that are self-
actuated (subsurface-controlled SSSVs) or those that are activated by an 
ESD system and/or a fire loop (surface-controlled SSSV). You do not have 
to receive approval from the District Manager for routine operations in 
accordance with Sec.  250.817;
    (vii) The pneumatic supply system; and
    (viii) The system for discharging gas to the atmosphere.
    (4) In instances where components of the ESD, as listed in paragraph 
(a)(3) of this section, are bypassed for maintenance, precautions must 
be taken to provide the equivalent level of protection that existed 
prior to the bypass.
    (b) When wells are disconnected from producing facilities and blind 
flanged, or equipped with a tubing plug, or the master valves have been 
locked closed, you are not required to comply with the provisions of API 
RP 14C (incorporated by reference as specified in Sec.  250.198) or this 
regulation concerning the following:
    (1) Automatic fail-close SSVs on wellhead assemblies, and
    (2) The PSH and PSL sensors in flowlines from wells.

[[Page 199]]

    (c) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, 
safety device testing in accordance with API RP 14C (incorporated by 
reference as specified in Sec.  250.198), or this subpart is not 
required, with the exception of the PSV, unless the vessel is open to 
the atmosphere.
    (d) All open-ended lines connected to producing facilities and wells 
must be plugged or blind-flanged, except those lines designed to be 
open-ended such as flare or vent lines.
    (e) On all new production safety system installations, component 
process control devices and component safety devices must not be 
installed utilizing the same sensing points.
    (f) All pneumatic control panels and computer based control stations 
must be labeled according to API RP 14C nomenclature.



Sec.  250.870  Time delays on pressure safety low (PSL) sensors.

    (a) You may apply industry standard Class B, Class C, or Class B/C 
logic to applicable PSL sensors installed on process equipment. If the 
device may be bypassed for greater than 45 seconds, you must monitor the 
bypassed devices in accordance with Sec.  250.869(a). You must document 
on your field test records any use of a PSL sensor with a time delay 
greater than 45 seconds. For purposes of this section, PSL sensors are 
categorized as follows:
    (1) Class B safety devices have logic that allows for the PSL 
sensors to be bypassed for a fixed time period (typically less than 15 
seconds, but not more than 45 seconds). Examples include sensors used in 
conjunction with the design of pump and compressor panels such as PSL 
sensors, lubricator no-flows, and high-water jacket temperature 
shutdowns.
    (2) Class C safety devices have logic that allows for the PSL 
sensors to be bypassed until the component comes into full service 
(i.e., the time at which the startup pressure equals or exceeds the set 
pressure of the PSL sensor, the system reaches a stabilized pressure, 
and the PSL sensor clears). If a Class C safety device is bypassed, you 
must monitor the device until it is in full service.
    (3) Class B/C safety devices have logic that allows for the PSL 
sensors to incorporate a combination of Class B and Class C circuitry. 
These devices are used to ensure that the PSL sensors are not 
unnecessarily bypassed during startup and idle operations, (e.g., Class 
B/C bypass circuitry activates when a pump is shut down during normal 
operations). The PSL sensor remains bypassed until the pump's start 
circuitry is activated and either:
    (i) The Class B timer expires no later than 45 seconds from start 
activation, or
    (ii) The Class C bypass is initiated until the pump builds up 
pressure above the PSL sensor set point and the PSL sensor comes into 
full service.
    (b) If you do not install time delay circuitry that bypasses 
activation of PSL sensor shutdown logic for a specified time period on 
process and product transport equipment during startup and idle 
operations, you must manually bypass (pin out or disengage) the PSL 
sensor, with a time delay not to exceed 45 seconds.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49259, Sept. 28, 2018]



Sec.  250.871  Welding and burning practices and procedures.

    All welding, burning, and hot-tapping activities must be conducted 
according to the specific requirements in Sec.  250.113.



Sec.  250.872  Atmospheric vessels.

    (a) You must equip atmospheric vessels used to process and/or store 
liquid hydrocarbons or other Class I liquids as described in API RP 500 
or 505 (both incorporated by reference in Sec.  250.198) with protective 
equipment identified in API RP 14C, section A.5 (incorporated by 
reference in Sec.  250.198). Transport tanks approved by the U.S. 
Department of Transportation, that are sealed and not connected via 
interconnected piping to the production process train and that are used 
only for storage of refined liquid hydrocarbons or Class I liquids, are 
not required to be equipped with the protective equipment identified in 
API RP 14C, section A.5. The atmospheric vessels connected to the 
process system that contains a

[[Page 200]]

Class I liquid and the associated pumps must be reflected on the design 
documents listed in Sec.  250.842(a)(1) through (4) and (b)(3).
    (b) You must ensure that all atmospheric vessels are designed and 
maintained to ensure the proper working conditions for LSH sensors. The 
LSH sensor bridle must be designed to prevent different density fluids 
from impacting sensor functionality.
    (c) You must ensure that all atmospheric vessels are designed, 
installed, and maintained to prevent pollution, including the 
displacement of oil out of an overboard water outlet, as required by 
Sec.  250.300(b)(3) and (4).

[83 FR 49259, Sept. 28, 2018]



Sec.  250.873  Subsea gas lift requirements.

    If you choose to install a subsea gas lift system, you must design 
your system as approved in your DWOP or as follows:
    (a) Design the gas lift supply pipeline in accordance with API RP 
14C (incorporated by reference as specified in Sec.  250.198) for the 
gas lift supply system located on the platform.
    (b) Meet the applicable requirements in the following table:

[[Page 201]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Then you must install a
                                  ---------------------------------------------------------------------------------------------
                                    API Spec 6A and API Spec
  If your subsea gas lift system    6AV1 (both incorporated                                                API Spec 6A and API
 introduces the lift gas to the .  by reference as specified   FSV on the gas-lift  PSHL on the gas-lift    Spec 6AV1 manual      In addition, you must
               . .                  in Sec.   250.198) gas-    supply pipeline . .      supply . . .       isolation valve . .
                                      lift shutdown valve               .                                           .
                                       (GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea pipelines, pipeline     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Ensure that the MAOP
 risers, or manifolds via an        requirements for the       upstream (in-board)   platform downstream   board) of the PSHL    of a subsea gas lift
 external gas lift pipeline or      BSDV described in Sec.     of the GLSDV.         (out board) of the    and above the         supply pipeline is
 umbilical.                         Sec.   250.835 and                               GLSDV.                waterline. This       equal to the MAOP of
                                    250.836 on the gas-lift                                                valve does not have   the production
                                    supply pipeline. Locate                                                to be actuated.       pipeline.
                                    the GLSDV within 10 feet                                                                    (ii) Install an actuated
                                    of the first point of                                                                        fail-safe close gas-
                                    access to the gas-lift                                                                       lift isolation valve
                                    riser or topsides                                                                            (GLIV) located at the
                                    umbilical termination                                                                        point of intersection
                                    assembly (TUTA) (i.e.,                                                                       between the gas lift
                                    within 10 feet of the                                                                        supply pipeline and the
                                    edge of the platform if                                                                      production pipeline,
                                    the GLSDV is horizontal,                                                                     pipeline riser, or
                                    or within 10 feet above                                                                      manifold.
                                    the first accessible                                                                        (iii) Install the GLIV
                                    working deck, excluding                                                                      downstream of the
                                    the boat landing and                                                                         underwater safety
                                    above the splash zone,                                                                       valve(s) (USV) and/or
                                    if the GLSDV is in the                                                                       AIV(s).
                                    vertical run of a riser,
                                    or within 10 feet of the
                                    TUTA if using an
                                    umbilical).
(2) Subsea well(s) through the     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Install an actuated,
 casing string via an external      requirements for the       upstream (in-board)   platform down-        board) of the PSHL    fail-safe-closed GLIV
 gas lift pipeline or umbilical.    GLSDV described in Sec.    of the GLSDV.         stream (out board)    and above the         on the gas lift supply
                                    Sec.   250.835 and                               of the GLSDV.         waterline. This       pipeline near the
                                    250.836 on the gas-lift                                                valve does not have   wellhead to provide the
                                    supply pipeline. Locate                                                to be actuated..      dual function of
                                    the GLSDV within 10 feet                                                                     containing annular
                                    of the first point of                                                                        pressure and shutting
                                    access to the gas-lift                                                                       off the gas lift supply
                                    riser or topsides                                                                            gas.
                                    umbilical termination                                                                       (ii) If your subsea tree
                                    assembly (TUTA) (i.e.,                                                                       or tubing head is
                                    within 10 feet of the                                                                        equipped with an
                                    edge of the platform if                                                                      annulus master valve
                                    the GLSDV is horizontal,                                                                     (AMV) or an annulus
                                    or within 10 feet above                                                                      wing valve (AWV), one
                                    the first accessible                                                                         of these may be
                                    working deck, excluding                                                                      designated as the GLIV.
                                    the boat landing and                                                                        (iii) Consider
                                    above the splash zone,                                                                       installing the GLIV
                                    if the GLSDV is in the                                                                       external to the subsea
                                    vertical run of a riser,                                                                     tree to facilitate
                                    or within 10 feet of the                                                                     repair and or
                                    TUTA if using an                                                                             replacement if
                                    umbilical).                                                                                  necessary.

[[Page 202]]

 
(3) Pipeline risers via a gas-     Meet all of the            upstream (in-board)   flowline upstream     downstream (out       (i) Ensure that the gas-
 lift line contained within the     requirements for the       of the GLSDV.         (in-board) of the     board) of the GLSDV.  lift supply flowline
 pipeline riser.                    GLSDV described in Sec.                          FSV.                                        from the gas-lift
                                    Sec.   250.835(a), (b),                                                                      compressor to the GLSDV
                                    and (d) and 250.836 on                                                                       is pressure-rated for
                                    the gas-lift supply                                                                          the MAOP of the
                                    pipeline.                                                                                    pipeline riser.
                                   Attach the GLSDV by                                                                          (ii) Ensure that any
                                    flanged connection                                                                           surface equipment
                                    directly to the ANSI/API                                                                     associated with the gas-
                                    Spec. 6A component used                                                                      lift system is rated
                                    to suspend and seal the                                                                      for the MAOP of the
                                    gas-lift line contained                                                                      pipeline riser.
                                    within the production                                                                       (iii) Ensure that the
                                    riser. To facilitate the                                                                     gas-lift compressor
                                    repair or replacement of                                                                     discharge pressure
                                    the GLSDV or production                                                                      never exceeds the MAOP
                                    riser BSDV, you may                                                                          of the pipeline riser.
                                    install a manual                                                                            (iv) Suspend and seal
                                    isolation valve between                                                                      the gas-lift flowline
                                    the GLSDV and the ANSI/                                                                      contained within the
                                    API Spec. 6A component                                                                       production riser in a
                                    used to suspend and seal                                                                     flanged ANSI/API Spec.
                                    the gas-lift line                                                                            6A component such as an
                                    contained within the                                                                         ANSI/API Spec. 6A
                                    production riser, or                                                                         tubing head and tubing
                                    outboard of the                                                                              hanger or a component
                                    production riser BSDV                                                                        designed, constructed,
                                    and inboard of the ANSI/                                                                     tested, and installed
                                    API Spec. 6A component                                                                       to the requirements of
                                    used to suspend and seal                                                                     ANSI/API Spec. 6A.
                                    the gas-lift line                                                                           (v) Ensure that all
                                    contained within the                                                                         potential leak paths
                                    production riser.                                                                            upstream or near the
                                                                                                                                 production riser BSDV
                                                                                                                                 on the platform provide
                                                                                                                                 the same level of
                                                                                                                                 safety and
                                                                                                                                 environmental
                                                                                                                                 protection as the
                                                                                                                                 production riser BSDV.
                                                                                                                                (vi) Ensure that this
                                                                                                                                 complete assembly is
                                                                                                                                 fire-rated for 30
                                                                                                                                 minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 203]]

    (c) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with gas lift,
    (2) Electro-hydraulic control system with gas lift with loss of 
communications,
    (3) Direct-hydraulic control system with gas lift.
    (d) Follow the gas lift system valve testing requirements according 
to the following table:

[[Page 204]]



----------------------------------------------------------------------------------------------------------------
      Type of gas lift system              Valve           Allowable leakage rate         Testing frequency
----------------------------------------------------------------------------------------------------------------
(1) Gas lifting a subsea pipeline,   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 pipeline riser, or manifold via an                                                   weeks.
 external gas lift pipeline.
                                     GLIV               N/A........................  Function tested quarterly,
                                                                                      not to exceed 120 days.
(2) Gas lifting a subsea well        GLSDV              Zero leakage...............  Monthly, not to exceed 6
 through the casing string via an                                                     weeks.
 external gas lift pipeline.
                                     GLIV               400 cc per minute of liquid  Function tested quarterly,
                                                         or 15 scf per minute of      not to exceed 120 days
                                                         gas..
(3) Gas lifting the pipeline riser   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 via a gas lift line contained                                                        weeks.
 within the pipeline riser.
----------------------------------------------------------------------------------------------------------------


[[Page 205]]


[76 FR 64462, Oct. 18, 2011, as amended at 84 FR 24707, May 29, 2019]



Sec.  250.874  Subsea water injection systems.

    If you choose to install a subsea water injection system, your 
system must comply with your approved DWOP, which must meet the 
following minimum requirements:
    (a) Adhere to the water injection requirements described in API RP 
14C (incorporated by reference as specified in Sec.  250.198) for the 
water injection equipment located on the platform. In accordance with 
Sec.  250.830, either a surface-controlled SSSV or a water injection 
valve (WIV) that is self-activated and not controlled by emergency shut-
down (ESD) or sensor activation must be installed in a subsea water 
injection well.
    (b) Equip a water injection pipeline with a surface FSV and water 
injection shutdown valve (WISDV) on the surface facility.
    (c) Install a PSHL sensor upstream (in-board) of the FSV and WISDV.
    (d) Use subsea tree(s), wellhead(s), connector(s), and tree valves, 
and surface-controlled SSSV or WIV associated with a water injection 
system that are rated for the maximum anticipated injection pressure.
    (e) Consider the effects of hydrogen sulfide (H2S) when designing 
your water flood system, as required by Sec.  250.805.
    (f) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with water injection,
    (2) Electro-hydraulic control system with water injection with loss 
of communications, and
    (3) Direct-hydraulic control system with water injection.
    (g) Comply with the following injection valve testing requirements:
    (1) You must test your injection valves as provided in the following 
table:

------------------------------------------------------------------------
                                   Allowable leakage
              Valve                      rate          Testing frequency
------------------------------------------------------------------------
(i) WISDV.......................  Zero leakage......  Monthly, not to
                                                       exceed 6 weeks
                                                       between tests.
(ii) Surface-controlled SSSV or   400 cc per minute   Semiannually, not
 WIV.                              of liquid or.       to exceed
                                  15 scf per minute   6 calendar months
                                   of gas.             between tests.
------------------------------------------------------------------------

    (2) If a designated USV on a water injection well fails the 
applicable test under Sec.  250.880(c)(4)(ii), you must notify the 
appropriate District Manager and request approval to designate another 
ANSI/API Spec 6A and API Spec. 6AV1 (both incorporated by reference in 
Sec.  250.198) certified subsea valve as your USV.
    (3) If a USV on a water injection well fails the test and the 
surface-controlled SSSV or WIV cannot be tested as required under 
(g)(1)(ii) of this section because of low reservoir pressure, you must 
submit a request to the appropriate District Manager with an alternative 
plan that ensures subsea shutdown capabilities.
    (h) If you experience a loss of communications during water 
injection operations, you must comply with the following:
    (1) Notify the appropriate District Manager within 12 hours after 
detecting loss of communication; and
    (2) Obtain approval from the appropriate District Manager to 
continue to inject during the loss of communication.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49262, Sept. 28, 2018]



Sec.  250.875  Subsea pump systems.

    If you choose to install a subsea pump system, your system must 
comply with your approved DWOP, which must meet the following minimum 
requirements:
    (a) Include the installation of an isolation valve at the inlet of 
your subsea pump module.
    (b) Include a PSHL sensor upstream of the BSDV, if the maximum 
possible discharge pressure of the subsea pump operating in a dead head 
condition

[[Page 206]]

(that is the maximum shut-in tubing pressure at the pump inlet and a 
closed BSDV) is less than the MAOP of the associated pipeline.
    (c) If the maximum possible discharge pressure of the subsea pump 
operating in a dead head situation could be greater than the MAOP of the 
pipeline:
    (1) Include, at minimum, 2 independent functioning PSHL sensors 
upstream of the subsea pump and 2 independent functioning PSHL sensors 
downstream of the pump, that:
    (i) Are operational when the subsea pump is in service; and
    (ii) Will, when activated, shut down the subsea pump, the subsea 
inlet isolation valve, and either the designated USV1, the USV2, or the 
alternate isolation valve.
    (iii) If more than 2 PSHL sensors are installed both upstream and 
downstream of the subsea pump for operational flexibility, then 2 out of 
3 voting logic may be implemented in which the subsea pump remains 
operational provided a minimum of 2 independent PSHL sensors are 
functional both upstream and downstream of the pump.
    (2) Interlock the subsea pump motor with the BSDV to ensure that the 
pump cannot start or operate when the BSDV is closed, incorporate at a 
minimum the following permissive signals into the control system for 
your subsea pump, and ensure that the subsea pump is not able to be 
started or re-started unless:
    (i) The BSDV is open;
    (ii) All automated valves downstream of the subsea pump are open;
    (iii) The upstream subsea pump isolation valve is open; and
    (iv) All parameters associated with the subsea pump operation (e.g., 
pump temperature high, pump vibration high, pump suction pressure high, 
pump discharge pressure high, pump suction flow low) must be cleared 
(i.e., within operational limits) or continuously monitored by personnel 
who observe visual indicators displayed at a designated control station 
and have the capability to initiate shut-in action in the event of an 
abnormal condition.
    (3) Monitor the separator for seawater.
    (4) Ensure that the subsea pump systems are controlled by an 
electro-hydraulic control system.
    (d) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with a subsea pump;
    (2) A loss of communication with the subsea well(s) and not a loss 
of communication with the subsea pump control system without an ESD or 
sensor activation;
    (3) A loss of communication with the subsea pump control system, and 
not a loss of communication with the subsea well(s);
    (4) A loss of communication with the subsea well(s) and the subsea 
pump control system.
    (e) For subsea pump testing:
    (1) Perform a complete subsea pump function test, including full 
shutdown, after any intervention or changes to the software and 
equipment affecting the subsea pump; and
    (2) Test the subsea pump shutdown, including PSHL sensors both 
upstream and downstream of the pump, each quarter (not to exceed 120 
days between tests). This testing may be performed concurrently with the 
ESD function test required by Sec.  250.880(c)(4)(v).



Sec.  250.876  Fired and exhaust heated components.

    No later than September 7, 2018, and at least once every 5 years 
thereafter, you must have qualified third-party inspect, and then you 
must repair or replace, as needed, the fire tube for tube-type heaters 
that are equipped with either automatically controlled natural or forced 
draft burners installed in either atmospheric or pressure vessels that 
heat hydrocarbons and/or glycol. If inspection indicates tube-type 
heater deficiencies, you must complete and document repairs or 
replacements. You must document the inspection results, retain such 
documentation for at least 5 years, and make the documentation available 
to BSEE upon request.

[83 FR 49262, Sept. 28, 2018]

[[Page 207]]



Sec. Sec.  250.877-250.879  [Reserved]

                          Safety Device Testing



Sec.  250.880  Production safety system testing.

    (a) Notification. You must:
    (1) Notify the District Manager at least 72 hours before you 
commence initial production on a facility as required in Sec.  
250.800(a)(2), in order for BSEE to conduct the preproduction inspection 
of the integrated safety system.
    (2) Notify the District Manager upon commencement of production so 
that BSEE may conduct a complete inspection.
    (3) Notify the District Manager and receive BSEE approval before you 
perform any subsea intervention that modifies the existing subsea 
infrastructure in a way that may affect the casing monitoring 
capabilities and testing frequencies specified in the table set forth in 
paragraph (c)(4) of this section.
    (b) Testing methodologies. You must:
    (1) Test safety valves and other equipment at the intervals 
specified in the tables set forth in paragraph (c) of this section or 
more frequently if operating conditions warrant; and
    (2) Perform testing and inspections in accordance with API RP 14C, 
Appendix D (incorporated by reference as specified in Sec.  250.198), 
and the additional requirements specified in the tables of this section 
or as approved in the DWOP for your subsea system.
    (c) Testing frequencies. You must:
    (1) Comply with the following testing requirements for subsurface 
safety devices on dry tree wells:

[[Page 208]]



----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Semi-annually, not to exceed 6 calendar
 in and injection wells).                                             months between tests. Also test in place
                                                                      when first installed or reinstalled. If
                                                                      the device does not operate properly, or
                                                                      if a liquid leakage rate  400
                                                                      cubic centimeters per minute or a gas
                                                                      leakage rate  15 standard cubic
                                                                      feet per minute is observed, the device
                                                                      must be removed, repaired, and reinstalled
                                                                      or replaced. Testing must be according to
                                                                      ANSI/API RP 14B (incorporated by reference
                                                                      in Sec.   250.198) to ensure proper
                                                                      operation.
(ii) Subsurface-controlled SSSVs...................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests for valves not
                                                                      installed in a landing nipple and 12
                                                                      months for valves installed in a landing
                                                                      nipple. The valve must be removed,
                                                                      inspected, and repaired or adjusted, as
                                                                      necessary, and reinstalled or replaced.
(iii) Tubing plug..................................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate  400 cubic centimeters per
                                                                      minute or a gas leakage rate 
                                                                      15 standard cubic feet per minute is
                                                                      observed, the plug must be removed,
                                                                      repaired, and reinstalled or replaced. An
                                                                      additional tubing plug may be installed in
                                                                      lieu of removal.
(iv) Injection valves..............................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate  400 cubic centimeters per
                                                                      minute or a gas leakage rate 
                                                                      15 standard cubic feet per minute is
                                                                      observed, the valve must be removed,
                                                                      repaired and reinstalled or replaced.
----------------------------------------------------------------------------------------------------------------


[[Page 209]]

    (2) Comply with the following testing requirements for surface 
valves:

[[Page 210]]



----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) PSVs...........................................................  Annually, not to exceed 12 calendar months
                                                                      between tests. Valve must either be bench-
                                                                      tested or equipped to permit testing with
                                                                      an external pressure source. Weighted disc
                                                                      vent valves used as PSVs on atmospheric
                                                                      tanks may be disassembled and inspected in
                                                                      lieu of function testing. The main valve
                                                                      piston must be lifted during this test.
(ii) Automatic inlet SDVs that are actuated by a sensor on a vessel  Once each calendar month, not to exceed 6
 or compressor.                                                       weeks between tests.
(iii) SDVs in liquid discharge lines and actuated by vessel low-     Once each calendar month, not to exceed 6
 level sensors.                                                       weeks between tests.
(iv) SSVs..........................................................  Once each calendar month, not to exceed 6
                                                                      weeks between tests. Valves must be tested
                                                                      for both operation and leakage. You must
                                                                      test according to API STD 6AV2
                                                                      (incorporated by reference in Sec.
                                                                      250.198). If an SSV does not operate
                                                                      properly or if any gas and/or liquid fluid
                                                                      flow is observed during the leakage test,
                                                                      the valve must be immediately repaired or
                                                                      replaced.
(v) Flowline FSVs..................................................  Once each calendar month, not to exceed 6
                                                                      weeks between tests. All flowline FSVs
                                                                      must be tested, including those installed
                                                                      on a host facility in lieu of being
                                                                      installed at a satellite well. You must
                                                                      test flowline FSVs for leakage in
                                                                      accordance with the test procedure
                                                                      specified in API RP 14C (incorporated by
                                                                      reference as specified in Sec.   250.198).
                                                                      If leakage measured exceeds a liquid flow
                                                                      of 400 cubic centimeters per minute or a
                                                                      gas flow of 15 standard cubic feet per
                                                                      minute, the FSV must be repaired or
                                                                      replaced.
----------------------------------------------------------------------------------------------------------------


[[Page 211]]

    (3) Comply with the following testing requirements for surface 
safety systems and devices:

[[Page 212]]



----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) Pumps for firewater systems....................................  Must be inspected and operated according to
                                                                      API RP 14G, Section 7.2 (incorporated by
                                                                      reference as specified in Sec.   250.198).
(ii) Fire- (flame, heat, or smoke) and gas detection systems.......  Must be tested for operation and
                                                                      recalibrated every 3 months, not to exceed
                                                                      120 days between tests, provided that
                                                                      testing can be performed in a non-
                                                                      destructive manner. Open flame or devices
                                                                      operating at temperatures that could
                                                                      ignite a methane-air mixture must not be
                                                                      used. All combustible gas-detection
                                                                      systems must be calibrated every 3 months.
(iii) ESD systems..................................................  (A) Pneumatic based ESD systems must be
                                                                      tested for operation at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. You must conduct the test
                                                                      by alternating ESD stations monthly to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. No station may be reused
                                                                      until all stations have been tested.
                                                                     (B) Electronic based ESD systems must be
                                                                      tested for operation at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between tests. The test must be conducted
                                                                      by alternating ESD stations to close at
                                                                      least one wellhead SSV and verify a
                                                                      surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been tested.
                                                                     (C) Electronic/pneumatic based ESD systems
                                                                      must be tested for operation at least once
                                                                      every 3 calendar months, not to exceed 120
                                                                      days between tests. The test must be
                                                                      conducted by alternating ESD stations to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been used.
(iv) TSH devices...................................................  Must be tested for operation annually, not
                                                                      to exceed 12 calendar months between
                                                                      tests, excluding those addressed in
                                                                      paragraph (c)(3)(v) of this section and
                                                                      those that would be destroyed by testing.
                                                                      Those that could be destroyed by testing
                                                                      must be visually inspected and the circuit
                                                                      tested for operations at least once every
                                                                      12 months.
(v) TSH shutdown controls installed on compressor installations      Must be tested every 6 months and repaired
 that can be nondestructively tested.                                 or replaced as necessary.
(vi) Burner safety low.............................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(vii) Flow safety low devices......................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(viii) Flame, spark, and detonation arrestors......................  Must be visually inspected annually, not to
                                                                      exceed 12 calendar months between
                                                                      inspections.
(ix) Electronic pressure transmitters and level sensors: PSH and     Must be tested at least once every 3
 PSL; LSH and LSL.                                                    months, not to exceed 120 days between
                                                                      tests.
(x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic    Must be tested at least once each calendar
 switch/electric analog with mechanical linkage LSH and LSL           month, not to exceed 6 weeks between
 controls.                                                            tests.
----------------------------------------------------------------------------------------------------------------


[[Page 213]]

    (4) Comply with the following testing requirements for subsurface 
safety devices and associated systems on subsea tree wells:

[[Page 214]]



----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Tested semiannually, not to exceed 6 months
 in and injection wells).                                             between tests. If the device does not
                                                                      operate properly, or if a liquid leakage
                                                                      rate  400 cubic centimeters per
                                                                      minute or a gas leakage rate 
                                                                      15 standard cubic feet per minute is
                                                                      observed, the device must be removed,
                                                                      repaired, and reinstalled or replaced.
                                                                      Testing must be according to ANSI/API RP
                                                                      14B (incorporated by reference in Sec.
                                                                      250.198) to ensure proper operation, or as
                                                                      approved in your DWOP.
(ii) USVs..........................................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. If the device does not function
                                                                      properly, or if a liquid leakage rate  400 cubic centimeters per minute
                                                                      or a gas leakage rate  15
                                                                      standard cubic feet per minute is
                                                                      observed, the valve must be removed,
                                                                      repaired, and reinstalled or replaced.
(iii) BSDVs........................................................  Tested at least once each calendar month,
                                                                      not to exceed 6 weeks between tests.
                                                                      Valves must be tested for both operation
                                                                      and leakage. You must test according to
                                                                      API STD 6AV2 for SSVs (incorporated by
                                                                      reference in Sec.   250.198). If a BSDV
                                                                      does not operate properly or if any fluid
                                                                      flow is observed during the leakage test,
                                                                      the valve must be immediately repaired or
                                                                      replaced.
(iv) Electronic ESD logic..........................................  Tested at least once each calendar month,
                                                                      not to exceed 6 weeks between tests.
(v) Electronic ESD function........................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. Shut-in at least one well during
                                                                      the ESD function test. If multiple wells
                                                                      are tied back to the same platform, a
                                                                      different well should be shut-in with each
                                                                      quarterly test.
----------------------------------------------------------------------------------------------------------------


[[Page 215]]

    (d) Subsea wells. (1) Any subsea well that is completed and 
disconnected from monitoring capability may not be disconnected for more 
than 24 months, unless authorized by BSEE.
    (2) Any subsea well that is completed and disconnected from 
monitoring capability for more than 6 months must meet the following 
testing and other requirements:
    (i) Each well must have 3 pressure barriers:
    (A) A closed and tested surface-controlled SSSV,
    (B) A closed and tested USV, and
    (C) One additional closed and tested tree valve.
    (ii) For new completed wells, prior to the rig leaving the well, the 
pressure barriers must be tested as follows:
    (A) The surface-controlled SSSV must be tested for leakage in 
accordance with Sec.  250.828(c);
    (B) The USV and other pressure barrier must be tested to confirm 
zero leakage rate.
    (iii) A sealing pressure cap must be installed on the flowline 
connection hub until the flowline is installed and connected. The 
pressure cap must be designed to accommodate monitoring for pressure 
between the production wing valve and cap. The pressure cap must also be 
designed so that a remotely operated vehicle can bleed pressure off, 
monitor for buildup, and confirm barrier integrity.
    (iv) Pressure monitoring at the sealing pressure cap on the flowline 
connection hub must be performed in each well at intervals not to exceed 
12 months from the time of initial testing of the pressure barrier 
(prior to demobilizing the rig from the field).
    (v) You must have a drilling vessel capable of intervention into the 
disconnected well in the field or readily accessible for use until the 
wells are brought on line.

[81 FR 60918, Sept. 7, 2016, as amended at 83 FR 49262, Sept. 28, 2018]



Sec. Sec.  250.881-250.889  [Reserved]

                          Records and Training



Sec.  250.890  Records.

    (a) You must maintain records that show the present status and 
history of each safety device. Your records must include dates and 
details of installation, removal, inspection, testing, repairing, 
adjustments, and reinstallation.
    (b) You must maintain these records for at least 2 years. You must 
maintain the records at your field office nearest the OCS facility and a 
secure onshore location. These records must be available for review by a 
representative of BSEE.
    (c) You must submit to the appropriate District Manager a contact 
list for all OCS facilities at least annually or when contact 
information is revised. The contact list must include:
    (1) Designated operator name;
    (2) Designated primary point of contact for the facility;
    (3) Facility phone number(s), if applicable;
    (4) Facility fax number, if applicable;
    (5) Facility radio frequency, if applicable;
    (6) Facility helideck rating and size, if applicable; and
    (7) Facility records location if not contained on the facility.



Sec.  250.891  Safety device training.

    You must ensure that personnel installing, repairing, testing, 
maintaining, and operating surface and subsurface safety devices, and 
personnel operating production platforms (including, but not limited to, 
separation, dehydration, compression, sweetening, and metering 
operations), are trained in accordance with the procedures in subpart O 
and subpart S of this part.



Sec. Sec.  250.892-250.899  [Reserved]



                   Subpart I_Platforms and Structures

                   General Requirements for Platforms



Sec.  250.900  What general requirements apply to all platforms?

    (a) You must design, fabricate, install, use, maintain, inspect, and 
assess all platforms and related structures on the Outer Continental 
Shelf (OCS) so as to ensure their structural integrity for the safe 
conduct of drilling, workover, and production operations.

[[Page 216]]

In doing this, you must consider the specific environmental conditions 
at the platform location.
    (b) You must also submit an application under Sec.  250.905 of this 
subpart and obtain the approval of the Regional Supervisor before 
performing any of the activities described in the following table:

------------------------------------------------------------------------
   Activity requiring application and     Conditions for conducting the
                approval                             activity
------------------------------------------------------------------------
(1) Install a platform. This includes    (i) You must adhere to the
 placing a newly constructed platform     requirements of this subpart,
 at a location or moving an existing      including the industry
 platform to a new site.                  standards in Sec.   250.901.
                                         (ii) If you are installing a
                                          floating platform, you must
                                          also adhere to U.S. Coast
                                          Guard (USCG) regulations for
                                          the fabrication, installation,
                                          and inspection of floating OCS
                                          facilities.
(2) Major modification to any platform.  (i) You must adhere to the
 This includes any structural changes     requirements of this subpart,
 that materially alter the approved       including the industry
 plan or cause a major deviation from     standards in Sec.   250.901.
 approved operations and any             (ii) Before you make a major
 modification that increases loading on   modification to a floating
 a platform by 10 percent or more.        platform, you must obtain
                                          approval from both the BSEE
                                          and the USCG for the
                                          modification.
(3) Major repair of damage to any        (i) You must adhere to the
 platform. This includes any corrective   requirements of this subpart,
 operations involving structural          including the industry
 members affecting the structural         standards in Sec.   250.901.
 integrity of a portion or all of the    (ii) Before you make a major
 platform.                                repair to a floating platform,
                                          you must obtain approval from
                                          both the BSEE and the USCG for
                                          the repair.
(4) Convert an existing platform at the  (i) The Regional Supervisor
 current location for a new purpose.      will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          platform at the current
                                          location.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted platform's intended
                                          use; and a demonstration of
                                          the adequacy of the design and
                                          structural condition of the
                                          converted platform.
                                         (iii) If a floating platform,
                                          you must also adhere to USCG
                                          regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.
(5) Convert an existing mobile offshore  (i) The Regional Supervisor
 drilling unit (MODU) for a new purpose.  will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          MODU.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted MODU's intended
                                          location and use; a
                                          demonstration of the adequacy
                                          of the design and structural
                                          condition of the converted
                                          MODU; and a demonstration that
                                          the level of safety for the
                                          converted MODU is at least
                                          equal to that of re-used
                                          platforms.
                                         (iii) You must also adhere to
                                          USCG regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.
------------------------------------------------------------------------

    (c) Under emergency conditions, you may make repairs to primary 
structural elements to restore an existing permitted condition without 
submitting an application or receiving prior BSEE approval for up to 
120-calendar days following an event. You must notify the Regional 
Supervisor of the damage that occurred within 24 hours of its discovery, 
and you must provide a written completion report to the Regional 
Supervisor of the repairs that were made within 1 week after completing 
the repairs. If you make emergency repairs on a floating platform, you 
must also notify the USCG.
    (d) You must determine if your new platform or major modification to 
an existing platform is subject to the Platform Verification Program 
(PVP). Section 250.910 of this subpart fully describes the facilities 
that are subject to the PVP. If you determine that your platform is 
subject to the PVP, you must follow the requirements of Sec. Sec.  
250.909 through 250.918 of this subpart.
    (e) You must submit notification of the platform installation date 
and the final as-built location data to the Regional Supervisor within 
45-calendar days of completion of platform installation.
    (1) For platforms not subject to the Platform Verification Program 
(PVP), BSEE will cancel the approved platform application 1 year after 
the approval has been granted if the platform has not been installed. If 
BSEE cancels the approval, you must resubmit your platform application 
and receive BSEE

[[Page 217]]

approval if you still plan to install the platform.
    (2) For platforms subject to the PVP, cancellation of an approval 
will be on an individual platform basis. For these platforms, BSEE will 
identify the date when the installation approval will be cancelled (if 
installation has not occurred) during the application and approval 
process. If BSEE cancels your installation approval, you must resubmit 
your platform application and receive BSEE approval if you still plan to 
install the platform.



Sec.  250.901  What industry standards must your platform meet?

    (a) In addition to the other requirements of this subpart, your 
plans for platform design, analysis, fabrication, installation, use, 
maintenance, inspection and assessment must, as appropriate, conform to:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by 
reference at Sec.  250.198);
    (2) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by 
reference at Sec.  250.198);
    (3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, 
(as specified in Sec.  250.198);
    (4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim 
Guidance for Design of Offshore Structures for Hurricane Conditions, (as 
incorporated by reference in Sec.  250.198);
    (5) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, (as incorporated 
by reference in Sec.  250.198);
    (6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, (as incorporated by reference in Sec.  250.198);
    (7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, 
and Constructing Fixed Offshore Platforms--Working Stress Design (as 
incorporated by reference in Sec.  250.198);
    (8) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (as incorporated by reference 
in Sec.  250.198);
    (9) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Drilling Units (as incorporated by reference in Sec.  250.198);
    (10) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (as incorporated by reference 
in Sec.  250.198);
    (11) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (as incorporated by 
reference in Sec.  250.198);
    (12) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (as incorporated by reference in Sec.  250.198);
    (13) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (as incorporated by reference in 
Sec.  250.198);
    (14) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (as incorporated by 
reference in Sec.  250.198);
    (15) American Society for Testing and Materials (ASTM) Standard C 
33-07, approved December 15, 2007, Standard Specification for Concrete 
Aggregates (as incorporated by reference in Sec.  250.198);
    (16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete (as incorporated by reference in 
Sec.  250.198);
    (17) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement (as incorporated by reference in Sec.  
250.198);
    (18) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete (as 
incorporated by reference in Sec.  250.198);
    (19) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements (as incorporated by 
reference in Sec.  250.198);
    (20) AWS D1.1, Structural Welding Code--Steel, including Commentary, 
(as incorporated by reference in Sec.  250.198);

[[Page 218]]

    (21) AWS D1.4, Structural Welding Code--Reinforcing Steel, (as 
incorporated by reference in Sec.  250.198);
    (22) AWS D3.6M, Specification for Underwater Welding, (as 
incorporated by reference in Sec.  250.198);
    (23) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (as incorporated by reference 
in Sec.  250.198);
    (24) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended 
Practice, Corrosion Control of Steel Fixed Offshore Structures 
Associated with Petroleum Production (as incorporated by reference in 
Sec.  250.198).
    (b) You must follow the requirements contained in the documents 
listed under paragraph (a) of this section insofar as they do not 
conflict with other provisions of 30 CFR part 250. You may use 
applicable provisions of these documents, as approved by the Regional 
Supervisor, for the design, fabrication, and installation of platforms 
such as spars, since standards specifically written for such structures 
do not exist. You may also use alternative codes, rules, or standards, 
as approved by the Regional Supervisor, under the conditions enumerated 
in Sec.  250.141.
    (c) For information on the standards mentioned in this section, and 
where they may be obtained, see Sec.  250.198 of this part.
    (d) The following chart summarizes the applicability of the industry 
standards listed in this section for fixed and floating platforms:

------------------------------------------------------------------------
                                                       Applicable to . .
                  Industry standard                            .
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code Requirements    Fixed and
 for Reinforced Concrete (ACI 318-95) and Commentary    floating
 (ACI 318R-95),                                         platform, as
                                                        appropriate.
(2) ANSI/AISC 360-05, Specification for Structural
 Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design
 of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for
 Assessment of Existing Offshore Structures for
 Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on
 Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and
 Constructing Fixed Offshore Platforms--Working
 Stress Design;
(7) ASTM Standard C 33-07, approved December 15,
 2007, Standard Specification for Concrete
 Aggregates;
(8) ASTM Standard C 94/C 94M-07, approved January 1,
 2007, Standard Specification for Ready-Mixed
 Concrete;
(9) ASTM Standard C 150-07, approved May 1, 2007,
 Standard Specification for Portland Cement;
(10) ASTM Standard C 330-05, approved December 15,
 2005, Standard Specification for Lightweight
 Aggregates for Structural Concrete;
(11) ASTM Standard C 595-08, approved January 1,
 2008, Standard Specification for Blended Hydraulic
 Cements;
(12) AWS D1.1, Structural Welding Code--Steel;
(13) AWS D1.4, Structural Welding Code--Reinforcing
 Steel;
(14) AWS D3.6M, Specification for Underwater Welding;
(15) NACE Standard RP 0176-2003, Standard Recommended
 Practice (RP), Corrosion Control of Steel Fixed
 Offshore Platforms Associated with Petroleum
 Production;
(16) ACI 357R-84, Guide for the Design and             Fixed platforms.
 Construction of Fixed Offshore Concrete Structures,
 1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis    Floating
 for Offshore Production Facilities;                    platforms.
(18) API RP 2FPS, RP for Planning, Designing, and
 Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating
 Production Systems (FPSs) and Tension-Leg Platforms
 (TLPs);
(20) API RP 2SK, RP for Design and Analysis of
 Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and
 Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture,
 Installation, and Maintenance of Synthetic Fiber
 Ropes for Offshore Mooring;
(23) API RP 2I, In-Service Inspection of Mooring       .................
 Hardware for Floating Drilling Units
------------------------------------------------------------------------


[[Page 219]]


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.902  What are the requirements for platform removal and location clearance?

    You must remove all structures according to Sec. Sec.  250.1725 
through 250.1730 of Subpart Q--Decommissioning Activities of this part.



Sec.  250.903  What records must I keep?

    (a) You must compile, retain, and make available to BSEE 
representatives for the functional life of all platforms:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation nondestructive 
examination records;
    (4) The inspection results from the inspections required by Sec.  
250.919 of this subpart; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec.  250.919(b).
    (b) You must record and retain the original material test results of 
all primary structural materials during all stages of construction. 
Primary material is material that, should it fail, would lead to a 
significant reduction in platform safety, structural reliability, or 
operating capabilities. Items such as steel brackets, deck stiffeners 
and secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide BSEE with the location of these records in the 
certification statement of your application for platform approval as 
required in Sec.  250.905(j).

                        Platform Approval Program



Sec.  250.904  What is the Platform Approval Program?

    (a) The Platform Approval Program is the BSEE basic approval process 
for platforms on the OCS. The requirements of the Platform Approval 
Program are described in Sec. Sec.  250.904 through 250.908 of this 
subpart. Completing these requirements will satisfy BSEE criteria for 
approval of fixed platforms of a proven design that will be placed in 
the shallow water areas (<=400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met by 
all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater ( 400 ft.) or a frontier area, you 
must also meet the requirements of the Platform Verification Program. 
The requirements of the Platform Verification Program are described in 
Sec. Sec.  250.909 through 250.918 of this subpart.



Sec.  250.905  How do I get approval for the installation, modification, or repair of my platform?

    The Platform Approval Program requires that you submit the 
information, documents, and fee listed in the following table for your 
proposed project. In lieu of submitting the paper copies specified in 
the table, you may submit your application electronically in accordance 
with 30 CFR 250.186(a)(3).

------------------------------------------------------------------------
     Required submittal         Required contents    Other requirements
------------------------------------------------------------------------
(a) Application cover letter  Proposed structure    You must submit
                               designation, lease    three copies. If,
                               number, area, name,   your facility is
                               and block number,     subject to the
                               and the type of       Platform
                               facility your         Verification
                               facility (e.g.,       Program (PVP), you
                               drilling,             must submit four
                               production,           copies.
                               quarters). The
                               structure
                               designation must be
                               unique for the
                               field (some fields
                               are made up of
                               several blocks);
                               i.e. once a
                               platform ``A'' has
                               been used in the
                               field there should
                               never be another
                               platform ``A'' even
                               if the old platform
                               ``A'' has been
                               removed. Single
                               well free standing
                               caissons should be
                               given the same
                               designation as the
                               well. All other
                               structures are to
                               be designated by
                               letter designations.

[[Page 220]]

 
(b) Location plat...........  Latitude and          Your plat must be
                               longitude             drawn to a scale of
                               coordinates,          1 inch equals 2,000
                               Universal Mercator    feet and include
                               grid-system           the coordinates of
                               coordinates, state    the lease block
                               plane coordinates     boundary lines. You
                               in the Lambert or     must submit three
                               Transverse Mercator   copies.
                               Projection System,
                               and distances in
                               feet from the
                               nearest block
                               lines. These
                               coordinates must be
                               based on the NAD
                               (North American
                               Datum) 27 datum
                               plane coordinate
                               system.
(c) Front, Side, and Plan     Platform dimensions   Your drawing sizes
 View drawings.                and orientation,      must not exceed
                               elevations relative   11 x
                               to M.L.L.W. (Mean     17. You
                               Lower Low Water),     must submit three
                               and pile sizes and    copies (four copies
                               penetration.          for PVP
                                                     applications).
(d) Complete set of           The approved for      Your drawing sizes
 structural drawings.          construction          must not exceed
                               fabrication           11 x
                               drawings should be    17. You
                               submitted             must submit one
                               including; e.g.,      copy.
                               cathodic protection
                               systems; jacket
                               design; pile
                               foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces; mooring
                               and tethering
                               systems;
                               foundations and
                               anchoring systems.
(e) Summary of environmental  A summary of the      You must submit one
 data.                         environmental data    copy.
                               described in the
                               applicable
                               standards
                               referenced under
                               Sec.   250.901(a)
                               of this subpart and
                               in Sec.   250.198
                               of Subpart A, where
                               the data is used in
                               the design or
                               analysis of the
                               platform. Examples
                               of relevant data
                               include information
                               on waves, wind,
                               current, tides,
                               temperature, snow
                               and ice effects,
                               marine growth, and
                               water depth.
(f) Summary of the            Loading information   You must submit one
 engineering design data.      (e.g., live, dead,    copy.
                               environmental),
                               structural
                               information (e.g.,
                               design-life;
                               material types;
                               cathodic protection
                               systems; design
                               criteria; fatigue
                               life; jacket
                               design; deck
                               design; production
                               component design;
                               pile foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               mooring or
                               tethering systems;
                               fabrication and
                               installation
                               guidelines), and
                               foundation
                               information (e.g.,
                               soil stability,
                               design criteria).
(g) Project-specific studies  All studies           You must submit one
 used in the platform design   pertinent to          copy of each study.
 or installation.              platform design or
                               installation, e.g.,
                               oceanographic and/
                               or soil reports
                               including the
                               overall site
                               investigative
                               report required in
                               Sec.   250.906.
(h) Description of the loads  Loads imposed by      You must submit one
 imposed on the facility.      jacket; decks;        copy.
                               production
                               components;
                               drilling,
                               production, and
                               pipeline risers,
                               and riser
                               tensioning systems;
                               turrets and turret-
                               and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               and mooring or
                               tethering systems.
(i) Summary of safety         A summary of          You must submit one
 factors utilized.             pertinent derived     copy.
                               factors of safety
                               against failure for
                               major structural
                               members, e.g.,
                               unity check ratios
                               exceeding 0.85 for
                               steel-jacket
                               platform members,
                               indicated on
                               ``line'' sketches
                               of jacket sections.
(j) A copy of the in-service  This plan is          You must submit one
 inspection plan.              described in Sec.     copy.
                               250.919.

[[Page 221]]

 
(k) Certification statement.  The following         An authorized
                               statement: ``The      company
                               design of this        representative must
                               structure has been    sign the statement.
                               certified by a        You must submit one
                               recognized            copy.
                               classification
                               society, or a
                               registered civil or
                               structural engineer
                               or equivalent, or a
                               naval architect or
                               marine engineer or
                               equivalent,
                               specializing in the
                               design of offshore
                               structures. The
                               certified design
                               and as-built plans
                               and specifications
                               will be on file at
                               (give location)''.
(l) Payment of the service
 fee listed in Sec.
 250.125.
------------------------------------------------------------------------



Sec.  250.906  What must I do to obtain approval for the proposed site of my platform?

    (a) Shallow hazards surveys. You must perform a high-resolution or 
acoustic-profiling survey to obtain information on the conditions 
existing at and near the surface of the seafloor. You must collect 
information through this survey sufficient to determine the presence of 
the following features and their likely effects on your proposed 
platform:
    (1) Shallow faults;
    (2) Gas seeps or shallow gas;
    (3) Slump blocks or slump sediments;
    (4) Shallow water flows;
    (5) Hydrates; or
    (6) Ice scour of seafloor sediments.
    (b) Geologic surveys. You must perform a geological survey relevant 
to the design and siting of your platform. Your geological survey must 
assess:
    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program, the various 
field and laboratory test methods employed, and the applicability of 
these methods as they pertain to the quality of the samples, the type of 
soil, and the anticipated design application. You must explain how the 
engineering properties of each soil stratum affect the design of your 
platform. In your explanation you must describe the uncertainties 
inherent in your overall testing program, and the reliability and 
applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for your 
platform that integrates the findings of your shallow hazards surveys 
and geologic surveys, and, if required, your subsurface surveys. Your 
overall site investigation report must include analyses of the potential 
for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquefaction, or possible reduction of soil strength due to 
increased pore pressures;
    (6) Degradation of subsea permafrost layers;
    (7) Cyclic loading;
    (8) Lateral loading;
    (9) Dynamic loading;
    (10) Settlements and displacements;

[[Page 222]]

    (11) Plastic deformation and formation collapse mechanisms; and
    (12) Soil reactions on the platform foundations or anchoring 
systems.



Sec.  250.907  Where must I locate foundation boreholes?

    (a) For fixed or bottom-founded platforms and tension leg platforms, 
your maximum distance from any foundation pile to a soil boring must not 
exceed 500 feet.
    (b) For deepwater floating platforms which utilize catenary or taut-
leg moorings, you must take borings at the most heavily loaded anchor 
location, at the anchor points approximately 120 and 240 degrees around 
the anchor pattern from that boring, and, as necessary, other points 
throughout the anchor pattern to establish the soil profile suitable for 
foundation design purposes.



Sec.  250.908  What are the minimum structural fatigue design requirements?

    (a) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms (as incorporated by reference in 
Sec.  250.198), requires that the design fatigue life of each joint and 
member be twice the intended service life of the structure. When 
designing your platform, the following table provides minimum fatigue 
life safety factors for critical structural members and joints.

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural          The results of the fatigue
 redundancy to prevent catastrophic          analysis must indicate a
 failure of the platform or structure        minimum calculated life of
 under consideration,                        twice the design life of
                                             the platform.
(2) There is not sufficient structural      The results of a fatigue
 redundancy to prevent catastrophic          analysis must indicate a
 failure of the platform or structure,       minimum calculated life or
                                             three times the design life
                                             of the platform.
(3) The desirable degree of redundancy is   The results of a fatigue
 significantly reduced as a result of        analysis must indicate a
 fatigue damage,                             minimum calculated life of
                                             three times the design life
                                             of the platform.
------------------------------------------------------------------------

    (b) The documents incorporated by reference in Sec.  250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph (a) 
of this section, the requirements of the incorporated document will 
prevail.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

                      Platform Verification Program



Sec.  250.909  What is the Platform Verification Program?

    The Platform Verification Program is the BSEE approval process for 
ensuring that floating platforms; platforms of a new or unique design; 
platforms in seismic areas; or platforms located in deepwater or 
frontier areas meet stringent requirements for design and construction. 
The program is applied during construction of new platforms and major 
modifications of, or repairs to, existing platforms. These requirements 
are in addition to the requirements of the Platform Approval Program 
described in Sec. Sec.  250.904 through 250.908 of this subpart.



Sec.  250.910  Which of my facilities are subject to the Platform Verification Program?

    (a) All new fixed or bottom-founded platforms that meet any of the 
following five conditions are subject to the Platform Verification 
Program:
    (1) Platforms installed in water depths exceeding 400 feet (122 
meters);
    (2) Platforms having natural periods in excess of 3 seconds;
    (3) Platforms installed in areas of unstable bottom conditions;
    (4) Platforms having configurations and designs which have not 
previously been used or proven for use in the area; or
    (5) Platforms installed in seismically active areas.
    (b) All new floating platforms are subject to the Platform 
Verification Program to the extent indicated in the following table:

[[Page 223]]



------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a         The entire platform is
 buoyant offshore facility that does not     subject to the Platform
 have a ship-shaped hull,                    Verification Program
                                             including the following
                                             associated structures:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser does not
                                             have tensioning systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
(2) Your new floating platform is a         Only the following
 buoyant offshore facility with a ship-      structures that may be
 shaped hull,                                associated with a floating
                                             platform are subject to the
                                             Platform Verification
                                             Program:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser tensioning
                                             systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
------------------------------------------------------------------------

    (c) If a platform is originally subject to the Platform Verification 
Program, then the conversion of that platform at that same site for a 
new purpose, or making a major modification of, or major repair to, that 
platform, is also subject to the Platform Verification Program. A major 
modification includes any modification that increases loading on a 
platform by 10 percent or more. A major repair is a corrective operation 
involving structural members affecting the structural integrity of a 
portion or all of the platform. Before you make a major modification or 
repair to a floating platform, you must obtain approval from both the 
BSEE and the USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by BSEE on a case-by-
case basis.



Sec.  250.911  If my platform is subject to the Platform Verification Program, what must I do?

    If your platform, conversion, or major modification or repair meets 
the criteria in Sec.  250.910, you must:
    (a) Design, fabricate, install, use, maintain and inspect your 
platform, conversion, or major modification or repair to your platform 
according to the requirements of this subpart, and the applicable 
documents listed in Sec.  250.901(a) of this subpart;
    (b) Comply with all the requirements of the Platform Approval 
Program found in Sec. Sec.  250.904 through 250.908 of this subpart.
    (c) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec.  250.912;
    (d) Submit a complete schedule of all phases of design, fabrication, 
and installation for the Regional Supervisor's approval. You must 
include a project management timeline, Gantt Chart, that depicts when 
interim and final reports required by Sec. Sec.  250.916, 250.917, and 
250.918 will be submitted to the Regional Supervisor for each phase. On 
the timeline, you must break-out the specific scopes of work that 
inherently stand alone (e.g., deck, mooring systems, tendon systems, 
riser systems, turret systems).
    (e) Include your nomination of a Certified Verification Agent (CVA) 
as a part of each verification plan required by Sec.  250.912;
    (f) Follow the additional requirements in Sec. Sec.  250.913 through 
250.918;
    (g) Obtain approval for modifications to approved plans and for 
major deviations from approved installation procedures from the Regional 
Supervisor; and
    (h) Comply with applicable USCG regulations for floating OCS 
facilities.

[[Page 224]]



Sec.  250.912  What plans must I submit under the Platform Verification Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec.  250.910, you must submit the following plans to 
the Regional Supervisor for approval:
    (a) Design verification plan. You may submit your design 
verification plan to BSEE with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD) to BOEM. Your design verification must be 
conducted by, or be under the direct supervision of, a registered 
professional civil or structural engineer or equivalent, or a naval 
architect or marine engineer or equivalent, with previous experience in 
directing the design of similar facilities, systems, structures, or 
equipment. For floating platforms, you must ensure that the requirements 
of the USCG for structural integrity and stability, e.g., verification 
of center of gravity, etc., have been met. Your design verification plan 
must include the following:
    (1) All design documentation specified in Sec.  250.905 of this 
subpart;
    (2) Abstracts of the computer programs used in the design process; 
and
    (3) A summary of the major design considerations and the approach to 
be used to verify the validity of these design considerations.
    (b) Fabrication verification plan. The Regional Supervisor must 
approve your fabrication verification plan before you may initiate any 
related operations. Your fabrication verification plan must include the 
following:
    (1) Fabrication drawings and material specifications for artificial 
island structures and major members of concrete-gravity and steel-
gravity structures;
    (2) For jacket and floating structures, all the primary load-bearing 
members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds and 
materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must specify 
the acceptance and rejection criteria to be used for any inspections 
conducted during installation, and for the post-installation 
verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.



Sec.  250.913  When must I resubmit Platform Verification Program plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or
    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.



Sec.  250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.

[[Page 225]]

    (b) For each CVA, you must submit a list of documents to be 
forwarded to the CVA, and a qualification statement that includes the 
following:
    (1) Previous experience in third-party verification or experience in 
the design, fabrication, installation, or major modification of offshore 
oil and gas platforms. This should include fixed platforms, floating 
platforms, manmade islands, other similar marine structures, and related 
systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with BSEE requirements and procedures;
    (7) The level of work to be performed by the CVA.



Sec.  250.915  What are the CVA's primary responsibilities?

    (a) The CVA must conduct specified reviews according to Sec. Sec.  
250.916, 250.917, and 250.918 of this subpart.
    (b) Individuals or organizations acting as CVAs must not function in 
any capacity that would create a conflict of interest, or the appearance 
of a conflict of interest.
    (c) The CVA must consider the applicable provisions of the documents 
listed in Sec.  250.901(a); the alternative codes, rules, and standards 
approved under Sec.  250.901(b); and the requirements of this subpart.
    (d) The CVA is the primary contact with the Regional Supervisor and 
is directly responsible for providing immediate reports of all incidents 
that affect the design, fabrication and installation of the platform.



Sec.  250.916  What are the CVA's primary duties during the design phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the environmental 
and functional load conditions appropriate for the intended service life 
at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For fixed platforms and non-ship-shaped floating  Conduct an independent assessment of all proposed:
 facilities,                                          (i) Planning criteria;
                                                      (ii) Operational requirements;
                                                      (iii) Environmental loading data;
                                                      (iv) Load determinations;
                                                      (v) Stress analyses;
                                                      (vi) Material designations;
                                                      (vii) Soil and foundation conditions;
                                                      (viii) Safety factors; and
                                                      (ix) Other pertinent parameters of the proposed design.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard for
                                                       structural integrity and stability, e.g., verification of
                                                       center of gravity, etc., have been met. The CVA must also
                                                       consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems;
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundations, foundation pilings and templates, and
                                                       anchoring systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the design phase in accordance 
with the approved schedule required by Sec.  250.911(d). In each interim 
and final report the CVA must:
    (1) Provide a summary of the material reviewed and the CVA's 
findings;

[[Page 226]]

    (2) In the final CVA report, make a recommendation that the Regional 
Supervisor either accept, request modifications, or reject the proposed 
design unless such a recommendation has been previously made in an 
interim report;
    (3) Describe the particulars of how, by whom, and when the 
independent review was conducted; and
    (4) Provide any additional comments the CVA deems necessary.



Sec.  250.917  What are the CVA's primary duties during the fabrication phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the fabrication activities. The 
CVA must monitor the fabrication of the platform or major modification 
to ensure that it has been built according to the approved design and 
the fabrication plan. If the CVA finds that fabrication procedures are 
changed or design specifications are modified, the CVA must inform you. 
If you accept the modifications, then the CVA must so inform the 
Regional Supervisor.
    (b) Primary duties of the CVA during the fabrication phase include 
the following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For all fixed platforms and non-ship-shaped       Make periodic onsite inspections while fabrication is in
 floating facilities,                                  progress and must verify the following fabrication items,
                                                       as appropriate:
                                                      (i) Quality control by lessee and builder;
                                                      (ii) Fabrication site facilities;
                                                      (iii) Material quality and identification methods;
                                                      (iv) Fabrication procedures specified in the approved
                                                       plan, and adherence to such procedures;
                                                      (v) Welder and welding procedure qualification and
                                                       identification;
                                                      (vi) Structural tolerances specified and adherence to
                                                       those tolerances;
                                                      (vii) The nondestructive examination requirements, and
                                                       evaluation results of the specified examinations;
                                                      (viii) Destructive testing requirements and results;
                                                      (ix) Repair procedures;
                                                      (x) Installation of corrosion-protection systems and
                                                       splash-zone protection;
                                                      (xi) Erection procedures to ensure that overstressing of
                                                       structural members does not occur;
                                                      (xii) Alignment procedures;
                                                      (xiii) Dimensional check of the overall structure,
                                                       including any turrets, turret-and-hull interfaces, any
                                                       mooring line and chain and riser tensioning line
                                                       segments; and
                                                      (xiv) Status of quality-control records at various stages
                                                       of fabrication.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard
                                                       floating for structural integrity and stability, e.g.,
                                                       verification of center of gravity, etc., have been met.
                                                       The CVA must also consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems (at least for the initial fabrication
                                                       of these elements);
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundation pilings and templates, and anchoring
                                                       systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the fabrication phase in 
accordance with the approved schedule required by Sec.  250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) In the final CVA report, make a recommendation to accept or 
reject the fabrication unless such a recommendation has been previously 
made in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

[[Page 227]]



Sec.  250.918  What are the CVA's primary duties during the installation phase?

    (a) The CVA must use good engineering judgment and practice in 
conducting an independent assessment of the installation activities.
    (b) Primary duties of the CVA during the installation phase include 
the following:

----------------------------------------------------------------------------------------------------------------
                 The CVA must . . .                          Operation or equipment to be inspected . . .
----------------------------------------------------------------------------------------------------------------
(1) Verify, as appropriate,                           (i) Loadout and initial flotation operations;
                                                      (ii) Towing operations to the specified location, and
                                                       review the towing records;
                                                      (iii) Launching and uprighting operations;
                                                      (iv) Submergence operations;
                                                      (v) Pile or anchor installations;
                                                      (vi) Installation of mooring and tethering systems;
                                                      (vii) Final deck and component installations; and
                                                      (viii) Installation at the approved location according to
                                                       the approved design and the installation plan.
(2) Witness (for a fixed or floating platform),       (i) The loadout of the jacket, decks, piles, or structures
                                                       from each fabrication site;
                                                      (ii) The actual installation of the platform or major
                                                       modification and the related installation activities.
(3) Witness (for a floating platform),                (i) The loadout of the platform;
                                                      (ii) The installation of drilling, production, and
                                                       pipeline risers, and riser tensioning systems (at least
                                                       for the initial installation of these elements);
                                                      (iii) The installation of turrets and turret-and-hull
                                                       interfaces;
                                                      (iv) The installation of foundation pilings and templates,
                                                       and anchoring systems; and
                                                      (v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey,                         Survey the platform after transportation to the approved
                                                       location.
(5) Spot-check as necessary to determine compliance   (i) Equipment;
 with the applicable documents listed in Sec.         (ii) Procedures; and
 250.901(a); the alternative codes, rules and         (iii) Recordkeeping.
 standards approved under Sec.   250.901(b); the
 requirements listed in Sec.   250.903 and Sec.
 Sec.   250.906 through 250.908 of this subpart and
 the approved plans,
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the installation phase in 
accordance with the approved schedule required by Sec.  250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the approved installation plan;
    (5) In the final report, make a recommendation to accept or reject 
the installation unless such a recommendation has been previously made 
in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

          Inspection, Maintenance, and Assessment of Platforms



Sec.  250.919  What in-service inspection requirements must I meet?

    (a) You must submit a comprehensive in-service inspection report 
annually by November 1 to the Regional Supervisor that must include:
    (1) A list of fixed and floating platforms you inspected in the 
preceding 12 months;
    (2) The extent and area of inspection for both the above-water and 
underwater portions of the platform and the pertinent components of the 
mooring system for floating platforms;
    (3) The type of inspection employed (e.g., visual, magnetic 
particle, ultrasonic testing);
    (4) The overall structural condition of each platform, including a 
corrosion protection evaluation; and
    (5) A summary of the inspection results indicating what repairs, if 
any, were needed.

[[Page 228]]

    (b) If any of your structures have been exposed to a natural 
occurrence (e.g., hurricane, earthquake, or tropical storm), the 
Regional Supervisor may require you to submit an initial report of all 
structural damage, followed by subsequent updates, which include the 
following:
    (1) A list of affected structures;
    (2) A timetable for conducting the inspections described in section 
14.4.3 of API RP 2A-WSD (as incorporated by reference in Sec.  250.198); 
and
    (3) An inspection plan for each structure that describes the work 
you will perform to determine the condition of the structure.
    (c) The Regional Supervisor may also require you to submit the 
results of the inspections referred to in paragraph (b)(2) of this 
section, including a description of any detected damage that may 
adversely affect structural integrity, an assessment of the structure's 
ability to withstand any anticipated environmental conditions, and any 
remediation plans. Under Sec. Sec.  250.900(b)(3) and 250.905, you must 
obtain approval from BSEE before you make major repairs of any damage 
unless you meet the requirements of Sec.  250.900(c).



Sec.  250.920  What are the BSEE requirements for assessment of fixed platforms?

    (a) You must document all wells, equipment, and pipelines supported 
by the platform if you intend to use either the A-2 or A-3 assessment 
category. Assessment categories are defined in API RP 2A-WSD, Section 
17.3 (as incorporated by reference in Sec.  250.198). If BSEE objects to 
the assessment category you used for your assessment, you may need to 
redesign and/or modify the platform to adequately demonstrate that the 
platform is able to withstand the environmental loadings for the 
appropriate assessment category.
    (b) You must perform an analysis check when your platform will have 
additional personnel, additional topside facilities, increased 
environmental or operational loading, inadequate deck height, or 
suffered significant damage (e.g., experienced damage to primary 
structural members or conductor guide trays or global structural 
integrity is adversely affected); or the exposure category changes to a 
more restrictive level (see Sections 17.2.1 through 17.2.5 of API RP 2A-
WSD, incorporated by reference in Sec.  250.198, for a description of 
assessment initiators).
    (c) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD. You must submit 
applications for your mitigation actions (e.g., repair, modification, 
decommissioning) to the Regional Supervisor for approval before you 
conduct the work.
    (d) The BSEE may require you to conduct a platform design basis 
check when the reduced environmental loading criteria contained in API 
RP 2A-WSD Section 17.6 are not applicable.
    (e) By November 1, 2009, you must submit a complete list of all the 
platforms you operate, together with all the appropriate data to support 
the assessment category you assign to each platform and the platform 
assessment initiators (as defined in API RP 2A-WSD) to the Regional 
Supervisor. You must submit subsequent complete lists and the 
appropriate data to support the consequence-of-failure category every 5 
years thereafter, or as directed by the Regional Supervisor.
    (f) The use of Section 17, Assessment of Existing Platforms, of API 
RP 2A-WSD is limited to existing fixed structures that are serving their 
original approved purpose. You must obtain approval from the Regional 
Supervisor for any change in purpose of the platform, following the 
provisions of API RP 2A-WSD, Section 15, Re-use.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.921  How do I analyze my platform for cumulative fatigue?

    (a) If you are required to analyze cumulative fatigue on your 
platform because of the results of an inspection or platform assessment, 
you must ensure that the safety factors for critical elements listed in 
Sec.  250.908 are met or exceeded.
    (b) If the calculated life of a joint or member does not meet the 
criteria of Sec.  250.908, you must either mitigate the load, strengthen 
the joint or member, or develop an increased inspection process.

[[Page 229]]



             Subpart J_Pipelines and Pipeline Rights-of-Way



Sec.  250.1000  General requirements.

    (a) Pipelines and associated valves, flanges, and fittings shall be 
designed, installed, operated, maintained, and abandoned to provide safe 
and pollution-free transportation of fluids in a manner which does not 
unduly interfere with other uses in the Outer Continental Shelf (OCS).
    (b) An application must be accompanied by payment of the service fee 
listed in Sec.  250.125 and submitted to the Regional Supervisor and 
approval obtained before:
    (1) Installation, modification, or abandonment of a lease term 
pipeline;
    (2) Installation or modification of a right-of-way (other than lease 
term) pipeline; or
    (3) Modification or relinquishment of a pipeline right-of way.
    (c)(1) Department of the Interior (DOI) pipelines, as defined in 
Sec.  250.1001, must meet the requirements in Sec. Sec.  250.1000 
through 250.1008.
    (2) A pipeline right-of-way grant holder must identify in writing to 
the Regional Supervisor the operator of any pipeline located on its 
right-of-way, if the operator is different from the right-of-way grant 
holder.
    (3) A producing operator must identify for its own records, on all 
existing pipelines located on its lease or right-of-way, the specific 
points at which operating responsibility transfers to a transporting 
operator.
    (i) Each producing operator must, if practical, durably mark all of 
its above-water transfer points as of the date a pipeline begins 
service.
    (ii) If it is not practical to durably mark a transfer point, and 
the transfer point is located above water, then the operator must 
identify the transfer point on a schematic located on the facility.
    (iii) If a transfer point is located below water, then the operator 
must identify the transfer point on a schematic and provide the 
schematic to BSEE upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point, the BSEE Regional Supervisor and the appropriate 
Department of Transportation (DOT) pipeline official may jointly 
determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may request that the BSEE Regional Supervisor grant an exception to this 
requirement for an individual facility or area. The Regional Supervisor, 
in consultation with the appropriate DOT pipeline official and affected 
parties, may grant the request.
    (5) Pipeline segments designed, constructed, maintained, and 
operated under DOT regulations but transferring to DOI regulation as of 
October 16, 1998, may continue to operate under DOT design and 
construction requirements until significant modifications or repairs are 
made to those segments. After October 16, 1998, BSEE operational and 
maintenance requirements will apply to those segments.
    (6) Any producer operating a pipeline that crosses into State waters 
without first connecting to a transporting operator's facility on the 
OCS must comply with this subpart. Compliance must extend from the point 
where hydrocarbons are first produced, through and including the last 
valve and associated safety equipment (e.g., pressure safety sensors) on 
the last production facility on the OCS.
    (7) Any producer operating a pipeline that connects facilities on 
the OCS must comply with this subpart.
    (8) Any operator of a pipeline that has a valve on the OCS 
downstream (landward) of the last production facility may ask in writing 
that the BSEE Regional Supervisor recognize that valve as the last point 
BSEE will exercise its regulatory authority.
    (9) A pipeline segment is not subject to BSEE regulations for 
design, construction, operation, and maintenance if:
    (i) It is downstream (generally shoreward) of the last valve and 
associated safety equipment on the last production facility on the OCS; 
and
    (ii) It is subject to regulation under 49 CFR parts 192 and 195.
    (10) DOT may inspect all upstream safety equipment (including 
valves, over-pressure protection devices, cathodic protection equipment, 
and pigging devices, etc.) that serve to protect

[[Page 230]]

the integrity of DOT-regulated pipeline segments.
    (11) OCS pipeline segments not subject to DOT regulation under 49 
CFR parts 192 and 195 are subject to all BSEE regulations.
    (12) A producer may request that its pipeline operate under DOT 
regulations governing pipeline design, construction, operation, and 
maintenance.
    (i) The operator's request must be in the form of a written petition 
to the BSEE Regional Supervisor that states the justification for the 
pipeline to operate under DOT regulation.
    (ii) The Regional Supervisor will decide, on a case-by-case basis, 
whether to grant the operator's request. In considering each petition, 
the Regional Supervisor will consult with the appropriate DOT pipeline 
official.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under BSEE regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to BSEE regulations governing design and construction.
    (i) The operator's request must be in the form of a written petition 
to the appropriate DOT pipeline official and the BSEE Regional 
Supervisor.
    (ii) The BSEE Regional Supervisor and the appropriate DOT pipeline 
official will decide how to act on this petition.
    (d) A pipeline which qualifies as a right-of-way pipeline (see Sec.  
250.1001, Definitions) shall not be installed until a right-of-way has 
been requested and granted in accordance with this subpart.
    (e)(1) The Regional Supervisor may suspend any pipeline operation 
upon a determination by the Regional Supervisor that continued activity 
would threaten or result in serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, 
mineral deposits, or the marine, coastal, or human environment.
    (2) The Regional Supervisor may also suspend pipeline operations or 
a right-of-way grant if the Regional Supervisor determines that the 
lessee or right-of-way holder has failed to comply with a provision of 
the Act or any other applicable law, a provision of these or other 
applicable regulations, or a condition of a permit or right-of-way 
grant.
    (3) The Secretary of the Interior (Secretary) may cancel a pipeline 
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A 
right-of-way grant may be forfeited in accordance with 43 U.S.C. 
1334(e).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1001  Definitions.

    Terms used in this subpart shall have the meanings given below:
    DOI pipelines include:
    (1) Producer-operated pipelines extending upstream (generally 
seaward) from each point on the OCS at which operating responsibility 
transfers from a producing operator to a transporting operator;
    (2) Producer-operated pipelines extending upstream (generally 
seaward) of the last valve (including associated safety equipment) on 
the last production facility on the OCS that do not connect to a 
transporter-operated pipeline on the OCS before crossing into State 
waters;
    (3) Producer-operated pipelines connecting production facilities on 
the OCS;
    (4) Transporter-operated pipelines that DOI and DOT have agreed are 
to be regulated as DOI pipelines; and
    (5) All OCS pipelines not subject to regulation under 49 CFR parts 
192 and 195.
    DOT pipelines include:
    (1) Transporter-operated pipelines currently operated under DOT 
requirements governing design, construction, maintenance, and operation;
    (2) Producer-operated pipelines that DOI and DOT have agreed are to 
be regulated under DOT requirements governing design, construction, 
maintenance, and operation; and
    (3) Producer-operated pipelines downstream (generally shoreward) of 
the last valve (including associated safety equipment) on the last 
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that 
are regulated under 49 CFR parts 192 and 195.

[[Page 231]]

    Lease term pipelines are those pipelines owned and operated by a 
lessee or operator and are wholly contained within the boundaries of a 
single lease, unitized leases, or contiguous (not cornering) leases of 
that lessee or operator.
    Out-of-service pipelines are those pipelines that have not been used 
to transport oil, natural gas, sulfur, or produced water for more than 
30 consecutive days.
    Pipelines are the piping, risers, and appurtenances installed for 
the purpose of transporting oil, gas, sulphur, and produced water. 
(Piping confined to a production platform or structure is covered in 
Subpart H, Production Safety Systems, and is excluded from this 
subpart.)
    Production facilities means OCS facilities that receive hydrocarbon 
production either directly from wells or from other facilities that 
produce hydrocarbons from wells. They may include processing equipment 
for treating the production or separating it into its various liquid and 
gaseous components before transporting it to shore.
    Right-of-way pipelines are those pipelines which--
    (1) Are contained within the boundaries of a single lease or group 
of unitized leases but are not owned and operated by the lessee or 
operator of that lease or unit,
    (2) Are contained within the boundaries of contiguous (not 
cornering) leases which do not have a common lessee or operator,
    (3) Are contained within the boundaries of contiguous (not 
cornering) leases which have a common lessee or operator but are not 
owned and operated by that common lessee or operator, or
    (4) Cross any portion of an unleased block(s).



Sec.  250.1002  Design requirements for DOI pipelines.

    (a) The internal design pressure for steel pipe shall be determined 
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR18OC11.000

    For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 (as incorporated by reference in Sec.  250.198) 
where--

P = Internal design pressure in pounds per square inch (psi).
S = Specified minimum yield strength, in psi, stipulated in the 
          specification under which the pipe was purchased from the 
          manufacturer or determined in accordance with section 
          811.253(h) of ANSI B31.8.
D = Nominal outside diameter of pipe, in inches.
t = Nominal wall thickness, in inches.
F = Construction design factor of 0.72 for the submerged component and 
          0.60 for the riser component.
E = Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8 
          (see also section 811.253(d)).
T = Temperature derating factor obtained from Table 841.1C of ANSI 
          B31.8.

    (b)(1) Pipeline valves shall meet the minimum design requirements of 
ANSI/API Spec 6A (as incorporated by reference in Sec.  250.198), ANSI/
API Spec 6D (as incorporated by reference in Sec.  250.198), or the 
equivalent. A valve may not be used under operating conditions that 
exceed the applicable pressure-temperature ratings contained in those 
standards.
    (2) Pipeline flanges and flange accessories shall meet the minimum 
design requirements of ANSI/ASME B16.5, ANSI/API Spec 6A, or the 
equivalent (as incorporated by reference in Sec.  250.198). Each flange 
assembly must be able to withstand the maximum pressure at which the 
pipeline is to be operated and to maintain its physical and chemical 
properties at any temperature to which it is anticipated that it might 
be subjected in service.
    (3) Pipeline fittings shall have pressure-temperature ratings based 
on stresses for pipe of the same or equivalent material. The actual 
bursting strength of the fitting shall at least be equal to the computed 
bursting strength of the pipe.
    (4) If you are installing pipelines constructed of unbonded flexible 
pipe, you must design them according to the standards and procedures of 
ANSI/API Spec. 17J, as incorporated by reference in Sec.  250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other

[[Page 232]]

floating platforms according to the design standards of API RP 2RD, 
Design of Risers for Floating Production Systems (FPSs) and Tension Leg 
Platforms (TLPs) (as incorporated by reference in Sec.  250.198).
    (c) The maximum allowable operating pressure (MAOP) shall not exceed 
the least of the following:
    (1) Internal design pressure of the pipeline, valves, flanges, and 
fittings;
    (2) Eighty percent of the hydrostatic pressure test (HPT) pressure 
of the pipeline; or
    (3) If applicable, the MAOP of the receiving pipeline when the 
proposed pipeline and the receiving pipeline are connected at a subsea 
tie-in.
    (d) If the maximum source pressure (MSP) exceeds the pipeline's 
MAOP, you must install and maintain redundant safety devices meeting the 
requirements of section A9 of API RP 14C (as incorporated by reference 
in Sec.  250.198). Pressure safety valves (PSV) may be used only after a 
determination by the Regional Supervisor that the pressure will be 
relieved in a safe and pollution-free manner. The setting level at which 
the primary and redundant safety equipment actuates shall not exceed the 
pipeline's MAOP.
    (e) Pipelines shall be provided with an external protective coating 
capable of minimizing underfilm corrosion and a cathodic protection 
system designed to mitigate corrosion for at least 20 years.
    (f) Pipelines shall be designed and maintained to mitigate any 
reasonably anticipated detrimental effects of water currents, storm or 
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing 
temperatures, and other environmental factors.

[76 FR 64462, Oct. 18, 2011, as amended at 83 FR 49263, Sept. 28, 2018]



Sec.  250.1003  Installation, testing, and repair requirements for DOI pipelines.

    (a)(1) Pipelines greater than 8\5/8\ inches in diameter and 
installed in water depths of less than 200 feet shall be buried to a 
depth of at least 3 feet unless they are located in pipeline congested 
areas or seismically active areas as determined by the Regional 
Supervisor. Nevertheless, the Regional Supervisor may require burial of 
any pipeline if the Regional Supervisor determines that such burial will 
reduce the likelihood of environmental degradation or that the pipeline 
may constitute a hazard to trawling operations or other uses. A trawl 
test or diver survey may be required to determine whether or not 
pipeline burial is necessary or to determine whether a pipeline has been 
properly buried.
    (2) Pipeline valves, taps, tie-ins, capped lines, and repaired 
sections that could be obstructive shall be provided with at least 3 
feet of cover unless the Regional Supervisor determines that such items 
present no hazard to trawling or other operations. A protective device 
may be used to cover an obstruction in lieu of burial if it is approved 
by the Regional Supervisor prior to installation.
    (3) Pipelines shall be installed with a minimum separation of 18 
inches at pipeline crossings and from obstructions.
    (4) Pipeline risers installed after April 1, 1988, shall be 
protected from physical damage that could result from contact with 
floating vessels. Riser protection on pipelines installed on or before 
April 1, 1988, may be required when the Regional Supervisor determines 
that significant damage potential exists.
    (b)(1) Pipelines shall be pressure tested with water at a stabilized 
pressure of at least 1.25 times the MAOP for at least 8 hours when 
installed, relocated, uprated, or reactivated after being out-of-service 
for more than 1 year.
    (2) Prior to returning a pipeline to service after a repair, the 
pipeline shall be pressure tested with water or processed natural gas at 
a minimum stabilized pressure of at least 1.25 times the MAOP for at 
least 2 hours.
    (3) Pipelines shall not be pressure tested at a pressure which 
produces a stress in the pipeline in excess of 95 percent of the 
specified minimum-yield strength of the pipeline. A temperature recorder 
measuring test fluid temperature synchronized with a pressure recorder 
along with deadweight test readings shall be employed for all pressure 
testing. When a pipeline is pressure tested, no observable leakage shall

[[Page 233]]

be allowed. Pressure gauges and recorders shall be of sufficient 
accuracy to verify that leakage is not occurring.
    (4) The Regional Supervisor may require pressure testing of 
pipelines to verify the integrity of the system when the Regional 
Supervisor determines that there is a reasonable likelihood that the 
line has been damaged or weakened by external or internal conditions.
    (c) When a pipeline is repaired utilizing a clamp, the clamp shall 
be a full encirclement clamp able to withstand the anticipated pipeline 
pressure.



Sec.  250.1004  Safety equipment requirements for DOI pipelines.

    (a) The lessee shall ensure the proper installation, operation, and 
maintenance of safety devices required by this section on all incoming, 
departing, and crossing pipelines on platforms.
    (b)(1)(i) Incoming pipelines to a platform shall be equipped with a 
flow safety valve (FSV).
    (ii) For sulphur operations, incoming pipelines delivering gas to 
the power plant platform may be equipped with high- and low-pressure 
sensors (PSHL), which activate audible and visual alarms in lieu of 
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be 
set at 15 percent or 5 psi, whichever is greater, above and below the 
normal operating pressure range.
    (2) Incoming pipelines boarding a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform. The SDV shall be connected to the automatic- and 
remote-emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
facilities shall be protected by high- and low-pressure sensors (PSHL) 
to directly or indirectly shut in all production facilities. The PSHL 
shall be set not to exceed 15 percent above and below the normal 
operating pressure range. However, high pilots shall not be set above 
the pipeline's MAOP.
    (4) Crossing pipelines on production or manned nonproduction 
platforms which do not receive production from the platform shall be 
equipped with an SDV immediately upon boarding the platform. The SDV 
shall be operated by a PSHL on the departing pipelines and connected to 
the platform automatic- and remote-emergency shut-in systems.
    (5) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (6) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and an FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (7) Gas-lift or water-injection pipelines on unmanned platforms need 
only be equipped with an FSV installed immediately upstream of each 
casing annulus or the first inlet valve on the christmas tree.
    (8) Bidirectional pipelines shall be equipped with a PSHL and an SDV 
immediately upon boarding each platform.
    (9) Pipeline pumps must comply with section A7 of API RP 14C (as 
incorporated by reference in Sec.  250.198). The setting levels for the 
PSHL devices are specified in paragraph (b)(3) of this section.
    (c) If the required safety equipment is rendered ineffective or 
removed from service on pipelines which are continued in operation, an 
equivalent degree of safety shall be provided. The safety equipment 
shall be identified by the placement of a sign on the equipment stating 
that the equipment is rendered ineffective or removed from service.



Sec.  250.1005  Inspection requirements for DOI pipelines.

    (a) Pipeline routes shall be inspected at time intervals and methods 
prescribed by the Regional Supervisor for indication of pipeline 
leakage. The results of these inspections shall be retained for at least 
2 years and be made available to the Regional Supervisor upon request.

[[Page 234]]

    (b) When pipelines are protected by rectifiers or anodes for which 
the initial life expectancy of the cathodic protection system either 
cannot be calculated or calculations indicate a life expectancy of less 
than 20 years, such pipelines shall be inspected annually by taking 
measurements of pipe-to-electrolyte potential.



Sec.  250.1006  How must I decommission and take out of service a DOI pipeline?

    (a) The requirements for decommissioning pipelines are listed in 
Sec.  250.1750 through Sec.  250.1754.
    (b) The table in this section lists the requirements if you take a 
DOI pipeline out of service:

----------------------------------------------------------------------------------------------------------------
    If you have the pipeline out of service for:                            Then you must:
----------------------------------------------------------------------------------------------------------------
(1) 1 year or less,                                   Isolate the pipeline with a blind flange or a closed block
                                                       valve at each end of the pipeline.
(2) More than 1 year but less than 5 years,           Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years,                                  Decommission the pipeline according to Sec.  Sec.
                                                       250.1750-250.1754.
----------------------------------------------------------------------------------------------------------------



Sec.  250.1007  What to include in applications.

    (a) Applications to install a lease term pipeline or for a pipeline 
right-of-way grant must be submitted in quadruplicate to the Regional 
Supervisor. Right-of-way grant applications must include an 
identification of the operator of the pipeline. Each application must 
include the following:
    (1) Plat(s) drawn to a scale specified by the Regional Supervisor 
showing major features and other pertinent data including area, lease, 
and block designations; water depths; route; length in Federal waters; 
width of right-of-way, if applicable; connecting facilities; size; 
product(s) to be transported with anticipated gravity or density; burial 
depth; direction of flow; X-Y coordinates of key points; and the 
location of other pipelines that will be connected to or crossed by the 
proposed pipeline(s). The initial and terminal points of the pipeline 
and any continuation into State jurisdiction shall be accurately located 
even if the pipeline is to have an onshore terminal point. A plat(s) 
submitted for a pipeline right-of-way shall bear a signed certificate 
upon its face by the engineer who made the map that certifies that the 
right-of-way is accurately represented upon the map and that the design 
characteristics of the associated pipeline are in accordance with 
applicable regulations.
    (2) A schematic drawing showing the size, weight, grade, wall 
thickness, and type of line pipe and risers; pressure-regulating devices 
(including back-pressure regulators); sensing devices with associated 
pressure-control lines; PSV's and settings; SDV's, FSV's, and block 
valves; and manifolds. This schematic drawing shall also show input 
source(s), e.g., wells, pumps, compressors, and vessels; maximum input 
pressure(s); the rated working pressure, as specified by ANSI or API, of 
all valves, flanges, and fittings; the initial receiving equipment and 
its rated working pressure; and associated safety equipment and pig 
launchers and receivers. The schematic must indicate the point on the 
OCS at which operating responsibility transfers between a producing 
operator and a transporting operator.
    (3) General information as follows:
    (i) Description of cathodic protection system. If pipeline anodes 
are to be used, specify the type, size, weight, number, spacing, and 
anticipated life;
    (ii) Description of external pipeline coating system;
    (iii) Description of internal protective measures;
    (iv) Specific gravity of the empty pipe;
    (v) MSP;
    (vi) MAOP and calculations used in its determination;
    (vii) Hydrostatic test pressure, medium, and period of time that the 
line will be tested;
    (viii) MAOP of the receiving pipeline or facility,
    (ix) Proposed date for commencing installation and estimated time 
for construction; and
    (x) Type of protection to be afforded crossing pipelines, subsea 
valves, taps, and manifold assemblies, if applicable.

[[Page 235]]

    (4) A description of any additional design precautions you took to 
enable the pipeline to withstand the effects of water currents, storm or 
ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and 
other environmental factors.
    (i) If you propose to use unbonded flexible pipe, your application 
must include:
    (A) The manufacturer's design specification sheet;
    (B) The design pressure (psi);
    (C) An identification of the design standards you used; and
    (D) A review by a third-party independent verification agent (IVA) 
according to ANSI/API Spec. 17J (as incorporated by reference in Sec.  
250.198), if applicable.
    (ii) If you propose to use one or more pipeline risers for a tension 
leg platform or other floating platform, your application must include:
    (A) The design fatigue life of the riser, with calculations, and the 
fatigue point at which you would replace the riser;
    (B) The results of your vortex-induced vibration (VIV) analysis;
    (C) An identification of the design standards you used; and
    (D) A description of any necessary mitigation measures such as the 
use of helical strakes or anchoring devices.
    (5) The application shall include a shallow hazards survey report 
and, if required by the Regional Director, an archaeological resource 
report that covers the entire length of the pipeline. A shallow hazards 
analysis may be included in a lease term pipeline application in lieu of 
the shallow hazards survey report with the approval of the Regional 
Director. The Regional Director may require the submission of the data 
upon which the report or analysis is based.
    (b) Applications to modify an approved lease term pipeline or right-
of-way grant shall be submitted in quadruplicate to the Regional 
Supervisor. These applications need only address those items in the 
original application affected by the proposed modification.

[76 FR 64462, Oct. 18, 2011, as amended at 83 FR 49263, Sept. 28, 2018]



Sec.  250.1008  Reports.

    (a) The lessee, or right-of-way holder, shall notify the Regional 
Supervisor at least 48 hours prior to commencing the installation or 
relocation of a pipeline or conducting a pressure test on a pipeline.
    (b) The lessee or right-of-way holder shall submit a report to the 
Regional Supervisor within 90 days after completion of any pipeline 
construction. The report, submitted in triplicate, shall include an 
``as-built'' location plat drawn to a scale specified by the Regional 
Supervisor showing the location, length in Federal waters, and X-Y 
coordinates of key points; the completion date; the proposed date of 
first operation; and the HPT data. Pipeline right-of-way ``as-built'' 
location plats shall be certified by a registered engineer or land 
surveyor and show the boundaries of the right-of-way as granted. If 
there is a substantial deviation of the pipeline route as granted in the 
right-of-way, the report shall include a discussion of the reasons for 
such deviation.
    (c) The lessee or right-of-way holder shall report to the Regional 
Supervisor any pipeline taken out of service. If the period of time in 
which the pipeline is out of service is greater than 60 days, written 
confirmation is also required.
    (d) The lessee or right-of-way holder shall report to the Regional 
Supervisor when any required pipeline safety equipment is taken out of 
service for more than 12 hours. The Regional Supervisor shall be 
notified when the equipment is returned to service.
    (e) The lessee or right-of-way holder must notify the Regional 
Supervisor before the repair of any pipeline or as soon as practicable. 
Your notification must be accompanied by payment of the service fee 
listed in Sec.  250.125. You must submit a detailed report of the repair 
of a pipeline or pipeline component to the Regional Supervisor within 30 
days after the completion of the repairs. In the report you must include 
the following:
    (1) Description of repairs;
    (2) Results of pressure test; and
    (3) Date returned to service.

[[Page 236]]

    (f) The Regional Supervisor may require that DOI pipeline failures 
be analyzed and that samples of a failed section be examined in a 
laboratory to assist in determining the cause of the failure. A 
comprehensive written report of the information obtained shall be 
submitted by the lessee to the Regional Supervisor as soon as available.
    (g) If the effects of scouring, soft bottoms, or other environmental 
factors are observed to be detrimentally affecting a pipeline, a plan of 
corrective action shall be submitted to the Regional Supervisor for 
approval within 30 days of the observation. A report of the remedial 
action taken shall be submitted to the Regional Supervisor by the lessee 
or right-of-way holder within 30 days after completion.
    (h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in 
accordance with Sec.  250.1005(b) of this part shall be submitted to the 
Regional Supervisor by the lessee before March of each year.



Sec.  250.1009  Requirements to obtain pipeline right-of-way grants.

    (a) In addition to applicable requirements of Sec. Sec.  250.1000 
through 250.1008 and other regulations of this part, regulations of the 
Department of Transportation, Department of the Army, and the Federal 
Energy Regulatory Commission (FERC), when a pipeline qualifies as a 
right-of-way pipeline, the pipeline shall not be installed until a 
right-of-way has been requested and granted in accordance with this 
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) 
and may be acquired and held only by citizens and nationals of the 
United States; aliens lawfully admitted for permanent residence in the 
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or 
municipal corporations organized under the laws of the United States or 
territory thereof, the District of Columbia, or of any State; or 
associations of such citizens, nationals, resident aliens, or private, 
public, or municipal corporations, States, or political subdivisions of 
States.
    (b) A right-of-way shall include the site on which the pipeline and 
associated structures are to be situated, shall not exceed 200 feet in 
width unless safety and environmental factors during construction and 
operation of the associated right-of-way pipeline require a greater 
width, and shall be limited to the area reasonably necessary for pumping 
stations or other accessory structures.



Sec.  250.1010  General requirements for pipeline right-of-way holders.

    An applicant, by accepting a right-of-way grant, agrees to comply 
with the following requirements:
    (a) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (b) The granting of the right-of-way shall be subject to the express 
condition that the rights granted shall not prevent or interfere in any 
way with the management, administration, or the granting of other rights 
by the United States, either prior or subsequent to the granting of the 
right-of-way. Moreover, the holder agrees to allow the occupancy and use 
by the United States, its lessees, or other right-of-way holders, of any 
part of the right-of-way grant not actually occupied or necessarily 
incident to its use for any necessary operations involved in the 
management, administration, or the enjoyment of such other granted 
rights.
    (c) If the right-of-way holder discovers any archaeological resource 
while conducting operations within the right-of-way, the right-of-way 
holder shall immediately halt operations within the area of the 
discovery and report the discovery to the Regional Director. If 
investigations determine that the resource is significant, the Regional 
Director will inform the right-of-way holder how to protect it.
    (d) The Regional Supervisor shall be kept informed at all times of 
the right-of-way holder's address and, if a corporation, the address of 
its principal place of business and the name and address of the officer 
or agent authorized to be served with process.
    (e) The right-of-way holder shall pay the United States or its 
lessees or right-of-way holders, as the case may be, the full value of 
all damages to the property of the United States or its

[[Page 237]]

said lessees or right-of-way holders and shall indemnify the United 
States against any and all liability for damages to life, person, or 
property arising from the occupation and use of the area covered by the 
right-of-way grant.
    (f)(1) The holder of a right-of-way oil or gas pipeline shall 
transport or purchase oil or natural gas produced from submerged lands 
in the vicinity of the pipeline without discrimination and in such 
proportionate amounts as the FERC may, after a full hearing with due 
notice thereof to the interested parties, determine to be reasonable, 
taking into account, among other things, conservation and the prevention 
of waste.
    (2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 
1334(f)(2), the holder shall:
    (i) Provide open and nondiscriminatory access to a right-of-way 
pipeline to both owner and nonowner shippers, and
    (ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under 
which FERC may order an expansion of the throughput capacity of a right-
of-way pipeline which is approved after September 18, 1978, and which is 
not located in the Gulf of Mexico or the Santa Barbara Channel.
    (g) The area covered by a right-of-way and all improvements thereon 
shall be kept open at all reasonable times for inspection by the Bureau 
of Safety and Environmental Enforcement (BSEE). The right-of-way holder 
shall make available all records relative to the design, construction, 
operation, maintenance and repair, and investigations on or with regard 
to such area.
    (h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms, 
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within 
1 year of the effective date of the relinquishment, forfeiture, or 
cancellation unless this requirement is waived in writing by the 
Regional Supervisor. All such improvements not removed within the time 
provided herein shall become the property of the United States but that 
shall not relieve the holder of liability for the cost of their removal 
or for restoration of the site. Furthermore, the holder is responsible 
for accidents or damages which might occur as a result of failure to 
timely remove improvements and equipment and restore a site. An 
application for relinquishment of a right-of-way grant shall be filed in 
accordance with Sec.  250.1019 of this part.



Sec.  250.1011  [Reserved]



Sec.  250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay ONRR, under the regulations at 30 CFR part 1218, an 
annual rental of $15 for each statute mile, or part of a statute mile, 
of the OCS that your pipeline right-of-way crosses.
    (b) This paragraph applies to you if you obtain a pipeline right-of-
way that includes a site for an accessory to the pipeline, including but 
not limited to a platform. This paragraph also applies if you apply to 
modify a right-of-way to change the site footprint. In either case, you 
must pay the amounts shown in the following table.

----------------------------------------------------------------------------------------------------------------
                      If . . .                                                Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of less than 200 meters;                              1218, a rental of $5 per acre per year with a minimum of
                                                       $450 per year. The area subject to annual rental includes
                                                       the areal extent of anchor chains, pipeline risers, and
                                                       other facilities and devices associated with the
                                                       accessory.
(2) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of 200 meters or greater;                             1218, a rental of $7.50 per acre per year with a minimum
                                                       of $675 per year. The area subject to annual rental
                                                       includes the areal extent of anchor chains, pipeline
                                                       risers, and other facilities and devices associated with
                                                       the accessory.
----------------------------------------------------------------------------------------------------------------

    (c) If you hold a pipeline right-of-way that includes a site for an 
accessory to your pipeline and you are not covered by paragraph (b) of 
this section, then you must pay ONRR, under the regulations at 30 CFR 
part 1218, an annual rental of $75 for use of the affected area.

[[Page 238]]

    (d) You may make the rental payments required by paragraphs (a), 
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year 
period, or for multiples of 5 years. You must make the first payment at 
the time you submit the pipeline right-of-way application. You must make 
all subsequent payments before the respective time periods begin.
    (e) Late payments. An interest charge will be assessed on unpaid and 
underpaid amounts from the date the amounts are due, in accordance with 
the provisions found in 30 CFR 1218.54. If you fail to make a payment 
that is late after written notice from ONRR, BSEE may initiate 
cancellation of the right-of-use grant and easement under Sec.  
250.1013.



Sec.  250.1013  Grounds for forfeiture of pipeline right-of-way grants.

    Failure to comply with the Act, regulations, or any conditions of 
the right-of-way grant prescribed by the Regional Supervisor shall be 
grounds for forfeiture of the grant in an appropriate judicial 
proceeding instituted by the United States in any U.S. District Court 
having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.



Sec.  250.1014  When pipeline right-of-way grants expire.

    Any right-of-way granted under the provisions of this subpart 
remains in effect as long as the associated pipeline is properly 
maintained and used for the purpose for which the grant was made, unless 
otherwise expressly stated in the grant. Temporary cessation or 
suspension of pipeline operations shall not cause the grant to expire. 
However, if the purpose of the grant ceases to exist or use of the 
associated pipeline is permanently discontinued for any reason, the 
grant shall be deemed to have expired.



Sec.  250.1015  Applications for pipeline right-of-way grants.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline ROW grant to the Regional Supervisor. The 
application must address those items required by Sec.  250.1007(a) or 
(b) of this subpart, as applicable. It must also state the primary 
purpose for which you will use the ROW grant. If the ROW has been used 
before the application is made, the application must state the date such 
use began, by whom, and the date the applicant obtained control of the 
improvement. When you file your application, you must pay the rental 
required under Sec.  250.1012 of this subpart, as well as the service 
fees listed in Sec.  250.125 of this part for a pipeline ROW grant to 
install a new pipeline, or to convert an existing lease term pipeline 
into a ROW pipeline. An application to modify an approved ROW grant must 
be accompanied by the additional rental required under Sec.  250.1012 if 
applicable. You must file a separate application for each ROW.
    (b)(1) An individual applicant shall submit a statement of 
citizenship or nationality with the application. An applicant who is an 
alien lawfully admitted for permanent residence in the United States 
shall also submit evidence of such status with the application.
    (2) If the applicant is an association (including a partnership), 
the application shall also be accompanied by a certified copy of the 
articles of association or appropriate reference to a copy of such 
articles already filed with BSEE and a statement as to any subsequent 
amendments.
    (3) If the applicant is a corporation, the application shall also 
include the following:
    (i) A statement certified by the Secretary or Assistant Secretary of 
the corporation with the corporate seal showing the State in which it is 
incorporated and the name of the person(s) authorized to act on behalf 
of the corporation, or
    (ii) In lieu of such a statement, an appropriate reference to 
statements or records previously submitted to BSEE (including material 
submitted in compliance with prior regulations).
    (c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the proposed 
right-of-way. The application shall also include

[[Page 239]]

a statement that a copy of the application has been sent by registered 
or certified mail to each such lessee or right-of-way holder.
    (d) The applicant shall include in the application an original and 
three copies of a completed Nondiscrimination in Employment form (YN 
3341-1 dated July 1982). These forms are available at each BSEE regional 
office.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1016  Granting pipeline rights-of-way.

    (a) In considering an application for a right-of-way, the Regional 
Supervisor shall consider the potential effect of the associated 
pipeline on the human, marine, and coastal environments, life (including 
aquatic life), property, and mineral resources in the entire area during 
construction and operational phases. The Regional Supervisor shall 
prepare an environmental analysis in accordance with applicable policies 
and guidelines. To aid in the evaluation and determinations, the 
Regional Supervisor may request and consider views and recommendations 
of appropriate Federal Agencies, hold public meetings after appropriate 
notice, and consult, as appropriate, with State agencies, organizations, 
industries, and individuals. Before granting a pipeline right-of-way, 
the Regional Supervisor shall give consideration to any recommendation 
by the intergovernmental planning program, or similar process, for the 
assessment and management of OCS oil and gas transportation.
    (b) Should the proposed route of a right-of-way adjoin and 
subsequently cross any State submerged lands, the applicant shall submit 
evidence to the Regional Supervisor that the State(s) so affected has 
reviewed the application. The applicant shall also submit any comment 
received as a result of that review. In the event of a State 
recommendation to relocate the proposed route, the Regional Supervisor 
may consult with the appropriate State officials.
    (c)(1) The applicant shall submit photocopies of return receipts to 
the Regional Supervisor that indicate the date that each lessee or 
right-of-way holder referenced in Sec.  250.1015(c) of this part has 
received a copy of the application. Letters of no objection may be 
submitted in lieu of the return receipts.
    (2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each 
such lessee or right-of-way holder has been afforded at least 30 days 
from the date determined in paragraph (c)(1) of this section in which to 
submit comments.
    (d) If a proposed right-of-way crosses any lands not subject to 
disposition by mineral leasing or restricted from oil and gas 
activities, it shall be rejected by the Regional Supervisor unless the 
Federal Agency with jurisdiction over such excluded or restricted area 
gives its consent to the granting of the right-of-way. In such case, the 
applicant, upon a request filed within 30 days after receipt of the 
notification of such rejection, shall be allowed an opportunity to 
eliminate the conflict.
    (e)(1) If the application and other required information are found 
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as conditions 
to the right-of-way grant, stipulations necessary to protect human, 
marine, and coastal environments, life (including aquatic life), 
property, and mineral resources located on or adjacent to the right-of-
way.
    (2) If the Regional Supervisor determines that a change in the 
application should be made, the Regional Supervisor shall notify the 
applicant that an amended application shall be filed subject to 
stipulated changes. The Regional Supervisor shall determine whether the 
applicant shall deliver copies of the amended application to other 
parties for comment.
    (3) A decision to reject an application shall be in writing and 
shall state the reasons for the rejection.



Sec.  250.1017  Requirements for construction under pipeline 
right-of-way grants.

    (a) Failure to construct the associated right-of-way pipeline within 
5 years of the date of the granting of a

[[Page 240]]

right-of-way shall cause the grant to expire.
    (b)(1) A right-of-way holder shall ensure that the right-of-way 
pipeline is constructed in a manner that minimizes deviations from the 
right-of-way as granted.
    (2) If, after constructing the right-of-way pipeline, it is 
determined that a deviation from the proposed right-of-way as granted 
has occurred, the right-of-way holder shall--
    (i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the 
date of the acceptance by the Regional Supervisor of the completion of 
pipeline construction report, provide the Regional Supervisor with 
evidence of such notification; and
    (ii) Relinquish any unused portion of the right-of-way.
    (3) Substantial deviation of a right-of-way pipeline as constructed 
from the proposed right-of-way as granted may be grounds for forfeiture 
of the right-of-way.
    (c) If the Regional Supervisor determines that a significant change 
in conditions has occurred subsequent to the granting of a right-of-way 
but prior to the commencement of construction of the associated 
pipeline, the Regional Supervisor may suspend or temporarily prohibit 
the commencement of construction until the right-of-way grant is 
modified to the extent necessary to address the changed conditions.



Sec.  250.1018  Assignment of pipeline right-of-way grants.

    (a) Assignment may be made of a right-of-way grant, in whole or of 
any lineal segment thereof, subject to the approval of the Regional 
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with 
the Regional Supervisor.
    (b) Any application for approval for an assignment, in whole or in 
part, of any right, title, or interest in a right-of-way grant must be 
accompanied by the same showing of qualifications of the assignees as is 
required of an applicant for a ROW in Sec.  250.1015 of this subpart and 
must be supported by a statement that the assignee agrees to comply with 
and to be bound by the terms and conditions of the ROW grant. The 
assignee must satisfy the bonding requirements in 30 CFR 550.1011. No 
transfer will be recognized unless and until it is first approved, in 
writing, by the Regional Supervisor. The assignee must pay the service 
fee listed in Sec.  250.125 of this part for a pipeline ROW assignment 
request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1019  Relinquishment of pipeline right-of-way grants.

    A right-of-way grant or a portion thereof may be surrendered by the 
holder by filing a written relinquishment in triplicate with the 
Regional Supervisor. It must contain those items addressed in Sec. Sec.  
250.1751 and 250.1752 of this part. A relinquishment shall take effect 
on the date it is filed subject to the satisfaction of all outstanding 
debts, fees, or fines and the requirements in Sec.  250.1010(h) of this 
part.



              Subpart K_Oil and Gas Production Requirements

                                 General



Sec.  250.1150  What are the general reservoir production requirements?

    You must produce wells and reservoirs at rates that provide for 
economic development while maximizing ultimate recovery and without 
adversely affecting correlative rights.

                         Well Tests and Surveys



Sec.  250.1151  How often must I conduct well production tests?

    (a) You must conduct well production tests as shown in the following 
table:

------------------------------------------------------------------------
                                             And you must submit to the
             You must conduct:                  Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all new,  Form BSEE-0126, Well
 recompleted, or reworked well completions   Potential Test Report,
 within 30 days of the date of first         along with the supporting
 continuous production,                      data as listed in the table
                                             in Sec.   250.1167, within
                                             15 days after the end of
                                             the test period.

[[Page 241]]

 
(2) At least one well test during a         Results on Form BSEE-0128,
 calendar half-year for each producing       Semiannual Well Test
 completion,                                 Report, of the most recent
                                             well test obtained. This
                                             must be submitted within 45
                                             days after the end of the
                                             calendar half-year.
------------------------------------------------------------------------

    (b) You may request an extension from the Regional Supervisor if you 
cannot submit the results of a semiannual well test within the specified 
time.
    (c) You must submit to the Regional Supervisor an original and two 
copies of the appropriate form required by paragraph (a) of this 
section; one of the copies of the form must be a public information copy 
in accordance with Sec. Sec.  250.186 and 250.197, and marked ``Public 
Information.'' You must submit two copies of the supporting information 
as listed in the table in Sec.  250.1167 with form BSEE-0126.



Sec.  250.1152  How do I conduct well tests?

    (a) When you conduct well tests you must:
    (1) Recover fluid from the well completion equivalent to the amount 
of fluid introduced into the formation during completion, recompletion, 
reworking, or treatment operations before you start a well test;
    (2) Produce the well completion under stabilized rate conditions for 
at least 6 consecutive hours before beginning the test period;
    (3) Conduct the test for at least 4 consecutive hours;
    (4) Adjust measured gas volumes to the standard conditions of 14.73 
pounds per square inch absolute (psia) and 60 [deg]F for all tests; and
    (5) Use measured specific gravity values to calculate gas volumes.
    (b) You may request approval from the Regional Supervisor to conduct 
a well test using alternative procedures if you can demonstrate test 
reliability under those procedures.
    (c) The Regional Supervisor may also require you to conduct the 
following tests and complete them within a specified time period:
    (1) A retest or a prolonged test of a well completion if it is 
determined to be necessary for the proper establishment of a Maximum 
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
    (2) A multipoint back-pressure test to determine the theoretical 
open-flow potential of a gas well.
    (d) A BSEE representative may witness any well test. Upon request, 
you must provide advance notice to the Regional Supervisor of the times 
and dates of well tests.



Sec. Sec.  250.1153-250.1155  [Reserved]

                      Approvals Prior to Production



Sec.  250.1156  What steps must I take to receive approval to produce
 within 500 feet of a unit or lease line?

    (a) You must obtain approval from the Regional Supervisor before you 
start producing from a reservoir within a well that has any portion of 
the completed interval less than 500 feet from a unit or lease line. 
Submit to BSEE the service fee listed in Sec.  250.125, according to the 
instructions in Sec.  250.126, and the supporting information, as listed 
in the table in Sec.  250.1167, with your request. The Regional 
Supervisor will determine whether approval of your request will maximize 
ultimate recovery, avoid the waste of natural resources, or protect 
correlative rights. You do not need to obtain approval if the adjacent 
leases or units have the same unit, lease (record title and operating 
rights), and royalty interests as the lease or unit you plan to produce. 
You do not need to obtain approval if the adjacent block is unleased.
    (b) You must notify the operator(s) of adjacent property(ies) that 
are within 500 feet of the completion, if the adjacent acreage is a 
leased block in the Federal OCS. You must provide the Regional 
Supervisor proof of the date of the notification. The operators of the 
adjacent properties have 30 days after receiving the notification to 
provide the Regional Supervisor letters of acceptance or objection. If 
an adjacent operator does not respond within 30

[[Page 242]]

days, the Regional Supervisor will presume there are no objections and 
proceed with a decision. The notification must include:
    (1) The well name;
    (2) The rectangular coordinates (x, y) of the location of the top 
and bottom of the completion or target completion referenced to the 
North American Datum 1983, and the subsea depths of the top and bottom 
of the completion or target completion;
    (3) The distance from the completion or target completion to the 
unit or lease line at its nearest point; and
    (4) A statement indicating whether or not it will be a high-capacity 
completion having a perforated or open hole interval greater than 150 
feet measured depth.



Sec.  250.1157  How do I receive approval to produce gas-cap gas from
 an oil reservoir with an associated gas cap?

    (a) You must request and receive approval from the Regional 
Supervisor:
    (1) Before producing gas-cap gas from each completion in an oil 
reservoir that is known to have an associated gas cap.
    (2) To continue production from a well if the oil reservoir is not 
initially known to have an associated gas cap, but the oil well begins 
to show characteristics of a gas well.
    (b) For either request, you must submit the service fee listed in 
Sec.  250.125, according to the instructions in Sec.  250.126, and the 
supporting information, as listed in the table in Sec.  250.1167, with 
your request.
    (c) The Regional Supervisor will determine whether your request 
maximizes ultimate recovery.



Sec.  250.1158  How do I receive approval to downhole commingle
 hydrocarbons?

    (a) Before you perforate a well, you must request and receive 
approval from the Regional Supervisor to commingle hydrocarbons produced 
from multiple reservoirs within a common wellbore. The Regional 
Supervisor will determine whether your request maximizes ultimate 
recovery. You must include the service fee listed in Sec.  250.125, 
according to the instructions in Sec.  250.126, and the supporting 
information, as listed in the table in Sec.  250.1167, with your 
request.
    (b) If one or more of the reservoirs proposed for commingling is a 
competitive reservoir, you must notify the operators of all leases that 
contain the reservoir that you intend to downhole commingle the 
reservoirs. Your request for approval of downhole commingling must 
include proof of the date of this notification. The notified operators 
have 30 days after notification to provide the Regional Supervisor with 
letters of acceptance or objection. If the notified operators do not 
respond within the specified period, the Regional Supervisor will assume 
the operators do not object and proceed with a decision.

                            Production Rates



Sec.  250.1159  May the Regional Supervisor limit my well or reservoir
 production rates?

    (a) The Regional Supervisor may set a Maximum Production Rate (MPR) 
for a producing well completion, or set a Maximum Efficient Rate (MER) 
for a reservoir, or both, if the Regional Supervisor determines that an 
excessive production rate could harm ultimate recovery. An MPR or MER 
will be based on well tests and any limitations imposed by well and 
surface equipment, sand production, reservoir sensitivity, gas-oil and 
water-oil ratios, location of perforated intervals, and prudent 
operating practices.
    (b) If the Regional Supervisor sets an MPR for a producing well 
completion and/or an MER for a reservoir, you may not exceed those rates 
except due to normal variations and fluctuations in production rates as 
set by the Regional Supervisor.

               Flaring, Venting, and Burning Hydrocarbons



Sec.  250.1160  When may I flare or vent gas?

    (a) You must request and receive approval from the Regional 
Supervisor to flare or vent natural gas at your facility, except in the 
following situations:

[[Page 243]]



------------------------------------------------------------------------
               Condition                     Additional requirements
------------------------------------------------------------------------
(1) When the gas is lease use gas        The volume of gas flared or
 (produced natural gas which is used on   vented may not exceed the
 or for the benefit of lease operations   amount necessary for its
 such as gas used to operate production   intended purpose. Burning
 facilities) or is used as an additive    waste products may require
 necessary to burn waste products, such   approval under other
 as H2S.                                  regulations.
(2) During the restart of a facility     Flaring or venting may not
 that was shut in because of weather      exceed 48 cumulative hours
 conditions, such as a hurricane.         without Regional Supervisor
                                          approval.
(3) During the blow down of              (i) You must report the
 transportation pipelines downstream of   location, time, flare/vent
 the royalty meter.                       volume, and reason for flaring/
                                          venting to the Regional
                                          Supervisor in writing within
                                          72 hours after the incident is
                                          over.
                                         (ii) Additional approval may be
                                          required under subparts H and
                                          J of this part.
(4) During the unloading or cleaning of  You may not exceed 48
 a well, drill-stem testing, production   cumulative hours of flaring or
 testing, other well-evaluation           venting per unloading or
 testing, or the necessary blow down to   cleaning or testing operation
 perform these procedures.                on a single completion without
                                          Regional Supervisor approval.
(5) When properly working equipment      You may not flare or vent more
 yields flash gas (natural gas released   than an average of 50 MCF per
 from liquid hydrocarbons as a result     day during any calendar month
 of a decrease in pressure, an increase   without Regional Supervisor
 in temperature, or both) from storage    approval.
 vessels or other low-pressure
 production vessels, and you cannot
 economically recover this flash gas.
(6) When the equipment works properly    (i) For oil-well gas and gas-
 but there is a temporary upset           well flash gas (natural gas
 condition, such as a hydrate or          released from condensate as a
 paraffin plug.                           result of a decrease in
                                          pressure, an increase in
                                          temperature, or both), you may
                                          not exceed 48 continuous hours
                                          of flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas
                                          (natural gas from a gas well
                                          completion that is at or near
                                          its wellhead pressure; this
                                          does not include flash gas),
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
(7) When equipment fails to work         (i) For oil-well gas and gas-
 properly, during equipment maintenance   well flash gas, you may not
 and repair, or when you must relieve     exceed 48 continuous hours of
 system pressures.                        flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas,
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
                                         (iv) The continuous and
                                          cumulative hours allowed under
                                          this paragraph may be counted
                                          separately from the hours
                                          under paragraph (a)(6) of this
                                          section.
------------------------------------------------------------------------

    (b) Regardless of the requirements in paragraph (a) of this section, 
you must not flare or vent gas over the volume approved in your 
Development Operations Coordination Document (DOCD) or your Development 
and Production Plan (DPP) submitted to BOEM.
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations when you cannot contact the BSEE office, 
such as during non-office hours.
    (d) The Regional Supervisor may specify a volume limit, or a shorter 
time limit than specified elsewhere in this part, in order to prevent 
air quality degradation or loss of reserves.
    (e) If you flare or vent gas without the required approval, or if 
the Regional Supervisor determines that you were negligent or could have 
avoided flaring or venting the gas, the hydrocarbons will be considered 
avoidably lost or wasted. You must pay royalties on the loss or waste, 
according to 30 CFR part 1202. You must value any gas or liquid 
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR 
part 1206.
    (f) Fugitive emissions from valves, fittings, flanges, pressure 
relief valves or similar components do not require approval under this 
subpart unless specifically required by the Regional Supervisor.



Sec.  250.1161  When may I flare or vent gas for extended periods of time?

    You must request and receive approval from the Regional Supervisor 
to flare or vent gas for an extended period of time. The Regional 
Supervisor will

[[Page 244]]

specify the approved period of time, which will not exceed 1 year. The 
Regional Supervisor may deny your request if it does not ensure the 
conservation of natural resources or is not consistent with National 
interests relating to development and production of minerals of the OCS. 
The Regional Supervisor may approve your request for one of the 
following reasons:
    (a) You initiated an action which, when completed, will eliminate 
flaring and venting; or
    (b) You submit to the Regional Supervisor an evaluation supported by 
engineering, geologic, and economic data indicating that the oil and gas 
produced from the well(s) will not economically support the facilities 
necessary to sell the gas or to use the gas on or for the benefit of the 
lease.



Sec.  250.1162  When may I burn produced liquid hydrocarbons?

    (a) You must request and receive approval from the Regional 
Supervisor to burn any produced liquid hydrocarbons. The Regional 
Supervisor may allow you to burn liquid hydrocarbons if you demonstrate 
that transporting them to market or re-injecting them is not technically 
feasible or poses a significant risk of harm to offshore personnel or 
the environment.
    (b) If you burn liquid hydrocarbons without the required approval, 
or if the Regional Supervisor determines that you were negligent or 
could have avoided burning liquid hydrocarbons, the hydrocarbons will be 
considered avoidably lost or wasted. You must pay royalties on the loss 
or waste, according to 30 CFR part 1202. You must value any liquid 
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR 
part 1206.



Sec.  250.1163  How must I measure gas flaring or venting volumes and
 liquid hydrocarbon burning volumes, and what records must I maintain?

    (a) If your facility processes more than an average of 2,000 bopd 
during May 2010, you must install flare/vent meters within 180 days 
after May 2010. If your facility processes more than an average of 2,000 
bopd during a calendar month after May 2010, you must install flare/vent 
meters within 120 days after the end of the month in which the average 
amount of oil processed exceeds 2,000 bopd.
    (1) You must notify the Regional Supervisor when your facility 
begins to process more than an average of 2,000 bopd in a calendar 
month;
    (2) The flare/vent meters must measure all flared and vented gas 
within 5 percent accuracy;
    (3) You must calibrate the meters regularly, in accordance with the 
manufacturer's recommendation, or at least once every year, whichever is 
shorter; and
    (4) You must use and maintain the flare/vent meters for the life of 
the facility.
    (b) You must report all hydrocarbons produced from a well 
completion, including all gas flared, gas vented, and liquid 
hydrocarbons burned, to Office of Natural Resources Revenue on Form 
ONRR-4054 (Oil and Gas Operations Report), in accordance with 30 CFR 
1210.102.
    (1) You must report the amount of gas flared and the amount of gas 
vented separately.
    (2) You may classify and report gas used to operate equipment on the 
lease, such as gas used to power engines, instrument gas, and gas used 
to maintain pilot lights, as lease use gas.
    (3) If flare/vent meters are required at one or more of your 
facilities, you must report the amount of gas flared and vented at each 
of those facilities separately from those facilities that do not require 
meters and separately from other facilities with meters.
    (4) If flare/vent meters are not required at your facility:
    (i) You may report the gas flared and vented on a lease or unit 
basis. Gas flared and vented from multiple facilities on a single lease 
or unit may be reported together.
    (ii) If you choose to install meters, you may report the gas volume 
flared and vented according to the method specified in paragraph (b)(3) 
of this section.
    (c) You must prepare and maintain records detailing gas flaring, gas 
venting, and liquid hydrocarbon burning for each facility for 6 years.
    (1) You must maintain these records on the facility for at least the 
first 2

[[Page 245]]

years and have them available for inspection by BSEE representatives.
    (2) After 2 years, you must maintain the records, allow BSEE 
representatives to inspect the records upon request and provide copies 
to the Regional Supervisor upon request, but are not required to keep 
them on the facility.
    (3) The records must include, at a minimum:
    (i) Daily volumes of gas flared, gas vented, and liquid hydrocarbons 
burned;
    (ii) Number of hours of gas flaring, gas venting, and liquid 
hydrocarbon burning, on a daily and monthly cumulative basis;
    (iii) A list of the wells contributing to gas flaring, gas venting, 
and liquid hydrocarbon burning, along with gas-oil ratio data;
    (iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon 
burning; and
    (v) Documentation of all required approvals.
    (d) If your facility is required to have flare/vent meters:
    (1) You must maintain the meter recordings for 6 years.
    (i) You must keep these recordings on the facility for 2 years and 
have them available for inspection by BSEE representatives.
    (ii) After 2 years, you must maintain the recordings, allow BSEE 
representatives to inspect the recordings upon request and provide 
copies to the Regional Supervisor upon request, but are not required to 
keep them on the facility.
    (iii) These recordings must include the begin times, end times, and 
volumes for all flaring and venting incidents.
    (2) You must maintain flare/vent meter calibration and maintenance 
records on the facility for 2 years.
    (e) If your flaring or venting of gas, or burning of liquid 
hydrocarbons, required written or oral approval, you must submit 
documentation to the Regional Supervisor summarizing the location, 
dates, number of hours, and volumes of gas flared, gas vented, and 
liquid hydrocarbons burned under the approval.



Sec.  250.1164  What are the requirements for flaring or venting
 gas containing H [bdi2]S?

    (a) You may not vent gas containing H2S, except for minor 
releases during maintenance and repair activities that do not result in 
a 15-minute time-weighted average atmosphere concentration of 
H2S of 20 ppm or higher anywhere on the platform.
    (b) You may flare gas containing H2S only if you meet the 
requirements of Sec. Sec.  250.1160, 250.1161, 250.1163, and the 
following additional requirements:
    (1) For safety or air pollution prevention purposes, the Regional 
Supervisor may further restrict the flaring of gas containing 
H2S. The Regional Supervisor will use information provided in 
the lessee's H2S Contingency Plan (Sec.  250.490(f)), 
Exploration Plan, DPP, DOCD submitted to BOEM, and associated documents 
to determine the need for restrictions; and
    (2) If the Regional Supervisor determines that flaring at a facility 
or group of facilities may significantly affect the air quality of an 
onshore area, the Regional Supervisor may require you to conduct an air 
quality modeling analysis, under 30 CFR 550.303, to determine the 
potential effect of facility emissions. The Regional Supervisor may 
require monitoring and reporting, or may restrict or prohibit flaring, 
under 30 CFR 550.303 and 30 CFR 550.304.
    (c) The Regional Supervisor may require you to submit monthly 
reports of flared and vented gas containing H2S. Each report 
must contain, on a daily basis:
    (1) The volume and duration of each flaring and venting occurrence;
    (2) H2S concentration in the flared or vented gas; and
    (3) The calculated amount of SO2 emitted.

                           Other Requirements



Sec.  250.1165  What must I do for enhanced recovery operations?

    (a) You must promptly initiate enhanced oil and gas recovery 
operations for all reservoirs where these operations would result in an 
increase in ultimate recovery of oil or gas under sound engineering and 
economic principles.

[[Page 246]]

    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the BSEE Regional Supervisor and receive approval for 
pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas from a reservoir. The proposed plan must include, for 
each project reservoir, a geologic and engineering overview and any 
additional information required by the BSEE Regional Supervisor. You 
also must submit Form BOEM-0127 to BOEM along with the supporting data 
specified in BOEM regulations, 30 CFR part 550, subpart K.
    (c) You must report to Office of Natural Resources Revenue the 
volumes of oil, gas, or other substances injected, produced, or produced 
for a second time under 30 CFR 1210.102.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1166  What additional reporting is required for developments
 in the Alaska OCS Region?

    (a) For any development in the Alaska OCS Region, you must submit an 
annual reservoir management report to the Regional Supervisor. The 
report must contain information detailing the activities performed 
during the previous year and planned for the upcoming year that will:
    (1) Provide for the prevention of waste;
    (2) Provide for the protection of correlative rights; and
    (3) Maximize ultimate recovery of oil and gas.
    (b) If your development is jointly regulated by BSEE and the State 
of Alaska, BSEE and the Alaska Oil and Gas Conservation Commission will 
jointly determine appropriate reporting requirements to minimize or 
eliminate duplicate reporting requirements.
    (c) [Reserved]



Sec.  250.1167  What information must I submit with forms and for approvals?

    You must submit the supporting information listed in the following 
table with the form identified in column 1 and for the approvals 
required under this subpart identified in columns 2 through 4:

----------------------------------------------------------------------------------------------------------------
                                                                                                    Production
                                               WPT BSEE-0126       Gas cap          Downhole      within 500-ft
                                                 (2 copies)       production      commingling      of a unit or
                                                                                                    lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface, bottomhole,    ...............        [bcheck]         [bcheck]         [bcheck]
     and completion locations with respect
     to the unit or lease line and the
     orientation of representative seismic
     lines or cross-sections................
    (2) Structure maps with penetration             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     point and subsea depth for each well
     penetrating the reservoirs,
     highlighting subject wells; reservoir
     boundaries; and original and current
     fluid levels...........................
    (3) Net sand isopach with total net sand  ...............        [bcheck]         [bcheck]
     penetrated for each well, identified at
     the penetration point..................
    (4) Net hydrocarbon isopach with net      ...............        [bcheck]         [bcheck]
     feet of pay for each well, identified
     at the penetration point...............
(b) Seismic data:
    (1) Representative seismic lines,         ...............        [bcheck]         [bcheck]         [bcheck]
     including strike and dip lines that
     confirm the structure; indicate
     polarity...............................
    (2) Amplitude extraction of seismic       ...............        [bcheck]         [bcheck]         [bcheck]
     horizon, if applicable.................
(c) Logs:
    (1) Well log sections with tops and             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     bottoms of the reservoir(s) and
     proposed or existing perforations......
    (2) Structural cross-sections showing     ...............        [bcheck]         [bcheck]                *
     the subject well and nearby wells......
(d) Engineering data:

[[Page 247]]

 
    (1) Estimated recoverable reserves for    ...............        [dagger]         [dagger]         [bcheck]
     each well completion in the reservoir;
     total recoverable reserves for each
     reservoir; method of calculation;
     reservoir parameters used in volumetric
     and decline curve analysis.............
    (2) Well schematics showing current and   ...............        [bcheck]         [bcheck]         [bcheck]
     proposed conditions....................
    (3) The drive mechanism of each           ...............        [bcheck]         [bcheck]         [bcheck]
     reservoir..............................
    (4) Pressure data, by date, and whether   ...............        [bcheck]         [bcheck]
     they are estimated or measured.........
    (5) Production data and decline curve     ...............        [bcheck]         [bcheck]
     analysis indicative of the reservoir
     performance............................
    (6) Reservoir simulation with the         ...............               *                *                *
     reservoir parameters used, history
     matches, and prediction runs (include
     proposed development scenario).........
(e) General information:
    (1) Detailed economic analysis..........  ...............               *                *
    (2) Reservoir name and whether or not it  ...............        [bcheck]         [bcheck]         [bcheck]
     is competitive as defined under Sec.
     250.105................................
    (3) Operator name, lessee name(s),        ...............        [bcheck]         [bcheck]         [bcheck]
     block, lease number, royalty rate, and
     unit number (if applicable) of all
     relevant leases........................
    (4) Geologic overview of project........  ...............        [bcheck]         [bcheck]         [bcheck]
    (5) Explanation of why the proposed       ...............        [bcheck]         [bcheck]         [bcheck]
     completion scenario will maximize
     ultimate recovery......................
    (6) List of all wells in subject          ...............        [bcheck]         [bcheck]         [bcheck]
     reservoirs that have ever produced or
     been used for injection................
----------------------------------------------------------------------------------------------------------------
[bcheck] Required.
[dagger] Each Gas Cap Production request and Downhole Commingling request must include the estimated recoverable
  reserves for (1) the case where your proposed production scenario is approved, and (2) the case where your
  proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
  submittal of some of the required data on a case-by-case basis.

    (f) Depending on the type of approval requested, you must submit the 
appropriate payment of the service fee(s) listed in Sec.  250.125, 
according to the instructions in Sec.  250.126.



 Subpart L_Oil and Gas Production Measurement, Surface Commingling, and 
                                Security



Sec.  250.1200  Question index table.

    The table in this section lists questions concerning Oil and Gas 
Production Measurement, Surface Commingling, and Security.

------------------------------------------------------------------------
            Frequently asked questions                  CFR citation
------------------------------------------------------------------------
1. What are the requirements for measuring liquid   Sec.   250.1202(a)
 hydrocarbons?
2. What are the requirements for liquid             Sec.   250.1202(b)
 hydrocarbon royalty meters?
3. What are the requirements for run tickets?       Sec.   250.1202(c)
4. What are the requirements for liquid             Sec.   250.1202(d)
 hydrocarbon royalty meter provings?
5. What are the requirements for calibrating a      Sec.   250.1202(e)
 master meter used in royalty meter provings?
6. What are the requirements for calibrating        Sec.   250.1202(f)
 mechanical-displacement provers and tank provers?
7. What correction factors must a lessee use when   Sec.   250.1202(g)
 proving meters with a mechanical displacement
 prover, tank prover, or master meter?
8. What are the requirements for establishing and   Sec.   250.1202(h)
 applying operating meter factors for liquid
 hydrocarbons?
9. Under what circumstances does a liquid           Sec.   250.1202(i)
 hydrocarbon royalty meter need to be taken out of
 service, and what must a lessee do?
10. How must a lessee correct gross liquid          Sec.   250.1202(j)
 hydrocarbon volumes to standard conditions?
11. What are the requirements for liquid            Sec.   250.1202(k)
 hydrocarbon allocation meters?
12. What are the requirements for royalty and       Sec.   250.1202(l)
 inventory tank facilities?
13. To which meters do BSEE requirements for gas    Sec.   250.1203(a)
 measurement apply?
14. What are the requirements for measuring gas?    Sec.   250.1203(b)
15. What are the requirements for gas meter         Sec.   250.1203(c)
 calibrations?
16. What must a lessee do if a gas meter is out of  Sec.   250.1203(d)
 calibration or malfunctioning?

[[Page 248]]

 
17. What are the requirements when natural gas      Sec.   250.1203(e)
 from a Federal lease is transferred to a gas
 plant before royalty determination?
18. What are the requirements for measuring gas     Sec.   250.1203(f)
 lost or used on a lease?
19. What are the requirements for the surface       Sec.   250.1204(a)
 commingling of production?
20. What are the requirements for a periodic well   Sec.   250.1204(b)
 test used for allocation?
21. What are the requirements for site security?    Sec.   250.1205(a)
22. What are the requirements for using seals?      Sec.   250.1205(b)
------------------------------------------------------------------------



Sec.  250.1201  Definitions.

    Terms not defined in this section have the meanings given in the 
applicable chapter of the API MPMS, which is incorporated by reference 
in Sec.  250.198. Terms used in Subpart L have the following meaning:
    Allocation meter--a meter used to determine the portion of 
hydrocarbons attributable to one or more platforms, leases, units, or 
wells, in relation to the total production from a royalty or allocation 
measurement point.
    API MPMS--the American Petroleum Institute's Manual of Petroleum 
Measurement Standards, chapters 1, 20, and 21.
    British Thermal Unit (Btu)--the amount of heat needed to raise the 
temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 
[deg]F) to 60.5 degrees Fahrenheit (60.5 [deg]F) at standard pressure 
base (14.73 pounds per square inch absolute (psia)).
    Compositional Analysis--separating mixtures into identifiable 
components expressed in mole percent.
    Force majeure event--an event beyond your control such as war, act 
of terrorism, crime, or act of nature which prevents you from operating 
the wells and meters on your OCS facility.
    Gas lost--gas that is neither sold nor used on the lease or unit nor 
used internally by the producer.
    Gas processing plant--an installation that uses any process designed 
to remove elements or compounds (hydrocarbon and non-hydrocarbon) from 
gas, including absorption, adsorption, or refrigeration. Processing does 
not include treatment operations, including those necessary to put gas 
into marketable conditions such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, desulphurization, 
and compression. The changing of pressures or temperatures in a 
reservoir is not processing.
    Gas processing plant statement--a monthly statement showing the 
volume and quality of the inlet or field gas stream and the plant 
products recovered during the period, volume of plant fuel, flare and 
shrinkage, and the allocation of these volumes to the sources of the 
inlet stream.
    Gas royalty meter malfunction--an error in any component of the gas 
measurement system which exceeds contractual tolerances.
    Gas volume statement--a monthly statement showing gas measurement 
data, including the volume (Mcf) and quality (Btu) of natural gas which 
flowed through a meter.
    Inventory tank--a tank in which liquid hydrocarbons are stored prior 
to royalty measurement. The measured volumes are used in the allocation 
process.
    Liquid hydrocarbons (free liquids)--hydrocarbons which exist in 
liquid form at standard conditions after passing through separating 
facilities.
    Malfunction factor--a liquid hydrocarbon royalty meter factor that 
differs from the previous meter factor by an amount greater than 0.0025.
    Natural gas--a highly compressible, highly expandable mixture of 
hydrocarbons which occurs naturally in a gaseous form and passes a meter 
in vapor phase.
    Operating meter--a royalty or allocation meter that is used for gas 
or liquid hydrocarbon measurement for any period during a calibration 
cycle.
    Pipeline (retrograde) condensate--liquid hydrocarbons which drop out 
of the separated gas stream at any point in a pipeline during 
transmission to shore.
    Pressure base--the pressure at which gas volumes and quality are 
reported. The standard pressure base is 14.73 psia.
    Prove--to determine (as in meter proving) the relationship between 
the volume passing through a meter at one

[[Page 249]]

set of conditions and the indicated volume at those same conditions.
    Royalty meter--a meter approved for the purpose of determining the 
volume of gas, oil, or other components removed, saved, or sold from a 
Federal lease.
    Royalty tank--an approved tank in which liquid hydrocarbons are 
measured and upon which royalty volumes are based.
    Run ticket--the invoice for liquid hydrocarbons measured at a 
royalty point.
    Sales meter--a meter at which custody transfer takes place (not 
necessarily a royalty meter).
    Seal--a device or approved method used to prevent tampering with 
royalty measurement components.
    Standard conditions--atmospheric pressure of 14.73 pounds per square 
inch absolute (psia) and 60 [deg]F.
    Surface commingling--the surface mixing of production from two or 
more leases and/or unit participating areas prior to royalty 
measurement.
    Temperature base--the temperature at which gas and liquid 
hydrocarbon volumes and quality are reported. The standard temperature 
base is 60 [deg]F.
    Verification/Calibration--testing and correcting, if necessary, a 
measuring device to ensure compliance with industry accepted, 
manufacturer's recommended, or regulatory required standard of accuracy.
    You or your--the lessee or the operator or other lessees' 
representative engaged in operations in the Outer Continental Shelf 
(OCS).



Sec.  250.1202  Liquid hydrocarbon measurement.

    (a) What are the requirements for measuring liquid hydrocarbons? You 
must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing liquid hydrocarbon production, or 
making any changes to the previously-approved measurement and/or 
allocation procedures. Your application (which may also include any 
relevant gas measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec.  250.125. The 
service fees are divided into two levels based on complexity as shown in 
the following table.

------------------------------------------------------------------------
      Application type                          Actions
------------------------------------------------------------------------
(i) Simple applications,      Applications to temporarily reroute
                               production (for a duration not to exceed
                               six months); Production tests prior to
                               pipeline construction; Departures related
                               to meter proving, well testing, or
                               sampling frequency.
(ii) Complex applications,    Creation of new facility measurement
                               points (FMPs); Association of leases or
                               units with existing FMPs; Inclusion of
                               production from additional structures;
                               Meter updates which add buy-back gas
                               meters or pigging meters; Other
                               applications which request deviations
                               from the approved allocation procedures.
------------------------------------------------------------------------

    (2) Use measurement equipment and procedures that will accurately 
measure the liquid hydrocarbons produced from a lease or unit to comply 
with the following additional API MPMS industry standards or API RP:
    (i) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as 
specified in Sec.  250.198);
    (iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (iv) API MPMS, Chapter 11, Section 1 (incorporated by reference as 
specified in Sec.  250.198);
    (v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec.  250.198);
    (vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec.  250.198);
    (vii) API MPMS, Chapter 21, Section 2 (incorporated by reference as 
specified in Sec.  250.198);
    (viii) API MPMS, Chapter 21, Addendum to Section 2 (incorporated by 
reference as specified in Sec.  250.198);
    (ix) API RP 86 (incorporated by reference as specified in Sec.  
250.198);
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS or RP as incorporated by reference 
in 30 CFR 250.198,

[[Page 250]]

including the following additional editions:
    (i) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as 
specified in Sec.  250.198);
    (iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (iv) API MPMS Chapter 11, Section 1 (incorporated by reference as 
specified in Sec.  250.198);
    (v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec.  250.198);
    (vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec.  250.198);
    (vii) API RP 86 (incorporated by reference as specified in Sec.  
250.198); when obtaining net standard volume and associated measurement 
parameters; and
    (4) When requested by the Regional Supervisor, provide the pipeline 
(retrograde) condensate volumes as allocated to the individual leases or 
units.
    (b) What are the requirements for liquid hydrocarbon royalty meters? 
You must:
    (1) Ensure that the royalty meter facilities include the following 
approved components (or other BSEE-approved components) which must be 
compatible with their connected systems:
    (i) A meter equipped with a nonreset totalizer;
    (ii) A calibrated mechanical displacement (pipe) prover, master 
meter, or tank prover;
    (iii) A proportional-to-flow sampling device pulsed by the meter 
output;
    (iv) A temperature measurement or temperature compensation device; 
and
    (v) A sediment and water monitor with a probe located upstream of 
the divert valve.
    (2) Ensure that the royalty meter facilities accomplish the 
following:
    (i) Prevent flow reversal through the meter;
    (ii) Protect meters subjected to pressure pulsations or surges;
    (iii) Prevent the meter from being subjected to shock pressures 
greater than the maximum working pressure; and
    (iv) Prevent meter bypassing.
    (3) Maintain royalty meter facilities to ensure the following:
    (i) Meters operate within the gravity range specified by the 
manufacturer;
    (ii) Meters operate within the manufacturer's specifications for 
maximum and minimum flow rate for linear accuracy; and
    (iii) Meters are reproven when changes in metering conditions affect 
the meters' performance such as changes in pressure, temperature, 
density (water content), viscosity, pressure, and flow rate.
    (4) Ensure that sampling devices conform to the following:
    (i) The sampling point is in the flowstream immediately upstream or 
downstream of the meter or divert valve in accordance with the API MPMS 
(as incorporated by reference in Sec.  250.198);
    (ii) The sample container is vapor-tight and includes a power mixing 
device to allow complete mixing of the sample before removal from the 
container; and
    (iii) The sample probe is in the center half of the pipe diameter in 
a vertical run and is located at least three pipe diameters downstream 
of any pipe fitting within a region of turbulent flow. The sample probe 
can be located in a horizontal pipe if adequate stream conditioning such 
as power mixers or static mixers are installed upstream of the probe 
according to the manufacturer's instructions.
    (c) What are the requirements for run tickets? You must:
    (1) For royalty meters, ensure that the run tickets clearly identify 
all observed data, all correction factors not included in the meter 
factor, and the net standard volume.
    (2) For royalty tanks, ensure that the run tickets clearly identify 
all observed data, all applicable correction factors, on/off seal 
numbers, and the net standard volume.
    (3) Pull a run ticket at the beginning of the month and immediately 
after establishing the monthly meter factor or a malfunction meter 
factor.
    (4) Send all run tickets for royalty meters and tanks to the 
Regional Supervisor within 15 days after the end of the month;

[[Page 251]]

    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? You must:
    (1) Permit BSEE representatives to witness provings;
    (2) Ensure that the integrity of the prover calibration is traceable 
to test measures certified by the National Institute of Standards and 
Technology;
    (3) Prove each operating royalty meter to determine the meter factor 
monthly, but the time between meter factor determinations must not 
exceed 42 days. When a force majeure event precludes the required 
monthly meter proving, meters must be proved within 15 days after being 
returned to service. The meters must be proved monthly thereafter, but 
the time between meter factor determinations must not exceed 42 days;
    (4) Obtain approval from the Regional Supervisor before proving on a 
schedule other than monthly; and
    (5) Submit copies of all meter proving reports for royalty meters to 
the Regional Supervisor monthly within 15 days after the end of the 
month.
    (e) What are the requirements for calibrating a master meter used in 
royalty meter provings? You must:
    (1) Calibrate the master meter to obtain a master meter factor 
before using it to determine operating meter factors;
    (2) Use a fluid of similar gravity, viscosity, temperature, and flow 
rate as the liquid hydrocarbons that flow through the operating meter to 
calibrate the master meter;
    (3) Calibrate the master meter monthly, but the time between 
calibrations must not exceed 42 days;
    (4) Calibrate the master meter by recording runs until the results 
of two consecutive runs (if a tank prover is used) or five out of six 
consecutive runs (if a mechanical-displacement prover is used) produce 
meter factor differences of no greater than 0.0002. Lessees must use the 
average of the two (or the five) runs that produced acceptable results 
to compute the master meter factor;
    (5) Install the master meter upstream of any back-pressure or 
reverse flow check valves associated with the operating meter. However, 
the master meter may be installed either upstream or downstream of the 
operating meter; and
    (6) Keep a copy of the master meter calibration report at your field 
location for 2 years.
    (f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? You must:
    (1) Calibrate mechanical-displacement provers and tank provers at 
least once every 5 years according to the API MPMS as incorporated by 
reference in 30 CFR 250.198, including the following additional 
editions:
    (i) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (ii) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec.  250.198);
    (2) Submit a copy of each calibration report to the Regional 
Supervisor within 15 days after the calibration.
    (g) What correction factors must I use when proving meters with a 
mechanical-displacement prover, tank prover, or master meter? Calculate 
the following correction factors using the API MPMS as referenced in 30 
CFR 250.198, including the following additional editions:
    (1) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec.  250.198);
    (2) API MPMS Chapter 11, Section 1 (incorporated by reference as 
specified in Sec.  250.198);
    (3) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec.  250.198);
    (4) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec.  250.198);
    (h) What are the requirements for establishing and applying 
operating meter factors for liquid hydrocarbons? (1) If you use a 
mechanical-displacement prover, you must record proof runs until five 
out of six consecutive runs produce a difference between individual runs 
of no greater than .05 percent. You must use the average of the five 
accepted runs to compute the meter factor.
    (2) If you use a master meter, you must record proof runs until 
three consecutive runs produce a total meter factor difference of no 
greater than 0.0005. The flow rate through the meters during the proving 
must be within 10 percent of the rate at which the line

[[Page 252]]

meter will operate. The final meter factor is determined by averaging 
the meter factors of the three runs;
    (3) If you use a tank prover, you must record proof runs until two 
consecutive runs produce a meter factor difference of no greater than 
.0005. The final meter factor is determined by averaging the meter 
factors of the two runs; and
    (4) You must apply operating meter factors forward starting with the 
date of the proving.
    (i) Under what circumstances does a liquid hydrocarbon royalty meter 
need to be taken out of service, and what must I do? (1) If the 
difference between the meter factor and the previous factor exceeds 
0.0025 it is a malfunction factor, and you must:
    (i) Remove the meter from service and inspect it for damage or wear;
    (ii) Adjust or repair the meter, and reprove it;
    (iii) Apply the average of the malfunction factor and the previous 
factor to the production measured through the meter between the date of 
the previous factor and the date of the malfunction factor; and
    (iv) Indicate that a meter malfunction occurred and show all 
appropriate remarks regarding subsequent repairs or adjustments on the 
proving report.
    (2) If a meter fails to register production, you must:
    (i) Remove the meter from service, repair and reprove it;
    (ii) Apply the previous meter factor to the production run between 
the date of that factor and the date of the failure; and
    (iii) Estimate and report unregistered production on the run ticket.
    (3) If the results of a royalty meter proving exceed the run 
tolerance criteria and all measures excluding the adjustment or repair 
of the meter cannot bring results within tolerance, you must:
    (i) Establish a factor using proving results made before any 
adjustment or repair of the meter; and
    (ii) Treat the established factor like a malfunction factor (see 
paragraph (i)(1) of this section).
    (j) How must I correct gross liquid hydrocarbon volumes to standard 
conditions? To correct gross liquid hydrocarbon volumes to standard 
conditions, you must:
    (1) Include Cpl factors in the meter factor calculation or list and 
apply them on the appropriate run ticket.
    (2) List Ctl factors on the appropriate run ticket when the meter is 
not automatically temperature compensated.
    (k) What are the requirements for liquid hydrocarbon allocation 
meters? For liquid hydrocarbon allocation meters you must:
    (1) Take samples continuously proportional to flow or daily (use the 
procedure in the applicable chapter of the API MPMS as incorporated by 
reference in Sec.  250.198;
    (2) For turbine meters, take the sample proportional to the flow 
only;
    (3) Prove operating allocation meters monthly if they measure 50 or 
more barrels per day per meter the previous month. When a force majeure 
event precludes the required monthly meter proving, meters must be 
proved within 15 days after being returned to service. The meters must 
be proved monthly thereafter; or
    (4) Prove operating allocation meters quarterly if they measure less 
than 50 barrels per day per meter the previous month. When a force 
majeure event precludes the required quarterly meter proving, meters 
must be proved within 15 days after being returned to service. The 
meters must be proved quarterly thereafter;
    (5) Keep a copy of the proving reports at the field location for 2 
years;
    (6) Adjust and reprove the meter if the meter factor differs from 
the previous meter factor by more than 2 percent and less than 7 
percent;
    (7) For turbine meters, remove from service, inspect and reprove the 
meter if the factor differs from the previous meter factor by more than 
2 percent and less than 7 percent;
    (8) Repair and reprove, or replace and prove the meter if the meter 
factor differs from the previous meter factor by 7 percent or more; and
    (9) Permit BSEE representatives to witness provings.
    (l) What are the requirements for royalty and inventory tank 
facilities? You must:
    (1) Equip each royalty and inventory tank with a vapor-tight thief 
hatch, a

[[Page 253]]

vent-line valve, and a fill line designed to minimize free fall and 
splashing;
    (2) For royalty tanks, submit a complete set of calibration charts 
(tank tables) to the Regional Supervisor before using the tanks for 
royalty measurement;
    (3) For inventory tanks, retain the calibration charts for as long 
as the tanks are in use and submit them to the Regional Supervisor upon 
request; and
    (4) Obtain the volume and other measurement parameters by using 
corrections factors and procedures in the API MPMS as incorporated by 
reference in 30 CFR 250.198, including: API MPMS Chapter 11, Section 1 
(incorporated by reference as specified in Sec.  250.198).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012]



Sec.  250.1203  Gas measurement.

    (a) To which meters do BSEE requirements for gas measurement apply? 
BSEE requirements for gas measurements apply to all OCS gas royalty and 
allocation meters.
    (b) What are the requirements for measuring gas? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing gas production, or making any 
changes to the previously-approved measurement and/or allocation 
procedures. Your application (which may also include any relevant liquid 
hydrocarbon measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec.  250.125. The 
service fees are divided into two levels based on complexity, see table 
in Sec.  250.1202(a)(1).
    (2) Design, install, use, maintain, and test measurement equipment 
and procedures to ensure accurate and verifiable measurement. You must 
follow the recommendations in API MPMS or RP and AGA as incorporated by 
reference in 30 CFR 250.198, including the following additional 
editions:
    (i) API RP 86 (incorporated by reference as specified in Sec.  
250.198);
    (ii) AGA Report No. 7 (incorporated by reference as specified in 
Sec.  250.198);
    (iii) AGA Report No. 9 (incorporated by reference as specified in 
Sec.  250.198);
    (iv) AGA Report No. 10 (incorporated by reference as specified in 
Sec.  250.198);
    (3) Ensure that the measurement components demonstrate consistent 
levels of accuracy throughout the system.
    (4) Equip the meter with a chart or electronic data recorder. If an 
electronic data recorder is used, you must follow the recommendations in 
API MPMS.
    (5) Take proportional-to-flow or spot samples upstream or downstream 
of the meter at least once every 6 months.
    (6) When requested by the Regional Supervisor, provide available 
information on the gas quality.
    (7) Ensure that standard conditions for reporting gross heating 
value (Btu) are at a base temperature of 60 [deg]F and at a base 
pressure of 14.73 psia and reflect the same degree of water saturation 
as in the gas volume.
    (8) When requested by the Regional Supervisor, submit copies of gas 
volume statements for each requested gas meter. Show whether gas volumes 
and gross Btu heating values are reported at saturated or unsaturated 
conditions; and
    (9) When requested by the Regional Supervisor, provide volume and 
quality statements on dispositions other than those on the gas volume 
statement.
    (c) What are the requirements for gas meter calibrations? You must:
    (1) Verify/calibrate operating meters monthly, but do not exceed 42 
days between verifications/calibrations. When a force majeure event 
precludes the required monthly meter verification/calibration, meters 
must be verified/calibrated within 15 days after being returned to 
service. The meters must be verified/calibrated monthly thereafter, but 
do not exceed 42 days between meter verifications/calibrations;
    (2) Calibrate each meter by using the manufacturer's specifications;
    (3) Conduct calibrations as close as possible to the average hourly 
rate of flow since the last calibration;
    (4) Retain calibration reports at the field location for 2 years, 
and send the reports to the Regional Supervisor upon request; and
    (5) Permit BSEE representatives to witness calibrations.

[[Page 254]]

    (d) What must I do if a gas meter is out of calibration or 
malfunctioning? If a gas meter is out of calibration or malfunctioning, 
you must:
    (1) If the readings are greater than the contractual tolerances, 
adjust the meter to function properly or remove it from service and 
replace it.
    (2) Correct the volumes to the last acceptable calibration as 
follows:
    (i) If the duration of the error can be determined, calculate the 
volume adjustment for that period.
    (ii) If the duration of the error cannot be determined, apply the 
volume adjustment to one-half of the time elapsed since the last 
calibration or 21 days, whichever is less.
    (e) What are the requirements when natural gas from a Federal lease 
on the OCS is transferred to a gas plant before royalty determination? 
If natural gas from a Federal lease on the OCS is transferred to a gas 
plant before royalty determination:
    (1) You must provide the following to the Regional Supervisor upon 
request:
    (i) A copy of the monthly gas processing plant allocation statement; 
and
    (ii) Gross heating values of the inlet and residue streams when not 
reported on the gas plant statement.
    (2) You must permit BSEE to inspect the measurement and sampling 
equipment of natural gas processing plants that process Federal 
production.
    (f) What are the requirements for measuring gas lost or used on a 
lease? (1) You must either measure or estimate the volume of gas lost or 
used on a lease.
    (2) If you measure the volume, document the measurement equipment 
used and include the volume measured.
    (3) If you estimate the volume, document the estimating method, the 
data used, and the volumes estimated.
    (4) You must keep the documentation, including the volume data, 
easily obtainable for inspection at the field location for at least 2 
years, and must retain the documentation at a location of your choosing 
for at least 7 years after the documentation is generated, subject to 
all other document retention and production requirements in 30 U.S.C. 
1713 and 30 CFR part 1212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18922, Mar. 29, 2012]



Sec.  250.1204  Surface commingling.

    (a) What are the requirements for the surface commingling of 
production? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing the commingling of production or 
making any changes to the previously approved commingling procedures. 
Your application (which may also include any relevant liquid hydrocarbon 
and gas measurement requests) must be accompanied by payment of the 
service fee listed in Sec.  250.125. The service fees are divided into 
two levels based on complexity, see table in Sec.  250.1202(a)(1).
    (2) Upon the request of the Regional Supervisor, lessees who deliver 
State lease production into a Federal commingling system must provide 
volumetric or fractional analysis data on the State lease production 
through the designated system operator.
    (b) What are the requirements for a periodic well test used for 
allocation? You must:
    (1) Conduct a well test at least once every 60 days unless the 
Regional Supervisor approves a different frequency. When a force majeure 
event precludes the required well test within the prescribed 60 day 
period (or other frequency approved by the Regional Supervisor), wells 
must be tested within 15 days after being returned to production. 
Thereafter, well tests must be conducted at least once every 60 days (or 
other frequency approved by the Regional Supervisor);
    (2) Follow the well test procedures in 30 CFR part 250, subpart K; 
and
    (3) Retain the well test data at the field location for 2 years.



Sec.  250.1205  Site security.

    (a) What are the requirements for site security? You must:
    (1) Protect Federal production against production loss or theft;
    (2) Post a sign at each royalty or inventory tank which is used in 
the royalty determination process. The sign

[[Page 255]]

must contain the name of the facility operator, the size of the tank, 
and the tank number;
    (3) Not bypass BSEE-approved liquid hydrocarbon royalty meters and 
tanks; and
    (4) Report the following to the Regional Supervisor as soon as 
possible, but no later than the next business day after discovery:
    (i) Theft or mishandling of production;
    (ii) Tampering or bypassing any component of the royalty measurement 
facility; and
    (iii) Falsifying production measurements.
    (b) What are the requirements for using seals? You must:
    (1) Seal the following components of liquid hydrocarbon royalty 
meter installations to ensure that tampering cannot occur without 
destroying the seal:
    (i) Meter component connections from the base of the meter up to and 
including the register;
    (ii) Sampling systems including packing device, fittings, sight 
glass, and container lid;
    (iii) Temperature and gravity compensation device components;
    (iv) All valves on lines leaving a royalty or inventory storage 
tank, including load-out line valves, drain-line valves, and connection-
line valves between royalty and non-royalty tanks; and
    (v) Any additional components required by the Regional Supervisor.
    (2) Seal all bypass valves of gas royalty and allocation meters.
    (3) Number and track the seals and keep the records at the field 
location for at least 2 years; and
    (4) Make the records of seals available for BSEE inspection.



                          Subpart M_Unitization



Sec.  250.1300  What is the purpose of this subpart?

    This subpart explains how Outer Continental Shelf (OCS) leases are 
unitized. If you are an OCS lessee, use the regulations in this subpart 
for both competitive reservoir and unitization situations. The purpose 
of joint development and unitization is to:
    (a) Conserve natural resources;
    (b) Prevent waste; and/or
    (c) Protect correlative rights, including Federal royalty interests.



Sec.  250.1301  What are the requirements for unitization?

    (a) Voluntary unitization. You and other OCS lessees may ask the 
Regional Supervisor to approve a request for voluntary unitization. The 
Regional Supervisor may approve the request for voluntary unitization if 
unitized operations:
    (1) Promote and expedite exploration and development; or
    (2) Prevent waste, conserve natural resources, or protect 
correlative rights, including Federal royalty interests, of a reasonably 
delineated and productive reservoir.
    (b) Compulsory unitization. The Regional Supervisor may require you 
and other lessees to unitize operations of a reasonably delineated and 
productive reservoir if unitized operations are necessary to:
    (1) Prevent waste;
    (2) Conserve natural resources; or
    (3) Protect correlative rights, including Federal royalty interests.
    (c) Unit area. The area that a unit includes is the minimum number 
of leases that will allow the lessees to minimize the number of 
platforms, facility installations, and wells necessary for efficient 
exploration, development, and production of mineral deposits, oil and 
gas reservoirs, or potential hydrocarbon accumulations common to two or 
more leases. A unit may include whole leases or portions of leases.
    (d) Unit agreement. You, the other lessees, and the unit operator 
must enter into a unit agreement. The unit agreement must: allocate 
benefits to unitized leases, designate a unit operator, and specify the 
effective date of the unit agreement. The unit agreement must terminate 
when: the unit no longer produces unitized substances, and the unit 
operator no longer conducts drilling or well-workover operations (Sec.  
250.180) under the unit agreement, unless the Regional Supervisor orders 
or approves a suspension of production under Sec.  250.170.

[[Page 256]]

    (e) Unit operating agreement. The unit operator and the owners of 
working interests in the unitized leases must enter into a unit 
operating agreement. The unit operating agreement must describe how all 
the unit participants will apportion all costs and liabilities incurred 
maintaining or conducting operations. When a unit involves one or more 
net-profit-share leases, the unit operating agreement must describe how 
to attribute costs and credits to the net-profit-share lease(s), and 
this part of the agreement must be approved by the Regional Supervisor. 
Otherwise, you must provide a copy of the unit operating agreement to 
the Regional Supervisor, but the Regional Supervisor does not need to 
approve the unit operating agreement.
    (f) Extension of a lease covered by unit operations. If your unit 
agreement expires or terminates, or the unit area adjusts so that no 
part of your lease remains within the unit boundaries, your lease 
expires unless:
    (1) Its initial term has not expired;
    (2) You conduct drilling, production, or well-reworking operations 
on your lease consistent with applicable regulations; or
    (3) BSEE orders or approves a suspension of production or operations 
for your lease.
    (g) Unit operations. If your lease, or any part of your lease, is 
subject to a unit agreement, the entire lease continues for the term 
provided in the lease, and as long thereafter as any portion of your 
lease remains part of the unit area, and as long as operations continue 
the unit in effect.
    (1) If you drill, produce or perform well-workover operations on a 
lease within a unit, each lease, or part of a lease, in the unit will 
remain active in accordance with the unit agreement. Following a 
discovery, if your unit ceases drilling activities for a reasonable time 
period between the delineation of one or more reservoirs and the 
initiation of actual development drilling or production operations and 
that time period would extend beyond your lease's primary term or any 
extension under Sec.  250.180, the unit operator must request and obtain 
BSEE approval of a suspension of production under Sec.  250.170 in order 
to keep the unit from terminating.
    (2) When a lease in a unit agreement is beyond the primary term and 
the lease or unit is not producing, the lease will expire unless:
    (i) You conduct a continuous drilling or well reworking program 
designed to develop or restore the lease or unit production; or
    (ii) BSEE orders or approves a suspension of operations under Sec.  
250.170.



Sec.  250.1302  What if I have a competitive reservoir on a lease?

    (a) The Regional Supervisor may require you to conduct development 
and production operations in a competitive reservoir under either a 
joint Competitive Reservoir Development Program submitted to BSEE or a 
unitization agreement. A competitive reservoir has one or more producing 
or producible well completions on each of two or more leases, or 
portions of leases, with different lease operating interests. For 
purposes of this paragraph, a producible well completion is a well which 
is capable of production and which is shut in at the well head or at the 
surface but not necessarily connected to production facilities and from 
which the operator plans future production.
    (b) You may request that the Regional Supervisor make a preliminary 
determination whether a reservoir is competitive. When you receive the 
preliminary determination, you have 30 days (or longer if the Regional 
Supervisor allows additional time) to concur or to submit an objection 
with supporting evidence if you do not concur. The Regional Supervisor 
will make a final determination and notify you and the other lessees.
    (c) If you conduct drilling or production operations in a reservoir 
determined competitive by the BSEE Regional Supervisor, you and the 
other affected lessees must submit for approval a joint Competitive 
Reservoir Development Program. You must submit the joint Competitive 
Reservoir Development Program within 90 days after the Regional 
Supervisor makes a final determination that the reservoir is 
competitive. The joint Competitive Reservoir Development Program must

[[Page 257]]

provide for the development and/or production of the reservoir. You may 
submit supplemental Competitive Reservoir Development Programs for the 
Regional Supervisor's approval.
    (d) If you and the other affected lessees cannot reach an agreement 
on a joint Competitive Reservoir Development Program, submitted to BSEE 
within the approved period of time, each lessee must submit a separate 
Competitive Reservoir Development Program to the Regional Supervisor. 
The Regional Supervisor will hold a hearing to resolve differences in 
the separate Competitive Reservoir Development Programs. If the 
differences in the separate programs are not resolved at the hearing and 
the Regional Supervisor determines that unitization is necessary under 
Sec.  250.1301(b), BSEE will initiate unitization under Sec.  250.1304.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1303  How do I apply for voluntary unitization?

    (a) You must file a request for a voluntary unit with the Regional 
Supervisor. Your request must include:
    (1) A draft of the proposed unit agreement;
    (2) A proposed initial plan of operation;
    (3) Supporting geological, geophysical, and engineering data; and
    (4) Other information that may be necessary to show that the 
unitization proposal meets the criteria of Sec.  250.1300.
    (b) The unit agreement must comply with the requirements of this 
part. BSEE will maintain and provide a model unit agreement for you to 
follow. If BSEE revises the model, BSEE will publish the revised model 
in the Federal Register. If you vary your unit agreement from the model 
agreement, you must obtain the approval of the Regional Supervisor.
    (c) After the Regional Supervisor accepts your unitization proposal, 
you, the other lessees, and the unit operator must sign and file copies 
of the unit agreement, the unit operating agreement, and the initial 
plan of operation with the Regional Supervisor for approval.
    (d) You must pay the service fee listed in Sec.  250.125 of this 
part with your request for a voluntary unitization proposal or the 
expansion of a previously approved voluntary unit to include additional 
acreage. Additionally, you must pay the service fee listed in Sec.  
250.125 with your request for unitization revision.



Sec.  250.1304  How will BSEE require unitization?

    (a) If the Regional Supervisor determines that unitization of 
operations within a proposed unit area is necessary to prevent waste, 
conserve natural resources of the OCS, or protect correlative rights, 
including Federal royalty interests, the Regional Supervisor may require 
unitization.
    (b) If you ask BSEE to require unitization, you must file a request 
with the Regional Supervisor. You must include a proposed unit agreement 
as described in Sec. Sec.  250.1301(d) and 250.1303(b); a proposed unit 
operating agreement; a proposed initial plan of operation; supporting 
geological, geophysical, and engineering data; and any other information 
that may be necessary to show that unitization meets the criteria of 
Sec.  250.1300. The proposed unit agreement must include a counterpart 
executed by each lessee seeking compulsory unitization. Lessees who seek 
compulsory unitization must simultaneously serve on the nonconsenting 
lessees copies of:
    (1) The request;
    (2) The proposed unit agreement with executed counterparts;
    (3) The proposed unit operating agreement; and
    (4) The proposed initial plan of operation.
    (c) If the Regional Supervisor initiates compulsory unitization, 
BSEE will serve all lessees of the proposed unit area with a proposed 
unitization plan and a statement of reasons for the proposed 
unitization.
    (d) The Regional Supervisor will not require unitization until BSEE 
provides all lessees of the proposed unit area written notice and an 
opportunity for a hearing. If you want BSEE to hold a hearing, you must 
request it

[[Page 258]]

within 30 days after you receive written notice from the Regional 
Supervisor or after you are served with a request for compulsory 
unitization from another lessee.
    (e) BSEE will not hold a hearing under this paragraph until at least 
30 days after BSEE provides written notice of the hearing date to all 
parties owning interests that would be made subject to the unit 
agreement. The Regional Supervisor must give all lessees of the proposed 
unit area an opportunity to submit views orally and in writing and to 
question both those seeking and those opposing compulsory unitization. 
Adjudicatory procedures are not required. The Regional Supervisor will 
make a decision based upon a record of the hearing, including any 
written information made a part of the record. The Regional Supervisor 
will arrange for a court reporter to make a verbatim transcript. The 
party seeking compulsory unitization must pay for the court reporter and 
pay for and provide to the Regional Supervisor within 10 days after the 
hearing three copies of the verbatim transcript.
    (f) The Regional Supervisor will issue an order that requires or 
rejects compulsory unitization. That order must include a statement of 
reasons for the action taken and identify those parts of the record 
which form the basis of the decision. Any adversely affected party may 
appeal the final order of the Regional Supervisor under 30 CFR part 290.



            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties



Sec.  250.1400  How does BSEE begin the civil penalty process?

    This subpart explains BSEEs civil penalty procedures whenever a 
lessee, operator or other person engaged in oil, gas, sulphur or other 
minerals operations in the OCS has a violation. Whenever BSEE 
determines, on the basis of available evidence, that a violation 
occurred and a civil penalty review is appropriate, it will prepare a 
case file. BSEE will appoint a Reviewing Officer.



Sec.  250.1401  [Reserved]



Sec.  250.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means a BSEE document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is a BSEE regulatory enforcement tool 
used in addition to Notices of Incidents of Noncompliance and directed 
suspensions of production or other operations.
    Reviewing Officer means a BSEE employee assigned to review case 
files and assess civil penalties.
    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.



Sec.  250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $44,675 per day per violation.

[84 FR 10992, Mar. 25, 2019]



Sec.  250.1404  Which violations will BSEE review for potential civil penalties?

    BSEE will review each of the following violations for potential 
civil penalties:
    (a) Violations that you do not correct within the period BSEE 
grants;
    (b) Violations that BSEE determines may constitute, or constituted, 
a threat of serious, irreparable, or immediate harm or damage to life 
(including fish and other aquatic life), property, any mineral deposit, 
or the marine, coastal, or human environment; or
    (c) Violations that cause serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposit, or the marine, coastal, or human environment.
    (d) Violations of the oil spill financial responsibility 
requirements at 30 CFR part 553.

[[Page 259]]



Sec.  250.1405  When is a case file developed?

    BSEE will develop a case file during its investigation of the 
violation, and forward it to a Reviewing Officer if any of the 
conditions in Sec.  250.1404 exist. The Reviewing Officer will review 
the case file and determine if a civil penalty is appropriate. The 
Reviewing Officer may administer oaths and issue subpoenas requiring 
witnesses to attend meetings, submit depositions, or produce evidence.



Sec.  250.1406  When will BSEE notify me and provide penalty information?

    If the Reviewing Officer determines that a civil penalty should be 
assessed, the Reviewing Officer will send the violator a letter of 
notification. The letter of notification will include:
    (a) The amount of the proposed civil penalty;
    (b) Information on the violation(s); and
    (c) Instruction on how to obtain a copy of the case file, schedule a 
meeting, submit information, or pay the penalty.



Sec.  250.1407  How do I respond to the letter of notification?

    You have 30 calendar days after you receive the Reviewing Officer's 
letter to either:
    (a) Request, in writing, a meeting with the Reviewing Officer;
    (b) Submit additional information; or
    (c) Pay the proposed civil penalty.



Sec.  250.1408  When will I be notified of the Reviewing Officer's decision?

    At the end of the 30 calendar days or after the meeting and 
submittal of additional information, the Reviewing Officer will review 
the case file, including all information you submitted, and send you a 
decision. The decision will include the amount of any final civil 
penalty, the basis for the civil penalty, and instructions for paying or 
appealing the civil penalty.



Sec.  250.1409  What are my appeal rights?

    (a) When you receive the Reviewing Officer's final decision, you 
have 60 days to either pay the penalty or file an appeal in accordance 
with 30 CFR part 290, subpart A.
    (b) If you file an appeal, you must either:
    (1) Submit a surety bond in the amount of the penalty to the 
appropriate Leasing Office in the Region where the penalty was assessed, 
following instructions that the Reviewing Officer will include in the 
final decision; or
    (2) Notify the appropriate Leasing Office, in the Region where the 
penalty was assessed, that you want your lease-specific/area-wide bond 
on file to be used as the bond for the penalty amount.
    (c) If you choose the alternative in paragraph (b)(2) of this 
section, the BOEM Regional Director may require additional security 
(i.e., security in excess of your existing bond) to ensure sufficient 
coverage during an appeal. In that event, the Regional Director will 
require you to post the supplemental bond with the regional office in 
the same manner as under 30 CFR 556.53(d) through (f). If the Regional 
Director determines the appeal should be covered by a lease-specific 
abandonment account then you must establish an account that meets the 
requirements of 30 CFR part 556.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
BSEE will take one or more of the following actions:
    (1) We will collect the amount you were assessed, plus interest, 
late payment charges, and other fees as provided by law, from the date 
you received the Reviewing Officer's final decision until the date we 
receive payment;
    (2) We may initiate additional enforcement, including, if 
appropriate, cancellation of the lease, right-of-way, license, permit, 
or approval, or the forfeiture of a bond under this part; or
    (3) We may bar you from doing further business with the Federal 
Government according to Executive Orders 12549 and 12689, and section 
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 
6101. The Department of the Interior's regulations implementing these 
authorities are found at 43 CFR part 12, subpart D.

[[Page 260]]

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions



Sec.  250.1450  What definitions apply to this subpart?

    The terms used in this subpart have the same meaning as in 30 U.S.C. 
1702.

                   Penalties After a Period To Correct



Sec.  250.1451  What may BSEE do if I violate a statute, regulation,
 order, or lease term relating to a Federal oil and gas lease?

    (a) If we believe that you have not followed any requirement of a 
statute, regulation, order, or lease term for any Federal oil or gas 
lease, we may send you a Notice of Noncompliance informing you what the 
violation is and what you need to do to correct it to avoid civil 
penalties under 30 U.S.C. 1719(a) and (b).
    (b) We will serve the Notice of Noncompliance by registered mail or 
personal service using the most current address on file as maintained by 
the BOEM Leasing Office in your respective Region.



Sec.  250.1452  What if I correct the violation?

    The matter will be closed if you correct all of the violations 
identified in the Notice of Noncompliance within 20 days after you 
receive the Notice (or within a longer time period specified in the 
Notice).



Sec.  250.1453  What if I do not correct the violation?

    (a) We may send you a Notice of Civil Penalty if you do not correct 
all of the violations identified in the Notice of Noncompliance within 
20 days after you receive the Notice of Noncompliance (or within a 
longer time period specified in that Notice). The Notice of Civil 
Penalty will tell you how much penalty you must pay. The penalty may be 
up to $500 per day, beginning with the date of the Notice of 
Noncompliance, for each violation identified in the Notice of 
Noncompliance for as long as you do not correct the violations.
    (b) If you do not correct all of the violations identified in the 
Notice of Noncompliance within 40 days after you receive the Notice of 
Noncompliance (or 20 days following the expiration of a longer time 
period specified in that Notice), we may increase the penalty to up to 
$5,000 per day, beginning with the date of the Notice of Noncompliance, 
for each violation for as long as you do not correct the violations.



Sec.  250.1454  How may I request a hearing on the record on a
 Notice of Noncompliance?

    You may request a hearing on the record on a Notice of Noncompliance 
by filing a request within 30 days of the date you received the Notice 
of Noncompliance with the Hearings Division (Departmental), Office of 
Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy 
Street, Arlington, Virginia 22203. You may do this regardless of whether 
you correct the violations identified in the Notice of Noncompliance.



Sec.  250.1455  Does my request for a hearing on the record affect
 the penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance, the penalties will continue to accrue even if you request 
a hearing on the record.
    (b) You may petition the Hearings Division (Departmental) of the 
Office of Hearings and Appeals, to stay the accrual of penalties pending 
the hearing on the record and a decision by the Administrative Law Judge 
under Sec.  250.1472.
    (1) You must file your petition within 45 calendar days of receiving 
the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in BOEM's regulations, 30 CFR 
part 550, subpart N. The posted amount must cover the unpaid principal 
and interest due for the Notice of Noncompliance, plus the amount of any 
penalties accrued before the date a stay becomes effective.

[[Page 261]]

    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1456  May I request a hearing on the record regarding the
 amount of a civil penalty if I did not request a hearing on the
 Notice of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty, if 
you did not previously request a hearing on the record under Sec.  
250.1454. If you did not request a hearing on the record on the Notice 
of Noncompliance under Sec.  250.1454, you may not contest your 
underlying liability for civil penalties.
    (b) You must file your request within 10 days after you receive the 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy Street, Arlington, Virginia 22203.

                  Penalties Without a Period To Correct



Sec.  250.1460  May I be subject to penalties without prior notice
 and an opportunity to correct?

    The Federal Oil and Gas Royalty Management Act sets out several 
specific violations for which penalties accrue without an opportunity to 
first correct the violation.
    (a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up 
to $10,000 per day per violation for each day the violation continues if 
you:
    (1) Fail or refuse to permit lawful entry, inspection, or audit; or
    (2) Knowingly or willfully fail or refuse to notify the Secretary, 
within 5 business days after any well begins production on a lease site 
or allocated to a lease site, or resumes production in the case of a 
well which has been off production for more than 90 days, of the date on 
which production has begun or resumed.
    (b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties 
of up to $25,000 per day for each day each violation continues if you:
    (1) Knowingly or willfully prepare, maintain, or submit false, 
inaccurate, or misleading reports, notices, affidavits, records, data, 
or other written information;
    (2) Knowingly or willfully take or remove, transport, use or divert 
any oil or gas from any lease site without having valid legal authority 
to do so; or
    (3) Purchase, accept, sell, transport, or convey to another person, 
any oil or gas knowing or having reason to know that such oil or gas was 
stolen or unlawfully removed or diverted.



Sec.  250.1461  How will BSEE inform me of violations without a
 period to correct?

    We will inform you of any violation, without a period to correct, by 
issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using your address of record as specified under 30 CFR 
part 1218, Subpart H.



Sec.  250.1462  How may I request a hearing on the record on a
 Notice of Noncompliance regarding violations without a period
 to correct?

    You may request a hearing on the record of a Notice of Noncompliance 
regarding violations without a period to correct by filing a request 
within 30 days after you receive the Notice of Noncompliance with the 
Hearings Division (Departmental), Office of Hearings and Appeals, U.S. 
Department of the Interior, 801 North Quincy Street, Arlington, Virginia 
22203. You may do this regardless of whether you correct the violations 
identified in the Notice of Noncompliance.



Sec.  250.1463  Does my request for a hearing on the record affect
 the penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance regarding violations without a period to correct, the 
penalties will continue to accrue even if you request a hearing on the 
record.
    (b) You may ask the Hearings Division (Departmental) to stay the 
accrual of penalties pending the hearing

[[Page 262]]

on the record and a decision by the Administrative Law Judge under Sec.  
250.1472.
    (1) You must file your petition within 45 calendar days after you 
receive the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in BOEM's regulations, 30 CFR 
part 550, subpart N. The posted amount must cover the unpaid principal 
and interest due for the Notice of Noncompliance, plus the amount of any 
penalties accrued before the date a stay becomes effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec.  250.1464  May I request a hearing on the record regarding the
 amount of a civil penalty if I did not request a hearing on the
 Notice of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty 
regarding violations without a period to correct, if you did not 
previously request a hearing on the record under Sec.  250.1462. If you 
did not request a hearing on the record on the Notice of Noncompliance 
under Sec.  250.1462, you may not contest your underlying liability for 
civil penalties.
    (b) You must file your request within 10 days after you receive 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy, Arlington, Virginia 22203.

                           General Provisions



Sec.  250.1470  How does BSEE decide what the amount of the penalty
 should be?

    We determine the amount of the penalty by considering the severity 
of the violations, your history of compliance, and if you are a small 
business.



Sec.  250.1471  Does the penalty affect whether I owe interest?

    If you do not pay the penalty by the date required under Sec.  
250.1475(d), BSEE will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.



Sec.  250.1472  How will the Office of Hearings and Appeals conduct
 the hearing on the record?

    If you request a hearing on the record under Sec. Sec.  250.1454, 
250.1456, 250.1462, or 250.1464, the hearing will be conducted by a 
Departmental Administrative Law Judge from the Office of Hearings and 
Appeals. After the hearing, the Administrative Law Judge will issue a 
decision in accordance with the evidence presented and applicable law.



Sec.  250.1473  How may I appeal the Administrative Law Judge's decision?

    If you are adversely affected by the Administrative Law Judge's 
decision, you may appeal that decision to the Interior Board of Land 
Appeals under 43 CFR part 4, subpart E.



Sec.  250.1474  May I seek judicial review of the decision of the
 Interior Board of Land Appeals?

    Under 30 U.S.C. 1719(j), you may seek judicial review of the 
decision of the Interior Board of Land Appeals. A suit for judicial 
review in the District Court will be barred unless filed within 90 days 
after the final order.



Sec.  250.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec.  250.1453 or Sec.  250.1461, if you do not request a hearing 
on the record under Sec.  250.1454, Sec.  250.1456, Sec.  250.1462, or 
Sec.  250.1464.
    (b) If you request a hearing on the record under Sec.  250.1454, 
Sec.  250.1456, Sec.  250.1462, or Sec.  250.1464, but you do not appeal 
the determination of the Administrative Law Judge to the Interior Board 
of Land Appeals under Sec.  250.1473, you must pay the amount assessed 
by the Administrative Law Judge.
    (c) If you appeal the determination of the Administrative Law Judge 
to the Interior Board of Land Appeals, you

[[Page 263]]

must pay the amount assessed in the IBLA decision.
    (d) You must pay the penalty assessed within 40 days after:
    (1) You received the Notice of Civil Penalty, if you did not request 
a hearing on the record under either Sec.  250.1454, Sec.  250.1456, 
Sec.  250.1462, or Sec.  250.1464;
    (2) You received an Administrative Law Judge's decision under Sec.  
250.1472, if you obtained a stay of the accrual of penalties pending the 
hearing on the record under Sec.  250.1455(b) or Sec.  250.1463(b) and 
did not appeal the Administrative Law Judge's determination to the IBLA 
under Sec.  250.1473;
    (3) You received an IBLA decision under Sec.  250.1473 if the IBLA 
continued the stay of accrual of penalties pending its decision and you 
did not seek judicial review of the IBLA's decision; or
    (4) A final non-appealable judgment of a court of competent 
jurisdiction is entered, if you sought judicial review of the IBLA's 
decision and the Department or the appropriate court suspended 
compliance with the IBLA's decision pending the adjudication of the 
case.
    (e) If you do not pay, that amount is subject to collection under 
the provisions of Sec.  250.1477.



Sec.  250.1476  Can BSEE reduce my penalty once it is assessed?

    Under 30 U.S.C. 1719(g), the Director or his or her delegate may 
compromise or reduce civil penalties assessed under this part.



Sec.  250.1477  How may BSEE collect the penalty?

    (a) BSEE may use all available means to collect the penalty 
including, but not limited to:
    (1) Requiring the lease surety, for amounts owed by lessees, to pay 
the penalty;
    (2) Deducting the amount of the penalty from any sums the United 
States owes to you; and
    (3) Using judicial process to compel your payment under 30 U.S.C. 
1719(k).
    (b) If the Department uses judicial process, or if you seek judicial 
review under Sec.  250.1474 and the court upholds assessment of a 
penalty, the court shall have jurisdiction to award the amount assessed 
plus interest assessed from the date of the expiration of the 90-day 
period referred to in Sec.  250.1474. The amount of any penalty, as 
finally determined, may be deducted from any sum owing to you by the 
United States.

                           Criminal Penalties



Sec.  250.1480  May the United States criminally prosecute me for
 violations under Federal oil and gas leases?

    If you commit an act for which a civil penalty is provided at 30 
U.S.C. 1719(d) and Sec.  250.1460(b), the United States may pursue 
criminal penalties as provided at 30 U.S.C. 1720, in addition to any 
authority for prosecution under other statutes.



          Subpart O_Well Control and Production Safety Training



Sec.  250.1500  Definitions.

    Terms used in this subpart have the following meaning:
    Contractor and contract personnel mean anyone, other than an 
employee of the lessee, performing well control, deepwater well control, 
or production safety duties for the lessee.
    Deepwater well control means well control when you are using a 
subsea BOP system.
    Employee means direct employees of the lessees who are assigned well 
control, deepwater well control, or production safety duties.
    I or you means the lessee engaged in oil, gas, or sulphur operations 
in the Outer Continental Shelf (OCS).
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes an owner of operating rights for that lease 
and the BOEM-approved assignee of that lease.
    Periodic means occurring or recurring at regular intervals. Each 
lessee must specify the intervals for periodic training and periodic 
assessment of training needs in their training programs.
    Production operations include, but are not limited to, separation, 
dehydration, compression, sweetening, and metering operations.
    Production safety includes measures, practices, procedures, and 
equipment

[[Page 264]]

to ensure safe, accident-free, and pollution-free production operations, 
as well as installation, repair, testing, maintenance, and operation of 
surface and subsurface safety equipment.
    Well completion/well workover means those operations following the 
drilling of a well that are intended to establish or restore production.
    Well-control means methods used to minimize the potential for the 
well to flow or kick and to maintain control of the well in the event of 
flow or a kick. Well-control applies to drilling, well-completion, well-
workover, abandonment, and well-servicing operations. It includes 
measures, practices, procedures and equipment, such as fluid flow 
monitoring, to ensure safe and environmentally protective drilling, 
completion, abandonment, and workover operations as well as the 
installation, repair, maintenance, and operation of surface and subsea 
well-control equipment.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012]



Sec.  250.1501  What is the goal of my training program?

    The goal of your training program must be safe and clean OCS 
operations. To accomplish this, you must ensure that your employees and 
contract personnel engaged in well control, deepwater well control, or 
production safety operations understand and can properly perform their 
duties.



Sec.  250.1503  What are my general responsibilities for training?

    (a) You must establish and implement a training program so that all 
of your employees are trained to competently perform their assigned well 
control, deepwater well control, and production safety duties. You must 
verify that your employees understand and can perform the assigned well 
control, deepwater well control, or production safety duties.
    (b) If you conduct operations with a subsea BOP stack, your 
employees and contract personnel must be trained in deepwater well 
control. The trained employees and contract personnel must have a 
comprehensive knowledge of deepwater well control equipment, practices, 
and theory.
    (c) You must have a training plan that specifies the type, 
method(s), length, frequency, and content of the training for your 
employees. Your training plan must specify the method(s) of verifying 
employee understanding and performance. This plan must include at least 
the following information:
    (1) Procedures for training employees in well control, deepwater 
well control, or production safety practices;
    (2) Procedures for evaluating the training programs of your 
contractors;
    (3) Procedures for verifying that all employees and contractor 
personnel engaged in well control, deepwater well control, or production 
safety operations can perform their assigned duties;
    (4) Procedures for assessing the training needs of your employees on 
a periodic basis;
    (5) Recordkeeping and documentation procedures; and
    (6) Internal audit procedures.
    (d) Upon request of the District Manager or Regional Supervisor, you 
must provide:
    (1) Copies of training documentation for personnel involved in well 
control, deepwater well control, or production safety operations during 
the past 5 years; and
    (2) A copy of your training plan.



Sec.  250.1504  May I use alternative training methods?

    You may use alternative training methods. These methods may include 
computer-based learning, films, or their equivalents. This training 
should be reinforced by appropriate demonstrations and ``hands-on'' 
training. Alternative training methods must be conducted according to, 
and meet the objectives of, your training plan.



Sec.  250.1505  Where may I get training for my employees?

    You may get training from any source that meets the requirements of 
your training plan.



Sec.  250.1506  How often must I train my employees?

    You determine the frequency of the training you provide your 
employees. You must do all of the following:

[[Page 265]]

    (a) Provide periodic training to ensure that employees maintain 
understanding of, and competency in, well control, deepwater well 
control, or production safety practices;
    (b) Establish procedures to verify adequate retention of the 
knowledge and skills that employees need to perform their assigned well 
control, deepwater well control, or production safety duties; and
    (c) Ensure that your contractors' training programs provide for 
periodic training and verification of well control, deepwater well 
control, or production safety knowledge and skills.



Sec.  250.1507  How will BSEE measure training results?

    BSEE may periodically assess your training program, using one or 
more of the methods in this section.
    (a) Training system audit. BSEE or its authorized representative may 
conduct a training system audit at your office. The training system 
audit will compare your training program against this subpart. You must 
be prepared to explain your overall training program and produce 
evidence to support your explanation.
    (b) Employee or contract personnel interviews. BSEE or its 
authorized representative may conduct interviews at either onshore or 
offshore locations to inquire about the types of training that were 
provided, when and where this training was conducted, and how effective 
the training was.
    (c) Employee or contract personnel testing. BSEE or its authorized 
representative may conduct testing at either onshore or offshore 
locations for the purpose of evaluating an individual's knowledge and 
skills in perfecting well control, deepwater well control, and 
production safety duties.
    (d) Hands-on production safety, simulator, or live well testing. 
BSEE or its authorized representative may conduct tests at either 
onshore or offshore locations. Tests will be designed to evaluate the 
competency of your employees or contract personnel in performing their 
assigned well control, deepwater well control, and production safety 
duties. You are responsible for the costs associated with this testing, 
excluding salary and travel costs for BSEE personnel.



Sec.  250.1508  What must I do when BSEE administers written or oral tests?

    BSEE or its authorized representative may test your employees or 
contract personnel at your worksite or at an onshore location. You and 
your contractors must:
    (a) Allow BSEE or its authorized representative to administer 
written or oral tests; and
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name).



Sec.  250.1509  What must I do when BSEE administers or requires
 hands-on, simulator, or other types of testing?

    If BSEE or its authorized representative conducts, or requires you 
or your contractor to conduct hands-on, simulator, or other types of 
testing, you must:
    (a) Allow BSEE or its authorized representative to administer or 
witness the testing;
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name); and
    (c) Pay for all costs associated with the testing, excluding salary 
and travel costs for BSEE personnel.



Sec.  250.1510  What will BSEE do if my training program does not 
comply with this subpart?

    If BSEE determines that your training program is not in compliance, 
we may initiate one or more of the following enforcement actions:
    (a) Issue an Incident of Noncompliance (INC);
    (b) Require you to revise and submit to BSEE your training plan to 
address identified deficiencies;
    (c) Assess civil/criminal penalties; or
    (d) Initiate disqualification procedures.

[[Page 266]]



                      Subpart P_Sulphur Operations



Sec.  250.1600  Performance standard.

    Operations to discover, develop, and produce sulphur in the OCS 
shall be in accordance with a BOEM-approved Exploration Plan or 
Development and Production Plan and shall be conducted in a manner to 
protect against harm or damage to life (including fish and other aquatic 
life), property, natural resources of the OCS including any mineral 
deposits (in areas leased or not leased), the National security or 
defense, and the marine, coastal, or human environment.



Sec.  250.1601  Definitions.

    Terms used in this subpart shall have the meanings as defined below:
    Air line means a tubing string that is used to inject air within a 
sulphur producing well to airlift sulphur out of the well.
    Bleedwater means a mixture of mine water or booster water and 
connate water that is produced by a bleedwell.
    Bleedwell means a well drilled into a producing sulphur deposit that 
is used to control the mine pressure generated by the injection of mine 
water.
    Brine means the water containing dissolved salt obtained from a 
brine well by circulating water into and out of a cavity in the salt 
core of a salt dome.
    Brine well means a well drilled through cap rock into the core at a 
salt dome for the purpose of producing brine.
    Cap rock means the rock formation, a body of limestone, anhydride, 
and/or gypsum, overlying a salt dome.
    Sulphur deposit means a formation of rock that contains elemental 
sulphur.
    Sulphur production rate means the number of long tons of sulphur 
produced during a certain period of time, usually per day.



Sec.  250.1602  Applicability.

    (a) The requirements of this subpart P are applicable to all 
exploration, development, and production operations under an OCS sulphur 
lease. Sulphur operations include all activities conducted under a lease 
for the purpose of discovery or delineation of a sulphur deposit and for 
the development and production of elemental sulphur. Sulphur operations 
also include activities conducted for related purposes. Activities 
conducted for related purposes include, but are not limited to, 
production of other minerals, such as salt, for use in the exploration 
for or the development and production of sulphur. The lessee must have 
obtained the right to produce and/or use these other minerals.
    (b) Lessees conducting sulphur operations in the OCS shall comply 
with the requirements of the applicable provisions of subparts A, B, C, 
I, J, M, N, O, and Q of this part and the applicable provisions of 30 
CFR 550 subparts A, B, C, J and N.
    (c) Lessees conducting sulphur operations in the OCS are also 
required to comply with the requirements in the applicable provisions of 
subparts D, E, F, H, K, and L of this part and the applicable provisions 
of 30 CFR 550, subpart K, where such provisions specifically are 
referenced in this subpart.



Sec.  250.1603  Determination of sulphur deposit.

    (a) Upon receipt of a written request from the lessee, the District 
Manager will determine whether a sulphur deposit has been defined that 
contains sulphur in paying quantities (i.e., sulphur in quantities 
sufficient to yield a return in excess of the costs, after completion of 
the wells, of producing minerals at the wellheads).
    (b) A determination under paragraph (a) of this section shall be 
based upon the following:
    (1) Core analyses that indicate the presence of a producible sulphur 
deposit (including an assay of elemental sulphur);
    (2) An estimate of the amount of recoverable sulphur in long tons 
over a specified period of time; and
    (3) Contour map of the cap rock together with isopach map showing 
the extent and estimated thickness of the sulphur deposit.



Sec.  250.1604  General requirements.

    Sulphur lessees shall comply with requirements of this section when 
conducting well-drilling, well-completion, well-workover, or production 
operations.

[[Page 267]]

    (a) Equipment movement. The movement of well-drilling, well-
completion, or well-workover rigs and related equipment on and off an 
offshore platform, or from one well to another well on the same offshore 
platform, including rigging up and rigging down, shall be conducted in a 
safe manner.
    (b) Hydrogen sulfide (H2S). When a drilling, well-completion, well-
workover, or production operation is being conducted on a well in zones 
known to contain H2S or in zones where the presence of 
H2S is unknown (as defined in Sec.  250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property, especially during operations such as dismantling wellhead 
equipment and flow lines and circulating the well. The lessee shall also 
take appropriate precautions when H2S is generated as a 
result of sulphur production operations. The lessee shall comply with 
the requirements in Sec.  250.490 of this part as well as the 
requirements of this subpart.
    (c) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities involved in drilling, well-
completion, well-workover or production operations shall be conducted 
with properly maintained equipment, trained personnel, and appropriate 
procedures in order to minimize the danger to life and property 
according to the specific requirements in Sec. Sec.  250.109 through 
250.113 of this part.
    (d) Electrical requirements. All electrical equipment and systems 
involved in drilling, well-completion, well-workover, and production 
operations shall be designed, installed, equipped, protected, operated, 
and maintained so as to minimize the danger to life and property in 
accordance with the requirements of Sec.  250.114 of this part.
    (e) Structures on fixed OCS platforms. Derricks, cranes, masts, 
substructures, and related equipment shall be selected, designed, 
installed, used, and maintained so as to be adequate for the potential 
loads and conditions of loading that may be encountered during the 
operations. Prior to moving equipment such as a well-drilling, well-
completion, or well-workover rig or associated equipment or production 
equipment onto a platform, the lessee shall determine the structural 
capability of the platform to safely support the equipment and 
operations, taking into consideration corrosion protection, platform 
age, and previous stresses.
    (f) Traveling-block safety device. All drilling units being used for 
drilling, well-completion, or well-workover operations that have both a 
traveling block and a crown block must be equipped with a safety device 
that is designed to prevent the traveling block from striking the crown 
block. The device must be checked for proper operation weekly and after 
each drill-line slipping operation. The results of the operational check 
must be entered in the operations log.



Sec.  250.1605  Drilling requirements.

    (a) Sulphur leases. Lessees of OCS sulphur leases shall conduct 
drilling operations in accordance with Sec. Sec.  250.1605 through 
250.1619 of this subpart and with other requirements of this part, as 
appropriate.
    (b) Fitness of drilling unit. (1) Drilling units shall be capable of 
withstanding the oceanographic and meteorological conditions for the 
proposed season and location of operations.
    (2) Prior to commencing operation, drilling units shall be made 
available for a complete inspection by the District Manager.
    (3) The lessee shall provide information and data on the fitness of 
the drilling unit to perform the proposed drilling operation. The 
information shall be submitted with, or prior to, the submission of Form 
BSEE-0123, Application for Permit to Drill (APD), in accordance with 
Sec.  250.1617 of this subpart. After a drilling unit has been approved 
by a BSEE district office, the information required in this paragraph 
need not be resubmitted unless required by the District Manager or there 
are changes in the equipment that affect the rated capacity of the unit.
    (c) Oceanographic, meteorological, and drilling unit performance 
data. Where oceanographic, meteorological, and drilling unit performance 
data are not otherwise readily available, lessees shall collect and 
report such data upon request to the District Manager. The type of 
information to be collected and

[[Page 268]]

reported will be determined by the District Manager in the interests of 
safety in the conduct of operations and the structural integrity of the 
drilling unit.
    (d) Foundation requirements. When the lessee fails to provide 
sufficient information pursuant to 30 CFR 550.211 through 550.228 and 30 
CFR 550.241 through 550.262 to support a determination that the seafloor 
is capable of supporting a specific bottom-founded drilling unit under 
the site-specific soil and oceanographic conditions, the District 
Manager may require that additional surveys and soil borings be 
performed and the results submitted for review and evaluation by the 
District Manager before approval is granted for commencing drilling 
operations.
    (e) Tests, surveys, and samples. (1) Lessees shall drill and take 
cores and/or run well and mud logs through the objective interval to 
determine the presence, quality, and quantity of sulphur and other 
minerals (e.g., oil and gas) in the cap rock and the outline of the 
commercial sulphur deposit.
    (2) Inclinational surveys shall be obtained on all vertical wells at 
intervals not exceeding 1,000 feet during the normal course of drilling. 
Directional surveys giving both inclination and azimuth shall be 
obtained on all directionally drilled wells at intervals not exceeding 
500 feet during the normal course of drilling and at intervals not 
exceeding 200 feet in all planned angle-change portions of the borehole.
    (3) Directional surveys giving both inclination and azimuth shall be 
obtained on both vertically and directionally drilled wells at intervals 
not exceeding 500 feet prior to or upon setting a string of casing, or 
production liner, and at total depth. Composite directional surveys 
shall be prepared with the interval shown from the bottom of the 
conductor casing. In calculating all surveys, a correction from the true 
north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north 
shall be made after making the magnetic-to-true-north correction. A 
composite dipmeter directional survey or a composite measurement while-
drilling directional survey will be acceptable as fulfilling the 
applicable requirements of this paragraph.
    (4) Wells are classified as vertical if the calculated average of 
inclination readings weighted by the respective interval lengths between 
readings from surface to drilled depth does not exceed 3 degrees from 
the vertical. When the calculated average inclination readings weighted 
by the length of the respective interval between readings from the 
surface to drilled depth exceeds 3 degrees, the well is classified as 
directional.
    (5) At the request of a holder of an adjoining lease, the Regional 
Supervisor may, for the protection of correlative rights, furnish a copy 
of the directional survey to that leaseholder.
    (f) Fixed drilling platforms. Applications for installation of fixed 
drilling platforms or structures including artificial islands shall be 
submitted in accordance with the provisions of subpart I, Platforms and 
Structures, of this part. Mobile drilling units that have their jacking 
equipment removed or have been otherwise immobilized are classified as 
fixed bottom founded drilling platforms.
    (g) Crane operations. You must operate a crane installed on fixed 
platforms according to Sec.  250.108 of this subpart.
    (h) Diesel-engine air intakes. Diesel-engine air intakes must be 
equipped with a device to shut down the diesel engine in the event of 
runaway. Diesel engines that are continuously attended must be equipped 
with either remote-operated manual or automatic-shutdown devices. Diesel 
engines that are not continuously attended must be equipped with 
automatic shutdown devices.



Sec.  250.1606  Control of wells.

    The lessee shall take necessary precautions to keep its wells under 
control at all times. Operations shall be conducted in a safe and 
workmanlike manner. The lessee shall utilize the best available and 
safest drilling technologies and state-of-the-art methods to evaluate 
and minimize the potential for a well to flow or kick. The lessee shall 
utilize personnel who are trained and competent and shall utilize and 
maintain equipment and materials necessary to assure the safety and 
protection of personnel, equipment, natural resources, and the 
environment.

[[Page 269]]



Sec.  250.1607  Field rules.

    When geological and engineering information in a field enables a 
District Manager to determine specific operating requirements, field 
rules may be established for drilling, well completion, or well workover 
on the District Manager's initiative or in response to a request from a 
lessee; such rules may modify the specific requirements of this subpart. 
After field rules have been established, operations in the field shall 
be conducted in accordance with such rules and other requirements of 
this subpart. Field rules may be amended or canceled for cause at any 
time upon the initiative of the District Manager or upon the request of 
a lessee.



Sec.  250.1608  Well casing and cementing.

    (a) General requirements. (1) For the purpose of this subpart, the 
several casing strings in order of normal installation are:
    (i) Drive or structural,
    (ii) Conductor,
    (iii) Cap rock casing,
    (iv) Bobtail cap rock casing (required when the cap rock casing does 
not penetrate into the cap rock),
    (v) Second cap rock casing (brine wells), and
    (vi) Production liner.
    (2) The lessee shall case and cement all wells with a sufficient 
number of strings of casing cemented in a manner necessary to prevent 
release of fluids from any stratum through the wellbore (directly or 
indirectly) into the sea, protect freshwater aquifers from 
contamination, support unconsolidated sediments, and otherwise provide a 
means of control of the formation pressures and fluids. Cement 
composition, placement techniques, and waiting time shall be designed 
and conducted so that the cement in place behind the bottom 500 feet of 
casing or total length of annular cement fill, if less, attains a 
minimum compressive strength of 160 pounds per square inch (psi).
    (3) The lessee shall install casing designed to withstand the 
anticipated stresses imposed by tensile, compressive, and buckling 
loads; burst and collapse pressures; thermal effects; and combinations 
thereof. Safety factors in the drilling and casing program designs shall 
be of sufficient magnitude to provide well control during drilling and 
to assure safe operations for the life of the well.
    (4) In cases where cement has filled the annular space back to the 
mud line, the cement may be washed out or displaced to a depth not 
exceeding the depth of the structural casing shoe to facilitate casing 
removal upon well abandonment if the District Manager determines that 
subsurface protection against damage to freshwater aquifers and against 
damage caused by adverse loads, pressures, and fluid flows is not 
jeopardized.
    (5) If there are indications of inadequate cementing (such as lost 
returns, cement channeling, or mechanical failure of equipment), the 
lessee shall evaluate the adequacy of the cementing operations by 
pressure testing the casing shoe. If the test indicates inadequate 
cementing, the lessee shall initiate remedial action as approved by the 
District Manager. For cap rock casing, the test for adequacy of 
cementing shall be the pressure testing of the annulus between the cap 
rock and the conductor casings. The pressure shall not exceed 70 percent 
of the burst pressure of the conductor casing or 70 percent of the 
collapse pressure of the cap rock casing.
    (b) Drive or structural casing. This casing shall be set by driving, 
jetting, or drilling to a minimum depth of 100 feet below the mud line 
or such other depth, as may be required or approved by the District 
Manager, in order to support unconsolidated deposits and to provide hole 
stability for initial drilling operations. If this portion of the hole 
is drilled, a quantity of cement sufficient to fill the annular space 
back to the mud line shall be used.
    (c) Conductor and cap rock casing setting and cementing 
requirements. (1) Conductor and cap rock casing design and setting 
depths shall be based upon relevant engineering and geologic factors 
including the presence or absence of hydrocarbons, potential hazards, 
and water depths. The proposed casing setting depths may be varied, 
subject to District Manager approval, to permit

[[Page 270]]

the casing to be set in a competent formation or through formations 
determined desirable to be isolated from the wellbore by casing for 
safer drilling operations. However, the conductor casing shall be set 
immediately prior to drilling into formations known to contain oil or 
gas or, if unknown, upon encountering such formations. Cap rock casing 
shall be set and cemented through formations known to contain oil or gas 
or, if unknown, upon encountering such formations. Upon encountering 
unexpected formation pressures, the lessee shall submit a revised casing 
program to the District Manager for approval.
    (2) Conductor casing shall be cemented with a quantity of cement 
that fills the calculated annular space back to the mud line. Cement 
fill shall be verified by the observation of cement returns. In the 
event that observation of cement returns is not feasible, additional 
quantities of cement shall be used to assure fill to the mud line.
    (3) Cap rock casing shall be cemented with a quantity of cement that 
fills the calculated annular space to at least 200 feet inside the 
conductor casing. When geologic conditions such as near surface 
fractures and faulting exist, cap rock casing shall be cemented with a 
quantity of cement that fills the calculated annular space to the mud 
line, unless otherwise approved by the District Manager. In brine wells, 
the second cap rock casing shall be cemented with a quantity of cement 
that fills the calculated annular space to at least 200 feet above the 
setting depth of the first cap rock casing.
    (d) Bobtail cap rock casing setting and cementing requirements. (1) 
Bobtail cap rock casing shall be set on or just in cap rock and lapped a 
minimum of 100 feet into the previous casing string.
    (2) Sufficient cement shall be used to fill the annular space to the 
top of the bobtail cap rock casing.
    (e) Production liner setting and cementing requirements. (1) 
Production liners for sulphur wells and bleedwells shall be set in cap 
rock at or above the bottom of the open hole (hole that is open in cap 
rock, below the bottom of the cap rock casing) and lapped into the 
previous casing string or to the surface. For brine wells, the liner 
shall be set in salt and lapped into the previous casing string or to 
the surface.
    (2) The production liner is not required to be cemented unless the 
cap rock contains oil or gas. If the cap rock contains oil or gas, 
sufficient cement shall be used to fill the annular space to the top of 
the production liner.



Sec.  250.1609  Pressure testing of casing.

    (a) Prior to drilling the plug after cementing, all casing strings, 
except the drive or structural casing, shall be pressure tested. The 
conductor casing shall be tested to at least 200 psi. All casing strings 
below the conductor casing shall be tested to 500 psi or 0.22 psi/ft, 
whichever is greater. (When oil or gas is not present in the cap rock, 
the production liner need not be cemented in place; thus, it would not 
be subject to pressure testing.) If the pressure declines more than 10 
percent in 30 minutes or if there is another indication of a leak, the 
casing shall be recemented, repaired, or an additional casing string run 
and the casing tested again. The above procedures shall be repeated 
until a satisfactory test is obtained. The time, conditions of testing, 
and results of all casing pressure tests shall be recorded in the 
driller's report.
    (b) After cementing any string of casing other than structural, 
drilling shall not be resumed until there has been a time lapse of at 
least 8 hours under pressure for the conductor casing string or 12 hours 
under pressure for all other casing strings. Cement is considered under 
pressure if one or more float valves are shown to be holding the cement 
in place or when other means of holding pressure are used.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]



Sec.  250.1610  Blowout preventer systems and system components.

    (a) General. The blowout preventer (BOP) systems and system 
components shall be designed, installed, used, maintained, and tested to 
assure well control.
    (b) BOP stacks. The BOP stacks shall consist of an annular preventer 
and the number of ram-type preventers as specified under paragraphs (e) 
and (f) of this section. The pipe rams shall be of proper size to fit 
the drill pipe in use.

[[Page 271]]

    (c) Working pressure. The working-pressure rating of any BOP shall 
exceed the surface pressure to which it may be anticipated to be 
subjected.
    (d) BOP equipment. All BOP systems shall be equipped and provided 
with the following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure, without assistance from a charging system. Accumulator 
regulators supplied by rig air that do not have a secondary source of 
pneumatic supply must be equipped with manual overrides or other devices 
alternately provided to ensure capability of hydraulic operations if rig 
air is lost.
    (2) An automatic backup to the accumulator system. The backup system 
shall be supplied by a power source independent from the power source to 
the primary accumulator system. The automatic backup system shall 
possess sufficient capability to close the BOP and hold it closed.
    (3) At least one operable remote BOP control station in addition to 
the one on the drilling floor. This control station shall be in a 
readily accessible location away from the drilling floor.
    (4) A drilling spool with side outlets, if side outlets are not 
provided in the body of the BOP stack, to provide for separate kill and 
choke lines.
    (5) A choke line and a kill line each equipped with two full-opening 
valves. At least one of the valves on the choke line and one valve on 
the kill line shall be remotely controlled, except that a check valve 
may be installed on the kill line in lieu of the remotely controlled 
valve, provided that two readily accessible manual valves are in place 
and the check valve is placed between the manual valve and the pump.
    (6) A fill-up line above the uppermost preventer.
    (7) A choke manifold designed with consideration of anticipated 
pressures to which it may be subjected, method of well control to be 
employed, surrounding environment, and corrosiveness, volume, and 
abrasiveness of fluids. The choke manifold shall also meet the following 
requirements:
    (i) Manifold and choke equipment subject to well and/or pump 
pressure shall have a rated working pressure at least as great as the 
rated working pressure of the ram-type BOP's or as otherwise approved by 
the District Manager;
    (ii) All components of the choke manifold system shall be protected 
from freezing by heating, draining, or filling with proper fluids; and
    (iii) When buffer tanks are installed downstream of the choke 
assemblies for the purpose of manifolding the bleed lines together, 
isolation valves shall be installed on each line.
    (8) Valves, pipes, flexible steel hoses, and other fittings upstream 
of, and including, the choke manifold with a pressure rating at least as 
great as the rated working pressure of the ram-type BOP's unless 
otherwise approved by the District Manager.
    (9) A wellhead assembly with a rated working pressure that exceeds 
the pressure to which it might be subjected.
    (10) The following system components:
    (i) A kelly cock (an essentially full-opening valve) installed below 
the swivel and a similar valve of such design that it can be run through 
the BOP stack installed at the bottom of the kelly. A wrench to fit each 
valve shall be stored in a location readily accessible to the drilling 
crew;
    (ii) An inside BOP and an essentially full-opening, drill-string 
safety valve in the open position on the rig floor at all times while 
drilling operations are being conducted. These valves shall be 
maintained on the rig floor to fit all connections that are in the drill 
string. A wrench to fit the drill-string safety valve shall be stored in 
a location readily accessible to the drilling crew;
    (iii) A safety valve available on the rig floor assembled with the 
proper connection to fit the casing string being run in the hole; and
    (iv) Locking devices installed on the ram-type preventers.
    (e) BOP requirements. Prior to drilling below cap rock casing, a BOP 
system shall be installed consisting of at least three remote-
controlled, hydraulically operated BOP's including at least one equipped 
with pipe rams, one with blind rams, and one annular type.

[[Page 272]]

    (f) Tapered drill-string operations. Prior to commencing tapered 
drill-string operations, the BOP stack shall be equipped with 
conventional and/or variable-bore pipe rams to provide either of the 
following:
    (1) One set of variable bore rams capable of sealing around both 
sizes in the string and one set of blind rams, or
    (2) One set of pipe rams capable of sealing around the larger size 
string, provided that blind-shear ram capability is present, and 
crossover subs to the larger size pipe are readily available on the rig 
floor.



Sec.  250.1611  Blowout preventer systems tests, actuations, 
inspections, and maintenance.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The date, time, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure testing shall be performed at intervals to allow each drilling 
crew to operate the equipment. The weekly pressure test is not required 
for blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly. In this situation, 
the pressure tests may be limited to the affected component.
    (e) All BOP systems shall be inspected and maintained to assure that 
the equipment will function properly. The BOP systems shall be visually 
inspected at least once each day. The manufacturer's recommended 
inspection and maintenance procedures are acceptable as guidelines in 
complying with this requirement.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the driller's report. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the driller's report may reference 
a BOP

[[Page 273]]

test plan that contains the required information and is retained on file 
at the facility.
    (2) The control station used during the test shall be identified in 
the driller's report.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the driller's report.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections, shall be available for BSEE 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



Sec.  250.1612  Well-control drills.

    Well-control drills must be conducted for each drilling crew in 
accordance with the requirements set forth in Sec.  250.711 or as 
approved by the District Manager.

[81 FR 26037, Apr. 29, 2016]



Sec.  250.1613  Diverter systems.

    (a) When drilling a conductor or cap rock hole, all drilling units 
shall be equipped with a diverter system consisting of a diverter 
sealing element, diverter lines, and control systems. The diverter 
system shall be designed, installed, and maintained so as to divert 
gases, water, mud, and other materials away from the facilities and 
personnel.
    (b) The diverter system shall be equipped with remote-control valves 
in the flow lines that can be operated from at least one remote-control 
station in addition to the one on the drilling floor. Any valve used in 
a diverter system shall be full opening. No manual or butterfly valves 
shall be installed in any part of a diverter system. There shall be a 
minimum number of turns in the vent line(s) downstream of the spool 
outlet flange, and the radius of curvature of turns shall be as large as 
practicable. Flexible hose may be used for diversion lines instead of 
rigid pipe if the flexible hose has integral end couplings. The entire 
diverter system shall be firmly anchored and supported to prevent 
whipping and vibrations. All diverter control equipment and lines shall 
be protected from physical damage from thrown and falling objects.
    (c) For drilling operations conducted with a surface wellhead 
configuration, the following shall apply:
    (1) If the diverter system utilizes only one spool outlet, branch 
lines shall be installed to provide downwind diversion capability, and
    (2) No spool outlet or diverter line internal diameter shall be less 
than 10 inches, except that dual spool outlets are acceptable if each 
outlet has a minimum internal diameter of 8 inches, and both outlets are 
piped to overboard lines and that each line downstream of the changeover 
nipple at the spool has a minimum internal diameter of 10 inches.
    (d) The diverter sealing element and diverter valves shall be 
pressure tested to a minimum of 200 psi when nippled upon conductor 
casing. No more than 7 days shall elapse between subsequent pressure 
tests. The diverter sealing element, diverter valves, and diverter 
control systems (including the remote) shall be actuation tested, and 
the diverter lines shall be tested for flow prior to spudding and 
thereafter at least once each 24-hour period alternating between control 
stations. All test times and results shall be recorded in the driller's 
report.



Sec.  250.1614  Mud program.

    (a) The quantities, characteristics, use, and testing of drilling 
mud and the related drilling procedures shall be designed and 
implemented to prevent the loss of well control.
    (b) The lessee shall comply with requirements concerning mud 
control, mud test and monitoring equipment, mud quantities, and safety 
precautions in enclosed mud handling areas as prescribed in Sec. Sec.  
250.455 through 250.459 of this part, except that the installation

[[Page 274]]

of an operable degasser in the mud system as required in Sec.  
250.456(g) is not required for sulphur operations.



Sec.  250.1615  Securing of wells.

    A downhole-safety device such as a cement plug, bridge plug, or 
packer shall be timely installed when drilling operations are 
interrupted by events such as those that force evacuation of the 
drilling crew, prevent station keeping, or require repairs to major 
drilling units or well-control equipment. The use of blind-shear rams or 
pipe rams and an inside BOP may be approved by the District Manager in 
lieu of the above requirements if cap rock casing has been set.



Sec.  250.1616  Supervision, surveillance, and training.

    (a) The lessee shall provide onsite supervision of drilling 
operations at all times.
    (b) From the time drilling operations are initiated and until the 
well is completed or abandoned, a member of the drilling crew or the 
toolpusher shall maintain rig-floor surveillance continuously, unless 
the well is secured with BOP's, bridge plugs, packers, or cement plugs.
    (c) Lessee and drilling contractor personnel shall be trained and 
qualified in accordance with the provisions of subpart O of this part. 
Records of specific training that lessee and drilling contractor 
personnel have successfully completed, the dates of completion, and the 
names and dates of the courses shall be maintained at the drill site.



Sec.  250.1617  Application for permit to drill.

    (a) Before drilling a well under a BOEM-approved Exploration Plan, 
Development and Production Plan, or Development Operations Coordination 
Document, you must file Form BSEE-0123, APD, with the District Manager 
for approval. The submission of your APD must be accompanied by payment 
of the service fee listed in Sec.  250.125. Before starting operations, 
you must receive written approval from the District Manager unless you 
received oral approval under Sec.  250.140.
    (b) An APD shall include rated capacities of the proposed drilling 
unit and of major drilling equipment. After a drilling unit has been 
approved for use in a BSEE district, the information need not be 
resubmitted unless required by the District Manager or there are changes 
in the equipment that affect the rated capacity of the unit.
    (c) An APD shall include a fully completed Form BSEE-0123 and the 
following:
    (1) A plat, drawn to a scale of 2,000 feet to the inch, showing the 
surface and subsurface location of the well to be drilled and of all the 
wells previously drilled in the vicinity from which information is 
available. For development wells on a lease, the wells previously 
drilled in the vicinity need not be shown on the plat. Locations shall 
be indicated in feet from the nearest block line;
    (2) The design criteria considered for the well and for well 
control, including the following:
    (i) Pore pressure;
    (ii) Formation fracture gradients;
    (iii) Potential lost circulation zones;
    (iv) Mud weights;
    (v) Casing setting depths;
    (vi) Anticipated surface pressures (which for purposes of this 
section are defined as the pressure that can reasonably be expected to 
be exerted upon a casing string and its related wellhead equipment). In 
the calculation of anticipated surface pressure, the lessee shall take 
into account the drilling, completion, and producing conditions. The 
lessee shall consider mud densities to be used below various casing 
strings, fracture gradients of the exposed formations, casing setting 
depths, and cementing intervals, total well depth, formation fluid type, 
and other pertinent conditions. Considerations for calculating 
anticipated surface pressure may vary for each segment of the well. The 
lessee shall include as a part of the statement of anticipated surface 
pressure the calculations used to determine this pressure during the 
drilling phase and the completion phase, including the anticipated 
surface pressure used for production string design; and
    (vii) If a shallow hazards site survey is conducted, the lessee 
shall submit with or prior to the submittal of the APD, two copies of a 
summary report

[[Page 275]]

describing the geological and manmade conditions present. The lessee 
shall also submit two copies of the site maps and data records 
identified in the survey strategy.
    (3) A BOP equipment program including the following:
    (i) The pressure rating of BOP equipment,
    (ii) A schematic drawing of the diverter system to be used (plan and 
elevation views) showing spool outlet internal diameter(s); diverter 
line lengths and diameters, burst strengths, and radius of curvature at 
each turn; valve type, size, working-pressure rating, and location; the 
control instrumentation logic; and the operating procedure to be used by 
personnel, and
    (iii) A schematic drawing of the BOP stack showing the inside 
diameter of the BOP stack and the number of annular, pipe ram, variable-
bore pipe ram, blind ram, and blind-shear ram preventers.
    (4) A casing program including the following:
    (i) Casing size, weight, grade, type of connection and setting 
depth, and
    (ii) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values.
    (5) The drilling prognosis including the following:
    (i) Estimated coring intervals,
    (ii) Estimated depths to the top of significant marker formations, 
and
    (iii) Estimated depths at which encounters with fresh water, 
sulphur, oil, gas, or abnormally pressured water are expected.
    (6) A cementing program including type and amount of cement in cubic 
feet to be used for each casing string;
    (7) A mud program including the minimum quantities of mud and mud 
materials, including weight materials, to be kept at the site;
    (8) A directional survey program for directionally drilled wells;
    (9) An H2S Contingency Plan, if applicable, and if not 
previously submitted; and
    (10) Such other information as may be required by the District 
Manager.
    (d) Public information copies of the APD shall be submitted in 
accordance with Sec.  250.186 of this part.



Sec.  250.1618  Application for permit to modify.

    (a) You must submit requests for changes in plans, changes in major 
drilling equipment, proposals to deepen, sidetrack, complete, workover, 
or plug back a well, or engage in similar activities to the District 
Manager on Form BSEE-0124, Application for Permit to Modify (APM). The 
submission of your APM must be accompanied by payment of the service fee 
listed in Sec.  250.125. Before starting operations associated with the 
change, you must receive written approval from the District Manager 
unless you received oral approval under Sec.  250.140.
    (b) The Form BSEE-0124 submittal shall contain a detailed statement 
of the proposed work that will materially change from the work described 
in the approved APD. Information submitted shall include the present 
state of the well, including the production liner and last string of 
casing, the well depth and production zone, and the well's capability to 
produce. Within 30 days after completion of the work, a subsequent 
detailed report of all the work done and the results obtained shall be 
submitted.
    (c) Public information copies of Form BSEE-0124 shall be submitted 
in accordance with Sec.  250.186 of this part.



Sec.  250.1619  Well records.

    (a) Complete and accurate records for each well and all well 
operations shall be retained for a period of 2 years at the lessee's 
field office nearest the OCS facility or at another location 
conveniently available to the District Manager. The records shall 
contain a description of any significant malfunction or problem; all the 
formations penetrated; the content and character of sulphur in each 
formation if cored and analyzed; the kind, weight, size, grade, and 
setting depth of casing; all well logs and surveys run in the wellbore; 
and all other information required by the District Manager in the 
interests of resource evaluation, prevention of waste, conservation of 
natural resources, protection of correlative rights, safety of 
operations, and environmental protection.
    (b) When drilling operations are suspended or temporarily prohibited 
under

[[Page 276]]

the provisions of Sec.  250.170 of this part, the lessee shall, within 
30 days after termination of the suspension or temporary prohibition or 
within 30 days after the completion of any activities related to the 
suspension or prohibition, transmit to the District Manager duplicate 
copies of the records of all activities related to and conducted during 
the suspension or temporary prohibition on, or attached to, Form BSEE-
0125, End of Operations Report, or Form BSEE-0124, Application for 
Permit to Modify, as appropriate.
    (c) Upon request by the District Manager or Regional Supervisor, the 
lessee shall furnish the following:
    (1) Copies of the records of any of the well operations specified in 
paragraph (a) of this section;
    (2) Copies of the driller's report at a frequency as determined by 
the District Manager. Items to be reported include spud dates, casing 
setting depths, cement quantities, casing characteristics, mud weights, 
lost returns, and any unusual activities; and
    (3) Legible, exact copies of reports on cementing, acidizing, 
analyses of cores, testing, or other similar services.
    (d) As soon as available, the lessee shall transmit copies of logs 
and charts developed by well-logging operations, directional-well 
surveys, and core analyses. Composite logs of multiple runs and 
directional-well surveys shall be transmitted to the District Manager in 
duplicate as soon as available but not later than 30 days after 
completion of such operations for each well.
    (e) If the District Manager determines that circumstances warrant, 
the lessee shall submit any other reports and records of operations in 
the manner and form prescribed by the District Manager.



Sec.  250.1620  Well-completion and well-workover requirements.

    (a) Lessees shall conduct well-completion and well-workover 
operations in sulphur wells, bleedwells, and brine wells in accordance 
with Sec. Sec.  250.1620 through 250.1626 of this part and other 
provisions of this part as appropriate (see Sec. Sec.  250.501 and 
250.601 of this part for the definition of well-completion and well-
workover operations).
    (b) Well-completion and well-workover operations shall be conducted 
in a manner to protect against harm or damage to life (including fish 
and other aquatic life), property, natural resources of the OCS 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment.



Sec.  250.1621  Crew instructions.

    Prior to engaging in well-completion or well-workover operations, 
crew members shall be instructed in the safety requirements of the 
operations to be performed, possible hazards to be encountered, and 
general safety considerations to protect personnel, equipment, and the 
environment. Date and time of safety meetings shall be recorded and 
available for BSEE review.



Sec.  250.1622  Approvals and reporting of well-completion and
 well-workover operations.

    (a) No well-completion or well-workover operation shall begin until 
the lessee receives written approval from the District Manager. Approval 
for such operations shall be requested on Form BSEE-0124. Approvals by 
the District Manager shall be based upon a determination that the 
operations will be conducted in a manner to protect against harm or 
damage to life, property, natural resources of the OCS, including any 
mineral deposits, the National security or defense, or the marine, 
coastal, or human environment.
    (b) The following information shall be submitted with Form BSEE-0124 
(or with Form BSEE-0123):
    (1) A brief description of the well-completion or well-workover 
procedures to be followed;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing showing the well equipment; and
    (3) Where the well is in zones known to contain H2S or 
zones where the presence of H2S is unknown, a description of 
the safety precautions to be implemented.
    (c)(1) Within 30 days after completion, Form BSEE-0125, including a 
schematic of the tubing and the results

[[Page 277]]

of any well tests, shall be submitted to the District Manager.
    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form BSEE-0124 shall be submitted to the 
District Manager and shall include the results of any well tests and a 
new schematic of the well if any subsurface equipment has been changed.



Sec.  250.1623  Well-control fluids, equipment, and operations.

    (a) Well-control fluids, equipment, and operations shall be 
designed, utilized, maintained, and/or tested as necessary to control 
the well in foreseeable conditions and circumstances, including 
subfreezing conditions. The well shall be continuously monitored during 
well-completion and well-workover operations and shall not be left 
unattended at any time unless the well is shut in and secured;
    (b) The following well-control fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP,
    (2) A well-control fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips, and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.
    (c) When coming out of the hole with drill pipe or a workover 
string, the annulus shall be filled with well-control fluid before the 
change in fluid level decreases the hydrostatic pressure 75 psi or every 
five stands of drill pipe or workover string, whichever gives a lower 
decrease in hydrostatic pressure. The number of stands of drill pipe or 
workover string and drill collars that may be pulled prior to filling 
the hole and the equivalent well-control fluid volume shall be 
calculated and posted near the operator's station. A mechanical, 
volumetric, or electronic device for measuring the amount of well-
control fluid required to fill the hole shall be utilized.



Sec.  250.1624  Blowout prevention equipment.

    (a) The BOP system and system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure of 
the BOP system and system components shall equal or exceed the expected 
surface pressure to which they may be subjected.
    (b) The minimum BOP stack for well-completion operations or for 
well-workover operations with the tree removed shall consist of the 
following:
    (1) Three remote-controlled, hydraulically operated preventers 
including at least one equipped with pipe rams, one with blind rams, and 
one annular type.
    (2) When a tapered string is used, the minimum BOP stack shall 
consist of either of the following:
    (i) An annular preventer, one set of variable bore rams capable of 
sealing around both sizes in the string, and one set of blind rams; or
    (ii) An annular preventer, one set of pipe rams capable of sealing 
around the larger size string, a preventer equipped with blind-shear 
rams, and a crossover sub to the larger size pipe that shall be readily 
available on the rig floor.
    (c) The BOP systems for well-completion operations, or for well-
workover operations with the tree removed, shall be equipped with the 
following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure without assistance from a charging system. After February 14, 
1992, accumulator regulators supplied by rig air which do not have a 
secondary source of pneumatic supply shall be equipped with manual 
overrides or alternately other devices provided to ensure capability of 
hydraulic operations if rig air is lost;
    (2) An automatic backup to the accumulator system supplied by a 
power source independent from the power source to the primary 
accumulator system and possessing sufficient capacity

[[Page 278]]

to close all BOP's and hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full-opening 
valves and a choke manifold. One of the choke-line valves and one of the 
kill-line valves shall be remotely controlled except that a check valve 
may be installed on the kill line in lieu of the remotely-controlled 
valve provided that two readily accessible manual valves are in place, 
and the check valve is placed between the manual valve and the pump.
    (d) The minimum BOP-stack components for well-workover operations 
with the tree in place and performed through the wellhead inside of the 
sulphur line using small diameter jointed pipe (usually \3/4\ inch to 
1\1/4\ inch) as a work string; i.e., small-tubing operations, shall 
consist of the following:
    (1) For air line changes, the well shall be killed prior to 
beginning operations. The procedures for killing the well shall be 
included in the description of well-workover procedures in accordance 
with Sec.  250.1622 of this part. Under these circumstances, no BOP 
equipment is required.
    (2) For other work inside of the sulphur line, a tubing stripper or 
annular preventer shall be installed prior to beginning work.
    (e) An essentially full-opening, work-string safety valve shall be 
maintained on the rig floor at all times during well-completion 
operations. A wrench to fit the work-string safety valve shall be 
readily available. Proper connections shall be readily available for 
inserting a safety valve in the work string.



Sec.  250.1625  Blowout preventer system testing, records, and drills.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to a rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations, and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The time, date, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure testing shall be performed at intervals to allow each drilling 
crew to operate the equipment. The weekly pressure test is not required 
for blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly, the pressure tests 
may be limited to the affected component.
    (e) All personnel engaged in well-completion operations shall 
participate

[[Page 279]]

in a weekly BOP drill to familiarize crew members with appropriate 
safety measures.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the operations log. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections shall be available for BSEE 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



Sec.  250.1626  Tubing and wellhead equipment.

    (a) No tubing string shall be placed into service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) Wellhead, tree, and related equipment shall be designed, 
installed, tested, used, and maintained so as to achieve and maintain 
pressure control.



Sec.  250.1627  Production requirements.

    (a) The lessee shall conduct sulphur production operations in 
compliance with the approved Development and Production Plan 
requirements of Sec. Sec.  250.1627 through 250.1634 of this subpart and 
requirements of this part, as appropriate.
    (b) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety of operations 
and protection of the human, marine, and coastal environments.



Sec.  250.1628  Design, installation, and operation of production systems.

    (a) General. All production facilities shall be designed, installed, 
and maintained in a manner that provides for efficiency and safety of 
operations and protection of the environment.
    (b) Approval of design and installation features for sulphur 
production facilities. Prior to installation, the lessee shall submit a 
sulphur production system application, in duplicate, to the District 
Manager for approval. The application shall include information relative 
to the proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility or 
at another location conveniently available to the District Manager. All 
approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other sulphur-handling vessels;
    (2) A schematic piping diagram showing the size and maximum 
allowable

[[Page 280]]

working pressures as determined in accordance with API RP 14E, 
Recommended Practice for Design and Installation of Offshore Production 
Platform Piping Systems (as incorporated by reference in Sec.  250.198);
    (3) Electrical system information including a plan of each platform 
deck, outlining all hazardous areas classified according to API RP 500, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Division 1 
and Division 2, or API RP 505, Recommended Practice for Classification 
of Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2 (as incorporated by 
reference in Sec.  250.198), and outlining areas in which potential 
ignition sources are to be installed;
    (4) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart.
    (c) Hydrocarbon handling vessels associated with fuel gas system. 
You must protect hydrocarbon handling vessels associated with the fuel 
gas system with a basic and ancillary surface safety system. This system 
must be designed, analyzed, installed, tested, and maintained in 
operating condition in accordance with API RP 14C, Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms (as incorporated by reference in Sec.  250.198). If 
processing components are to be utilized, other than those for which 
Safety Analysis Checklists are included in API RP 14C, you must use the 
analysis technique and documentation specified therein to determine the 
effect and requirements of these components upon the safety system.
    (d) Approval of safety-systems design and installation features for 
fuel gas system. Prior to installation, the lessee shall submit a fuel 
gas safety system application, in duplicate, to the District Manager for 
approval. The application shall include information relative to the 
proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility or 
at another location conveniently available to the District Manager. All 
approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other hydrocarbon-handling vessels;
    (2) A schematic flow diagram (API RP 14C, Figure E1, as incorporated 
by reference in Sec.  250.198) and the related Safety Analysis Function 
Evaluation chart (API RP 14C, subsection 4.3c, as incorporated by 
reference in Sec.  250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Design and Installation of Offshore Production Platform Piping Systems 
(as incorporated by reference in Sec.  250.198);
    (4) Electrical system information including the following:
    (i) A plan of each platform deck, outlining all hazardous areas 
classified according to API RP 500, Recommended Practice for 
Classification of Locations for Electrical Installations at Petroleum 
Facilities Classified as Class I, Division 1 and Division 2, or API RP 
505, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Zone 0, 
Zone 1, and Zone 2 (as incorporated by reference in Sec.  250.198), and 
outlining areas in which potential ignition sources are to be installed;
    (ii) All significant hydrocarbon sources and a description of the 
type of decking, ceiling, walls (e.g., grating or solid), and firewalls; 
and
    (iii) Elementary electrical schematic of any platform safety 
shutdown system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed was approved by registered professional 
engineers. After these systems are installed, the lessee

[[Page 281]]

shall submit a statement to the District Manager certifying that the new 
installations conform to the approved designs of this subpart; and
    (6) Design and schematics of the installation and maintenance of all 
fire- and gas-detection systems including the following:
    (i) Type, location, and number of detection heads;
    (ii) Type and kind of alarm, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.



Sec.  250.1629  Additional production and fuel gas system requirements.

    (a) General. Lessees shall comply with the following production 
safety system requirements (some of which are in addition to those 
contained in Sec.  250.1628 of this part).
    (b) Design, installation, and operation of additional production 
systems, including fuel gas handling safety systems. (1) Pressure and 
fired vessels must be designed, fabricated, and code stamped in 
accordance with the applicable provisions of sections I, IV, and VIII of 
the American Society of Mechanical Engineers (ASME) Boiler and Pressure 
Vessel Code (as specified in Sec.  250.198). Pressure and fired vessels 
must have maintenance inspection, rating, repair, and alteration 
performed in accordance with the applicable provisions of API Pressure 
Vessel Inspections Code: In-Service Inspection, Rating, Repair, and 
Alteration, API 510 (except Sections 5.8 and 9.5) (as incorporated by 
reference in Sec.  250.198).
    (i) Pressure safety relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ANSI/ASME Boiler and Pressure Vessel Code (as specified 
in Sec.  250.198). The safety relief valves shall conform to the valve-
sizing and pressure-relieving requirements specified in these documents; 
however, the safety relief valves shall be set no higher than the 
maximum-allowable working pressure of the vessel. All safety relief 
valves and vents shall be piped in such a way as to prevent fluid from 
striking personnel or ignition sources.
    (ii) The lessee shall use pressure recorders to establish the 
operating pressure ranges of pressure vessels in order to establish the 
pressure-sensor settings. Pressure-recording charts used to determine 
operating pressure ranges shall be maintained by the lessee for a period 
of 2 years at the lessee's field office nearest the OCS facility or at 
another location conveniently available to the District Manager. The 
high-pressure sensor shall be set no higher than 15 percent or 5 psi, 
whichever is greater, above the highest operating pressure of the 
vessel. This setting shall also be set sufficiently below (15 percent or 
5 psi, whichever is greater) the safety relief valve's set pressure to 
assure that the high-pressure sensor sounds an alarm before the safety 
relief valve starts relieving. The low-pressure sensor shall sound an 
alarm no lower than 15 percent or 5 psi, whichever is greater, below the 
lowest pressure in the operating range.
    (2) Engine exhaust. You must equip engine exhausts to comply with 
the insulation and personnel protection requirements of API RP 14C, 
section 4.2c(4) (as incorporated by reference in Sec.  250.198). Exhaust 
piping from diesel engines must be equipped with spark arresters.
    (3) Firefighting systems. Firefighting systems must conform to 
subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice 
for Fire Prevention and Control on Open Type Offshore Production 
Platforms (as incorporated by reference in Sec.  250.198), and must be 
subject to the approval of the District Manager. Additional requirements 
must apply as follows:
    (i) A firewater system consisting of rigid pipe with firehose 
stations shall be installed. The firewater system shall be installed to 
provide needed protection, especially in areas where fuel handling 
equipment is located.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during platform shut-in time. If 
necessary, an alternate fuel or power supply shall be installed to 
provide for this pump-operating time unless an alternate firefighting

[[Page 282]]

system has been approved by the District Manager;
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control; and
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) 
sensors shall be installed in all enclosed classified areas. Gas sensors 
shall be installed in all inadequately ventilated, enclosed classified 
areas. Adequate ventilation is defined as ventilation that is sufficient 
to prevent accumulation of significant quantities of vapor-air mixture 
in concentrations over 25 percent of the lower explosive limit. One 
approved method of providing adequate ventilation is a change of air 
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per 
square foot of solid floor area, whichever is greater. Enclosed areas 
(e.g., buildings, living quarters, or doghouses) are defined as those 
areas confined on more than four of their six possible sides by walls, 
floors, or ceilings more restrictive to air flow than grating or fixed 
open louvers and of sufficient size to allow entry of personnel. A 
classified area is any area classified Class I, Group D, Division 1 or 
2, following the guidelines of API RP 500 (as incorporated by reference 
in Sec.  250.198), or any area classified Class I, Zone 0, Zone 1, or 
Zone 2, following the guidelines of API RP 505 (as incorporated by 
reference in Sec.  205.198).
    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset type.
    (iii) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility that are provided with fuel gas. Living quarters and doghouses 
not containing a gas source and not located in a classified area do not 
require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents as incorporated 
by reference in Sec.  250.198).
    (c) General platform operations. Safety devices shall not be 
bypassed or blocked out of service unless they are temporarily out of 
service for startup, maintenance, or testing procedures. Only the 
minimum number of safety devices shall be taken out of service. 
Personnel shall monitor the bypassed or blocked out functions until the 
safety devices are placed back in service. Any safety device that is 
temporarily out of service shall be flagged by the person taking such 
device out of service.



Sec.  250.1630  Safety-system testing and records.

    (a) Inspection and testing. You must inspect and successfully test 
safety system devices at the interval specified below or more frequently 
if operating conditions warrant. Testing must be in accordance with API 
RP 14C, Appendix D (as incorporated by reference in Sec.  250.198). For 
safety system devices other than those listed in API RP 14C, Appendix D, 
you must utilize the analysis technique and documentation specified 
therein for inspection and testing of these components, and the 
following:
    (1) Safety relief valves on the natural gas feed system for power 
plant operations such as pressure safety valves shall be inspected and 
tested for operation at least once every 12 months. These valves shall 
be either bench tested or equipped to permit testing with an external 
pressure source.
    (2) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be inspected and tested at least 
once each calendar month, but at no time may

[[Page 283]]

more than 6 weeks elapse between tests:
    (i) All pressure safety high or pressure safety low, and
    (ii) All level safety high and level safety low controls.
    (3) The following electronic pressure transmitters and level sensors 
must be inspected and tested at least once every 3 months, but at no 
time may more than 120 days elapse between tests:
    (i) All PSH or PSL, and
    (ii) All LSH and LSL controls.
    (4) All pumps for firewater systems shall be inspected and operated 
weekly.
    (5) All fire- (flame, heat, or smoke) and gas-detection systems 
shall be inspected and tested for operation and recalibrated every 3 
months provided that testing can be performed in a nondestructive 
manner.
    (6) Prior to the commencement of production, the lessee shall notify 
the District Manager when the lessee is ready to conduct a preproduction 
test and inspection of the safety system. The lessee shall also notify 
the District Manager upon commencement of production in order that a 
complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each safety device installed. These records shall be 
maintained by the lessee at the lessee's field office nearest the OCS 
facility or another location conveniently available to the District 
Manager. These records shall be available for BSEE review. The records 
shall show the present status and history of each safety device, 
including dates and details of installation, removal, inspection, 
testing, repairing, adjustments, and reinstallation.



Sec.  250.1631  Safety device training.

    Prior to engaging in production operations on a lease and 
periodically thereafter, personnel installing, inspecting, testing, and 
maintaining safety devices shall be instructed in the safety 
requirements of the operations to be performed; possible hazards to be 
encountered; and general safety considerations to be taken to protect 
personnel, equipment, and the environment. Date and time of safety 
meetings shall be recorded and available for BSEE review.



Sec.  250.1632  Production rates.

    Each sulphur deposit shall be produced at rates that will provide 
economic development and depletion of the deposit in a manner that would 
maximize the ultimate recovery of sulphur without resulting in waste 
(e.g., an undue reduction in the recovery of oil and gas from an 
associated hydrocarbon accumulation).



Sec.  250.1633  Production measurement.

    (a) General. Measurement equipment and security procedures shall be 
designed, installed, used, maintained, and tested so as to accurately 
and completely measure the sulphur produced on a lease for purposes of 
royalty determination.
    (b) Application and approval. The lessee shall not commence 
production of sulphur until the Regional Supervisor has approved the 
method of measurement. The request for approval of the method of 
measurement shall contain sufficient information to demonstrate to the 
satisfaction of the Regional Supervisor that the method of measurement 
meets the requirements of paragraph (a) of this section.



Sec.  250.1634  Site security.

    (a) All locations where sulphur is produced, measured, or stored 
shall be operated and maintained to ensure against the loss or theft of 
produced sulphur and to assure accurate and complete measurement of 
produced sulphur for royalty purposes.
    (b) Evidence of mishandling of produced sulphur from an offshore 
lease, or tampering or falsifying any measurement of production for an 
offshore lease, shall be reported to the Regional Supervisor as soon as 
possible but no later than the next business day after discovery of the 
evidence of mishandling.

[[Page 284]]



                  Subpart Q_Decommissioning Activities

                                 General



Sec.  250.1700  What do the terms ``decommissioning'', 
``obstructions'', and ``facility'' mean?

    (a) Decommissioning means:
    (1) Ending oil, gas, or sulphur operations; and
    (2) Returning the lease or pipeline right-of-way to a condition that 
meets the requirements of regulations of BSEE and other agencies that 
have jurisdiction over decommissioning activities.
    (b) Obstructions mean structures, equipment, or objects that were 
used in oil, gas, or sulphur operations or marine growth that, if left 
in place, would hinder other users of the OCS. Obstructions may include, 
but are not limited to, shell mounds, wellheads, casing stubs, mud line 
suspensions, well protection devices, subsea trees, jumper assemblies, 
umbilicals, manifolds, termination skids, production and pipeline 
risers, platforms, templates, pilings, pipelines, pipeline valves, and 
power cables.
    (c) Facility means any installation other than a pipeline used for 
oil, gas, or sulphur activities that is permanently or temporarily 
attached to the seabed on the OCS. Facilities include production and 
pipeline risers, templates, pilings, and any other facility or equipment 
that constitutes an obstruction such as jumper assemblies, termination 
skids, umbilicals, anchors, and mooring lines.



Sec.  250.1701  Who must meet the decommissioning obligations in 
this subpart?

    (a) Lessees and owners of operating rights are jointly and severally 
responsible for meeting decommissioning obligations for facilities on 
leases, including the obligations related to lease-term pipelines, as 
the obligations accrue and until each obligation is met.
    (b) All holders of a right-of-way are jointly and severally liable 
for meeting decommissioning obligations for facilities on their right-
of-way, including right-of-way pipelines, as the obligations accrue and 
until each obligation is met.
    (c) In this subpart, the terms ``you'' or ``I'' refer to lessees and 
owners of operating rights, as to facilities installed under the 
authority of a lease, and to right-of-way holders as to facilities 
installed under the authority of a right-of-way.



Sec.  250.1702  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you do any of the 
following:
    (a) Drill a well;
    (b) Install a platform, pipeline, or other facility;
    (c) Create an obstruction to other users of the OCS;
    (d) Are or become a lessee or the owner of operating rights of a 
lease on which there is a well that has not been permanently plugged 
according to this subpart, a platform, a lease term pipeline, or other 
facility, or an obstruction;
    (e) Are or become the holder of a pipeline right-of-way on which 
there is a pipeline, platform, or other facility, or an obstruction; or
    (f) Re-enter a well that was previously plugged according to this 
subpart.



Sec.  250.1703  What are the general requirements for decommissioning?

    When your facilities are no longer useful for operations, you must:
    (a) Get approval from the appropriate District Manager before 
decommissioning wells and from the Regional Supervisor before 
decommissioning platforms and pipelines or other facilities;
    (b) Permanently plug all wells. Permanently installed packers and 
bridge plugs must comply with API Spec. 11D1 (as incorporated by 
reference in Sec.  250.198);
    (c) Remove all platforms and other facilities, except as provided in 
Sec. Sec.  250.1725(a) and 250.1730.
    (d) Decommission all pipelines;
    (e) Clear the seafloor of all obstructions created by your lease and 
pipeline right-of-way operations;
    (f) Follow all applicable requirements of subpart G of this part; 
and

[[Page 285]]

    (g) Conduct all decommissioning activities in a manner that is safe, 
does not unreasonably interfere with other uses of the OCS, and does not 
cause undue or serious harm or damage to the human, marine, or coastal 
environment.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26037, Apr. 29 2016]

    Effective Date Note: At 84 FR 21984, May 15, 2019, Sec.  250.1703 
was amended by revising paragraph (b), effective July 15, 2019. For the 
convenience of the user, the revised text is set forth as follows:



Sec.  250.1703  What are the general requirements for decommissioning?

                                * * * * *

    (b) Permanently plug all wells. Packers and bridge plugs used as 
qualified mechanical barriers must comply with ANSI/API Spec. 11D1 (as 
incorporated by reference in Sec.  250.198). You must have two 
independent barriers, one being an ANSI/API Spec. 11D1 qualified 
mechanical barrier, in the exposed center wellbore prior to removing the 
tree and/or well control equipment;

                                * * * * *



Sec.  250.1704  What decommissioning applications and reports must I submit and when must I submit them?

    You must submit decommissioning applications, receive approval of 
those applications, and submit subsequent reports according to the 
requirements and deadlines in the following table.

                                 Decommissioning Applications and Reports Table
----------------------------------------------------------------------------------------------------------------
  Decommissioning applications and
              reports                      When to submit                          Instructions
----------------------------------------------------------------------------------------------------------------
(a) Initial platform removal         In the Pacific OCS Region   Include information required under Sec.
 application [not required in the     or Alaska OCS Region,       250.1726.
 Gulf of Mexico OCS Region].          submit the application to
                                      the Regional Supervisor
                                      at least 2 years before
                                      production is projected
                                      to cease.
(b) Final removal application for a  Before removing a platform  Include information required under Sec.
 platform or other facility.          or other facility in the    250.1727.
                                      Gulf of Mexico OCS
                                      Region, or not more than
                                      2 years after the
                                      submittal of an initial
                                      platform removal
                                      application to the
                                      Pacific OCS Region and
                                      the Alaska OCS Region.
(c) Post-removal report for a        Within 30 days after you    Include information required under Sec.
 platform or other facility.          remove a platform or        250.1729.
                                      other facility.
(d) Pipeline decommissioning         Before you decommission a   Include information required under Sec.
 application.                         pipeline.                   250.1751(a) or Sec.   250.1752(a), as
                                                                  applicable.
(e) Post-pipeline decommissioning    Within 30 days after you    Include information required under Sec.
 report.                              decommission a pipeline.    250.1753.
(f) Site clearance report for a      Within 30 days after you    Include information required under Sec.
 platform or other facility.          complete site clearance     250.1743(b).
                                      verification activities.
(g) Form BSEE-0124, Application for  (1) Before you temporarily  (i) Include information required under Sec.
 Permit to Modify (APM). The          abandon or permanently      Sec.   250.1712 and 250.1721.
 submission of your APM must be       plug a well or zone,.      (ii) When using a BOP for abandonment
 accompanied by payment of the                                    operations, include information required under
 service fee listed in Sec.                                       Sec.   250.731.
 250.125;.
                                     (2) Before you install a    Refer to Sec.   250.1722(a).
                                      subsea protective device,.
                                     (3) Before you remove any   Refer to Sec.   250.1723.
                                      casing stub or mud line
                                      suspension equipment and
                                      any subsea protective
                                      device,.
(h) Form BSEE-0125, End of           (1) Within 30 days after    Include information required under Sec.
 Operations Report (EOR);.            you complete a protective   250.1722(d).
                                      device trawl test,.
                                     (2) Within 30 days after    Include information required under Sec.
                                      you complete site           250.1743(a).
                                      clearance verification
                                      activities,.
----------------------------------------------------------------------------------------------------------------

[[Page 286]]

 
(i) A certified summary of           Within 120 days after       Submit to the Regional Supervisor a complete
 expenditures for permanently         completion of each          summary of expenditures actually incurred for
 plugging any well, removal of any    decommissioning activity    each decommissioning activity (including, but
 platform or other facility,          specified in this           not limited to, the use of rigs, vessels,
 clearance of any site after wells    paragraph.                  equipment, supplies and materials;
 have been plugged or platforms or                                transportation of any kind; personnel; and
 facilities removed, and                                          services). Include in, or attach to, the
 decommissioning of pipelines.                                    summary a certified statement by an authorized
                                                                  representative of your company attesting to
                                                                  the truth, accuracy and completeness of the
                                                                  summary. The Regional Supervisor may provide
                                                                  specific instructions or guidance regarding
                                                                  how to submit the certified summary.
(j) If requested by the Regional     Within a reasonable time    The Regional Supervisor will review the summary
 Supervisor, additional information   as determined by the        and may provide specific instructions or
 in support of any decommissioning    Regional Supervisor.        guidance regarding the submission of
 activity expenditures included in                                additional information (including, but not
 a summary submitted under                                        limited to, copies of contracts and invoices),
 paragraph (i) of this section.                                   if requested, to complete or otherwise support
                                                                  the summary.
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012; 
80 FR 75810, Dec. 4, 2015; 81 FR 26037, Apr. 29, 2016; 81 FR 80591, Nov. 
16, 2016]

    Effective Date Note: At 84 FR 21984, May 15, 2019, Sec.  250.1704 
was amended by adding paragraph (g)(4) and revising paragraph (h)(2), 
effective July 15, 2019. For the convenience of the user, the added and 
revised text is set forth as follows:



Sec.  250.1704  What decommissioning applications and reports must I submit and when must I submit them?

                                * * * * *

------------------------------------------------------------------------
Decommissioning applications and
             reports                When to submit       Instructions
------------------------------------------------------------------------
 
                              * * * * * * *
(g) * * *.......................  (4) Within 30 days  Include
                                   after you           information
                                   complete site       required under
                                   clearance           Sec.
                                   verification        250.1743(a).
                                   activities,
(h) * * *.......................  (2) Within 30 days  Include
                                   after completion    information
                                   of                  required under
                                   decommissioning     Sec.  Sec.
                                   activity,           250.1712 and
                                                       250.1721.
 
                              * * * * * * *
------------------------------------------------------------------------



Sec.  250.1705  [Reserved]



Sec.  250.1706  Coiled tubing and snubbing operations.

    If you use a BOP for any well abandonment operations, your BOP must 
meet the following requirements:
    (a) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

------------------------------------------------------------------------
                                 BOP system when
   BOP system when expected      expected surface   BOP system for wells
  surface pressures are less      pressures are      with returns taken
  than or equal to 3,500 psi       greater than     through an outlet on
                                    3,500 psi          the BOP stack
------------------------------------------------------------------------
(i) Stripper or annular-type    Stripper or        Stripper or annular-
 well-control component,         annular-type       type well-control
                                 well-control       component.
                                 component,
(ii) Hydraulically-operated     Hydraulically-     Hydraulically-
 blind rams,                     operated blind     operated blind rams.
                                 rams,
(iii) Hydraulically-operated    Hydraulically-     Hydraulically-
 shear rams,                     operated shear     operated shear rams.
                                 rams,
(iv) Kill line inlet,           Kill line inlet,   Kill line inlet.

[[Page 287]]

 
(v) Hydraulically-operated two- Hydraulically-     Hydraulically-
 way slip rams,                  operated two-way   operated two-way
                                 slip rams,         slip rams.
                                                   Hydraulically-
                                                    operated pipe rams.
(vi) Hydraulically-operated     Hydraulically-     A flow tee or cross.
 pipe rams,                      operated pipe     Hydraulically-
                                 rams.              operated pipe rams.
                                Hydraulically-     Hydraulically-
                                 operated blind-    operated blind-shear
                                 shear rams.        rams on wells with
                                 These rams         surface pressures
                                 should be          3,500
                                 located as close   psi. As an option,
                                 to the tree as     the pipe rams can be
                                 practical,.        placed below the
                                                    blind-shear rams.
                                                    The blind-shear rams
                                                    should be located as
                                                    close to the tree as
                                                    practical.
------------------------------------------------------------------------

    (2) You may use a set of hydraulically-operated combination rams for 
the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams for 
the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled tubing 
connector at the downhole end of the coiled tubing string for all coiled 
tubing well abandonment operations. If you plan to conduct operations 
without downhole check valves, you must describe alternate procedures 
and equipment in Form BSEE-0124, Application for Permit to Modify, and 
have it approved by the BSEE District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well-control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well-control stack and the first full-opening valve on the 
choke line and the kill line.
    (b) The minimum BOP system components for well abandonment 
operations with the tree in place and performed by moving tubing or 
drill pipe in or out of a well under pressure utilizing equipment 
specifically designed for that purpose, i.e., snubbing operations, must 
include the following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (c) An inside BOP or a spring-loaded, back-pressure safety valve, 
and an essentially full-opening, work-string safety valve in the open 
position must be maintained on the rig floor at all times during well 
abandonment operations when the tree is removed or during well 
abandonment operations with the tree installed and using small tubing as 
the work string. A wrench to fit the work-string safety valve must be 
readily available. Proper connections must be readily available for 
inserting valves in the work string. The full-opening safety valve is 
not required for coiled tubing or snubbing operations.

[77 FR 50897, Aug. 22, 2012, as amended at 81 FR 26037, Apr. 29, 2016]

    Effective Date Note: At 84 FR 21985, May 15, 2019, Sec.  250.1706 
was removed and reserved, effective July 15, 2019.

[[Page 288]]



Sec. Sec.  250.1707-250.1709  [Reserved]

                       Permanently Plugging Wells



Sec.  250.1710  When must I permanently plug all wells on a lease?

    You must permanently plug all wells on a lease within 1 year after 
the lease terminates.



Sec.  250.1711  When will BSEE order me to permanently plug a well?

    BSEE will order you to permanently plug a well if that well:
    (a) Poses a hazard to safety or the environment; or
    (b) Is not useful for lease operations and is not capable of oil, 
gas, or sulphur production in paying quantities.



Sec.  250.1712  What information must I submit before I permanently plug a well or zone?

    Before you permanently plug a well or zone, you must submit form 
BSEE-0124, Application for Permit to Modify, to the appropriate District 
Manager and receive approval. A request for approval must contain the 
following information:
    (a) The reason you are plugging the well (or zone), for completions 
with production amounts specified by the Regional Supervisor, along with 
substantiating information demonstrating its lack of capacity for 
further profitable production of oil, gas, or sulfur;
    (b) Recent well test data and pressure data, if available;
    (c) Maximum possible surface pressure, and how it was determined;
    (d) Type and weight of well-control fluid you will use;
    (e) A description of the work;
    (f) A current and proposed well schematic and description that 
includes:
    (1) Well depth;
    (2) All perforated intervals that have not been plugged;
    (3) Casing and tubing depths and details;
    (4) Subsurface equipment;
    (5) Estimated tops of cement (and the basis of the estimate) in each 
casing annulus;
    (6) Plug locations;
    (7) Plug types;
    (8) Plug lengths;
    (9) Properties of mud and cement to be used;
    (10) Perforating and casing cutting plans;
    (11) Plug testing plans;
    (12) Casing removal (including information on explosives, if used);
    (13) Proposed casing removal depth; and
    (14) Your plans to protect archaeological and sensitive biological 
features, including anchor damage during plugging operations, a brief 
assessment of the environmental impacts of the plugging operations, and 
the procedures and mitigation measures you will take to minimize such 
impacts; and
    (g) Certification by a Registered Professional Engineer of the well 
abandonment design and procedures and that all plugs meet the 
requirements in the table in Sec.  250.1715. In addition to the 
requirements of Sec.  250.1715, the Registered Professional Engineer 
must also certify the design will include two independent barriers, one 
of which must be a mechanical barrier, in the center wellbore as 
described in Sec.  250.420(b)(3). The Registered Professional Engineer 
must be registered in a State of the United States and have sufficient 
expertise and experience to perform the certification. You must submit 
this certification with your APM (Form BSEE-0124).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]



Sec.  250.1713  Must I notify BSEE before I begin well plugging operations?

    You must notify the appropriate District Manager at least 48 hours 
before beginning operations to permanently plug a well.

    Effective Date Note: At 84 FR 21985, May 15, 2019, Sec.  250.1713 
was removed and reserved, effective July 15, 2019.



Sec.  250.1714  What must I accomplish with well plugs?

    You must ensure that all well plugs:
    (a) Provide downhole isolation of hydrocarbon and sulphur zones;
    (b) Protect freshwater aquifers; and
    (c) Prevent migration of formation fluids within the wellbore or to 
the seafloor.

[[Page 289]]



Sec.  250.1715  How must I permanently plug a well?

    (a) You must permanently plug wells according to the table in this 
section. The District Manager may require additional well plugs as 
necessary.

                                      Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
                 If you have . . .                                    Then you must use . . .
---------------------------------------------------------------------------------------------------------------
(1) Zones in open hole,                              Cement plug(s) set from at least 100 feet below the
                                                      bottom to 100 feet above the top of oil, gas, and fresh-
                                                      water zones to isolate fluids in the strata.
(2) Open hole below casing,                          (i) A cement plug, set by the displacement method, at
                                                      least 100 feet above and below deepest casing shoe;
                                                     (ii) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the casing shoe, and a
                                                      cement plug that extends at least 100 feet below the
                                                      casing shoe and at least 50 feet above the retainer; or
                                                     (iii) A bridge plug set 50 feet to 100 feet above the
                                                      shoe with 50 feet of cement on top of the bridge plug,
                                                      for expected or known lost circulation conditions.
(3) A perforated zone that is currently open and     (i) A method to squeeze cement to all perforations;
 not previously squeezed or isolated,                (ii) A cement plug set by the displacement method, at
                                                      least 100 feet above to 100 feet below the perforated
                                                      interval, or down to a casing plug, whichever is less;
                                                      or.
                                                     (iii) If the perforated zones are isolated from the hole
                                                      below, you may use any of the plugs specified in
                                                      paragraphs (a)(3)(iii)(A) through (E) of this section
                                                      instead of those specified in paragraphs (a)(3)(i) and
                                                      (a)(3)(ii) of this section..
                                                     (A) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the top of the
                                                      perforated interval, and a cement plug that extends at
                                                      least 100 feet below the bottom of the perforated
                                                      interval with at least 50 feet of cement above the
                                                      retainer;
                                                     (B) A casing bridge plug set 50 to 100 feet above the top
                                                      of the perforated interval and at least 50 feet of
                                                      cement on top of the bridge plug;
                                                     (C) A cement plug at least 200 feet in length, set by the
                                                      displacement method, with the bottom of the plug no more
                                                      than 100 feet above the perforated interval;
                                                     (D) A through-tubing basket plug set no more than 100
                                                      feet above the perforated interval with at least 50 feet
                                                      of cement on top of the basket plug; or
                                                     (E) A tubing plug set no more than 100 feet above the
                                                      perforated interval topped with a sufficient volume of
                                                      cement so as to extend at least 100 feet above the
                                                      uppermost packer in the wellbore and at least 300 feet
                                                      of cement in the casing annulus immediately above the
                                                      packer.
(4) A casing stub where the stub end is within the   (i) A cement plug set at least 100 feet above and below
 casing,                                              the stub end;
                                                     (ii) A cement retainer or bridge plug set at least 50 to
                                                      100 feet above the stub end with at least 50 feet of
                                                      cement on top of the retainer or bridge plug; or
                                                     (iii) A cement plug at least 200 feet long with the
                                                      bottom of the plug set no more than 100 feet above the
                                                      stub end.
(5) A casing stub where the stub end is below the    A plug as specified in paragraph (a)(1) or (a)(2) of this
 casing,                                              section, as applicable.
(6) An annular space that communicates with open     A cement plug at least 200 feet long set in the annular
 hole and extends to the mud line,                    space. For a well completed above the ocean surface, you
                                                      must pressure test each casing annulus to verify
                                                      isolation.
(7) A subsea well with unsealed annulus,             A cutter to sever the casing, and you must set a stub
                                                      plug as specified in paragraphs (a)(4) and (a)(5) of
                                                      this section.
(8) A well with casing,                              A cement surface plug at least 150 feet long set in the
                                                      smallest casing that extends to the mud line with the
                                                      top of the plug no more than 150 feet below the mud
                                                      line.
(9) Fluid left in the hole,                          A fluid in the intervals between the plugs that is dense
                                                      enough to exert a hydrostatic pressure that is greater
                                                      than the formation pressures in the intervals.
(10) Permafrost areas,                               (i) A fluid to be left in the hole that has a freezing
                                                      point below the temperature of the permafrost, and a
                                                      treatment to inhibit corrosion; and
                                                     (ii) Cement plugs designed to set before freezing and
                                                      have a low heat of hydration.
(11) Removed the barriers required in Sec.           Two independent barriers, one of which must be a
 250.420(b)(3) for the well to be completed           mechanical barrier, in the center wellbore as described
                                                      in Sec.   250.420(b)(3) once the well is to be placed in
                                                      a permanent or temporary abandonment..
----------------------------------------------------------------------------------------------------------------

    (b) You must test the first plug below the surface plug and all 
plugs in lost circulation areas that are in open hole. The plug must 
pass one of the following tests to verify plug integrity:
    (1) A pipe weight of at least 15,000 pounds on the plug; or
    (2) A pump pressure of at least 1,000 pounds per square inch. Ensure 
that the pressure does not drop more than 10

[[Page 290]]

percent in 15 minutes. The District Manager may require you to tests 
other plug(s).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012; 
81 FR 26038, Apr. 29, 2016]



Sec.  250.1716  To what depth must I remove wellheads and casings?

    (a) Unless the District Manager approves an alternate depth under 
paragraph (b) of this section, you must remove all wellheads and casings 
to at least 15 feet below the mud line.
    (b) The District Manager may approve an alternate removal depth if:
    (1) The wellhead or casing would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers, and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).

    Effective Date Note: At 84 FR 21985, May 15, 2019, Sec.  250.1716 
was amended by revising paragraph (b)(3), effective July 15, 2019. For 
the convenience of the user, the revised text is set forth as follows:



Sec.  250.1716  To what depth must I remove wellheads and casings?

                                * * * * *

    (b) * * *
    (3) The water depth is greater than 1,000 feet.



Sec.  250.1717  [Reserved]

                        Temporary Abandoned Wells



Sec.  250.1721  If I temporarily abandon a well that I plan to
 re-enter, what must I do?

    You may temporarily abandon a well when it is necessary for proper 
development and production of a lease. To temporarily abandon a well, 
you must do all of the following:
    (a) Submit form BSEE-0124, Application for Permit to Modify, and the 
applicable information required by Sec.  250.1712 to the appropriate 
District Manager and receive approval;
    (b) Adhere to the plugging and testing requirements for permanently 
plugged wells listed in the table in Sec.  250.1715, except for Sec.  
250.1715(a)(8). You do not need to sever the casings, remove the 
wellhead, or clear the site;
    (c) Set a bridge plug or a cement plug at least 100-feet long at the 
base of the deepest casing string, unless the casing string has been 
cemented and has not been drilled out. If a cement plug is set, it is 
not necessary for the cement plug to extend below the casing shoe into 
the open hole;
    (d) Set a retrievable or a permanent-type bridge plug or a cement 
plug at least 100 feet long in the inner-most casing. The top of the 
bridge plug or cement plug must be no more than 1,000 feet below the mud 
line. BSEE may consider approving alternate requirements for subsea 
wells case-by-case;
    (e) Identify and report subsea wellheads, casing stubs, or other 
obstructions that extend above the mud line according to U.S. Coast 
Guard (USCG) requirements;
    (f) Except in water depths greater than 300 feet, protect subsea 
wellheads, casing stubs, mud line suspensions, or other obstructions 
remaining above the seafloor by using one of the following methods, as 
approved by the District Manager or Regional Supervisor:
    (1) A caisson designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation;
    (2) A jacket designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation; or
    (3) A subsea protective device that meets the requirements in Sec.  
250.1722.
    (g) Submit certification by a Registered Professional Engineer of 
the well abandonment design and procedures and that all plugs meet the 
requirements of paragraph (b) of this section. In addition to the 
requirements of paragraph (b) of this section, the Registered 
Professional Engineer must also certify the design will include two 
independent barriers, one of which must be a mechanical barrier, in the 
center wellbore as described in Sec.  250.420(b)(3). The Registered 
Professional Engineer must be registered in a State of the United States 
and have sufficient expertise and experience to

[[Page 291]]

perform the certification. You must submit this certification with your 
APM (Form BSEE-0124) required by Sec.  250.1712 of this part.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012; 
81 FR 26038, Apr. 29, 2016]



Sec.  250.1722  If I install a subsea protective device, what
 requirements must I meet?

    If you install a subsea protective device under Sec.  
250.1721(f)(3), you must install it in a manner that allows fishing gear 
to pass over the obstruction without damage to the obstruction, the 
protective device, or the fishing gear.
    (a) Use form BSEE-0124, Application for Permit to Modify to request 
approval from the appropriate District Manager to install a subsea 
protective device.
    (b) The protective device may not extend more than 10 feet above the 
seafloor (unless BSEE approves otherwise).
    (c) You must trawl over the protective device when you install it 
(adhere to the requirements at Sec.  250.1741(d) through (h)). If the 
trawl does not pass over the protective device or causes damage to it, 
you must notify the appropriate District Manager within 5 days and 
perform remedial action within 30 days of the trawl;
    (d) Within 30 days after you complete the trawling test described in 
paragraph (c) of this section, submit a report to the appropriate 
District Manager using form BSEE-0124, Application for Permit to Modify 
that includes the following:
    (1) The date(s) the trawling test was performed and the vessel that 
was used;
    (2) A plat at an appropriate scale showing the trawl lines;
    (3) A description of the trawling operation and the net(s) that were 
used;
    (4) An estimate by the trawling contractor of the seafloor 
penetration depth achieved by the trawl;
    (5) A summary of the results of the trawling test including a 
discussion of any snags and interruptions, a description of any damage 
to the protective covering, the casing stub or mud line suspension 
equipment, or the trawl, and a discussion of any snag removals requiring 
diver assistance; and
    (6) A letter signed by your authorized representative stating that 
he/she witnessed the trawling test.
    (e) If a temporarily abandoned well is protected by a subsea device 
installed in a water depth less than 100 feet, mark the site with a buoy 
installed according to the USCG requirements.
    (f) Provide annual reports to the Regional Supervisor describing 
your plans to either re-enter and complete the well or to permanently 
plug the well.
    (g) Ensure that all subsea wellheads, casing stubs, mud line 
suspensions, or other obstructions in water depths less than 300 feet 
remain protected.
    (1) To confirm that the subsea protective covering remains properly 
installed, either conduct a visual inspection or perform a trawl test at 
least annually.
    (2) If the inspection reveals that a casing stub or mud line 
suspension is no longer properly protected, or if the trawl does not 
pass over the subsea protective covering without causing damage to the 
covering, the casing stub or mud line suspension equipment, or the 
trawl, notify the appropriate District Manager within 5 days, and 
perform the necessary remedial work within 30 days of discovery of the 
problem.
    (3) In your annual report required by paragraph (f) of this section, 
include the inspection date, results, and method used and a description 
of any remedial work you will perform or have performed.
    (h) You may request approval to waive the trawling test required by 
paragraph (c) of this section if you plan to use either:
    (1) A buoy with automatic tracking capabilities installed and 
maintained according to USCG requirements at 33 CFR part 67 (or its 
successor); or
    (2) A design and installation method that has been proven successful 
by trawl testing of previous protective devices of the same design and 
installed in areas with similar bottom conditions.

    Effective Date Note: At 84 FR 21985, May 15, 2019, Sec.  250.1722 
was amended by revising paragraph (d) introductory text, effective

[[Page 292]]

July 15, 2019. For the convenience of the user, the revised text is set 
forth as follows:



Sec.  250.1722  If I install a subsea protective device, what 
          requirements must I meet?

                                * * * * *

    (d) Within 30 days after you complete the trawling test described in 
paragraph (c) of this section, submit a report to the appropriate 
District Manager using form BSEE-0125, End of Operations Report (EOR) 
that includes the following:

                                * * * * *



Sec.  250.1723  What must I do when it is no longer necessary to
 maintain a well in temporary abandoned status?

    If you or BSEE determines that continued maintenance of a well in a 
temporary abandoned status is not necessary for the proper development 
or production of a lease, you must:
    (a) Promptly and permanently plug the well according to Sec.  
250.1715;
    (b) Remove any casing stub or mud line suspension equipment and any 
subsea protective covering. You must submit a request for approval to 
perform such work to the appropriate District Manager using form BSEE-
0124, Application for Permit to Modify; and
    (c) Clear the well site according to Sec. Sec.  250.1740 through 
250.1742.

                 Removing Platforms and Other Facilities



Sec.  250.1725  When do I have to remove platforms and other
 facilities?

    (a) You must remove all platforms and other facilities within 1 year 
after the lease or pipeline right-of-way terminates, unless you receive 
approval to maintain the structure to conduct other activities. 
Platforms include production platforms, well jackets, single-well 
caissons, and pipeline accessory platforms. Other activities include 
those supporting OCS oil and gas production and transportation, as well 
as other energy-related or marine-related uses (including LNG) for which 
adequate financial assurance for decommissioning has been provided to a 
Federal agency which has given BSEE a commitment that it has and will 
exercise authority to compel the performance of decommissioning within a 
time following cessation of the new use acceptable to BSEE. The approval 
will specify:
    (1) Whether you must continue to maintain any financial assurance 
for decommissioning; and
    (2) Whether, and under what circumstances, you must perform any 
decommissioning not performed by the new facility owner/user.
    (b) Before you may remove a platform or other facility, you must 
submit a final removal application to the Regional Supervisor for 
approval and include the information listed in Sec.  250.1727.
    (c) You must remove a platform or other facility according to the 
approved application.
    (d) You must flush all production risers with seawater before you 
remove them.
    (e) You must notify the Regional Supervisor at least 48 hours before 
you begin the removal operations.



Sec.  250.1726  When must I submit an initial platform removal
 application and what must it include?

    An initial platform removal application is required only for leases 
and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS 
Region. It must include the following information:
    (a) Platform or other facility removal procedures, including the 
types of vessels and equipment you will use;
    (b) Facilities (including pipelines) you plan to remove or leave in 
place;
    (c) Platform or other facility transportation and disposal plans;
    (d) Plans to protect marine life and the environment during 
decommissioning operations, including a brief assessment of the 
environmental impacts of the operations, and procedures and mitigation 
measures that you will take to minimize the impacts; and
    (e) A projected decommissioning schedule.



Sec.  250.1727  What information must I include in my final 
application to remove a platform or other facility?

    You must submit to the Regional Supervisor, a final application for 
approval to remove a platform or other

[[Page 293]]

facility. Your application must be accompanied by payment of the service 
fee listed in Sec.  250.125. If you are proposing to use explosives, 
provide three copies of the application. If you are not proposing to use 
explosives, provide two copies of the application. Include the following 
information in the final removal application, as applicable:
    (a) Identification of the applicant including:
    (1) Lease operator/pipeline right-of-way holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.
    (b) Identification of the structure you are removing including:
    (1) Platform Name/BSEE Complex ID Number;
    (2) Location (lease/right-of-way, area, block, and block 
coordinates);
    (3) Date installed (year);
    (4) Proposed date of removal (Month/Year); and
    (5) Water depth.
    (c) Description of the structure you are removing including:
    (1) Configuration (attach a photograph or a diagram);
    (2) Size;
    (3) Number of legs/casings/pilings;
    (4) Diameter and wall thickness of legs/casings/pilings;
    (5) Whether piles are grouted inside or outside;
    (6) Brief description of soil composition and condition;
    (7) The sizes and weights of the jacket, topsides (by module), 
conductors, and pilings; and
    (8) The maximum removal lift weight and estimated number of main 
lifts to remove the structure.
    (d) A description, including anchor pattern, of the vessel(s) you 
will use to remove the structure.
    (e) Identification of the purpose, including:
    (1) Lease expiration/right-of-way relinquishment date; and
    (2) Reason for removing the structure.
    (f) A description of the removal method, including:
    (1) A brief description of the method you will use;
    (2) If you are using explosives, the following:
    (i) Type of explosives;
    (ii) Number and sizes of charges;
    (iii) Whether you are using single shot or multiple shots;
    (iv) If multiple shots, the sequence and timing of detonations;
    (v) Whether you are using a bulk or shaped charge;
    (vi) Depth of detonation below the mud line; and
    (vii) Whether you are placing the explosives inside or outside of 
the pilings;
    (3) If you will use divers or acoustic devices to conduct a pre-
removal survey to detect the presence of turtles and marine mammals, a 
description of the proposed detection method; and
    (4) A statement whether or not you will use transducers to measure 
the pressure and impulse of the detonations.
    (g) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed platform.
    (h) If available, the results of any recent biological surveys 
conducted in the vicinity of the structure and recent observations of 
turtles or marine mammals at the structure site.
    (i) Your plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures you will take to minimize such impacts.
    (j) A statement whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.



Sec.  250.1728  To what depth must I remove a platform or other facility?

    (a) Unless the Regional Supervisor approves an alternate depth under 
paragraph (b) of this section, you must remove all platforms and other 
facilities (including templates and pilings) to at least 15 feet below 
the mud line.
    (b) The Regional Supervisor may approve an alternate removal depth 
if:
    (1) The remaining structure would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional

[[Page 294]]

processes capable of exposing the obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).



Sec.  250.1729  After I remove a platform or other facility, 
what information must I submit?

    Within 30 days after you remove a platform or other facility, you 
must submit a written report to the Regional Supervisor that includes 
the following:
    (a) A summary of the removal operation including the date it was 
completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the types and amount of explosives you used in removing 
the platform or other facility were consistent with those set forth in 
the approved removal application.



Sec.  250.1730  When might BSEE approve partial structure removal 
or toppling in place?

    The Regional Supervisor may grant a departure from the requirement 
to remove a platform or other facility by approving partial structure 
removal or toppling in place for conversion to an artificial reef if you 
meet the following conditions:
    (a) The structure becomes part of a State artificial reef program, 
and the responsible State agency acquires a permit from the U.S. Army 
Corps of Engineers and accepts title and liability for the structure; 
and
    (b) You satisfy any U.S. Coast Guard (USCG) navigational 
requirements for the structure.



Sec.  250.1731  Who is responsible for decommissioning an OCS
 facility subject to an Alternate Use RUE?

    (a) The holder of an Alternate Use RUE issued under 30 CFR part 585 
is responsible for all decommissioning obligations that accrue following 
the issuance of the Alternate Use RUE and which pertain to the Alternate 
Use RUE. See 30 CFR part 585, subpart J, for additional information 
concerning the decommissioning responsibilities of an Alternate Use RUE 
grant holder.
    (b) The lessee under the lease originally issued under 30 CFR part 
556 will remain responsible for decommissioning obligations that accrued 
before issuance of the Alternate Use RUE, as well as for decommissioning 
obligations that accrue following issuance of the Alternate Use RUE to 
the extent associated with continued activities authorized under this 
part.
    (c) If a lease issued under 30 CFR part 556 is cancelled or 
otherwise terminated under any provision of this subchapter, the lessee, 
upon our approval, may defer removal of any OCS facility within the 
lease area that is subject to an Alternate Use RUE. If we elect to grant 
such a deferral, the lessee remains responsible for removing the 
facility upon termination of the Alternate Use RUE and will be required 
to retain sufficient bonding or other financial assurances to ensure 
that the structure is removed or otherwise decommissioned in accordance 
with the provisions of this subpart.

        Site Clearance for Wells, Platforms, and Other Facilities



Sec.  250.1740  How must I verify that the site of a permanently
 plugged well, removed platform, or other removed facility is
 clear of obstructions?

    Within 60 days after you permanently plug a well or remove a 
platform or other facility, you must verify that the site is clear of 
obstructions by using one of the following methods:
    (a) For a well site, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the location using sonar equipment;
    (3) Inspect the site using a diver;
    (4) Videotape the site using a camera on a remotely operated vehicle 
(ROV); or
    (5) Use another method approved by the District Manager if the 
particular site conditions warrant.
    (b) For a platform or other facility site in water depths less than 
300 feet, you must drag a trawl over the site.
    (c) For a platform or other facility site in water depths 300 feet 
or more, you must either:

[[Page 295]]

    (1) Drag a trawl over the site;
    (2) Scan across the site using sonar equipment; or
    (3) Use another method approved by the Regional Supervisor if the 
particular site conditions warrant.



Sec.  250.1741  If I drag a trawl across a site, what requirements 
must I meet?

    If you drag a trawl across the site in accordance with Sec.  
250.1740, you must meet all of the requirements of this section.
    (a) You must drag the trawl in a grid-like pattern as shown in the 
following table:

------------------------------------------------------------------------
                                               You must drag the trawl
                For a . . .                        across a . . .
------------------------------------------------------------------------
(1) Well site,                              300-foot-radius circle
                                             centered on the well
                                             location.
(2) Subsea well site,                       600-foot-radius circle
                                             centered on the well
                                             location.
(3) Platform site,                          1,320-foot-radius circle
                                             centered on the location of
                                             the platform.
(4) Single-well caisson, well protector     600-foot-radius circle
 jacket, template, or manifold,              centered on the structure
                                             location.
------------------------------------------------------------------------

    (b) You must trawl 100 percent of the limits described in paragraph 
(a) of this section in two directions.
    (c) You must mark the area to be cleared as a hazard to navigation 
according to USCG requirements until you complete the site clearance 
procedures.
    (d) You must use a trawling vessel equipped with a calibrated 
navigational positioning system capable of providing position accuracy 
of 30 feet.
    (e) You must use a trawling net that is representative of those used 
in the commercial fishing industry (one that has a net strength equal or 
greater than that provided by No. 18 twine).
    (f) You must ensure that you trawl no closer than 300 feet from a 
shipwreck, and 500 feet from a sensitive biological feature.
    (g) If you trawl near an active pipeline, you must meet the 
requirements in the following table:

----------------------------------------------------------------------------------------------------------------
                For . . .                            You must trawl . . .                 And you must . . .
----------------------------------------------------------------------------------------------------------------
(1) Buried active pipelines,               ........................................  First contact the pipeline
                                                                                      owner or operator to
                                                                                      determine the condition of
                                                                                      the pipeline before
                                                                                      trawling over the buried
                                                                                      pipeline.
(2) Unburied active pipelines that are 8   no closer than 100 feet to the either     Trawl parallel to the
 inches in diameter or larger,              side of the pipeline,                     pipeline Do not trawl
                                                                                      across the pipeline.
(3) Unburied smaller diameter active       no closer than 100 feet to either side    Trawl parallel to the
 pipelines in the trawl area that have      of the pipeline,                          pipeline. Do not trawl
 obstructions (e.g., pipeline valves)                                                 across the pipeline.
 present,
(4) Unburied active pipelines in the       parallel to the pipeline,                 ...........................
 trawl area that are smaller than 8
 inches in diameter and have no
 obstructions present,
----------------------------------------------------------------------------------------------------------------

    (h) You must ensure that any trawling contractor you may use:
    (1) Has no corporate or other financial ties to you; and
    (2) Has a valid commercial trawling license for both the vessel and 
its captain.



Sec.  250.1742  What other methods can I use to verify that a site is clear?

    If you do not trawl a site, you can verify that the site is clear of 
obstructions by using any of the methods shown in the following table:

----------------------------------------------------------------------------------------------------------------
             If you use . . .                           You must . . .                    And you must . . .
----------------------------------------------------------------------------------------------------------------
(a) Sonar,                                 cover 100 percent of the appropriate      Use a sonar signal with a
                                            grid area listed in Sec.   250.1741(a),   frequency of at least 500
                                                                                      kHz.

[[Page 296]]

 
(b) A diver,                               ensure that the diver visually inspects   Ensure that the diver uses
                                            100 percent of the appropriate grid       a search pattern of
                                            area listed in Sec.   250.1741(a),        concentric circles or
                                                                                      parallel lines spaced no
                                                                                      more than 10 feet apart.
(c) An ROV (remotely operated vehicle),    ensure that the ROV camera records        Ensure that the ROV uses a
                                            videotape over 100 percent of the         pattern of concentric
                                            appropriate grid area listed in Sec.      circles or parallel lines
                                            250.1741(a),                              spaced no more than 10
                                                                                      feet apart.
----------------------------------------------------------------------------------------------------------------



Sec.  250.1743  How do I certify that a site is clear of obstructions?

    (a) For a well site, you must submit to the appropriate District 
Manager within 30 days after you complete the verification activities a 
form BSEE-0124, Application for Permit to Modify, to include the 
following information:
    (1) A signed certification that the well site area is cleared of all 
obstructions;
    (2) The date the verification work was performed and the vessel 
used;
    (3) The extent of the area surveyed;
    (4) The survey method used;
    (5) The results of the survey, including a list of any debris 
removed or a statement from the trawling contractor that no objects were 
recovered; and
    (6) A post-trawling job plot or map showing the trawled area.
    (b) For a platform or other facility site, you must submit the 
following information to the appropriate Regional Supervisor within 30 
days after you complete the verification activities:
    (1) A letter signed by an authorized company official certifying 
that the platform or other facility site area is cleared of all 
obstructions and that a company representative witnessed the 
verification activities;
    (2) A letter signed by an authorized official of the company that 
performed the verification work for you certifying that it cleared the 
platform or other facility site area of all obstructions;
    (3) The date the verification work was performed and the vessel 
used;
    (4) The extent of the area surveyed;
    (5) The survey method used;
    (6) The results of the survey, including a list of any debris 
removed or a statement from the trawling contractor that no objects were 
recovered; and
    (7) A post-trawling job plot or map showing the trawled area.

                        Pipeline Decommissioning



Sec.  250.1750  When may I decommission a pipeline in place?

    You may decommission a pipeline in place when the Regional 
Supervisor determines that the pipeline does not constitute a hazard 
(obstruction) to navigation and commercial fishing operations, unduly 
interfere with other uses of the OCS, or have adverse environmental 
effects.



Sec.  250.1751  How do I decommission a pipeline in place?

    You must do the following to decommission a pipeline in place:
    (a) Submit a pipeline decommissioning application in triplicate to 
the Regional Supervisor for approval. Your application must be 
accompanied by payment of the service fee listed in Sec.  250.125. Your 
application must include the following information:
    (1) Reason for the operation;
    (2) Proposed decommissioning procedures;
    (3) Length (feet) of segment to be decommissioned; and
    (4) Length (feet) of segment remaining.
    (b) Pig the pipeline, unless the Regional Supervisor determines that 
pigging is not practical;
    (c) Flush the pipeline;
    (d) Fill the pipeline with seawater;
    (e) Cut and plug each end of the pipeline;
    (f) Bury each end of the pipeline at least 3 feet below the seafloor 
or cover each end with protective concrete mats, if required by the 
Regional Supervisor; and
    (g) Remove all pipeline valves and other fittings that could unduly 
interfere with other uses of the OCS.

[[Page 297]]



Sec.  250.1752  How do I remove a pipeline?

    Before removing a pipeline, you must:
    (a) Submit a pipeline removal application in triplicate to the 
Regional Supervisor for approval. Your application must be accompanied 
by payment of the service fee listed in Sec.  250.125. Your application 
must include the following information:
    (1) Proposed removal procedures;
    (2) If the Regional Supervisor requires it, a description, including 
anchor pattern(s), of the vessel(s) you will use to remove the pipeline;
    (3) Length (feet) to be removed;
    (4) Length (feet) of the segment that will remain in place;
    (5) Plans for transportation of the removed pipe for disposal or 
salvage;
    (6) Plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures that you will take to minimize such impacts; and
    (7) Projected removal schedule and duration.
    (b) Pig the pipeline, unless the Regional Supervisor determines that 
pigging is not practical; and
    (c) Flush the pipeline.



Sec.  250.1753  After I decommission a pipeline, what information must I submit?

    Within 30 days after you decommission a pipeline, you must submit a 
written report to the Regional Supervisor that includes the following:
    (a) A summary of the decommissioning operation including the date it 
was completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the pipeline was decommissioned according to the approved 
application.



Sec.  250.1754  When must I remove a pipeline decommissioned in place?

    You must remove a pipeline decommissioned in place if the Regional 
Supervisor determines that the pipeline is an obstruction.

Subpart R [Reserved]



      Subpart S_Safety and Environmental Management Systems (SEMS)



Sec.  250.1900  Must I have a SEMS program?

    You must develop, implement, and maintain a safety and environmental 
management system (SEMS) program. Your SEMS program must address the 
elements described in Sec.  250.1902, American Petroleum Institute's 
Recommended Practice for Development of a Safety and Environmental 
Management Program for Offshore Operations and Facilities (API RP 75) 
(as incorporated by reference in Sec.  250.198), and other requirements 
as identified in this subpart.
    (a) If there are any conflicts between the requirements of this 
subpart and API RP 75; COS-2-01, COS-2-03, or COS-2-04; or ISO/IEC 17011 
(incorporated by reference as specified in Sec.  250.198), you must 
follow the requirements of this subpart.
    (b) Nothing in this subpart affects safety or other matters under 
the jurisdiction of the Coast Guard.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]



Sec.  250.1901  What is the goal of my SEMS program?

    The goal of your SEMS program is to promote safety and environmental 
protection by ensuring all personnel aboard a facility are complying 
with the policies and procedures identified in your SEMS.
    (a) To accomplish this goal, you must ensure that your SEMS program 
identifies, addresses, and manages safety, environmental hazards, and 
impacts during the design, construction, start-up, operation (including, 
but not limited to, drilling and decommissioning), inspection, and 
maintenance of all new and existing facilities, including mobile 
offshore drilling units (MODUs) when attached to the seabed and 
Department of the Interior (DOI) regulated pipelines.
    (b) All personnel involved with your SEMS program must be trained to 
have

[[Page 298]]

the skills and knowledge to perform their assigned duties.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]



Sec.  250.1902  What must I include in my SEMS program?

    You must have a properly documented SEMS program in place and make 
it available to BSEE upon request as required by Sec.  250.1924(b).
    (a) Your SEMS program must meet the minimum criteria outlined in 
this subpart, including the following SEMS program elements:
    (1) General (see Sec.  250.1909)
    (2) Safety and Environmental Information (see Sec.  250.1910)
    (3) Hazards Analysis (see Sec.  250.1911)
    (4) Management of Change (see Sec.  250.1912)
    (5) Operating Procedures (see Sec.  250.1913)
    (6) Safe Work Practices (see Sec.  250.1914)
    (7) Training (see Sec.  250.1915)
    (8) Mechanical Integrity (Assurance of Quality and Mechanical 
Integrity of Critical Equipment) (see Sec.  250.1916)
    (9) Pre-startup Review (see Sec.  250.1917)
    (10) Emergency Response and Control (see Sec.  250.1918)
    (11) Investigation of Incidents (see Sec.  250.1919)
    (12) Auditing (Audit of Safety and Environmental Management Program 
Elements) (see Sec.  250.1920)
    (13) Recordkeeping (Records and Documentation) and additional BSEE 
requirements (see Sec.  250.1928)
    (14) Stop Work Authority (SWA) (see Sec.  250.1930)
    (15) Ultimate Work Authority (UWA) (see Sec.  250.1931)
    (16) Employee Participation Plan (EPP) (see Sec.  250.1932)
    (17) Reporting Unsafe Working Conditions (see Sec.  250.1933).
    (b) You must include a job safety analysis (JSA) for OCS activities 
identified or discussed in your SEMS program (see Sec.  250.1911).
    (c) Your SEMS program must meet or exceed the standards of safety 
and environmental protection of API RP 75 (as incorporated by reference 
in Sec.  250.198).

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]



Sec.  250.1903  Acronyms and definitions.

    Definitions listed in this section apply to this subpart and 
supersede definitions in API RP 75, Appendices D and E; COS-2-01, COS-2-
03, and COS-2-04; and ISO/IEC 17011 (incorporated by reference as 
specified in Sec.  250.198).
    (a) Acronyms used frequently in this subpart have the following 
meanings:
    AB means Accreditation Body,
    ASP means Audit Service Provider,
    CAP means Corrective Action Plan,
    COS means Center for Offshore Safety,
    EPP means Employee Participation Plan,
    ISO means International Organization for Standardization,
    JSA means Job Safety Analysis,
    MODU means Mobile Offshore Drilling Unit,
    OCS means Outer Continental Shelf,
    SEMS means Safety and Environmental Management Systems,
    SWA means Stop Work Authority,
    USCG means United States Coast Guard, and
    UWA means Ultimate Work Authority.
    (b) Terms used in this subpart are listed alphabetically as follows:
    Accreditation Body (AB) means a BSEE-approved independent third-
party organization that assesses and accredits ASPs.
    Audit Service Provider (ASP) means an independent third-party 
organization that demonstrates competence to conduct SEMS audits in 
accordance with the requirements of this subpart.
    Corrective Action Plan (CAP) means a scheduled plan to correct 
deficiencies identified during an audit and that is developed by an 
operator following the issuance of an audit report.
    Personnel means direct employee(s) of the operator and contracted 
workers.
    Ultimate Work Authority (UWA) means the authority assigned to an 
individual or position to make final decisions relating to activities 
and operations on the facility.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]



Sec.  250.1904  Special instructions.

    (a) For purposes of this subpart, each and every reference in COS-2-
01, COS-

[[Page 299]]

2-03, and COS-2-04 (incorporated by reference as specified in Sec.  
250.198) to the term deepwater means the entire OCS, including all water 
depths.
    (b) The BSEE does not incorporate by reference any requirement that 
you must be a COS member company. For purposes of this subpart, each and 
every reference in COS-2-01, COS-2-03, and COS-2-04 to the phrase COS 
member company(ies) means you, whether or not you are a COS member.
    (c) For purposes of this subpart, each and every reference in the 
relevant sections of COS-2-01, COS-2-03, and COS-2-04 (incorporated by 
reference as specified in Sec.  250.198) to the Center for Offshore 
Safety or COS means accreditation body or AB.
    (d) For purposes of this subpart, each and every reference in ISO/
IEC 17011 (incorporated by reference as specified in Sec.  250.198) to 
conformity assessment body (CAB) means ASP.

[78 FR 20441, Apr. 5, 2013]



Sec. Sec.  250.1905-250.1908  [Reserved]



Sec.  250.1909  What are management's general responsibilities for
 the SEMS program?

    You, through your management, must require that the program elements 
discussed in API RP 75 (as incorporated by reference in Sec.  250.198) 
and in this subpart are properly documented and are available at field 
and office locations, as appropriate for each program element. You, 
through your management, are responsible for the development, support, 
continued improvement, and overall success of your SEMS program. 
Specifically you, through your management, must:
    (a) Establish goals and performance measures, demand accountability 
for implementation, and provide necessary resources for carrying out an 
effective SEMS program.
    (b) Appoint management representatives who are responsible for 
establishing, implementing and maintaining an effective SEMS program.
    (c) Designate specific management representatives who are 
responsible for reporting to management on the performance of the SEMS 
program.
    (d) At intervals specified in the SEMS program and at least 
annually, review the SEMS program to determine if it continues to be 
suitable, adequate and effective (by addressing the possible need for 
changes to policy, objectives, and other elements of the program in 
light of program audit results, changing circumstances and the 
commitment to continual improvement) and document the observations, 
conclusions and recommendations of that review.
    (e) Develop and endorse a written description of your safety and 
environmental policies and organizational structure that define 
responsibilities, authorities, and lines of communication required to 
implement the SEMS program.
    (f) Utilize personnel with expertise in identifying safety hazards, 
environmental impacts, optimizing operations, developing safe work 
practices, developing training programs and investigating incidents.
    (g) Ensure that facilities are designed, constructed, maintained, 
monitored, and operated in a manner compatible with applicable industry 
codes, consensus standards, and generally accepted practice as well as 
in compliance with all applicable governmental regulations.
    (h) Ensure that management of safety hazards and environmental 
impacts is an integral part of the design, construction, maintenance, 
operation, and monitoring of each facility.
    (i) Ensure that suitably trained and qualified personnel are 
employed to carry out all aspects of the SEMS program.
    (j) Ensure that the SEMS program is maintained and kept up to date 
by means of periodic audits to ensure effective performance.



Sec.  250.1910  What safety and environmental information is required?

    (a) You must require that SEMS program safety and environmental 
information be developed and maintained for any facility that is subject 
to the SEMS program.
    (b) SEMS program safety and environmental information must include:
    (1) Information that provides the basis for implementing all SEMS 
program elements, including the requirements of hazard analysis (Sec.  
250.1911);

[[Page 300]]

    (2) process design information including, as appropriate, a 
simplified process flow diagram and acceptable upper and lower limits, 
where applicable, for items such as temperature, pressure, flow and 
composition; and
    (3) mechanical design information including, as appropriate, piping 
and instrument diagrams; electrical area classifications; equipment 
arrangement drawings; design basis of the relief system; description of 
alarm, shutdown, and interlock systems; description of well control 
systems; and design basis for passive and active fire protection 
features and systems and emergency evacuation procedures.



Sec.  250.1911  What hazards analysis criteria must my SEMS program meet?

    You must ensure that a hazards analysis (facility level) and a JSA 
(operations/task level) are developed and implemented for all of your 
facilities and activities identified or discussed in your SEMS. You must 
document and maintain a current analysis for each operation covered by 
this section for the life of the operation at the facility. You must 
update the analysis when an internal audit is conducted to ensure that 
it is consistent with your facility's current operations.
    (a) Hazards analysis (facility level). The hazards analysis must be 
appropriate for the complexity of the operation and must identify, 
evaluate, and manage the hazards involved in the operation.
    (1) The hazards analysis must address the following:
    (i) Hazards of the operation;
    (ii) Previous incidents related to the operation you are evaluating, 
including any incident in which you were issued an Incident of 
Noncompliance or a civil or criminal penalty;
    (iii) Control technology applicable to the operation your hazards 
analysis is evaluating; and
    (iv) A qualitative evaluation of the possible safety and health 
effects on employees, and potential impacts to the human and marine 
environments, which may result if the control technology fails.
    (2) The hazards analysis must be performed by a person(s) with 
experience in the operations being evaluated. These individuals also 
need to be experienced in the hazards analysis methodologies being 
employed.
    (3) You should assure that the recommendations in the hazards 
analysis are resolved and that the resolution is documented.
    (4) A single hazards analysis can be performed to fulfill the 
requirements for simple and nearly identical facilities, such as well 
jackets and single well caissons. You can apply this single hazards 
analysis to simple and nearly identical facilities after you verify that 
any site-specific deviations are addressed in each of your SEMS program 
elements.
    (b) JSA. You must ensure a JSA is prepared, conducted, and approved 
for OCS activities that are identified or discussed in your SEMS 
program. The JSA is a technique used to identify risks to personnel 
associated with their job activities. The JSAs are also used to 
determine the appropriate mitigation measures needed to reduce job risks 
to personnel. The JSA must include all personnel involved with the job 
activity.
    (1) You must ensure that your JSA identifies, analyzes, and records:
    (i) The steps involved in performing a specific job;
    (ii) The existing or potential safety, health, and environmental 
hazards associated with each step; and
    (iii) The recommended action(s) and/or procedure(s) that will 
eliminate or reduce these hazards, the risk of a workplace injury or 
illness, or environmental impacts.
    (2) The immediate supervisor of the crew performing the job onsite 
must conduct the JSA, sign the JSA, and ensure that all personnel 
participating in the job understand and sign the JSA.
    (3) The individual you designate as being in charge of the facility 
must approve and sign all JSAs before personnel start the job.
    (4) If a particular job is conducted on a recurring basis, and if 
the parameters of these recurring jobs do not change, then the person in 
charge of the job may decide that a JSA for each individual job is not 
required. The parameters you must consider in making this

[[Page 301]]

determination include, but are not limited to, changes in personnel, 
procedures, equipment, and environmental conditions associated with the 
job.
    (c) All personnel, which includes contractors, must be trained in 
accordance with the requirements of Sec.  250.1915. You must also verify 
that contractors are trained in accordance with Sec.  250.1915 prior to 
performing a job.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]



Sec.  250.1912  What criteria for management of change must my
SEMS program meet?

    (a) You must develop and implement written management of change 
procedures for modifications associated with the following:
    (1) Equipment,
    (2) Operating procedures,
    (3) Personnel changes (including contractors),
    (4) Materials, and
    (5) Operating conditions.
    (b) Management of change procedures do not apply to situations 
involving replacement in kind (such as, replacement of one component by 
another component with the same performance capabilities).
    (c) You must review all changes prior to their implementation.
    (d) The following items must be included in your management of 
change procedures:
    (1) The technical basis for the change;
    (2) Impact of the change on safety, health, and the coastal and 
marine environments;
    (3) Necessary time period to implement the change; and
    (4) Management approval procedures for the change.
    (e) Employees, including contractors whose job tasks will be 
affected by a change in the operation, must be informed of, and trained 
in, the change prior to startup of the process or affected part of the 
operation; and
    (f) If a management of change results in a change in the operating 
procedures of your SEMS program, such changes must be documented and 
dated.



Sec.  250.1913  What criteria for operating procedures must my
 SEMS program meet?

    (a) You must develop and implement written operating procedures that 
provide instructions for conducting safe and environmentally sound 
activities involved in each operation addressed in your SEMS program. 
These procedures must include the job title and reporting relationship 
of the person or persons responsible for each of the facility's 
operating areas and address the following:
    (1) Initial startup;
    (2) Normal operations;
    (3) All emergency operations (including but not limited to medical 
evacuations, weather-related evacuations and emergency shutdown 
operations);
    (4) Normal shutdown;
    (5) Startup following a turnaround, or after an emergency shutdown;
    (6) Bypassing and flagging out-of-service equipment;
    (7) Safety and environmental consequences of deviating from your 
equipment operating limits and steps required to correct or avoid this 
deviation;
    (8) Properties of, and hazards presented by, the chemicals used in 
the operations;
    (9) Precautions you will take to prevent the exposure of chemicals 
used in your operations to personnel and the environment. The 
precautions must include control technology, personal protective 
equipment, and measures to be taken if physical contact or airborne 
exposure occurs;
    (10) Raw materials used in your operations and the quality control 
procedures you used in purchasing these raw materials;
    (11) Control of hazardous chemical inventory; and
    (12) Impacts to the human and marine environment identified through 
your hazards analysis.
    (b) Operating procedures must be accessible to all employees 
involved in the operations.
    (c) Operating procedures must be reviewed at the conclusion of 
specified periods and as often as necessary to assure they reflect 
current and actual operating practices, including any changes made to 
your operations.

[[Page 302]]

    (d) You must develop and implement safe and environmentally sound 
work practices for identified hazards during operations and the degree 
of hazard presented.
    (e) Review of and changes to the procedures must be documented and 
communicated to responsible personnel.



Sec.  250.1914  What criteria must be documented in my SEMS program 
for safe work practices and contractor selection?

    Your SEMS program must establish and implement safe work practices 
designed to minimize the risks associated with operations, maintenance, 
modification activities, and the handling of materials and substances 
that could affect safety or the environment. Your SEMS program must also 
document contractor selection criteria. When selecting a contractor, you 
must obtain and evaluate information regarding the contractor's safety 
record and environmental performance. You must ensure that contractors 
have their own written safe work practices. Contractors may adopt 
appropriate sections of your SEMS program. You and your contractor must 
document an agreement on appropriate contractor safety and environmental 
policies and practices before the contractor begins work at your 
facilities.
    (a) A contractor is anyone performing work for you. However, these 
requirements do not apply to contractors providing domestic services to 
you or other contractors. Domestic services include janitorial work, 
food and beverage service, laundry service, housekeeping, and similar 
activities.
    (b) You must document that your contracted employees are 
knowledgeable and experienced in the work practices necessary to perform 
their job in a safe and environmentally sound manner. Documentation of 
each contracted employee's expertise to perform his/her job and a copy 
of the contractor's safety policies and procedures must be made 
available to the operator and BSEE upon request.
    (c) Your SEMS program must include procedures and verification for 
selecting a contractor as follows:
    (1) Your SEMS program must have procedures that verify that 
contractors are conducting their activities in accordance with your SEMS 
program.
    (2) You are responsible for making certain that contractors have the 
skills and knowledge to perform their assigned duties and are conducting 
these activities in accordance with the requirements in your SEMS 
program.
    (3) You must make the results of your verification for selecting 
contractors available to BSEE upon request.
    (d) Your SEMS program must include procedures and verification that 
contractor personnel understand and can perform their assigned duties 
for activities such as, but not limited to:
    (1) Installation, maintenance, or repair of equipment;
    (2) Construction, startup, and operation of your facilities;
    (3) Turnaround operations;
    (4) Major renovation; or
    (5) Specialty work.
    (e) You must:
    (1) Perform periodic evaluations of the performance of contract 
employees that verifies they are fulfilling their obligations, and
    (2) Maintain a contractor employee injury and illness log for 2 
years related to the contractor's work in the operation area, and 
include this information on Form BSEE-0131.
    (f) You must inform your contractors of any known hazards at the 
facility they are working on including, but not limited to fires, 
explosions, slips, trips, falls, other injuries, and hazards associated 
with lifting operations.
    (g) You must develop and implement safe work practices to control 
the presence, entrance, and exit of contract employees in operation 
areas.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]



Sec.  250.1915  What training criteria must be in my SEMS program?

    Your SEMS program must establish and implement a training program so 
that all personnel are trained in accordance with their duties and 
responsibilities to work safely and are aware of potential environmental 
impacts. Training must address such areas as operating procedures (Sec.  
250.1913), safe work practices (Sec.  250.1914), emergency response and 
control measures (Sec.  250.1918), SWA (Sec.  250.1930), UWA

[[Page 303]]

(Sec.  250.1931), EPP (Sec.  250.1932), reporting unsafe working 
conditions (Sec.  250.1933), and how to recognize and identify hazards 
and how to construct and implement JSAs (Sec.  250.1911). You must 
document your instructors' qualifications. Your SEMS program must 
address:
    (a) Initial training for the basic well-being of personnel and 
protection of the environment, and ensure that persons assigned to 
operate and maintain the facility possess the required knowledge and 
skills to carry out their duties and responsibilities, including startup 
and shutdown.
    (b) Periodic training to maintain understanding of, and adherence 
to, the current operating procedures, using periodic drills, to verify 
adequate retention of the required knowledge and skills.
    (c) Communication requirements to ensure that personnel will be 
informed of and trained as outlined in this section whenever a change is 
made in any of the areas in your SEMS program that impacts their ability 
to properly understand and perform their duties and responsibilities. 
Training and/or notice of the change must be given before personnel are 
expected to operate the facility.
    (d) How you will verify that the contractors are trained in the work 
practices necessary to understand and perform their jobs in a safe and 
environmentally sound manner in accordance with all provisions of this 
section.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]



Sec.  250.1916  What criteria for mechanical integrity must my SEMS
 program meet?

    You must develop and implement written procedures that provide 
instructions to ensure the mechanical integrity and safe operation of 
equipment through inspection, testing, and quality assurance. The 
purpose of mechanical integrity is to ensure that equipment is fit for 
service. Your mechanical integrity program must encompass all equipment 
and systems used to prevent or mitigate uncontrolled releases of 
hydrocarbons, toxic substances, or other materials that may cause 
environmental or safety consequences. These procedures must address the 
following:
    (a) The design, procurement, fabrication, installation, calibration, 
and maintenance of your equipment and systems in accordance with the 
manufacturer's design and material specifications.
    (b) The training of each employee involved in maintaining your 
equipment and systems so that your employees can implement your 
mechanical integrity program.
    (c) The frequency of inspections and tests of your equipment and 
systems. The frequency of inspections and tests must be in accordance 
with BSEE regulations and meet the manufacturer's recommendations. 
Inspections and tests can be performed more frequently if determined to 
be necessary by prior operating experience.
    (d) The documentation of each inspection and test that has been 
performed on your equipment and systems. This documentation must 
identify the date of the inspection or test; include the name and 
position, and the signature of the person who performed the inspection 
or test; include the serial number or other identifier of the equipment 
on which the inspection or test was performed; include a description of 
the inspection or test performed; and the results of the inspection 
test.
    (e) The correction of deficiencies associated with equipment and 
systems that are outside the manufacturer's recommended limits. Such 
corrections must be made before further use of the equipment and system.
    (f) The installation of new equipment and constructing systems. The 
procedures must address the application for which they will be used.
    (g) The modification of existing equipment and systems. The 
procedures must ensure that they are modified for the application for 
which they will be used.
    (h) The verification that inspections and tests are being performed. 
The procedures must be appropriate to ensure that equipment and systems 
are installed consistent with design specifications and the 
manufacturer's instructions.

[[Page 304]]

    (i) The assurance that maintenance materials, spare parts, and 
equipment are suitable for the applications for which they will be used.



Sec.  250.1917  What criteria for pre-startup review must be in my 
SEMS program?

    Your SEMS program must require that the commissioning process 
include a pre-startup safety and environmental review for new and 
significantly modified facilities that are subject to this subpart to 
confirm that the following criteria are met:
    (a) Construction and equipment are in accordance with applicable 
specifications.
    (b) Safety, environmental, operating, maintenance, and emergency 
procedures are in place and are adequate.
    (c) Safety and environmental information is current.
    (d) Hazards analysis recommendations have been implemented as 
appropriate.
    (e) Training of operating personnel has been completed.
    (f) Programs to address management of change and other elements of 
this subpart are in place.
    (g) Safe work practices are in place.



Sec.  250.1918  What criteria for emergency response and control must
 be in my SEMS program?

    Your SEMS program must require that emergency response and control 
plans are in place and are ready for immediate implementation. These 
plans must be validated by drills carried out in accordance with a 
schedule defined by the SEMS training program (Sec.  250.1915). The SEMS 
emergency response and control plans must include:
    (a) Emergency Action Plan that assigns authority and responsibility 
to the appropriate qualified person(s) at a facility for initiating 
effective emergency response and control, addressing emergency reporting 
and response requirements, and complying with all applicable 
governmental regulations;
    (b) Emergency Control Center(s) designated for each facility with 
access to the Emergency Action Plans, oil spill contingency plan, and 
other safety and environmental information (Sec.  250.1910); and
    (c) Training and Drills incorporating emergency response and 
evacuation procedures conducted periodically for all personnel 
(including contractor's personnel), as required by the SEMS training 
program (Sec.  250.1915). Drills must be based on realistic scenarios 
conducted periodically to exercise elements contained in the facility or 
area emergency action plan. An analysis and critique of each drill must 
be conducted to identify and correct weaknesses.



Sec.  250.1919  What criteria for investigation of incidents must be
 in my SEMS program?

    To learn from incidents and help prevent similar incidents, your 
SEMS program must establish procedures for investigation of all 
incidents with serious safety or environmental consequences and require 
investigation of incidents that are determined by facility management or 
BSEE to have possessed the potential for serious safety or environmental 
consequences. Incident investigations must be initiated as promptly as 
possible, with due regard for the necessity of securing the incident 
scene and protecting people and the environment. Incident investigations 
must be conducted by personnel knowledgeable in the process involved, 
investigation techniques, and other specialties that are relevant or 
necessary.
    (a) The investigation of an incident must address the following:
    (1) The nature of the incident;
    (2) The factors (human or other) that contributed to the initiation 
of the incident and its escalation/control; and
    (3) Recommended changes identified as a result of the investigation.
    (b) A corrective action program must be established based on the 
findings of the investigation in order to analyze incidents for common 
root causes. The corrective action program must:
    (1) Retain the findings of investigations for use in the next hazard 
analysis update or audit;
    (2) Determine and document the response to each finding to ensure 
that corrective actions are completed; and

[[Page 305]]

    (3) Implement a system whereby conclusions of investigations are 
distributed to similar facilities and appropriate personnel within their 
organization.



Sec.  250.1920  What are the auditing requirements for my SEMS program?

    (a) Your SEMS program must be audited by an accredited ASP according 
to the requirements of this subpart and API RP 75, Section 12 
(incorporated by reference as specified in Sec.  250.198). The audit 
process must also meet or exceed the criteria in Sections 9.1 through 
9.8 of Requirements for Third-party SEMS Auditing and Certification of 
Deepwater Operations COS-2-03 (incorporated by reference as specified in 
Sec.  250.198) or its equivalent. Additionally, the audit team lead must 
be an employee, representative, or agent of the ASP, and must not have 
any affiliation with the operator. The remaining team members may be 
chosen from your personnel and those of the ASP. The audit must be 
comprehensive and include all elements of your SEMS program. It must 
also identify safety and environmental performance deficiencies.
    (b) Your audit plan and procedures must meet or exceed all of the 
recommendations included in API RP 75 section 12 (as specified in Sec.  
250.198) and include information on how you addressed those 
recommendations. You must specifically address the following items:
    (1) Section 12.1 General.
    (2) Section 12.2 Scope.
    (3) Section 12.3 Audit Coverage.
    (4) Section 12.4 Audit Plan. You must submit your written Audit Plan 
to BSEE at least 30 days before the audit. BSEE reserves the right to 
modify the list of facilities that you propose to audit.
    (5) Section 12.5 Audit Frequency. You must have your SEMS program 
audited by an ASP within 2 years after initial implementation and every 
3 years thereafter. The 3-year auditing cycle begins on the start date 
of each comprehensive audit (including the initial implementation audit) 
and ends on the start date of your next comprehensive audit. For 
exploratory drilling operations taking place on the Arctic OCS, you must 
conduct an audit, consisting of an onshore portion and an offshore 
portion, including all related infrastructure, once per year for every 
year in which drilling is conducted.
    (6) Section 12.6 Audit Team. Your audits must be performed by an ASP 
as described in Sec.  250.1921. You must include the ASP's 
qualifications in your audit plan.
    (c) You must submit an audit report of the audit findings, 
observations, deficiencies identified, and conclusions to BSEE within 60 
days of the audit completion date. For exploratory drilling operations 
taking place on the Arctic OCS, you must submit an audit report of the 
audit findings, observations, deficiencies and conclusions for the 
onshore portion of your audit no later than March 1 in any year in which 
you plan to drill, and for the offshore portion of your audit, within 30 
days of the close of the audit.
    (d) You must provide BSEE with a copy of your CAP for addressing the 
deficiencies identified in your audit within 60 days of the audit 
completion date. Your CAP must include the name and job title of the 
personnel responsible for correcting the identified deficiency(ies). The 
BSEE will notify you as soon as practicable after receipt of your CAP if 
your proposed schedule is not acceptable or if the CAP does not 
effectively address the audit findings. For exploratory drilling 
operations taking place on the Arctic OCS, you must provide BSEE with a 
copy of your CAP for addressing deficiencies or nonconformities 
identified in the onshore portion of the audit no later than March 1 in 
any year in which you plan to drill, and for the offshore portion of 
your audit, within 30 days of the close of the audit.
    (e) BSEE may verify that you undertook the corrective actions and 
that these actions effectively address the audit findings.
    (f) For exploratory drilling operations taking place on the Arctic 
OCS, during the offshore portion of each audit, 100 percent of the 
facilities operated must be audited while drilling activities are 
underway. You must start and close the offshore portion of the audit for 
each facility within 30 days after the first spudding of the well or

[[Page 306]]

entry into an existing wellbore for any purpose from that facility.
    (g) For exploratory drilling operations taking place on the Arctic 
OCS, if BSEE determines that the CAP or progress toward implementing the 
CAP is not satisfactory, BSEE may order you to shut down all or part of 
your operations.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013; 81 
FR 36151, June 6, 2016; 81 FR 46563, July 15, 2016]



Sec.  250.1921  What qualifications must the ASP meet?

    (a) The ASP must meet or exceed the qualifications, competency, and 
training criteria contained in Section 3 and Sections 6 through 10 of 
Qualification and Competence Requirements for Audit Teams and Auditors 
Performing Third-party SEMS Audits of Deepwater Operations, COS-2-01, 
(incorporated by reference as specified in Sec.  250.198) or its 
equivalent;
    (b) The ASP must be accredited by a BSEE-approved AB; and
    (c) The ASP must perform an audit in accordance with 250.1920(a).

[78 FR 20442, Apr. 5, 2013]



Sec.  250.1922  What qualifications must an AB meet?

    (a) In order for BSEE to approve an AB, the organization must 
satisfy the requirements of the International Organization for 
Standardization's (ISO/IEC 17011) Conformity assessment--General 
requirements for accreditation bodies accrediting conformity assessment 
bodies, First Edition 2004-09-01; Corrected Version 2005-02-15 
(incorporated by reference as specified in Sec.  250.198) or its 
equivalent.
    (1) The AB must have an accreditation process that meets or exceeds 
the requirements contained in Section 6 of Requirements for 
Accreditation of Audit Service Providers Performing SEMS Audits and 
Certification of Deepwater Operations, COS-2-04 (incorporated by 
reference as specified in Sec.  250.198) or its equivalent, and other 
requirements specified in this subpart. Organizations requesting 
approval must submit documentation to BSEE describing the process for 
assessing an ASP for accreditation and approving, maintaining, and 
withdrawing the accreditation of an ASP. Requests for approval must be 
sent to DOI/BSEE, ATTN: Chief, Office of Offshore Regulatory Programs, 
381 Elden Street, HE-3314, Herndon, VA 20170.
    (2) An AB may be subject to BSEE audits and other requirements 
deemed necessary to verify compliance with the accreditation 
requirements.
    (b) An AB must have procedures in place to avoid conflicts of 
interest with the ASP and make such information available to BSEE upon 
request.

[78 FR 20442, Apr. 5, 2013]



Sec.  250.1923  [Reserved]



Sec.  250.1924  How will BSEE determine if my SEMS program is effective?

    (a) The BSEE, or its authorized representative, may evaluate or 
visit your facility(ies) to determine whether your SEMS program is in 
place, addresses all required elements, is effective in protecting 
worker safety and health and the environment, and preventing incidents. 
The BSEE, or its authorized representative, may evaluate any and all 
aspects of your SEMS program as outlined in this subpart. These 
evaluations or visits may be random and may be based upon your 
performance or that of your contractors.
    (b) For the evaluations, you must make the following available to 
BSEE upon request:
    (1) Your SEMS program;
    (2) Your audit team's qualifications;
    (3) The SEMS audits conducted of your program;
    (4) Documents or information relevant to whether you have addressed 
and corrected the deficiencies of your audit; and
    (5) Other relevant documents or information.
    (c) During the site visit BSEE may verify that:
    (1) Personnel are following your SEMS program,
    (2) You can explain and demonstrate the procedures and policies 
included in your SEMS program; and
    (3) You can produce evidence to support the implementation of your 
SEMS program.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013]

[[Page 307]]



Sec.  250.1925  May BSEE direct me to conduct additional audits?

    (a) The BSEE may direct you to have an ASP audit of your SEMS 
program if BSEE identifies safety or non-compliance concerns based on 
the results of our inspections and evaluations, or as a result of an 
event. This BSEE-directed audit is in addition to the regular audit 
required by Sec.  250.1920. Alternatively, BSEE may conduct an audit.
    (1) If BSEE directs you to have an ASP audit, you are responsible 
for all of the costs associated with the audit, and
    (i) The ASP must meet the requirements of Sec. Sec.  250.1920 and 
250.1921 of this subpart.
    (ii) You must submit an audit report of the audit findings, 
observations, deficiencies identified, and conclusions to BSEE within 60 
days of the audit completion date.
    (2) If BSEE conducts the audit, BSEE will provide you with a report 
of the audit findings, observations, deficiencies identified, and 
conclusions as soon as practicable.
    (b) You must provide BSEE a copy of your CAP for addressing the 
deficiencies identified in the BSEE-directed audit within 60 days of the 
audit completion date. Your CAP must include the name and job title of 
the personnel responsible for correcting the identified deficiency(ies). 
The BSEE will notify you as soon as practicable after receipt of your 
CAP if your proposed schedule is not acceptable or if the CAP does not 
effectively address the audit findings.

[78 FR 20442, Apr. 5, 2013]



Sec.  250.1926  [Reserved]



Sec.  250.1927  What happens if BSEE finds shortcomings in my
 SEMS program?

    If BSEE determines that your SEMS program is not in compliance with 
this subpart we may initiate one or more of the following enforcement 
actions:
    (a) Issue an Incident(s) of Noncompliance;
    (b) Assess civil penalties; or
    (c) Initiate probationary or disqualification procedures from 
serving as an OCS operator.



Sec.  250.1928  What are my recordkeeping and documentation
 requirements?

    (a) Your SEMS program procedures must ensure that records and 
documents are maintained for a period of 6 years, except as provided 
below. You must document and keep all SEMS audits for 6 years and make 
them available to BSEE upon request. You must maintain a copy of all 
SEMS program documents at an onshore location.
    (b) For JSAs, the person in charge of the job must document the 
results of the JSA in writing and must ensure that records are kept 
onsite for 30 days. In the case of a MODU, records must be kept onsite 
for 30 days or until you release the MODU, whichever comes first. You 
must retain these records for 2 years and make them available to BSEE 
upon request.
    (c) You must document and date all management of change provisions 
as specified in Sec.  250.1912. You must retain these records for 2 
years and make them available to BSEE upon request.
    (d) You must keep your injury/illness log for 2 years and make them 
available to BSEE upon request.
    (e) You must keep all evaluations completed on contractor's safety 
policies and procedures for 2 years and make them available to BSEE upon 
request.
    (f) For SWA, you must document all training and reviews required by 
Sec.  250.1930(e). You must ensure that these records are kept onsite 
for 30 days. In the case of a MODU, records must be kept onsite for 30 
days or until you release the MODU, whichever comes first. You must 
retain these records for 2 years and make them available to BSEE upon 
request.
    (g) For EPP, you must document your employees' participation in the 
development and implementation of the SEMS program. You must retain 
these records for 2 years and make them available to BSEE upon request.
    (h) You must keep all records in an orderly manner, readily 
identifiable, retrievable and legible, and include the date of any and 
all revisions.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013]

[[Page 308]]



Sec.  250.1929  What are my responsibilities for submitting OCS 
performance measure data?

    You must submit Form BSEE-0131 on an annual basis by March 31st. The 
form must be broken down quarterly, reporting the previous calendar 
year's data.



Sec.  250.1930  What must be included in my SEMS program for SWA?

    (a) Your SWA procedures must ensure the capability to immediately 
stop work that is creating imminent risk or danger. These procedures 
must grant all personnel the responsibility and authority, without fear 
of reprisal, to stop work or decline to perform an assigned task when an 
imminent risk or danger exists. Imminent risk or danger means any 
condition, activity, or practice in the workplace that could reasonably 
be expected to cause:
    (1) Death or serious physical harm; or
    (2) Significant environmental harm to:
    (i) Land;
    (ii) Air; or
    (iii) Mineral deposits, marine, coastal, or human environment.
    (b) The person in charge of the conducted work is responsible for 
ensuring the work is stopped in an orderly and safe manner. Individuals 
who receive a notification to stop work must comply with that direction 
immediately.
    (c) Work may be resumed when the individual on the facility with UWA 
determines that the imminent risk or danger does not exist or no longer 
exists. The decision to resume activities must be documented in writing 
as soon as practicable.
    (d) You must include SWA procedures and expectations as a standard 
statement in all JSAs.
    (e) You must conduct training on your SWA procedures as part of 
orientations for all new personnel who perform activities on the OCS. 
Additionally, the SWA procedures must be reviewed during all meetings 
focusing on safety on facilities subject to this subpart.

[78 FR 20443, Apr. 5, 2013]



Sec.  250.1931  What must be included in my SEMS program for UWA?

    (a) Your SEMS program must have a process to identify the individual 
with the UWA on your facility(ies). You must designate this individual 
taking into account all applicable USCG regulations that deal with 
designating a person in charge of an OCS facility. Your SEMS program 
must clearly define who is in charge at all times. In the event that 
multiple facilities, including a MODU, are attached and working together 
or in close proximity to one another to perform an OCS operation, your 
SEMS program must identify the individual with the UWA over the entire 
operation, including all facilities.
    (b) You must ensure that all personnel clearly know who has UWA and 
who is in charge of a specific operation or activity at all times, 
including when that responsibility shifts to a different individual.
    (c) The SEMS program must provide that if an emergency occurs that 
creates an imminent risk or danger to the health or safety of an 
individual, the public, or to the environment (as specified in Sec.  
250.1930(a)), the individual with the UWA is authorized to pursue the 
most effective action necessary in that individual's judgment for 
mitigating and abating the conditions or practices causing the 
emergency.

[78 FR 20443, Apr. 5, 2013]



Sec.  250.1932  What are my EPP requirements?

    (a) Your management must consult with their employees on the 
development, implementation, and modification of your SEMS program.
    (b) Your management must develop a written plan of action regarding 
how your appropriate employees, in both your offices and those working 
on offshore facilities, will participate in your SEMS program 
development and implementation.
    (c) Your management must ensure that employees have access to 
sections of your SEMS program that are relevant to their jobs.

[78 FR 20443, Apr. 5, 2013]

[[Page 309]]



Sec.  250.1933  What procedures must be included for reporting
 unsafe working conditions?

    (a) Your SEMS program must include procedures for all personnel to 
report unsafe working conditions in accordance with Sec.  250.193. These 
procedures must take into account applicable USCG reporting requirements 
for unsafe working conditions.
    (b) You must post a notice at the place of employment in a visible 
location frequently visited by personnel that contains the reporting 
information in Sec.  250.193.

[78 FR 20443, Apr. 5, 2013]



PART 251_GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF 
THE OUTER CONTINENTAL SHELF--Table of Contents



Sec.
251.1 Definitions.
251.2 [Reserved]
251.3 Authority and applicability of this part.
251.4-251.6 [Reserved]
251.7 Test drilling activities under a permit.
251.8-251.14 [Reserved]
251.15 Authority for information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



Sec.  251.1  Definitions.

    Terms used in this part have the following meaning:
    Act means the Outer Continental Shelf Lands Act (OCSLA), as amended 
(43 U.S.C. 1331 et seq.).
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurements, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resources mean any material remains of human life or 
activities that are at least 50 years of age and of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal Zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder), strongly influenced by each other and in 
proximity to the shorelines of the several coastal States and extends 
seaward to the outer limit of the U.S. territorial sea.
    Coastal Zone Management Act means the Coastal Zone Management Act of 
1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts, statistics, measurements, or samples that have not 
been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the penetration 
into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Safety and 
Environmental Enforcement, U.S. Department of the Interior, or a 
subordinate authorized to act on the Director's behalf.
    Exploration means the commercial search for oil, gas, and sulphur. 
Activities classified as exploration include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, 
coring, or other systems are used to detect or imply the presence of 
oil, gas, or sulphur; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical scientific research means any oil, gas, 
or sulphur related investigation conducted in the OCS for scientific 
and/or research purposes. Geological, geophysical, and geochemical data 
and information

[[Page 310]]

gathered and analyzed are made available to the public for inspection 
and reproduction at the earliest practicable time. The term does not 
include commercial geological or geophysical exploration or research.
    Geological exploration means exploration that uses geological and 
geochemical techniques (e.g., coring and test drilling, well logging, 
and bottom sampling) to produce data and information on oil, gas, and 
sulphur resources in support of possible exploration and development 
activities. The term does not include geological scientific research.
    Geological information means geological or geochemical data that 
have been analyzed, processed, or interpreted.
    Geophysical data means measurements that have not been processed or 
interpreted.
    Geophysical exploration means exploration that utilizes geophysical 
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to 
produce data and information on oil, gas, and sulphur resources in 
support of possible exploration and development activities. The term 
does not include geophysical scientific research.
    Geophysical information means geophysical data that have been 
processed or interpreted.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a Governor 
pursuant to the Act.
    Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Hydrocarbon occurrence means the direct or indirect detection during 
drilling operations of any liquid or gaseous hydrocarbons by examination 
of well cuttings, cores, gas detector readings, formation fluid tests, 
wireline logs, or by any other means. The term does not include 
background gas, minor accumulations of gas, or heavy oil residues on 
cuttings and cores.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of geological 
data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and maps, 
developed by determining the geological significance of geophysical data 
and processed geophysical information.
    Lease means an agreement which is issued under section 8 or 
maintained under section 6 of the Act and which authorizes exploration 
for, and development and production of, minerals or the area covered by 
that authorization, whichever is required by the context.
    Lessee means a person who has entered into, or is the BOEM approved 
assignee of, a lease with the United States to explore for, develop, and 
produce the leased minerals. The term ``lessee'' also includes an owner 
of operating rights.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
quality of the marine ecosystem in the coastal zone and in the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals mean oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from public lands as defined in section 
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 
1702).
    Notice means a written statement of intent to conduct geological or 
geophysical scientific research related to oil, gas, and sulphur in the 
OCS other than under a permit.
    Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-
geothermal, and associated resources.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C.

[[Page 311]]

1301), and of which the subsoil and seabed appertain to the United 
States and are subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
pursuant to this part, under which a person acquires the right to 
conduct on the OCS, in accordance with appropriate statutes, 
regulations, and stipulations:
    (1) Geological exploration for mineral resources;
    (2) Geophysical exploration for mineral resources;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued pursuant to 
this part to conduct activities on the OCS.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residence in the United States as 
defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; and associations of such citizens, 
nationals, resident aliens, or private, public, or municipal 
corporations, States, or political subdivisions of States or anyone 
operating in a manner provided for by treaty or other applicable 
international agreements. The term does not include Federal agencies.
    Processed geological or geophysical information means data collected 
under a permit and later processed or reprocessed. Processing involves 
changing the form of data so as to facilitate interpretation. Processing 
operations may include, but are not limited to, applying corrections for 
known perturbing causes, rearranging or filtering data, and combining or 
transforming data elements. Reprocessing is the additional processing 
other than ordinary processing used in the general course of evaluation. 
Reprocessing operations may include varying identified parameters for 
the detailed study of a specific problem area. Reprocessing may occur 
several years after the original processing date. Reprocessing is 
determined to be completed on the date that the reprocessed information 
is first available in a useable format for in-house interpretation by 
BOEM or the permittee, or becomes first available to third parties via 
sale, trade, license agreement, or other means.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4.
    Third Party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    Violation means a failure to comply with any provision of the Act, 
or a provision of a regulation or order issued under the Act, or any 
provision of a lease, license, or permit issued under the Act.
    You means a person who applies for and/or obtains a permit, or files 
a Notice to conduct geological or geophysical exploration or scientific 
research related to oil, gas, and sulphur in the OCS.



Sec.  251.2  [Reserved]



Sec.  251.3  Authority and applicability of this part.

    BSEE authorizes you to conduct exploration or scientific research 
activities under this part in accordance with the Act, the regulations 
in this part, orders of the Director/Regional Director, and other 
applicable statutes, regulations, and amendments.
    (a) This part does not apply to G&G exploration conducted by or on 
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 550 if 
you plan to conduct G&G activities related to oil, gas, or sulphur under 
terms of a lease.
    (b) Federal agencies are exempt from the regulations in this part.
    (c) G&G exploration or G&G scientific research related to minerals

[[Page 312]]

other than oil, gas, and sulphur is covered by regulations at 30 CFR 
part 580.



Sec. Sec.  251.4-251.6  [Reserved]



Sec.  251.7  Test drilling activities under a permit.

    (a) [Reserved]
    (b) Deep stratigraphic tests. You must submit to the appropriate 
BOEM or BSEE Regional Director, at the address in 30 CFR 551.5(d) for 
BOEM or 30 CFR 254.7 for BSEE, a drilling plan (submitted to BOEM), an 
environmental report (submitted to BOEM), an Application for Permit to 
Drill (Form BSEE-0123) (submitted to BSEE), and a Supplemental APD 
Information Sheet (Form BSEE-0123S) (submitted to BSEE) as follows:
    (1) Drilling plan. The drilling plan must include:
    (i) The proposed type, sequence, and timetable of drilling 
activities;
    (ii) A description of your drilling rig, indicating the important 
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
    (iii) The location of each deep stratigraphic test you will conduct, 
including the location of the surface and projected bottomhole of the 
borehole;
    (iv) The types of geological and geophysical survey instruments you 
will use before and during drilling;
    (v) Seismic, bathymetric, sidescan sonar, magnetometer, or other 
geophysical data and information sufficient to evaluate seafloor 
characteristics, shallow geologic hazards, and structural detail across 
and in the vicinity of the proposed test to the total depth of the 
proposed test well; and
    (vi) Other relevant data and information that the BOEM Regional 
Director requires.
    (2) Environmental report. The environmental report must include all 
of the following material:
    (i) A summary with data and information available at the time you 
submitted the related drilling plan. BOEM will consider site-specific 
data and information developed since the most recent environmental 
impact statement or other environmental impact analysis in the immediate 
area. The summary must meet the following requirements:
    (A) You must concentrate on the issues specific to the site(s) of 
drilling activity. However, you only need to summarize data and 
information discussed in any environmental reports, analyses, or impact 
statements prepared for the geographic area of the drilling activity.
    (B) You must list referenced material. Include brief descriptions 
and a statement of where the material is available for inspection.
    (C) You must refer only to data that are available to BOEM.
    (ii) Details about your project such as:
    (A) A list and description of new or unusual technologies;
    (B) The location of travel routes for supplies and personnel;
    (C) The kinds and approximate levels of energy sources;
    (D) The environmental monitoring systems; and
    (E) Suitable maps and diagrams showing details of the proposed 
project layout.
    (iii) A description of the existing environment. For this section, 
you must include the following information on the area:
    (A) Geology;
    (B) Physical oceanography;
    (C) Other uses of the area;
    (D) Flora and fauna;
    (E) Existing environmental monitoring systems; and
    (F) Other unusual or unique characteristics that may affect or be 
affected by the drilling activities.
    (iv) A description of the probable impacts of the proposed action on 
the environment and the measures you propose for mitigating these 
impacts.
    (v) A description of any unavoidable or irreversible adverse effects 
on the environment that could occur.
    (vi) Other relevant data that the BOEM Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the BOEM Regional Director for 
transmittal to the Governor of each affected coastal State and the 
coastal zone management agency of each affected coastal State that has 
an approved program under

[[Page 313]]

the Coastal Zone Management Act. (The BOEM Regional Director will make 
the drilling plan and environmental report available to appropriate 
Federal agencies and the public according to the Department of the 
Interior's policies and procedures).
    (4) Certification of coastal zone management program consistency and 
State concurrence. When required under an approved coastal zone 
management program of an affected State, your drilling plan must include 
a certification that the proposed activities described in the plan 
comply with enforceable policies of, and will be conducted in a manner 
consistent with such State's program. The BOEM Regional Director may not 
approve any of the activities described in the drilling plan unless the 
State concurs with the consistency certification or the Secretary of 
Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of 
the Coastal Zone Management Act.
    (5) Protecting archaeological resources. If the BOEM Regional 
Director believes that an archaeological resource may exist in the area 
that may be affected by drilling, the BOEM Regional Director will notify 
you of the need to prepare an archaeological report under 30 CFR 
551.7(b)(5).
    (i) If the evidence suggests that an archaeological resource may be 
present, you must:
    (A) Locate the site of the drilling so as to not adversely affect 
the area where the archaeological resources may be, or
    (B) Establish to the satisfaction of the BOEM Regional Director that 
an archaeological resource does not exist or will not be adversely 
affected by drilling. This must be done by further archaeological 
investigation, conducted by an archaeologist and a geophysicist, using 
survey equipment and techniques deemed necessary by the Regional 
Director. A report on the investigation must be submitted to the BOEM 
Regional Director for review.
    (ii) If the BOEM Regional Director determines that an archaeological 
resource is likely to be present in the area that may be affected by 
drilling, and may be adversely affected by drilling, the BOEM Regional 
Director will notify you immediately. You must take no action that may 
adversely affect the archaeological resource unless further 
investigations determine that the resource is not archaeologically 
significant.
    (iii) If you discover any archaeological resource while drilling, 
you must immediately halt drilling and report the discovery to the BOEM 
Regional Director. If investigations determine that the resource is 
significant, the BOEM Regional Director will inform you how to protect 
it.
    (6) Application for permit to drill (APD). Before commencing deep 
stratigraphic test drilling activities under an approved drilling plan, 
you must submit an APD and a Supplemental APD Information Sheet (Forms 
BSEE-0123 and BSEE-0123S) and receive approval. You must comply with all 
regulations relating to drilling operations in 30 CFR part 250.
    (7) Revising an approved drilling plan. Before you revise an 
approved drilling plan, you must obtain the BOEM Regional Director's 
approval.
    (8) After drilling. When you complete the test activities, you must 
permanently plug and abandon the boreholes of all deep stratigraphic 
tests in compliance with 30 CFR part 250. If the tract on which you 
conducted a deep stratigraphic test is leased to another party for 
exploration and development, and if the lessee has not disturbed the 
borehole, BSEE will hold you and not the lessee responsible for problems 
associated with the test hole.
    (9) Deadline for completing a deep stratigraphic test. If your deep 
stratigraphic test well is within 50 geographic miles of a tract that 
BOEM has identified for a future lease sale, as listed on the currently 
approved OCS leasing schedule, you must complete all drilling activities 
and submit the data and information to the BOEM Regional Director at 
least 60 days before the first day of the month in which BOEM schedules 
the lease sale. However, the BOEM Regional Director may extend your 
permit duration to allow you to complete drilling activities and submit 
data and information if the extension is in the National interest.
    (c)-(d) [Reserved]

[[Page 314]]



Sec. Sec.  251.8-251.14  [Reserved]



Sec.  251.15  Authority for information collection.

    The Office of Management and Budget has approved the information 
collection requirements in this part under 44 U.S.C. 3501 et seq. and 
assigned OMB control number 1014-0025 as it pertains to Application for 
Permit to Drill (APD, Form BSEE-0123), and Supplemental APD Information 
Sheet (Form BSEE-0123S). The title of this information collection is 
``30 CFR Part 250, Application for Permit to Drill (APD, Revised APD) 
Supplemental APD Information Sheet, and all supporting documents.''

[81 FR 36151, June 6, 2016]



PART 252_OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION 
PROGRAM--Table of Contents



Sec.
252.1 Purpose.
252.2 Definitions.
252.3 Oil and gas data and information to be provided for use in the OCS 
          Oil and Gas Information Program.
252.4 Summary Report to affected States.
252.5 Information to be made available to affected States.
252.6 Freedom of Information Act requirements.
252.7 Privileged and proprietary data and information to be made 
          available to affected States.

    Authority: OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92 
Stat. 629; Freedom of Information Act, 5 U.S.C. 552; Sec.  252.3 also 
issued under Pub. L. 99-190 making continuing appropriations for Fiscal 
Year 1986, and for other purposes.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



Sec.  252.1  Purpose.

    The purpose of this part is to implement the provisions of section 
26 of the Act (43 U.S.C. 1352). This part supplements the procedures and 
requirements contained in 30 CFR parts 250, 251, 550, and 551 and 
provides procedures and requirements for the submission of oil and gas 
data and information resulting from exploration, development, and 
production operations on the Outer Continental Shelf (OCS) to the 
Director, Bureau of Safety and Environmental Enforcement (BSEE). In 
addition, this part establishes procedures for the Director to make 
available certain information to the Governors of affected States and, 
upon request, to the executives of affected local governments in 
accordance with the provisions of the Freedom of Information Act and the 
Act.



Sec.  252.2  Definitions.

    When used in the regulations in this part, the following terms shall 
have the following meanings:
    Act refers to the Outer Continental Shelf Lands Act, as amended (43 
U.S.C. 1331 et seq.).
    Affected local government means the principal governing body of a 
locality which is in an affected State and is identified by the Governor 
of that State as a locality which will be significantly affected by oil 
and gas activities on the OCS.
    Affected State means, with respect to any program, plan, lease sale, 
or other activity, proposed, conducted, or approved pursuant to the 
provisions of the Act, any State:
    (1) The laws of which are declared, pursuant to section 4(a)(2)(A) 
of the Act, to be the law of the United States for the portion of the 
OCS on which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installations and 
other devices permanently, or temporarily attached to the seabed;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Director as a State in which there is 
a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and

[[Page 315]]

production of oil and gas anywhere on the OCS; or
    (5) In which the Director finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Analyzed geological information means data collected under a permit 
or a lease which have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, logs 
or charts of electrical, radioactive, sonic, and other well logs, and 
descriptions of hydrocarbon shows or hazardous conditions.
    Area adjacent to a State means all of that portion of the OCS 
included within a planning area if such planning area is bordered by 
that State. The portion of the OCS in the Navarin Basin Planning Area is 
deemed to be adjacent to the State of Alaska. The States of New York and 
Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning 
Area and the North Atlantic Planning Area.
    Data means facts and statistics or samples which have not been 
analyzed or processed.
    Development means those activities which take place following 
discovery of oil or natural gas in paying quantities, including 
geophysical activity, drilling, platform construction, and operation of 
all onshore support facilities, and which are for the purpose of 
ultimately producing the oil and gas discovered.
    Director means the Director of the Bureau of Safety and 
Environmental Enforcement (BSEE) of the U.S. Department of the Interior 
or a designee of the Director.
    Exploration means the process of searching for oil and natural gas, 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of such oil or natural 
gas, and
    (2) Any drilling, whether on or off known geological structures, 
including the drilling of a well in which a discovery of oil or natural 
gas in paying quantities is made and the drilling of any additional 
delineation well after such discovery which is needed to delineate any 
reservoir and to enable the lessee to determine whether to proceed with 
development and production.
    Governor means the Governor of a State, or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to a Governor pursuant to the Act.
    Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of data and analyzed geological information.
    Interpreted geophysical information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of geophysical data and processed geophysical 
information.
    Lease means any form of authorization which is issued under section 
8 or maintained under section 6 of the Act and which authorizes 
exploration for, and development and production of, oil or natural gas, 
or the land covered by such authorization, whichever is required by the 
context.
    Lessee means the party authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in 30 CFR part 550, 
including all parties holding such authority by or through the lessee.
    Outer Continental Shelf (OCS) means all submerged lands which lie 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (67 Stat. 29) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Permittee means the party authorized by a permit issued pursuant to 
30 CFR parts 251 and 551 to conduct activities on the OCS.

[[Page 316]]

    Processed geophysical information means data collected under a 
permit or a lease which have been processed. Processing involves 
changing the form of data so as to facilitate interpretation. Processing 
operations may include, but are not limited to, applying corrections for 
known perturbing causes, rearranging or filtering data, and combining or 
transforming data elements.
    Production means those activities which take place after the 
successful completion of any means for the removal of oil or natural 
gas, including such removal, field operations, transfer of oil or 
natural gas to shore, operation monitoring, maintenance, and workover 
drilling.
    Secretary means the Secretary of the Interior or a designee of the 
Secretary.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]



Sec.  252.3  Oil and gas data and information to be provided for
 use in the OCS Oil and Gas Information Program.

    (a) Any permittee or lessee engaging in the activities of 
exploration for, or development and production of, oil and gas on the 
OCS shall provide the Director access to all data and information 
obtained or developed as a result of such activities, including 
geological data, geophysical data, analyzed geological information, 
processed and reprocessed geophysical information, interpreted 
geophysical information, and interpreted geological information. Copies 
of these data and information and any interpretation of these data and 
information shall be provided to the Director upon request. No permittee 
or lessee submitting an interpretation of data or information, where 
such interpretation has been submitted in good faith, shall be held 
responsible for any consequence of the use of or reliance upon such 
interpretation.
    (b)(1) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program in a form and manner of 
processing which is utilized by the lessee or permittee in the normal 
conduct of business, the Director shall pay the reasonable cost of 
reproducing the data and information if the lessee or permittee requests 
reimbursement. The cost shall be computed and paid in accordance with 
the applicable provisions of paragraph (e)(1) of this section.
    (2) Whenever a lessee or permittee provides any data or information, 
at the request of the Director and specifically for use in the OCS Oil 
and Gas Information Program, in a form and manner of processing not 
normally utilized by the lessee or permittee in the normal conduct of 
business, the Director shall pay the lessee or permittee, if the lessee 
or permittee requests reimbursement, the reasonable cost of processing 
and reproducing the requested data and information. The cost is to be 
computed and paid in accordance with the applicable provisions of 
paragraph (e)(2) of this section.
    (c) Data or information requested by the Director shall be provided 
as soon as practicable, but not later than 30 days following receipt of 
the Director's request, unless, for good reason, the Director authorizes 
a longer time period for the submission of the requested data or 
information.
    (d) The Director reserves the right to disclose any data or 
information acquired from a lessee or permittee to an independent 
contractor or agent for the purpose of reproducing, processing, 
reprocessing, or interpreting such data or information. When 
practicable, the Director shall notify the lessee(s) or permittee(s) who 
provided the data or information of the intent to disclose the data or 
information to an independent contractor or agent. The Director's notice 
of intent will afford the permittee(s) or lessee(s) a period of not less 
than 5 working days within which to comment on the intended action. When 
the Director so notifies a lessee or permittee of the intent to disclose 
data or information to an independent contractor or agent, all other 
owners of such data or information shall be deemed to have been notified 
of the Director's intent. Prior to any such disclosure, the contractor 
or agent shall be required to execute a written commitment not to 
disclose any data or information to anyone without the express consent 
of the Director, and not to make any disclosure or use of the data or 
information other than that

[[Page 317]]

provided in the contract. Contracts between BSEE and independent 
contractors shall be available to the lessee(s) or permittee(s) for 
inspection. In the event of any unauthorized use or disclosure of data 
or information by the contractor or agent, or by an employee thereof, 
the responsible contractor or agent or employee thereof shall be liable 
for penalties pursuant to section 24 of the Act.
    (e)(1) After delivery of data or information in accordance with 
paragraph (b)(1) of this section and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of reproducing the data or information at the lessee's or 
permittee's lowest rate or at the lowest commercial rate established in 
the area, whichever is less. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information requested 
under paragraph (b)(1) of this section.
    (2) After delivery of data or information in accordance with 
paragraph (b)(3) of this section, and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of processing or reprocessing and of reproducing the requested 
data or information. Requests for reimbursement must be made within 60 
days of the delivery date of the data or information and shall be for 
only the costs attributable to processing or reprocessing and 
reproducing, as distinguished from the costs of data acquisition.
    (3) Requests for reimbursement are to contain a breakdown of costs 
in sufficient detail to allow separation of reproduction, processing, 
and reprocessing costs from acquisition and other costs.
    (f) Each Federal Department or Agency shall provide the Director 
with any data which it has obtained pursuant to section 11 of the Act 
and any other information which may be necessary or useful to assist the 
Director in carrying out the provisions of the Act.



Sec.  252.4  Summary Report to affected States.

    (a) The Director, as soon as practicable after analysis, 
interpretation, and compilation of oil and gas data and information 
developed by BSEE or furnished by lessees, permittees, or other 
government agencies, shall make available to affected States and, upon 
request, to the executive of any affected local government, a Summary 
Report of data and information designed to assist them in planning for 
the onshore impacts of potential OCS oil and gas development and 
production. The Director shall consult with affected States and other 
interested parties to define the nature, scope, content, and timing of 
the Summary Report. The Director may consult with affected States and 
other interested parties regarding subsequent revisions in the 
definition of the nature, scope, content, and timing of the Summary 
Report. The Summary Report shall not contain data or information which 
the Director determines is exempt from disclosure in accordance with 
this part. The Summary Report shall not contain data or information the 
release of which the Director determines would unduly damage the 
competitive position of the lessee or permittee who provided the data or 
information which the Director has processed, analyzed, or interpreted 
during the development of the Summary Report. The Summary Report shall 
include:
    (1) Estimates of oil and gas reserves; estimates of the oil and gas 
resources that may be found within areas which the Secretary has leased 
or plans to offer for lease; and when available, projected rates and 
volumes of oil and gas to be produced from leased areas;
    (2) Magnitude of the approximate projections and timing of 
development, if and when oil or gas, or both, is discovered;
    (3) Methods of transportation to be used, including vessels and 
pipelines and approximate location of routes to be followed; and
    (4) General location and nature of near-shore and onshore facilities 
expected to be utilized.
    (b) When the Director determines that significant changes have 
occurred

[[Page 318]]

in the information contained in a Summary Report, the Director shall 
prepare and make available the new or revised information to each 
affected State, and, upon request, to the executive of any affected 
local government.



Sec.  252.5  Information to be made available to affected States.

    (a) The BOEM Director shall prepare an index of OCS information (see 
30 CFR 556.10). The index shall list all relevant actual or proposed 
programs, plans, reports, environmental impact statements, nominations 
information, environmental study reports, lease sale information, and 
any similar type of relevant information, including modifications, 
comments, and revisions prepared or directly obtained by the Director 
under the Act. The index shall be sent to affected States and, upon 
request, to any affected local government. The public shall be informed 
of the availability of the index.
    (b) Upon request, the Director shall transmit to affected States, 
affected local governments, and the public a copy of any information 
listed in the index which is subject to the control of BOEM, in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C.552) and implementing regulations. 
The Director shall not transmit or make available any information which 
he determines is exempt from disclosure in accordance with this part.



Sec.  252.6  Freedom of Information Act requirements.

    (a) The Director shall make data and information available in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552), the regulations contained in 
43 CFR part 2 (Records and Testimony), the requirements of the Act, and 
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and 
Sulphur Operations in the Outer Continental Shelf) and 30 CFR parts 251 
and 551 (Geological and Geophysical Explorations of the Outer 
Continental Shelf).
    (b) Except as provided in Sec.  252.7 or in 30 CFR parts 250, 251, 
550, and 551, no data or information determined by the Director to be 
exempt from public disclosure under paragraph (a) of this section shall 
be provided to any affected State or be made available to the executive 
of any affected local government or to the public unless the lessee, or 
the permittee and all persons to whom such permittee has sold such data 
or information under promise of confidentiality, agree to such action.



Sec.  252.7  Privileged and proprietary data and information to be
 made available to affected States.

    (a)(1) The Governor of any affected State may designate an 
appropriate State official to inspect, at a regional location which the 
Director shall designate, any privileged or proprietary data or 
information received by the Director regarding any activity in an area 
adjacent to such State, except that no such inspection shall take place 
prior to the sale of a lease covering the area in which such activity 
was conducted.
    (2)(i) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and 
30 CFR 551.14, no privileged or proprietary data or information will be 
transmitted to any affected State unless the lessee who provided the 
privileged or proprietary data or information agrees in writing to the 
transmittal of the data or information.
    (ii) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and 
30 CFR 551.14, no privileged or proprietary data or information will be 
transmitted to any affected State unless the permittee and all persons 
to whom the permittee has sold the data or information under promise of 
confidentiality agree in writing to the transmittal of the data or 
information.
    (3) Knowledge obtained by a State official who inspects data or 
information under paragraph (a)(1) or who receives data or information 
under paragraph (a)(2) of this section shall be subject to the 
requirements and limitations of the Freedom of Information Act (5 U.S.C. 
552), the regulations contained in 43 CFR part 2 (Records and 
Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR 
parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer 
Continental Shelf), the regulations contained in 30 CFR

[[Page 319]]

parts 251 and 551 (Geological and Geophysical Explorations of the Outer 
Continental Shelf), and the regulations contained in 30 CFR parts 252 
and 552 (Outer Continental Shelf Oil and Gas Information Program).
    (4) Prior to the transmittal of any privileged or proprietary data 
or information to any State, or the grant of access to a State official 
to such data or information, the Secretary shall enter into a written 
agreement with the Governor of the State in accordance with section 
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall 
agree, as a condition precedent to receiving or being granted access to 
such data or information to: (i) Protect and maintain the 
confidentiality of privileged or proprietary data and information in 
accordance with the laws and regulations listed in paragraph (a)(3) of 
this section;
    (ii) Waive the defenses as set forth in paragraph (b)(2) of this 
section; and
    (iii) Hold the United States harmless from any violations of the 
agreement to protect the confidentiality of privileged or proprietary 
data or information by the State or its employees or contractors.
    (b)(1) Whenever any employee of the Federal Government or of any 
State reveals in violation of the Act or of the provisions of the 
regulations implementing the Act, privileged or proprietary data or 
information obtained pursuant to the regulations in this chapter, the 
lessee or permittee who supplied such information to the Director or any 
other Federal official, and any person to whom such lessee or permittee 
has sold such data or information under the promise of confidentiality, 
may commence a civil action for damages in the appropriate district 
court of the United States against the Federal Government or such State, 
as the case may be. Any Federal or State employee who is found guilty of 
failure to comply with any of the requirements of this section shall be 
subject to the penalties described in section 24 of the Act (43 U.S.C. 
1350).
    (2) In any action commenced against the Federal Government or a 
State pursuant to paragraph (b)(1) of this section, the Federal 
Government or such State, as the case may be, may not raise as a defense 
any claim of sovereign immunity, or any claim that the employee who 
revealed the privileged or proprietary data or information which is the 
basis of such suit was acting outside the scope of the person's 
employment in revealing such data or information.
    (c) If the Director finds that any State cannot or does not comply 
with the conditions described in the agreement entered into pursuant to 
paragraph (a)(4) of this section, the Director shall thereafter withhold 
transmittal and deny access for inspection of privileged or proprietary 
data or information to such State until the Director finds that such 
State can and will comply with those conditions.

                           PART 253 [RESERVED]



PART 254_OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED 
SEAWARD OF THE COAST LINE--Table of Contents



                            Subpart A_General

Sec.
254.1 Who must submit an oil spill response plan (OSRP)?
254.2 When must I submit an OSRP?
254.3 May I cover more than one facility in my OSRP?
254.4 May I reference other documents in my OSRP?
254.5 General response plan requirements.
254.6 Definitions.
254.7 How do I submit my OSRP to the BSEE?
254.8 May I appeal decisions under this part?
254.9 Authority for information collection.

     Subpart B_Oil-Spill Response Plans for Outer Continental Shelf 
                               Facilities

254.20 Purpose.
254.21 How must I format my OSRP?
254.22 What information must I include in the ``Introduction and OSRP 
          contents'' section?
254.23 What information must I include in the ``Emergency response 
          action plan'' section?
254.24 What information must I include in the ``Equipment inventory'' 
          appendix?
254.25 What information must I include in the ``Contractual agreements'' 
          appendix?
254.26 What information must I include in the ``Worst case discharge 
          scenario'' appendix?

[[Page 320]]

254.27 What information must I include in the ``Dispersant use plan'' 
          appendix?
254.28 What information must I include in the ``In situ burning plan'' 
          appendix?
254.29 What information must I include in the ``Training and drills'' 
          appendix?
254.30 When must I revise my OSRP?

  Subpart C_Related Requirements for Outer Continental Shelf Facilities

254.40 Records.
254.41 Training your response personnel.
254.42 Exercises for your response personnel and equipment.
254.43 Maintenance and periodic inspection of response equipment.
254.44 Calculating response equipment effective daily recovery 
          capacities.
254.45 Verifying the capabilities of your response equipment.
254.46 Whom do I notify if an oil spill occurs?
254.47 Determining the volume of oil of your worst case discharge 
          scenario.

  Subpart D_Oil-Spill Response Requirements for Facilities Located in 
                 State Waters Seaward of the Coast Line

254.50 Spill response plans for facilities located in State waters 
          seaward of the coast line.
254.51 Modifying an existing OCS OSRP.
254.52 Following the format for an OCS OSRP.
254.53 Submitting an OSRP developed under State requirements.
254.54 Spill prevention for facilities located in State waters seaward 
          of the coast line.
254.55 Spill response plans for facilities located in Alaska State 
          waters seaward of the coast line in the Chukchi and Beaufort 
          Seas.

Subpart E_Oil-Spill Response Requirements for Facilities Located on the 
                               Arctic OCS

254.65 Purpose.
254.66-254.69 [Reserved]
254.70 What are the additional requirements for facilities conducting 
          exploratory drilling from a MODU on the Arctic OCS?
254.71-254.79 [Reserved]
254.80 What additional information must I include in the ``Emergency 
          response action plan'' section for facilities conducting 
          exploratory drilling from a MODU on the Arctic OCS?
254.81-254.89 [Reserved]
254.90 What are the additional requirements for exercises of your 
          response personnel and equipment for facilities conducting 
          exploratory drilling from a MODU on the Arctic OCS?

    Authority: 33 U.S.C. 1321.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General



Sec.  254.1  Who must submit an oil spill response plan (OSRP)?

    (a) If you are the owner or operator of an oil handling, storage, or 
transportation facility, and it is located seaward of the coast line, 
you must submit an oil spill response plan (OSRP) to BSEE for approval. 
Your OSRP must demonstrate that you can respond quickly and effectively 
whenever oil is discharged from your facility. Refer to Sec.  254.6 for 
the definitions of oil, facility, and coast line if you have any doubts 
about whether to submit a plan.
    (b) You must maintain a current OSRP for an abandoned facility until 
you physically remove or dismantle the facility or until the Chief, Oil 
Spill Preparedness Division (OSPD) notifies you in writing that a plan 
is no longer required.
    (c) Owners or operators of offshore pipelines carrying essentially 
dry gas do not need to submit a plan. You must, however, submit a plan 
for a pipeline that carries:
    (1) Oil;
    (2) Condensate that has been injected into the pipeline; or
    (3) Gas and naturally occurring condensate.
    (d) If you are in doubt as to whether you must submit a plan for an 
offshore facility or pipeline, you should check with the Chief, OSPD.
    (e) If your facility is located landward of the coast line, but you 
believe your facility is sufficiently similar to OCS facilities that it 
should be regulated by BSEE, you may contact the Chief, OSPD, offer to 
accept BSEE jurisdiction over your facility, and request that BSEE seek 
from the agency with jurisdiction over your facility a relinquishment of 
that jurisdiction.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]



Sec.  254.2  When must I submit an OSRP?

    (a) You must submit, and BSEE must approve, an OSRP that covers each 
facility located seaward of the coast line before you may use that 
facility. To continue operations, you must operate

[[Page 321]]

the facility in compliance with the OSRP.
    (b) Despite the provisions of paragraph (a) of this section, you may 
operate your facility after you submit your OSRP while BSEE reviews it 
for approval. To operate a facility without an approved OSRP, you must 
certify in writing to the Chief, OSPD that you have the capability to 
respond, to the maximum extent practicable, to a worst case discharge or 
a substantial threat of such a discharge. The certification must show 
that you have ensured by contract, or other means approved by the Chief, 
OSPD, the availability of private personnel and equipment necessary to 
respond to the discharge. Verification from the organization(s) 
providing the personnel and equipment must accompany the certification. 
BSEE will not allow you to operate a facility for more than 2 years 
without an approved OSRP.

[81 FR 36151, June 6, 2016]



Sec.  254.3  May I cover more than one facility in my OSRP?

    (a) Your OSRP may be for a single lease or facility or a group of 
leases or facilities. All the leases or facilities in your plan must 
have the same owner or operator (including affiliates) and must be 
located in the same BSEE Region (see definition of Regional OSRP in 
Sec.  254.6).
    (b) Regional OSRPs must address all the elements required for an 
OSRP in subpart B, or subpart D of this part, as appropriate.
    (c) When developing a Regional OSRP, you may group leases or 
facilities subject to the approval of the Chief, OSPD, for the purposes 
of:
    (1) Calculating response times;
    (2) Determining quantities of response equipment;
    (3) Conducting oil-spill trajectory analyses;
    (4) Determining worst case discharge scenarios; and
    (5) Identifying areas of special economic and environmental 
importance that may be impacted and the strategies for their protection.
    (d) The Chief, OSPD, may specify how to address the elements of a 
Regional OSRP. The Chief, OSPD, also may require that Regional OSRPs 
contain additional information if necessary for compliance with 
appropriate laws and regulations.

[81 FR 36151, June 6, 2016]



Sec.  254.4  May I reference other documents in my OSRP?

    You may reference information contained in other readily accessible 
documents in your OSRP. Examples of documents that you may reference are 
the National Contingency Plan (NCP), Area Contingency Plan (ACP), BSEE 
or BOEM environmental documents, and Oil Spill Removal Organization 
(OSRO) documents that are readily accessible to the Chief, OSPD. You 
must ensure that the Chief, OSPD, possesses or is provided with copies 
of all OSRO documents you reference. You should contact the Chief, OSPD, 
if you want to know whether a reference is acceptable.

[81 FR 36152, June 6, 2016]



Sec.  254.5  General response plan requirements.

    (a) The OSRP must provide for response to an oil spill from the 
facility. You must immediately carry out the provisions of the OSRP 
whenever there is a release of oil from the facility. You must also 
carry out the training, equipment testing, and periodic drills described 
in the OSRP, and these measures must be sufficient to ensure the safety 
of the facility and to mitigate or prevent a discharge or a substantial 
threat of a discharge.
    (b) The OSRP must be consistent with the National Contingency Plan 
and the appropriate Area Contingency Plan(s).
    (c) Nothing in this part relieves you from taking all appropriate 
actions necessary to immediately abate the source of a spill and remove 
any spills of oil.
    (d) In addition to the requirements listed in this part, you must 
provide any other information the Chief, OSPD, requires for compliance 
with appropriate laws and regulations.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



Sec.  254.6  Definitions.

    For the purposes of this part:

[[Page 322]]

    Adverse weather conditions means, for the purposes of this part, 
weather conditions found in the operating area that make it difficult 
for response equipment and personnel to clean up or remove spilled oil 
or hazardous substances. These conditions include, but are not limited 
to: fog, inhospitable water and air temperatures, wind, sea ice, extreme 
cold, freezing spray, snow, currents, sea states, and extended periods 
of low light. Adverse weather conditions do not refer to conditions 
under which it would be dangerous or impossible to respond to a spill, 
such as a hurricane.
    Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas 
(for more information on these areas, see the Proposed Final OCS Oil and 
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
    Area Contingency Plan means an Area Contingency Plan prepared and 
published under section 311(j) of the Federal Water Pollution Control 
Act (FWPCA).
    Chief, OSPD means the Chief, BSEE Oil Spill Preparedness Division or 
designee.
    Coast line means the line of ordinary low water along that portion 
of the coast which is in direct contact with the open sea and the line 
marking the seaward limit of inland waters.
    Discharge means any emission (other than natural seepage), 
intentional or unintentional, and includes, but is not limited to, 
spilling, leaking, pumping, pouring, emitting, emptying, or dumping.
    District Manager means the BSEE officer with authority and 
responsibility for a district within a BSEE Region.
    Facility means any structure, group of structures, equipment, or 
device (other than a vessel) which is used for one or more of the 
following purposes: Exploring for, drilling for, producing, storing, 
handling, transferring, processing, or transporting oil. The term 
excludes deep-water ports and their associated pipelines as defined by 
the Deepwater Port Act of 1974, but includes other pipelines used for 
one or more of these purposes. A mobile offshore drilling unit is 
classified as a facility when engaged in drilling or downhole 
operations.
    Ice intervention practices mean the equipment, vessels, and 
procedures used to increase oil encounter rates and the effectiveness of 
spill response techniques and equipment when sea ice is present.
    Maximum extent practicable means within the limitations of available 
technology, as well as the physical limitations of personnel, when 
responding to a worst case discharge in adverse weather conditions.
    National Contingency Plan means the National Oil and Hazardous 
Substances Pollution Contingency Plan prepared and published under 
section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or revised under 
section 105 of the Comprehensive Environmental Response Compensation and 
Liability Act (42 U.S.C. 9605).
    National Contingency Plan Product Schedule means a schedule of 
dispersants and other chemical or biological products, maintained by the 
Environmental Protection Agency, that may be authorized for use on oil 
discharges in accordance with the procedures found at 40 CFR 300.910.
    Oil means oil of any kind or in any form, including but not limited 
to petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes 
other than dredged spoil. This also includes hydrocarbons produced at 
the wellhead in liquid form (includes distillates or condensate 
associated with produced natural gas), and condensate that has been 
separated from a gas prior to injection into a pipeline. It does not 
include petroleum, including crude oil or any fraction thereof, which is 
specifically listed or designated as a hazardous substance under 
paragraphs (A) through (F) of section 101(14) of the Comprehensive 
Environmental Response, Compensation, and Liability Act (42 U.S.C. 9601) 
and which is subject to the provisions of that Act. It also does not 
include animal fats and oils and greases and fish and marine mammal 
oils, within the meaning of paragraph (2) of section 61(a) of title 13, 
United States Code, and oils of vegetable origin, including oils from 
the seeds, nuts, and

[[Page 323]]

kernels referred to in paragraph (1)(A) of that section.
    Oil spill removal organization (OSRO) means an entity contracted by 
an owner or operator to provide spill-response equipment and/or manpower 
in the event of an oil or hazardous substance spill.
    OSRP means an Oil Spill Response Plan.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Owner or operator means, in the case of an offshore facility, any 
person owning or operating such offshore facility. In the case of any 
abandoned offshore facility, it means the person who owned such facility 
immediately prior to such abandonment.
    Pipeline means pipe and any associated equipment, appurtenance, or 
building used or intended for use in the transportation of oil located 
seaward of the coast line, except those used for deep-water ports. 
Pipelines do not include vessels such as barges or shuttle tankers used 
to transport oil from facilities located seaward of the coast line.
    Qualified individual means an English-speaking representative of an 
owner or operator, located in the United States, available on a 24-hour 
basis, with full authority to obligate funds, carry out removal actions, 
and communicate with the appropriate Federal officials and the persons 
providing personnel and equipment in removal operations.
    Regional Response Plan means a spill-response plan required by this 
part which covers multiple facilities or leases of an owner or operator, 
including affiliates, which are located in the same BSEE Region.
    Regional Supervisor means the BSEE official with responsibility and 
authority for operations or other designated program functions within a 
BSEE Region.
    Remove means containment and cleanup of oil from water and 
shorelines or the taking of other actions as may be necessary to 
minimize or mitigate damage to the public health or welfare, including, 
but not limited to, fish, shellfish, wildlife, public and private 
property, shorelines, and beaches.
    Spill is synonymous with ``discharge'' for the purposes of this 
part.
    Spill management team means the trained persons identified in an 
OSRP who staff the organizational structure to manage spill response.
    Spill-response coordinator means a trained person charged with the 
responsibility and designated the commensurate authority for directing 
and coordinating response operations.
    Spill-response operating team means the trained persons who respond 
to spills through deployment and operation of oil-spill response 
equipment.
    State waters located seaward of the coast line means the belt of the 
seas measured from the coast line and extending seaward a distance of 3 
miles (except the coast of Texas and the Gulf coast of Florida, where 
the State waters extend seaward a distance of 3 leagues).
    You means the owner or the operator as defined in this section.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016; 81 
FR 46563, July 15, 2016]



Sec.  254.7  How do I submit my OSRP to the BSEE?

    You must submit the number of copies of your OSRP that the 
appropriate BSEE regional office requires. If you prefer to use improved 
information technology such as electronic filing to submit your plan, 
ask the Chief, OSPD, for further guidance.
    (a) Send OSRPs for facilities located seaward of the coast line of 
Alaska to: Bureau of Safety and Environmental Enforcement, Oil Spill 
Preparedness Division, Attention: Senior Analyst, 3801 Centerpoint 
Drive, Suite 500, Anchorage, AK 99503-5823.
    (b) Send OSRPs for facilities in the Gulf of Mexico or Atlantic 
Ocean to: Bureau of Safety and Environmental Enforcement, Oil Spill 
Preparedness Division, Attention: GOM Section Supervisor, 1201 Elmwood 
Park Boulevard, New Orleans, LA 70123-2394.

[[Page 324]]

    (c) Send OSRPs for facilities in the Pacific Ocean (except seaward 
of the coast line of Alaska) to: Bureau of Safety and Environmental 
Enforcement, Oil Spill Preparedness Division, Attention: Senior Analyst, 
760 Paseo Camarillo, Suite 201, Camarillo, CA 93010-6002.

[81 FR 36152, June 6, 2016]



Sec.  254.8  May I appeal decisions under this part?

    See 30 CFR part 290 for instructions on how to appeal any order or 
decision that we issue under this part.



Sec.  254.9  Authority for information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq. OMB assigned the control number 1014-0007. The title of this 
information collection is ``30 CFR part 254, Oil Spill Response 
Requirements for Facilities Located Seaward of the Coast line.''
    (b) BSEE collects this information to ensure that the owner or 
operator of an offshore facility is prepared to respond to an oil spill. 
BSEE uses the information to verify compliance with the mandates of the 
Oil Pollution Act of 1990 (OPA). The requirement to submit this 
information is mandatory. No confidential or proprietary information is 
collected.
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



     Subpart B_Oil-Spill Response Plans for Outer Continental Shelf 
                               Facilities



Sec.  254.20  Purpose.

    This subpart describes the requirements for preparing OSRPs for 
facilities located on the OCS.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



Sec.  254.21  How must I format my OSRP?

    (a) You must divide your OSRP for OCS facilities into the sections 
specified in paragraph (b) of this section and explained in the other 
sections of this subpart. The OSRP must have an easily found marker 
identifying each section. You may use an alternate format if you include 
a cross reference table to identify the location of required sections. 
You may use alternate contents if you can demonstrate to the Chief, OSPD 
that they provide for equal or greater levels of preparedness.
    (b) Your OSRP must include:
    (1) Introduction and OSRP contents.
    (2) Emergency response action plan.
    (3) Appendices:
    (i) Equipment inventory.
    (ii) Contractual agreements.
    (iii) Worst case discharge scenario.
    (iv) Dispersant use plan.
    (v) In situ burning plan.
    (vi) Training and drills.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



Sec.  254.22  What information must I include in the ``Introduction
 and OSRP contents'' section?

    The ``Introduction and OSRP contents'' section must provide:
    (a) Identification of the facility the OSRP covers, including its 
location and type;
    (b) A table of contents;
    (c) A record of changes made to the OSRP; and
    (d) A cross-reference table, if needed, because you are using an 
alternate format for your OSRP.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

[[Page 325]]



Sec.  254.23  What information must I include in the ``Emergency
 response action plan'' section?

    The ``Emergency response action plan'' section is the core of the 
OSRP. Put information in easy-to-use formats such as flow charts or 
tables where appropriate. This section must include:
    (a) Designation, by name or position, of a trained qualified 
individual (QI) who has full authority to implement removal actions and 
ensure immediate notification of appropriate Federal officials and 
response personnel.
    (b) Designation, by name or position, of a trained spill management 
team available on a 24-hour basis. The team must include a trained 
spill-response coordinator and alternate(s) who have the responsibility 
and authority to direct and coordinate response operations on your 
behalf. You must describe the team's organizational structure as well as 
the responsibilities and authorities of each position on the spill 
management team.
    (c) Description of a spill-response operating team. Team members 
must be trained and available on a 24-hour basis to deploy and operate 
spill-response equipment. They must be able to respond within a 
reasonable minimum specified time. You must include the number and types 
of personnel available from each identified labor source.
    (d) A planned location for a spill-response operations center and 
provisions for primary and alternate communications systems available 
for use in coordinating and directing spill-response operations. You 
must provide telephone numbers for the response operations center. You 
also must provide any facsimile numbers and primary and secondary radio 
frequencies that will be used.
    (e) A listing of the types and characteristics of the oil handled, 
stored, or transported at the facility.
    (f) Procedures for the early detection of a spill.
    (g) Identification of procedures you will follow in the event of a 
spill or a substantial threat of a spill. The procedures should show 
appropriate response levels for differing spill sizes including those 
resulting from a fire or explosion. These will include, as appropriate:
    (1) Your procedures for spill notification. The plan must provide 
for the use of the oil spill reporting forms included in the Area 
Contingency Plan or an equivalent reporting form.
    (i) Your procedures must include a current list which identifies the 
following by name or position, corporate address, and telephone number 
(including facsimile number if applicable):
    (A) The qualified individual;
    (B) The spill-response coordinator and alternate(s); and
    (C) Other spill-response management team members.
    (ii) You must also provide names, telephone numbers, and addresses 
for the following:
    (A) OSRO's that the plan cites;
    (B) Federal, State, and local regulatory agencies that you must 
consult to obtain site specific environmental information; and
    (C) Federal, State, and local regulatory agencies that you must 
notify when an oil spill occurs.
    (2) Your methods to monitor and predict spill movement;
    (3) Your methods to identify and prioritize the beaches, waterfowl, 
other marine and shoreline resources, and areas of special economic and 
environmental importance;
    (4) Your methods to protect beaches, waterfowl, other marine and 
shoreline resources, and areas of special economic or environmental 
importance;
    (5) Your methods to ensure that containment and recovery equipment 
as well as the response personnel are mobilized and deployed at the 
spill site;
    (6) Your methods to ensure that devices for the storage of recovered 
oil are sufficient to allow containment and recovery operations to 
continue without interruption;
    (7) Your procedures to remove oil and oiled debris from shallow 
waters and along shorelines and rehabilitating waterfowl which become 
oiled;
    (8) Your procedures to store, transfer, and dispose of recovered oil 
and oil-contaminated materials and to ensure that all disposal is in 
accordance with Federal, State, and local requirements; and

[[Page 326]]

    (9) Your methods to implement your dispersant use plan and your in 
situ burning plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



Sec.  254.24  What information must I include in the ``Equipment
 inventory'' appendix?

    Your ``Equipment inventory appendix'' must include:
    (a) An inventory of spill-response materials and supplies, services, 
equipment, and response vessels available locally and regionally. You 
must identify each supplier and provide their locations and telephone 
numbers.
    (b) A description of the procedures for inspecting and maintaining 
spill-response equipment in accordance with Sec.  254.43.



Sec.  254.25  What information must I include in the ``Contractual
 agreements'' appendix?

    Your ``Contractual agreements'' appendix must furnish proof of any 
contracts or membership agreements with OSRO's, cooperatives, spill-
response service providers, or spill management team members who are not 
your employees that you cite in the OSRP. To provide this proof, submit 
copies of the contracts or membership agreements or certify that 
contracts or membership agreements are in effect. The contract or 
membership agreement must include provisions for ensuring the 
availability of the personnel and/or equipment on a 24-hour-per-day 
basis.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]



Sec.  254.26  What information must I include in the ``Worst case
 discharge scenario'' appendix?

    The discussion of your worst case discharge scenario must include 
all of the following elements:
    (a) The volume of your worst case discharge scenario determined 
using the criteria in Sec.  254.47. Provide any assumptions made and the 
supporting calculations used to determine this volume.
    (b) An appropriate trajectory analysis specific to the area in which 
the facility is located. The analysis must identify onshore and offshore 
areas that a discharge potentially could affect. The trajectory analysis 
chosen must reflect the maximum distance from the facility that oil 
could move in a time period that it reasonably could be expected to 
persist in the environment.
    (c) A list of the resources of special economic or environmental 
importance that potentially could be impacted in the areas identified by 
your trajectory analysis. You also must state the strategies that you 
will use for their protection. At a minimum, this list must include 
those resources of special economic and environmental importance, if 
any, specified in the appropriate Area Contingency Plan(s).
    (d) A discussion of your response to your worst case discharge 
scenario in adverse weather conditions. This discussion must include:
    (1) A description of the response equipment that you will use to 
contain and recover the discharge to the maximum extent practicable. 
This description must include the types, location(s) and owner, 
quantity, and capabilities of the equipment. You also must include the 
effective daily recovery capacities, where applicable. You must 
calculate the effective daily recovery capacities using the methods 
described in Sec.  254.44. For operations at a drilling or production 
facility, your scenario must show how you will cope with the initial 
spill volume upon arrival at the scene and then support operations for a 
blowout lasting 30 days.
    (2) A description of the personnel, materials, and support vessels 
that would be necessary to ensure that the identified response equipment 
is deployed and operated promptly and effectively. Your description must 
include the location and owner of these resources as well as the 
quantities and types (if applicable);
    (3) A description of your oil storage, transfer, and disposal 
equipment. Your description must include the types, location and owner, 
quantity, and capacities of the equipment; and
    (4) An estimation of the individual times needed for:
    (i) Procurement of the identified containment, recovery, and storage 
equipment;

[[Page 327]]

    (ii) Procurement of equipment transportation vessel(s);
    (iii) Procurement of personnel to load and operate the equipment;
    (iv) Equipment loadout (transfer of equipment to transportation 
vessel(s));
    (v) Travel to the deployment site (including any time required for 
travel from an equipment storage area); and
    (vi) Equipment deployment.
    (e) In preparing the discussion required by paragraph (d) of this 
section, you must:
    (1) Ensure that the response equipment, materials, support vessels, 
and strategies listed are suitable, within the limits of current 
technology, for the range of environmental conditions anticipated at 
your facility; and
    (2) Use standardized, defined terms to describe the range of 
environmental conditions anticipated and the capabilities of response 
equipment. Examples of acceptable terms include those defined in 
American Society for Testing of Materials (ASTM) publication F625-94, 
Standard Practice for Describing Environmental Conditions Relevant to 
Spill Control Systems for Use on Water, and ASTM F818-93, Standard 
Definitions Relating to Spill Response Barriers.



Sec.  254.27  What information must I include in the ``Dispersant 
use plan'' appendix?

    Your dispersant use plan must be consistent with the National 
Contingency Plan Product Schedule and other provisions of the National 
Contingency Plan and the appropriate Area Contingency Plan(s). The plan 
must include:
    (a) An inventory and a location of the dispersants and other 
chemical or biological products which you might use on the oils handled, 
stored, or transported at the facility;
    (b) A summary of toxicity data for these products;
    (c) A description and a location of any application equipment 
required as well as an estimate of the time to commence application 
after approval is obtained;
    (d) A discussion of the application procedures;
    (e) A discussion of the conditions under which product use may be 
requested; and
    (f) An outline of the procedures you must follow in obtaining 
approval for product use.



Sec.  254.28  What information must I include in the ``In situ
 burning plan'' appendix?

    Your in situ burning plan must be consistent with any guidelines 
authorized by the National Contingency Plan and the appropriate Area 
Contingency Plan(s). Your in situ burning plan must include:
    (a) A description of the in situ burn equipment including its 
availability, location, and owner;
    (b) A discussion of your in situ burning procedures, including 
provisions for ignition of an oil spill;
    (c) A discussion of environmental effects of an in situ burn;
    (d) Your guidelines for well control and safety of personnel and 
property;
    (e) A discussion of the circumstances in which in situ burning may 
be appropriate;
    (f) Your guidelines for making the decision to ignite; and
    (g) An outline of the procedures you must follow to obtain approval 
for an in situ burn.



Sec.  254.29  What information must I include in the ``Training
 and drills'' appendix?

    Your ``Training and drills'' appendix must:
    (a) Identify and include the dates of the training provided to 
members of the spill-response management team and the qualified 
individual. The types of training given to the members of the spill-
response operating team also must be described. The training 
requirements for your spill management team and your spill-response 
operating team are specified in Sec.  254.41. You must designate a 
location where you keep course completion certificates or attendance 
records for this training.
    (b) Describe in detail your plans for satisfying the exercise 
requirements of Sec.  254.42. You must designate a location where you 
keep the records of these exercises.

[[Page 328]]



Sec.  254.30  When must I revise my OSRP?

    (a) You must review your OSRP at least every 2 years and submit all 
resulting modifications to the Chief, OSPD. If this review does not 
result in modifications, you must inform the Chief, OSPD, in writing 
that there are no changes.
    (b) You must submit revisions to your OSRP for approval within 15 
days whenever:
    (1) A change occurs which significantly reduces your response 
capabilities;
    (2) A significant change occurs in the worst case discharge scenario 
or in the type of oil being handled, stored, or transported at the 
facility;
    (3) There is a change in the name(s) or capabilities of the oil 
spill removal organizations cited in the OSRP; or
    (4) There is a significant change to the Area Contingency Plan(s).
    (c) The Chief, OSPD, may require that you resubmit your OSRP if the 
OSRP has become outdated or if numerous revisions have made its use 
difficult.
    (d) The Chief, OSPD, will periodically review the equipment 
inventories of OSRO's to ensure that sufficient spill removal equipment 
is available to meet the cumulative needs of the owners and operators 
who cite these organizations in their OSRPs.
    (e) The Chief, OSPD, may require you to revise your OSRP if 
significant inadequacies are indicated by:
    (1) Periodic reviews (described in paragraph (d) of this section);
    (2) Information obtained during drills or actual spill responses; or
    (3) Other relevant information the Chief, OSPD, obtained.

[81 FR 36152, June 6, 2016]



  Subpart C_Related Requirements for Outer Continental Shelf Facilities



Sec.  254.40  Records.

    You must make all records of services, personnel, and equipment 
provided by OSRO's or cooperatives available to any authorized BSEE 
representative upon request.



Sec.  254.41  Training your response personnel.

    (a) You must ensure that the members of your spill-response 
operating team who are responsible for operating response equipment 
attend hands-on training classes at least annually. This training must 
include the deployment and operation of the response equipment they will 
use. Those responsible for supervising the team must be trained annually 
in directing the deployment and use of the response equipment.
    (b) You must ensure that the spill-response management team, 
including the spill-response coordinator and alternates, receives annual 
training. This training must include instruction on:
    (1) Locations, intended use, deployment strategies, and the 
operational and logistical requirements of response equipment;
    (2) Spill reporting procedures;
    (3) Oil-spill trajectory analysis and predicting spill movement; and
    (4) Any other responsibilities the spill management team may have.
    (c) You must ensure that the qualified individual is sufficiently 
trained to perform his or her duties.
    (d) You must keep all training certificates and training attendance 
records at the location designated in your OSRP for at least 2 years. 
They must be made available to any authorized BSEE representative upon 
request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.42  Exercises for your response personnel and equipment.

    (a) You must exercise your entire OSRP at least once every 3 years 
(triennial exercise). You may satisfy this requirement by conducting 
separate exercises for individual parts of the OSRP over the 3-year 
period; you do not have to exercise your entire OSRP at one time.
    (b) In satisfying the triennial exercise requirement, you must, at a 
minimum, conduct:
    (1) An annual spill management team tabletop exercise. The exercise 
must test the spill management team's organization, communication, and 
decision making in managing a response. You must not reveal the spill 
scenario to

[[Page 329]]

team members before the exercise starts.
    (2) An annual deployment exercise of response equipment identified 
in your OSRP that is staged at onshore locations. You must deploy and 
operate each type of equipment in each triennial period. However, it is 
not necessary to deploy and operate each individual piece of equipment.
    (3) An annual notification exercise for each facility that is manned 
on a 24- hour basis. The exercise must test the ability of facility 
personnel to communicate pertinent information in a timely manner to the 
qualified individual.
    (4) A semiannual deployment exercise of any response equipment which 
the BSEE Regional Supervisor requires an owner or operator to maintain 
at the facility or on dedicated vessels. You must deploy and operate 
each type of this equipment at least once each year. Each type need not 
be deployed and operated at each exercise.
    (c) During your exercises, you must simulate conditions in the area 
of operations, including seasonal weather variations, to the extent 
practicable. The exercises must cover a range of scenarios over the 3-
year exercise period, simulating responses to large continuous spills, 
spills of short duration and limited volume, and your worst case 
discharge scenario.
    (d) BSEE will recognize and give credit for any documented exercise 
conducted that satisfies some part of the required triennial exercise. 
You will receive this credit whether the owner or operator, an OSRO, or 
a Government regulatory agency initiates the exercise. BSEE will give 
you credit for an actual spill response if you evaluate the response and 
generate a proper record. Exercise documentation should include the 
following information:
    (1) Type of exercise;
    (2) Date and time of the exercise;
    (3) Description of the exercise;
    (4) Objectives met; and
    (5) Lessons learned.
    (e) All records of spill-response exercises must be maintained for 
the complete 3-year exercise cycle. Records should be maintained at the 
facility or at a corporate location designated in the OSRP. Records 
showing that OSROs and oil spill removal cooperatives have deployed each 
type of equipment also must be maintained for the 3-year cycle.
    (f) You must inform the Chief, OSPD of the date of any exercise 
required by paragraph (b)(1), (2), or (4) of this section at least 30 
days before the exercise. This will allow BSEE personnel the opportunity 
to witness any exercises.
    (g) The Regional Supervisor periodically will initiate unannounced 
drills to test the spill response preparedness of owners and operators.
    (h) The Chief, OSPD may require changes in the frequency or location 
of the required exercises, equipment to be deployed and operated, or 
deployment procedures or strategies. The Chief, OSPD may evaluate the 
results of the exercises and advise the owner or operator of any needed 
changes in response equipment, procedures, or strategies.
    (i) Compliance with the National Preparedness for Response Exercise 
Program (PREP) Guidelines will satisfy the exercise requirements of this 
section. Copies of the PREP document may be obtained from the Chief, 
OSPD.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.43  Maintenance and periodic inspection of response equipment.

    (a) You must ensure that the response equipment listed in your OSRP 
is inspected at least monthly and is maintained, as necessary, to ensure 
optimal performance.
    (b) You must ensure that records of the inspections and the 
maintenance activities are kept for at least 2 years and are made 
available to any authorized BSEE representative upon request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.44  Calculating response equipment effective daily
 recovery capacities.

    (a) You are required by Sec.  254.26(d)(1) to calculate the 
effective daily recovery capacity of the response equipment identified 
in your OSRP that you would use to contain and recover your

[[Page 330]]

worst case discharge. You must calculate the effective daily recovery 
capacity of the equipment by multiplying the manufacturer's rated 
throughput capacity over a 24-hour period by 20 percent. This 20 percent 
efficiency factor takes into account the limitations of the recovery 
operations due to available daylight, sea state, temperature, viscosity, 
and emulsification of the oil being recovered. You must use this 
calculated rate to determine if you have sufficient recovery capacity to 
respond to your worst case discharge scenario.
    (b) If you want to use a different efficiency factor for specific 
oil recovery devices, you must submit evidence to substantiate that 
efficiency factor. Adequate evidence includes verified performance data 
measured during actual spills or test data gathered according to the 
provisions of Sec.  254.45(b) and (c).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.45  Verifying the capabilities of your response equipment.

    (a) The Regional Supervisor may require performance testing of any 
spill-response equipment listed in your OSRP to verify its capabilities 
if the equipment:
    (1) Has been modified;
    (2) Has been damaged and repaired; or
    (3) Has a claimed effective daily recovery capacity that is 
inconsistent with data otherwise available to BSEE.
    (b) You must conduct any required performance testing of booms in 
accordance with BSEE-approved test criteria. You may use the document 
``Test Protocol for the Evaluation of Oil-Spill Containment Booms,'' 
available from BSEE, for guidance. Performance testing of skimmers also 
must be conducted in accordance with BSEE approved test criteria. You 
may use the document ``Suggested Test Protocol for the Evaluation of Oil 
Spill Skimmers for the OCS,'' available from BSEE, for guidance.
    (c) You are responsible for any required testing of equipment 
performance and for the accuracy of the information submitted.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.46  Whom do I notify if an oil spill occurs?

    (a) You must immediately notify the National Response Center (1-800-
424-8802) if you observe:
    (1) An oil spill from your facility;
    (2) An oil spill from another offshore facility; or
    (3) An offshore spill of unknown origin.
    (b) In the event of a spill of 1 barrel or more from your facility, 
you must orally notify the Regional Supervisor without delay. You also 
must report spills from your facility of unknown size but thought to be 
1 barrel or more.
    (1) If a spill from your facility not originally reported to the 
Regional Supervisor is subsequently found to be 1 barrel or more, you 
must then report it without delay.
    (2) You must file a written follow up report for any spill from your 
facility of 1 barrel or more. The Chief, OSPD must receive this 
confirmation within 15 days after the spillage has been stopped. All 
reports must include the cause, location, volume, and remedial action 
taken. Reports of spills of more than 50 barrels must include 
information on the sea state, meteorological conditions, and the size 
and appearance of the slick. The Regional Supervisor may require 
additional information if it is determined that an analysis of the 
response is necessary.
    (c) If you observe a spill resulting from operations at another 
offshore facility, you must immediately notify the responsible party and 
the Regional Supervisor.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.47  Determining the volume of oil of your worst case
 discharge scenario.

    You must calculate the volume of oil of your worst case discharge 
scenario as follows:
    (a) For an oil production platform facility, the size of your worst 
case discharge scenario is the sum of the following:
    (1) The maximum capacity of all oil storage tanks and flow lines on 
the facility. Flow line volume may be estimated; and

[[Page 331]]

    (2) The volume of oil calculated to leak from a break in any 
pipelines connected to the facility considering shutdown time, the 
effect of hydrostatic pressure, gravity, frictional wall forces and 
other factors; and
    (3) The daily production volume from an uncontrolled blowout of the 
highest capacity well associated with the facility. In determining the 
daily discharge rate, you must consider reservoir characteristics, 
casing/production tubing sizes, and historical production and reservoir 
pressure data. Your scenario must discuss how to respond to this well 
flowing for 30 days as required by Sec.  254.26(d)(1).
    (b) For exploratory or development drilling operations, the size of 
your worst case discharge scenario is the daily volume possible from an 
uncontrolled blowout. In determining the daily discharge rate, you must 
consider any known reservoir characteristics. If reservoir 
characteristics are unknown, you must consider the characteristics of 
any analog reservoirs from the area and give an explanation for the 
selection of the reservoir(s) used. Your scenario must discuss how to 
respond to this well flowing for 30 days as required by Sec.  
254.26(d)(1).
    (c) For a pipeline facility, the size of your worst case discharge 
scenario is the volume possible from a pipeline break. You must 
calculate this volume as follows:
    (1) Add the pipeline system leak detection time to the shutdown 
response time.
    (2) Multiply the time calculated in paragraph (c)(1) of this section 
by the highest measured oil flow rate over the preceding 12-month 
period. For new pipelines, you should use the predicted oil flow rate in 
the calculation.
    (3) Add to the volume calculated in paragraph (c)(2) of this section 
the total volume of oil that would leak from the pipeline after it is 
shut in. Calculate this volume by taking into account the effects of 
hydrostatic pressure, gravity, frictional wall forces, length of 
pipeline segment, tie-ins with other pipelines, and other factors.
    (d) If your facility which stores, handles, transfers, processes, or 
transports oil does not fall into the categories listed in paragraph 
(a), (b), or (c) of this section, contact the Chief, OSPD for 
instructions on the calculation of the volume of your worst case 
discharge scenario.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



  Subpart D_Oil-Spill Response Requirements for Facilities Located in 
                 State Waters Seaward of the Coast Line



Sec.  254.50  Spill response plans for facilities located in State
 waters seaward of the coast line.

    Owners or operators of facilities located in State waters seaward of 
the coast line must submit a spill-response plan to BSEE for approval. 
You may choose one of three methods to comply with this requirement. The 
three methods are described in Sec. Sec.  254.51, 254.52, and 254.53.



Sec.  254.51  Modifying an existing OCS OSRP.

    You may modify an existing response plan covering a lease or 
facility on the OCS to include a lease or facility in State waters 
located seaward of the coast line. Since this OSRP would cover more than 
one lease or facility, it would be considered a Regional Response Plan. 
You should refer to Sec.  254.3 and contact the appropriate regional 
BSEE office if you have any questions on how to prepare this Regional 
Response Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.52  Following the format for an OCS OSRP.

    You may develop a response OSRP following the requirements for plans 
for OCS facilities found in subpart B of this part.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.53  Submitting an OSRP developed under State requirements.

    (a) You may submit a response plan to BSEE for approval that you 
developed in accordance with the laws or regulations of the appropriate 
State.

[[Page 332]]

The OSRP must contain all the elements the State and OPA require and 
must:
    (1) Be consistent with the requirements of the National Contingency 
Plan and appropriate Area Contingency Plan(s).
    (2) Identify a qualified individual and require immediate 
communication between that person and appropriate Federal officials and 
response personnel if there is a spill.
    (3) Identify any private personnel and equipment necessary to 
remove, to the maximum extent practicable, a worst case discharge as 
defined in Sec.  254.47. The plan must provide proof of contractual 
services or other evidence of a contractual agreement with any OSRO's or 
spill management team members who are not employees of the owner or 
operator.
    (4) Describe the training, equipment testing, periodic unannounced 
drills, and response actions of personnel at the facility. These must 
ensure both the safety of the facility and the mitigation or prevention 
of a discharge or the substantial threat of a discharge.
    (5) Describe the procedures you will use to periodically update and 
resubmit the plan for approval of each significant change.
    (b) Your plan developed under State requirements also must include 
the following information:
    (1) A list of the facilities and leases the plan covers and a map 
showing their location;
    (2) A list of the types of oil handled, stored, or transported at 
the facility;
    (3) Name and address of the State agency to whom the plan was 
submitted;
    (4) Date you submitted the plan to the State;
    (5) If the plan received formal approval, the name of the approving 
organization, the date of approval, and a copy of the State agency's 
approval letter if one was issued; and
    (6) Identification of any regulations or standards used in preparing 
the plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.54  Spill prevention for facilities located in State waters
 seaward of the coast line.

    In addition to your OSRP, you must submit to the Regional Supervisor 
a description of the steps you are taking to prevent spills of oil or 
mitigate a substantial threat of such a discharge. You must identify all 
State or Federal safety or pollution prevention requirements that apply 
to the prevention of oil spills from your facility, and demonstrate your 
compliance with these requirements. You also should include a 
description of industry safety and pollution prevention standards your 
facility meets. The Chief, OSPD may prescribe additional equipment or 
procedures for spill prevention if it is determined that your efforts to 
prevent spills do not reflect good industry practices.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  254.55  Spill response plans for facilities located in Alaska
 State waters seaward of the coast line in the Chukchi and Beaufort 
Seas.

    Response plans for facilities conducting exploratory drilling 
operations from a MODU seaward of the coast line in Alaska State waters 
in the Chukchi and Beaufort Seas must follow the requirements contained 
within subpart E of this part, in addition to the other requirements of 
this subpart. Such response plans must address how the source control 
procedures selected to comply with State law will be integrated into the 
planning, training, and exercise requirements of Sec. Sec.  254.70(a), 
254.90(a), and 254.90(c), in the event that the proposed operations do 
not incorporate the capping stack, cap and flow system, containment 
dome, and/or other similar subsea and surface devices and equipment and 
vessels referenced in those sections.

[81 FR 46563, July 15, 2016]



Subpart E_Oil-Spill Response Requirements for Facilities Located on the 
                               Arctic OCS

    Source: 81 FR 46564, July 15, 2016, unless otherwise noted.

[[Page 333]]



Sec.  254.65  Purpose.

    This subpart describes the additional requirements for preparing 
OSRPs and maintaining oil spill preparedness for facilities conducting 
exploratory drilling operations from a mobile offshore drilling unit 
(MODU) on the Arctic OCS.



Sec. Sec.  254.66-254.69  [Reserved]



Sec.  254.70  What are the additional requirements for facilities 
conducting exploratory drilling from a MODU on the Arctic OCS?

    In addition to meeting the applicable requirements of this part, 
your OSRP must:
    (a) Describe how the relevant personnel, equipment, materials, and 
support vessels associated with the capping stack, cap and flow system, 
containment dome, and other similar subsea and surface devices and 
equipment and vessels will be integrated into oil spill response 
incident action planning;
    (b) Describe how you will address human factors, such as cold stress 
and cold related conditions, associated with oil spill response 
activities in adverse weather conditions and their impacts on decision-
making and health and safety; and
    (c) Undergo plan-holder review prior to handling, storing, or 
transporting oil in connection with seasonal exploratory drilling 
activities, and all resulting modifications must be submitted to the 
Regional Supervisor. If this review does not result in modifications, 
you must inform the Regional Supervisor in writing that there are no 
changes. The requirements of this paragraph (c) are in lieu of the 
requirements in Sec.  254.30(a).



Sec. Sec.  254.71-254.79  [Reserved]



Sec.  254.80  What additional information must I include in the
 ``Emergency response action plan'' section for facilities
 conducting exploratory drilling from a MODU on the Arctic OCS?

    In addition to the requirements in Sec.  254.23, you must include 
the following information in the emergency response action plan section 
of your OSRP:
    (a) A description of your ice intervention practices and how they 
will improve the effectiveness of the oil spill response options and 
strategies that are listed in your OSRP in the presence of sea ice. When 
developing the ice intervention practices for your OSRP, you must 
consider, at a minimum, the use of specialized tactics, modified 
response equipment, ice management assist vessels, and technologies for 
the identification, tracking, containment and removal of oil in ice.
    (b) On areas of the Arctic OCS where a planned shore-based response 
would not satisfy Sec.  254.1(a):
    (1) A list of all resources required to ensure an effective 
offshore-based response capable of operating in adverse weather 
conditions. This list must include a description of how you will ensure 
the shortest possible transit times, including but not limited to 
establishing an offshore resource management capability (e.g., sea-based 
staging, maintenance, and berthing logistics); and
    (2) A list and description of logistics resupply chains, including 
waste management, that effectively factor in the remote and limited 
infrastructure that exists in the Arctic and ensure you can adequately 
sustain all oil spill response activities for the duration of the 
response. The components of the logistics supply chain include, but are 
not limited to:
    (i) Personnel and equipment transport services;
    (ii) Airfields and types of aircraft that can be supported;
    (iii) Capabilities to mobilize supplies (e.g., response equipment, 
fuel, food, fresh water) and personnel to the response sites;
    (iv) Onshore staging areas, storage areas that may be used en-route 
to staging areas, and camp facilities to support response personnel 
conducting offshore, nearshore and shoreline response; and
    (v) Management of recovered fluid and contaminated debris and 
response materials (e.g., oiled sorbents), as well as waste streams 
generated at offshore and on-shore support facilities (e.g., sewage, 
food, and medical).
    (c) A description of the system you will use to maintain real-time 
location

[[Page 334]]

tracking for all response resources while operating, transiting, or 
staging/maintaining such resources during a spill response.



Sec. Sec.  254.81-254.89  [Reserved]



Sec.  254.90  What are the additional requirements for exercises
 of your response personnel and equipment for facilities conducting
 exploratory drilling from a MODU on the Arctic OCS?

    In addition to the requirements in Sec.  254.42, the following 
requirements apply to exercises for your response personnel and 
equipment for facilities conducting exploratory drilling from a MODU on 
the Arctic OCS:
    (a) You must incorporate the personnel, materials, and equipment 
identified in Sec.  254.70(a), the safe working practices identified in 
Sec.  254.70(b), the ice intervention practices described in Sec.  
254.80(a), the offshore-based response requirements in Sec.  254.80(b), 
and the resource tracking requirements in Sec.  254.80(c) into your 
spill-response training and exercise activities.
    (b) For each season in which you plan to conduct exploratory 
drilling operations from a MODU on the Arctic OCS, you must notify the 
Regional Supervisor 60 days prior to handling, storing, or transporting 
oil.
    (c) After the Regional Supervisor receives notice pursuant to Sec.  
254.90(b), the Regional Supervisor may direct you to deploy and operate 
your spill response equipment and/or your capping stack, cap and flow 
system, and containment dome, and other similar subsea and surface 
devices and equipment and vessels, as part of announced or unannounced 
exercises or compliance inspections. For the purposes of this section, 
spill response equipment does not include the use of blowout preventers, 
diverters, heavy weight mud to kill the well, relief wells, or other 
similar conventional well control options.



PART 256_LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL
 SHELF--Table of Contents



  Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management, 
                                 General

Sec.
256.1 Purpose.
256.7 Cross references.
256.8-256.12 [Reserved]

            Subpart B_Assignments, Transfers, and Extensions

256.70 Extension of lease by drilling or well reworking operations.
256.71 Directional drilling.
256.72 Compensatory payments as production.
256.73 Effect of suspensions on lease term.

                     Subpart C_Termination of Leases

256.77 Cancellation of leases.

                       Subpart D_Section 6 Leases

256.79 Effect of regulations on lease.

    Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. L. 
109-432.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



  Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management, 
                                 General



Sec.  256.1  Purpose.

    The purpose of the regulations in 30 CFR part 256 is to establish 
the procedures under which the Secretary of the Interior (Secretary) 
will exercise the authority to administer a leasing program for oil, gas 
and sulphur. The procedures under which the Secretary will exercise the 
authority to administer a program to grant rights-of-way, are addressed 
in part 250, subpart J.



Sec.  256.7  Cross references.

    (a) For Bureau of Safety and Environmental Enforcement (BSEE) 
regulations governing exploration, development and production on leases, 
see 30 CFR parts 250 and 270.
    (b) For BSEE regulations governing the appeal of an order or 
decision issued under the regulations in this part, see 30 CFR part 290.

[[Page 335]]

    (c) For multiple use conflicts, see the Environmental Protection 
Agency listing of ocean dumping sites--40 CFR part 228.
    (d) For related National Oceanic and Atmospheric Administration 
programs see:
    (1) Marine sanctuary regulations, 15 CFR part 922;
    (2) Fishermen's Contingency Fund, 50 CFR part 296;
    (3) Coastal Energy Impact Program, 15 CFR part 931;
    (e) For Coast Guard regulations on the oil spill liability of 
vessels and operators, see 33 CFR parts 132, 135, and 136.
    (f) For Coast Guard regulations on port access routes, see 33 CFR 
part 164.
    (g) For compliance with the National Environmental Policy Act, see 
40 CFR parts 1500 through 1508.
    (h) For Department of Transportation regulations on offshore 
pipeline facilities, see 49 CFR part 195.
    (i) For Department of Defense regulations on military activities on 
offshore areas, see 32 CFR part 252.
    (j) For Bureau of Ocean Energy Management (BOEM) regulations, see 30 
CFR chapter V.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



            Subpart B_Assignments, Transfers, and Extensions

    Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153, 
June 6, 2016.



Sec.  256.70  Extension of lease by drilling or well reworking operations.

    The term of a lease shall be extended beyond the primary term so 
long as drilling or well reworking operations are approved by the 
Secretary according to the conditions set forth in 30 CFR 250.180.



Sec.  256.71  Directional drilling.

    In accordance with a BOEM-approved exploration plan or development 
and production plan, a lease may be maintained in force by directional 
wells drilled under the leased area from surface locations on adjacent 
or adjoining land not covered by the lease. In such circumstances, 
drilling shall be considered to have commenced on the leased area when 
drilling is commenced on the adjacent or adjoining land for the purpose 
of directional drilling under the leased area through any directional 
well surfaced on adjacent or adjoining land. Production, drilling or 
reworking of any such directional well shall be considered production or 
drilling or reworking operations on the leased area for all purposes of 
the lease.



Sec.  256.72  Compensatory payments as production.

    If an oil and gas lessee makes compensatory payments and if the 
lease is not being maintained in force by other production of oil or gas 
in paying quantities or by other approved drilling or reworking 
operations, such payments shall be considered as the equivalent of 
production in paying quantities for all purposes of the lease.



Sec.  256.73  Effect of suspensions on lease term.

    (a) A suspension may extend the term of a lease (see 30 CFR 250.171) 
with the extension being the length of time the suspension is in effect 
except as provided in paragraph (b) of this section.
    (b) A Directed Suspension does not extend the lease term when the 
Regional Supervisor directs a suspension because of:
    (1) Gross negligence; or
    (2) A willful violation of a provision of the lease or governing 
regulations.
    (c) BSEE may issue suspensions for a period of up to 5 years per 
suspension. The Regional Supervisor will set the length of the 
suspension based on the conditions of the individual case involved. BSEE 
may grant consecutive suspensions. For more information on suspension of 
operations or production refer to the section under the heading 
``Suspensions'' in 30 CFR part 250, subpart A.



                     Subpart C_Termination of Leases

    Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153, 
June 6, 2016.



Sec.  256.77  Cancellation of leases.

    (a) Any nonproducing lease issued under the act may be cancelled by 
the

[[Page 336]]

authorized officer whenever the lessee fails to comply with any 
provision of the act or lease or applicable regulations, if such failure 
to comply continues for 30 days after mailing of notice by registered or 
certified letter to the lease owner at the owner's record post office 
address. Any such cancellation is subject to judicial review as provided 
in section 23(b) of the Act.
    (b) Producing leases issued under the Act may be cancelled by the 
Secretary whenever the lessee fails to comply with any provision of the 
Act, applicable regulations or the lease only after judicial proceedings 
as prescribed by section 5(d) of the Act.
    (c) Any lease issued under the Act, whether producing or not, shall 
be canceled by the authorized officer upon proof that it was obtained by 
fraud or misrepresentation, and after notice and opportunity to be heard 
has been afforded to the lessee.
    (d) Pursuant to section 5(a) of the Act, the Secretary may cancel a 
lease when:
    (1) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life, property, any mineral, National security 
or defense, or to the marine, coastal or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of cancellation outweigh the advantages of 
continuing such lease or permit in force. Procedures and conditions 
contained in Sec.  550.182 shall apply as appropriate.



                       Subpart D_Section 6 Leases

    Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153, 
June 6, 2016.



Sec.  256.79  Effect of regulations on lease.

    (a) All regulations in this part, insofar as they are applicable, 
shall supersede the provisions of any lease which is maintained under 
section 6(a) of the Act. However, the provisions of a lease relating to 
area, minerals, rentals, royalties (subject to sections 6(a) (8) and (9) 
of the Act), and term (subject to section 6(a)(10) of the Act and, as to 
sulfur, subject to section 6(b)(2) of the Act) shall continue in effect, 
and, in the event of any conflict or inconsistency, shall take 
precedence over these regulations.
    (b) A lease maintained under section 6(a) of the Act shall also be 
subject to all operating and conservation regulations applicable to the 
OCS. In addition, the regulations relating to geophysical and geological 
exploratory operations and to pipeline rights-of-way are applicable, to 
the extent that those regulations are not contrary to or inconsistent 
with the lease provisions relating to area, the minerals, rentals, 
royalties and term. The lessee shall comply with any provision of the 
lease as validated, the subject matter of which is not covered in the 
regulations in this part.

                        PARTS 259	260 [RESERVED]



PART 270_NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF--Table of Contents



Sec.
270.1 Purpose.
270.2 Application of this part.
270.3 Definitions.
270.4 Discrimination prohibited.
270.5 Complaint.
270.6 Process.
270.7 Remedies.

    Authority: 43 U.S.C. 1863.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



Sec.  270.1  Purpose.

    The purpose of this part is to implement the provisions of section 
604 of the OCSLA of 1978 which provides that ``no person shall, on the 
grounds of race, creed, color, national origin, or sex, be excluded from 
receiving or participating in any activity, sale, or employment, 
conducted pursuant to the provisions of * * * the Outer Continental 
Shelf Lands Act.''



Sec.  270.2  Application of this part.

    This part applies to any contract or subcontract entered into by a 
lessee or by a contractor or subcontractor of a lessee after the 
effective date of these regulations to provide goods, services, 
facilities, or property in an amount of $10,000 or more in connection 
with any activity related to the exploration for

[[Page 337]]

or development and production of oil, gas, or other minerals or 
materials in the OCS under the Act.



Sec.  270.3  Definitions.

    As used in this part, the following terms shall have the following 
meanings:
    Contract means any business agreement or arrangement (in which the 
parties do not stand in the relationship of employer and employee) 
between a lessee and any person which creates an obligation to provide 
goods, services, facilities, or property.
    Lessee means the party authorized by a lease, grant of right-of-way, 
or an approved assignment thereof to explore, develop, produce, or 
transport oil, gas, or other minerals or materials in the OCS pursuant 
to the Act and this part.
    Person means a person or company, including but not limited to, a 
corporation, partnership, association, joint stock venture, trust, 
mutual fund, or any receiver, trustee in bankruptcy, or other official 
acting in a similar capacity for such company.
    Subcontract means any business agreement or arrangement (in which 
the parties do not stand in the relationship of employer and employee) 
between a lessee's contractor and any person other than a lessee that is 
in any way related to the performance of any one or more contracts.



Sec.  270.4  Discrimination prohibited.

    No contract or subcontract to which this part applies shall be 
denied to or withheld from any person on the grounds of race, creed, 
color, national origin, or sex.



Sec.  270.5  Complaint.

    (a) Whenever any person believes that he or she has been denied a 
contract or subcontract to which this part applies on the grounds of 
race, creed, color, national origin, or sex, such person may complain of 
such denial or withholding to the Regional Director of the OCS Region in 
which such action is alleged to have occurred. Any complaint filed under 
this part must be submitted in writing to the appropriate Regional 
Director not later than 180 days after the date of the alleged unlawful 
denial of a contract or subcontract which is the basis of the complaint.
    (b) The complaint referred to in paragraph (a) of this section shall 
be accompanied by such evidence as may be available to a person and 
which is relevant to the complaint including affidavits and other 
documents.
    (c) Whenever any person files a complaint under this part, the 
Regional Director with whom such complaint is filed shall give written 
notice of such filing to all persons cited in the complaint no later 
than 10 days after receipt of such complaint. Such notice shall include 
a statement describing the alleged incident of discrimination, including 
the date and the names of persons involved in it.



Sec.  270.6  Process.

    Whenever a Regional Director determines on the basis of any 
information, including that which may be obtained under Sec.  270.5 of 
this part, that a violation of or failure to comply with any provision 
of this subpart probably occurred, the Regional director shall undertake 
to afford the complainant and the person(s) alleged to have violated the 
provisions of this part an opportunity to engage in informal 
consultations, meetings, or any other form of communications for the 
purpose of resolving the complaint. In the event such communications or 
consultations result in a mutually satisfactory resolution of the 
complaint, the complainant and all persons cited in the complaint shall 
notify the Regional Director in writing of their agreement to such 
resolution. If either the complainant or the person(s) alleged to have 
wrongfully discriminated fail to provide such written notice within a 
reasonable period of time, the Regional Director must proceed in 
accordance with the provisions of 30 CFR 250, subpart N.



Sec.  270.7  Remedies.

    In addition to the penalties available under 30 CFR part 250, 
subpart N, the Director may invoke any other remedies available to him 
or her under the Act or regulations for the lessee's failure to comply 
with provisions of the Act, regulations, or lease.

[[Page 338]]



PART 280_PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR
 ON THE OUTER CONTINENTAL SHELF--Table of Contents



Subparts A-B [Reserved]

                  Subpart C_Obligations Under This Part

                         Interrupted Activities

Sec.
280.20-280.24 [Reserved]
280.25 When may BSEE require me to stop activities under this part?
280.26 When may I resume activities?
280.27 When may BSEE cancel my permit?
280.28 May I relinquish my permit?

Subparts D-E [Reserved]

    Authority: 43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subparts A-B [Reserved]



                  Subpart C_Obligations Under This Part

                         Interrupted Activities



Sec. Sec.  280.20-280.24  [Reserved]



Sec.  280.25  When may BSEE require me to stop activities
 under this part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, and any minerals (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order 
or provision of the permit. This would include the required submission 
of reports, well records or logs, and G&G data and information within 
the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.
    (b) The Regional Director will advise you either orally or in 
writing of the procedures to temporarily stop activities. We will 
confirm an oral notification in writing and deliver all written 
notifications by courier or certified/registered mail. You must stop all 
activities under a permit as soon as you receive an oral or written 
notification.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  280.26  When may I resume activities?

    The Regional Director will advise you when you may start your permit 
activities again.



Sec.  280.27  When may BSEE cancel my permit?

    The Regional Director may cancel a permit at any time.
    (a) If we cancel your permit, the Regional Director will advise you 
by certified or registered mail 30 days before the cancellation date and 
will state the reason.
    (b) After we cancel your permit, you are still responsible for 
proper abandonment of any drill site according to the requirements of 30 
CFR 251.7(b)(8). You must comply with all other obligations specified in 
this part or in the permit.



Sec.  280.28  May I relinquish my permit?

    (a) You may relinquish your permit at any time by advising the 
Bureau of Ocean Energy Management Regional Director by certified or 
registered mail 30 days in advance.
    (b) After you relinquish your permit, you are still responsible for 
proper abandonment of any drill sites according to the requirements of 
30 CFR 251.7(b)(8). You must also comply with all other obligations 
specified in this part or in the permit.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Subparts D-E [Reserved]

                           PART 281 [RESERVED]

[[Page 339]]



PART 282_OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER
 THAN OIL, GAS, AND SULPHUR--Table of Contents



                            Subpart A_General

Sec.
282.0 Authority for information collection.
282.1 Purpose and authority.
282.2 Scope.
282.3 Definitions.
282.4 [Reserved]
282.5 Disclosure of data and information to the public.
282.6 Disclosure of data and information to an adjacent State.
282.7 Jurisdictional controversies.

         Subpart B_Jurisdiction and Responsibilities of Director

282.10 Jurisdiction and responsibilities of Director.
282.11 Director's authority.
282.12 Director's responsibilities.
282.13 Suspension of production or other operations.
282.14 Noncompliance, remedies, and penalties.
282.15 [Reserved]

          Subpart C_Obligations and Responsibilities of Lessees

282.20 [Reserved]
282.21 Plans, general.
282.22-282.26 [Reserved]
282.27 Conduct of operations.
282.28 Environmental protection measures.
282.29-282.30 [Reserved]
282.31 Suspension of production or other operations.

                           Subpart D_Payments

282.40 [Reserved]
282.41 Method of royalty calculation
282.42 [Reserved]

                            Subpart E_Appeals

282.50 Appeals.

    Authority: 43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General



Sec.  282.0  Authority for information collection.

    (a) The information collection requirements in this part have been 
approved by the Office of Management and Budget under 44 U.S.C. 3507 and 
assigned clearance number 1014-0021. The information is being collected 
to inform the Bureau of Safety and Environmental Enforcement (BSEE) of 
general mining operations in the Outer Continental Shelf (OCS). The 
information will be used to ensure that operations are conducted in a 
safe and environmentally responsible manner in compliance with governing 
laws and regulations. The requirement to respond is mandatory.
    (b) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to: Information Collection Clearance Officer, Bureau of Safety 
and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  282.1  Purpose and authority.

    (a) The Act authorizes the Secretary to prescribe such rules and 
regulations as may be necessary to carry out the provisions of the Act 
(43 U.S.C. 1334). The Secretary is authorized to prescribe and amend 
regulations that the Secretary determines to be necessary and proper in 
order to provide for the prevention of waste, conservation of the 
natural resources of the OCS, and the protection of correlative rights 
therein. In the enforcement of safety, environmental, and conservation 
laws and regulations, the Secretary is authorized to cooperate with 
adjacent States and other Departments and Agencies of the Federal 
Government.
    (b) Subject to the supervisory authority of the Secretary, and 
unless otherwise specified, the regulations in this part shall be 
administered by the Director of BSEE.



Sec.  282.2  Scope.

    The rules and regulations in this part apply as of their effective 
date to all operations conducted under a mineral lease for OCS minerals 
other than oil, gas, or sulphur issued under the provisions of section 
8(k) of the Act.

[[Page 340]]



Sec.  282.3  Definitions.

    When used in this part, the following terms shall have the following 
meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State:
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipment OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, or mining activities; or
    (3) In which there is a reasonable probability of significant effect 
on land or water uses from such activity.
    Contingency Plan means a plan for action to be taken in emergency 
situations.
    Data means geological and geophysical (G&G) facts and statistics or 
samples which have not been analyzed, processed, or interpreted.
    Development means those activities which take place following the 
discovery of minerals in paying quantities including geophysical 
activities, drilling, construction of offshore facilities, and operation 
of all onshore support facilities, which are for the purpose of 
ultimately producing the minerals discovered.
    Director means the Director of BSEE of the U.S. Department of the 
Interior or an official authorized to act on the Director's behalf.
    Exploration means the process of searching for minerals on a lease 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of minerals;
    (2) Any drilling including the drilling of a borehole in which the 
discovery of a mineral other than oil, gas, or sulphur is made and the 
drilling of any additional boreholes needed to delineate any mineral 
deposits; and
    (3) The taking of sample portions of a mineral deposit to enable the 
lessee to determine whether to proceed with development and production.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters (when obtained for geochemical 
analysis) acquired while conducting postlease mining activities.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the power granted 
to a Governor.
    Information means G&G data that have been analyzed, processed, or 
interpreted.
    Lease means one of the following, whichever is required by the 
context: Any form of authorization which is issued under section 8 or 
maintained under section 6 of the Acts and which authorizes exploration 
for, and development and production of, specific minerals; or the area 
covered by that authorization.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all parties holding that authority by or through the lessee.
    Major Federal action means any action or proposal by the Secretary 
which is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act (NEPA) (i.e., an action which will have a 
significant impact on the quality of the human environment requiring 
preparation of an Environmental Impact Statement (EIS) pursuant to 
section 102(2)(C) of NEPA).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors which interactively determine the 
productivity, state, condition, and quality of the marine ecosystem, 
including the waters of the high seas, the contiguous zone, transitional 
and intertidal areas, salt marshes, and wetlands within the coastal zone 
and on the OCS.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from ``public lands'' as defined in 
section 103 of the

[[Page 341]]

Federal Land Policy and Management Act of 1976.
    OCS mineral means any mineral deposit or accretion found on or below 
the surface of the seabed but does not include oil, gas, or sulphur; 
salt or sand and gravel intended for use in association with the 
development of oil, gas, or sulphur; or source materials essential to 
production of fissionable materials which are reserved to the United 
States pursuant to section 12(e) of the Act.
    Operator means the individual, partnership, firm, or corporation 
having control or management of operations on the lease or a portion 
thereof. The operator may be a lessee, designated agent of the lessee, 
or holder of rights under an approved operating agreement.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. The 
term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Testing means removing bulk samples for processing tests and 
feasibility studies and/or the testing of mining equipment to obtain 
information needed to develop a detailed Mining Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  282.4  [Reserved]



Sec.  282.5  Disclosure of data and information to the public.

    (a) The Director shall make data, information, and samples available 
in accordance with the requirements and subject to the limitations of 
the Act, the Freedom of Information Act (5 U.S.C. 552), and the 
implementing regulations (43 CFR part 2).
    (b) Geophysical data, processed G&G information, interpreted G&G 
information, and other data and information submitted pursuant to the 
requirements of this part shall not be available for public inspection 
without the consent of the lessee so long as the lease remains in 
effect, unless the Director determines that earlier limited release of 
such information is necessary for the unitization of operations on two 
or more leases, to ensure proper Mining Plans for a common ore body, or 
to promote operational safety. When the Director determines that early 
limited release of data and information is necessary, the data and 
information shall be shown only to persons with a direct interest in the 
affected lease(s), unitization agreement, or joint Mining Plan.
    (c) Geophysical data, processed geophysical information and 
interpreted geophysical information collected on a lease with high 
resolution systems (including, but not limited to, bathymetry, side-scan 
sonar, subbottom profiler, and magnetometer) in compliance with 
stipulations or orders concerning protection of environmental aspects of 
the lease may be made available to the public 60 days after submittal to 
the Director, unless the lessee can demonstrate to the satisfaction of 
the Director that release of the information or data would unduly damage 
the lessee's competitive position.



Sec.  282.6  Disclosure of data and information to an adjacent State.

    (a) Proprietary data, information, and samples submitted to BSEE 
pursuant to the requirements of this part shall be made available for 
inspection by representatives of adjacent State(s) upon request by the 
Governor(s) in accordance with paragraphs (b) and (c) of this section.

[[Page 342]]

    (b) Disclosure shall occur only after the Governor has entered into 
an agreement with the Secretary providing that:
    (1) The confidentiality of the information shall be maintained;
    (2) In any action commenced against the Federal Government or the 
State for failure to protect the confidentiality of proprietary 
information, the Federal Government or the State, as the case may be, 
may not raise as a defense any claim of sovereign immunity or any claim 
that the employee who revealed the proprietary information, which is the 
basis of the suit, was acting outside the scope of the person's 
employment in revealing the information;
    (3) The State agrees to hold the United States harmless for any 
violation by the State or its employees or contractors of the agreement 
to protect the confidentiality of proprietary data, information, and 
samples; and
    (c) The data, information, and samples available for inspection by 
representatives of adjacent State(s) pursuant to an agreement shall be 
related to leased lands.



Sec.  282.7  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State 
jurisdiction, either the Governor of the State or the Secretary may 
initiate negotiations in an attempt to settle the jurisdictional 
controversy. With the concurrence of the Attorney General, the Secretary 
may enter into an agreement with a State with respect to OCS mineral 
activities and to payment and impounding of rents, royalties, and other 
sums and with respect to the issuance or nonissuance of new leases 
pending settlement of the controversy.



         Subpart B_Jurisdiction and Responsibilities of Director



Sec.  282.10  Jurisdiction and responsibilities of Director.

    Subject to the authority of the Secretary, the following activities 
are subject to the regulations in this part and are under the 
jurisdiction of the Director: Exploration, testing, and mining 
operations together with the associated environmental protection 
measures needed to permit those activities to be conducted in an 
environmentally responsible manner; handling, measurement, and 
transportation of OCS minerals; and other operations and activities 
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant 
to a right of use and easement granted under 30 CFR 582.30, by or on 
behalf of a lessee or the holder of a right of use and easement.



Sec.  282.11  Director's authority.

    (a)-(c) [Reserved]
    (d)(1) The Director may approve the consolidation of two or more OCS 
mineral leases or portions of two or more OCS mineral leases into a 
single mining unit requested by lessees, or the Director may require 
such consolidation when the operation of those leases or portions of 
leases as a single mining unit is in the interest of conservation of the 
natural resources of the OCS or the prevention of waste. A mining unit 
may also include all or portions of one or more OCS mineral leases with 
all or portions of one or more adjacent State leases for minerals in a 
common orebody. A single unit operator shall be responsible for 
submission of required Delineation, Testing, and Mining Plans covering 
OCS mineral operations for an approved mining unit.
    (2) Operations such as exploration, testing, and mining activities 
conducted in accordance with an approved plan on any lease or portion of 
a lease which is subject to an approved mining unit shall be considered 
operations on each of the leases that is made subject to the approved 
mining unit.
    (3) Minimum royalty paid pursuant to a Federal lease, which is 
subject to an approved mining unit, is creditable against the production 
royalties allocated to that Federal lease during the lease year for 
which the minimum royalty is paid.
    (4) Any OCS minerals produced from State and Federal leases which 
are subject to an approved mining unit shall be accounted for separately 
unless a method of allocating production between State and Federal 
leases has been approved by the Director and the appropriate State 
official.

[[Page 343]]



Sec.  282.12  Director's responsibilities.

    (a) The Director is responsible for the regulation of activities to 
assure that all operations conducted under a lease or right of use and 
easement are conducted in a manner that protects the environment and 
promotes orderly development of OCS mineral resources. Those activities 
are to be designed to prevent serious harm or damage to, or waste of, 
any natural resource (including OCS mineral deposits and oil, gas, and 
sulphur resources in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the marine, coastal, or human 
environment.
    (b)-(d) [Reserved]
    (e) The Director shall assure that a scheduled onsite compliance 
inspection of each facility which is subject to regulations in this part 
is conducted at least once a year. The inspection shall be to determine 
that the lessee is in compliance with the requirements of the law; 
provisions of the lease; the approved Delineation, Testing, or Mining 
Plan; and the regulations in this part. Additional unscheduled onsite 
inspections shall be conducted without advance notice to the lessee to 
assure compliance with the provisions of applicable law; the lease; the 
approved Delineation, Testing, or Mining Plan; and the regulations in 
this part.
    (f)(1) The Director shall, after completion of the technical and 
environmental evaluations, approve, disapprove, or require modification 
of the lessee's requests, applications, plans, and notices submitted 
pursuant to the provisions of this part; issue orders to govern lease 
operations; and require compliance with applicable provisions of the 
law, the regulations, the lease, and the approved Delineation, Testing, 
or Mining Plans. The Director may give oral orders or approvals whenever 
prior approval is required before the commencement of an operation or 
activity. Oral orders or approvals given in response to a written 
request shall be confirmed in writing within 3 working days after 
issuance of the order or granting of the oral approval.
    (2) The Director shall, after completion of the technical and 
environmental evaluations, approve, disapprove, or require modification, 
as appropriate, of the design plan, fabrication plan, and installation 
plan for platforms, artificial islands, and other installations and 
devices permanently or temporarily attached to the seabed. The approval, 
disapproval, or requirement to modify such plans may take the form of a 
condition of granting a right of use and easement under paragraph (a) of 
this section or as authorized under any lease issued or maintained under 
the Act.
    (g) [Reserved]
    (h) The Director may prescribe or approve, in writing or orally, 
departures from the operating requirements of the regulations of this 
part when such departures are necessary to facilitate the proper 
development of a lease; to conserve natural resources; or to protect 
life (including fish and other aquatic life), property, or the marine, 
coastal, or human environment.



Sec.  282.13  Suspension of production or other operations.

    (a) The Director may direct the suspension or temporary prohibition 
of production or any other operation or activity on all or any part of a 
lease when it has been determined that such suspension or temporary 
prohibition is in the National interest to:
    (1) Facilitate proper development of a lease including a reasonable 
time to develop a mine and construct necessary support facilities, or
    (2) Allow for the construction or negotiation for use of 
transportation facilities.
    (b) The Director may also direct or, at the request of the lessee, 
approve a suspension or temporary prohibition of production or any other 
operation or activity, if:
    (1) The lessee failed to comply with a provision of applicable law, 
regulation, order, or the lease;
    (2) There is a threat of serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposit, or the marine, coastal, or human environment;
    (3) The suspension or temporary prohibition is in the interest of 
National security or defense;
    (4) The suspension or temporary prohibition is necessary for the 
initiation

[[Page 344]]

and conduct of an environmental evaluation to define mitigation measures 
to avoid or minimize adverse environmental impacts.
    (5) The suspension or temporary prohibition is necessary to 
facilitate the installation of equipment necessary for safety of 
operations and protection of the environment;
    (6) The suspension or temporary prohibition is necessary to allow 
for undue delays encountered by the lessee in obtaining required permits 
or consents, including administrative or judicial challenges or appeals;
    (7) The Director determines that continued operations would result 
in premature abandonment of a producing mine, resulting in the loss of 
otherwise recoverable OCS minerals;
    (8) The Director determines that the lessee cannot successfully 
operate a producing mine due to market conditions that are either 
temporary in nature or require temporary shutdown and reinvestment in 
order for the lessee to adapt to the conditions; or
    (9) The suspension or temporary prohibition is necessary to comply 
with judicial decrees prohibiting production or any other operation or 
activity, or the permitting of those activities, effective the date set 
by the court for that prohibition.
    (c) When the Director orders or approves a suspension or a temporary 
prohibition of operation or activity including production on all of a 
lease pursuant to paragraph (a) or (b) of this section, the term of the 
lease shall be extended for a period of time equal to the period of time 
that the suspension or temporary prohibition is in effect, except that 
no lease shall be so extended when the suspension or temporary 
prohibition is the result of the lessee's gross negligence or willful 
violation of a provision of the lease or governing regulations.
    (d) The Director may, at any time within the period prescribed for a 
suspension or temporary prohibition issued pursuant to paragraph (b)(2) 
of this section, require the lessee to submit a Delineation, Testing, or 
Mining Plan to the Bureau of Ocean Energy Management for approval in 
accordance with the requirements for the approval of such plans in part 
582 of this title.
    (e)(1) When the Director orders or issues a suspension or a 
temporary prohibition pursuant to paragraph (b)(2) of this section, the 
Director may require the lessee to conduct site-specific studies to 
identify and evaluate the cause(s) of the hazard(s) generating the 
suspension or temporary prohibition, the potential for damage from the 
hazard(s), and the measures available for mitigating the hazard(s). The 
nature, scope, and content of any study shall be subject to approval by 
the Director. The lessee shall furnish copies and all results of any 
such study to the Director. The cost of the study shall be borne by the 
lessee unless the Director arranges for the cost of the study to be 
borne by a party other than the lessee. The Director shall make results 
of any such study available to interested parties and to the public as 
soon as practicable after the completion of the study and submission of 
the results thereof.
    (2) When the Director determines that measures are necessary, on the 
basis of the results of the studies conducted in accordance with 
paragraph (e)(1) of this section and other information available to and 
identified by the Director, the lessee will be required to take 
appropriate measures to mitigate, avoid, or minimize the damage or 
potential damage on which the suspension or temporary prohibition is 
based. In choosing between alternative mitigation measures, the Director 
will balance the cost of the required measures against the reduction or 
potential reduction in damage or threat of damage or harm to life 
(including fish and other aquatic life), to property, to any mineral 
deposits (in areas leased or not leased), to the National security or 
defense, or to the marine, coastal, or human environment. When deemed 
appropriate by the Director, the lessee must submit to the Bureau of 
Ocean Energy Management a revised Delineation, Testing, or Mining Plan 
that incorporates the mitigation measures required by the Director.
    (f)(1) If under the provisions of paragraphs (b)(2), (3), and (4) of 
this section, the Director, with respect to any lease, directs the 
suspension of production or

[[Page 345]]

other operations on the entire leasehold, no payment of rental or 
minimum royalty shall be due for or during the period of the directed 
suspension and the time for the lessee specify royalty free period of a 
period of reduced royalty pursuant to 30 CFR 581.28(b) will be extended 
for the period of directed suspension. If under the provisions of 
paragraphs (b)(2), (3), and (4) of this section the Director, with 
respect to a lease on which there has been no production, directs the 
suspension of operations on the entire leasehold, no payment of rental 
shall be due during the period of the directed suspension.
    (2) If under the provisions of this section, the Director grants the 
request of a lessee for a suspension of production or other operations, 
the lessee's obligations to pay rental, minimum royalty, or royalty 
shall continue to apply during the period of the approved suspension, 
unless the Director's approval of the lessee's request for suspension 
authorizes the payment of a lesser amount during the period of approved 
suspension. If under the provision of this section, the Director grants 
a lessee's request for a suspension of production or other operations 
for a lease which includes provisions for a time period which the lessee 
may specify during which production from the leasehold would be royalty 
free or subject to a reduced royalty obligation pursuant to 30 CFR 
581.28(b), the time during which production from a leasehold may be 
royalty free or subject to a reduced royalty obligation shall not be 
extended unless the Director's approval of the suspension specifies 
otherwise.
    (3) If the lease anniversary date falls within a period of 
suspension for which no rental or minimum royalty payments are required 
under paragraph (a) of this section, the prorated rentals or minimum 
royalties are due and payable as of the date the suspension period 
terminates. These amounts shall be computed and notice thereof given the 
lessee. The lessee shall pay the amount due within 30 days after receipt 
of such notice. The anniversary date of a lease shall not change by 
reason of any period of lease suspension or rental or royalty relief 
resulting therefrom.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]



Sec.  282.14  Noncompliance, remedies, and penalties.

    (a)(1) If the Director determines that a lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the approved Delineation, Testing, or 
Mining Plan; or the Director's orders or instructions, and the Director 
determines that such noncompliance poses a threat of immediate, serious, 
or irreparable damage to the environment, the mine or the deposit being 
mined, or other valuable mineral deposits or other resources, the 
Director shall order the lessee to take immediate and appropriate 
remedial action to alleviate the threat. Any oral orders shall be 
followed up by service of a notice of noncompliance upon the lessee by 
delivery in person to the lessee or agent, or by certified or registered 
mail addressed to the lessee at the last known address.
    (2) If the Director determines that the lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the requirements of an approved 
Delineation, Testing, or Mining Plan; or the Director's orders or 
instructions, and such noncompliance does not pose a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall serve a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent or by certified or 
registered mail addressed to the lessee at the last known address.
    (b) A notice of noncompliance shall specify in what respect(s) the 
lessee has failed to comply with the provisions of applicable law; 
regulations; the lease; the requirements of an approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
shall specify the action(s) which must be taken to correct the 
noncompliance and the time limits

[[Page 346]]

within which such action must be taken.
    (c) Failure of a lessee to take the actions specified in the notice 
of noncompliance within the time limit specified shall be grounds for a 
suspension of operations and other appropriate actions, including but 
not limited to the assessment of a civil penalty of up to $40,000 per 
day for each violation that is not corrected within the time period 
specified (43 U.S.C. 1350(b)).
    (d) Whenever the Director determines that a violation of or failure 
to comply with any provision of the Act; or any provision of a lease, 
license, or permit issued pursuant to the Act; or any provision of any 
regulation promulgated under the Act probably occurred and that such 
apparent violation continued beyond notice of the violation and the 
expiration of the reasonable time period allowed for corrective action, 
the Director shall follow the procedures concerning remedies and 
penalties in subpart N, Remedies and Penalties, of 30 CFR part 250 to 
determine and assess an appropriate penalty.
    (e) The remedies and penalties prescribed in this section shall be 
concurrent and cumulative, and the exercise of one shall not preclude 
the exercise of the other. Further, the remedies and penalties 
prescribed in this section shall be in addition to any other remedies 
and penalties afforded by any other law or regulation (43 U.S.C. 
1350(e)).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  282.15  [Reserved]



          Subpart C_Obligations and Responsibilities of Lessees



Sec.  282.20  [Reserved]



Sec.  282.21  Plans, general.

    (a)-(d) [Reserved]
    (e) Leasehold activities shall be carried out with due regard to 
conservation of resources, paying particular attention to the wise 
management of OCS mineral resources, minimizing waste of the leased 
resource(s) in mining and processing, and preventing damage to unmined 
parts of the mineral deposit and other resources of the OCS.



Sec. Sec.  282.22-282.26  [Reserved]



Sec.  282.27  Conduct of operations.

    (a) The lessee shall conduct all exploration, testing, development, 
and production activities and other operations in a safe and workmanlike 
manner and shall maintain equipment in a manner which assures the 
protection of the lease and its improvements, the health and safety of 
all persons, and the conservation of property, and the environment.
    (b) Nothing in this part shall preclude the use of new or 
alternative technologies, techniques, procedures, equipment, or 
activities, other than those prescribed in the regulations of this part, 
if such other technologies, techniques, procedures, equipment, or 
activities afford a degree of protection, safety, and performance equal 
to or better than that intended to be achieved by the regulations of 
this part, provided the lessee obtains the written approval of the 
Director prior to the use of such new or alternative technologies, 
techniques, procedures, equipment, or activities.
    (c) The lessee shall immediately notify the Director when there is a 
death or serious injury; fire, explosion, or other hazardous event which 
threatens damage to life, a mineral deposit, or equipment; spills of 
oil, chemical reagents, or other liquid pollutants which could cause 
pollution; or damage to aquatic life or the environment associated with 
operations on the lease. As soon as practical, the lessee shall file a 
detailed report on the event and action(s) taken to control the 
situation and to mitigate any further damage.
    (d)(1) Lessees shall provide means, at all reasonable hours either 
day or night, for the Director to inspect or investigate the conditions 
of the operation and to determine whether applicable regulations; terms 
and conditions of the lease; and the requirements of the approved 
Delineation, Testing, or Mining Plan are being met.
    (2) A lessee shall, on request by the Director, furnish food, 
quarters, and

[[Page 347]]

transportation for BSEE representatives to inspect its facilities. Upon 
request, you will be reimbursed by BSEE for the actual costs that you 
incur as a result of providing transportation to BSEE representatives. 
In addition, you will be reimbursed for the actual costs that you incur 
for providing food and quarters for a BSEE representative's stay of more 
than 12 hours. You must submit an invoice for reimbursement within 90 
days of the inspection.
    (e) Mining and processing vessels, platforms, structures, artificial 
islands, and mobile drilling units which have helicopter landing 
facilities shall be identified with at least one sign using letters and 
figures not less than 12 inches in height. Signs for structures without 
helicopter landing facilities shall be identified with at least one sign 
using letters and figures not less than 3 inches in height. Signs shall 
be affixed at a location that is visible to approaching traffic and 
shall contain the following information which may be abbreviated:
    (1) Name of the lease operator;
    (2) The area designation based on Official OCS Protraction Diagrams;
    (3) The block number in which the facility is located; and
    (4) Vessel, platform, structure, or rig name.
    (f)(1) Drilling. (i) When drilling on lands valuable or potentially 
valuable for oil and gas or geopressured or geothermal resources, 
drilling equipment shall be equipped with blowout prevention and control 
devices acceptable to the Director before penetrating more than 500 feet 
unless a different depth is specified in advance by the Director.
    (ii) In cases where the Director determines that there is sufficient 
likelihood of encountering pressurized hydrocarbons, the Director may 
require that the lessee comply with all or portions of the requirements 
in part 250, subpart D, of this title.
    (iii) Before drilling any hole which may penetrate an aquifer, the 
lessee shall follow the procedures included in the approved plan for the 
penetration and isolation of the aquifer during the drilling operation, 
during use of the hole, and for subsequent abandonment of the hole.
    (iv) Cuttings from holes drilled on the lease shall be disposed of 
and monitored in accordance with the approved plan.
    (v) The use of muds in drilling holes on the lease and their 
subsequent disposition shall be according to the approved plan.
    (2) All drill holes which are susceptible to logging shall be 
logged, and the lessee shall prepare a detailed lithologic log of each 
drill hole. Drill holes which are drilled deeper than 500 feet shall be 
drilled in a manner which permits logging. Copies of logs of cores and 
cuttings and all in-hole surveys such as electronic logs, gamma ray 
logs, neutron density logs, and sonic logs shall be provided to the 
Director.
    (3) Drill holes for exploration, testing, development, or production 
shall be properly plugged and abandoned to the satisfaction of the 
Director in accordance with the approved plan and in such a manner as to 
protect the surface and not endanger any operation; any freshwater 
aquifer; or deposit of oil, gas, or other mineral substance.
    (g) The use of explosives on the lease shall be in accordance with 
the approved plan.
    (h)(1) Any equipment placed on the seabed shall be designed to allow 
its recovery and removal upon abandonment of leasehold activities.
    (2) Disposal of equipment, cables, chains, containers, or other 
materials into the ocean is prohibited.
    (3) Materials, equipment, tools, containers, and other items used on 
the OCS which are of such shape or configuration that they are likely to 
snag or damage fishing devices shall be handled and marked as follows:
    (i) All loose materials, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in use 
or in a marked container before transport over OCS waters;
    (ii) All cable, chain, or wire segments shall be recovered after use 
and securely stored;
    (iii) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over OCS waters; and

[[Page 348]]

    (iv) All markings must clearly identify the owner and must be 
durable enough to resist the effects of the environmental conditions to 
which they are exposed.
    (4) Any equipment or material described in paragraphs (h)(2), 
(h)(3)(ii), and (iii) of this section that is lost overboard shall be 
recorded on the daily operations report of the facility and reported to 
the Director and to the U.S. Coast Guard.
    (i) Any bulk sampling or testing that is necessary to be conducted 
prior to submission of a Mining Plan shall be in accordance with an 
approved Testing Plan. The sale of any OCS minerals acquired under an 
approved Testing Plan shall be subject to the payment of the royalty 
specified in the lease to the United States.
    (j) Installations and structures: (1) The lessee shall design, 
fabricate, install, use, inspect, and maintain all installations and 
structures, including platforms on the OCS, to assure the structural 
integrity of all installations and structures for the safe conduct of 
exploration, testing, mining, and processing activities considering the 
specific environmental conditions at the location of the installation or 
structure.
    (2) All fixed or bottom-founded platforms or other structures, e.g., 
artificial islands shall be designed, fabricated, installed, inspected, 
and maintained in accordance with the provisions of 30 CFR part 250, 
subpart I.
    (k) The lessee shall not produce any OCS mineral until the method of 
measurement and the procedures for product valuation have been 
instituted in accordance with the approved Testing or Mining Plan. The 
lessee shall enter the weight or quantity and quality of each mineral 
produced in accordance with 30 CFR 582.29.
    (l) The lessee shall conduct OCS mineral processing operations in 
accordance with the approved Testing or Mining Plan and use due 
diligence in the reduction, concentration, or separation of mineral 
substances by mechanical or chemical processes, by evaporation, or other 
means, so that the percentage of concentrates or other mineral 
substances are recovered in accordance with the practices approved in 
the Testing or Mining Plan.
    (m) No material shall be discharged or disposed of except in 
accordance with the approved disposal practice and procedures contained 
in the approved Delineation, Testing, or Mining Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  282.28  Environmental protection measures.

    (a)-(b) [Reserved]
    (c)(1) The lessee shall monitor activities in a manner that develops 
the data and information necessary to enable the Director to assess the 
impacts of exploration, testing, mining, and processing activities on 
the environment on and off the lease; develop and evaluate methods for 
mitigating adverse environmental effects; validate assessments made in 
previous environmental evaluations; and ensure compliance with lease and 
other requirements for the protection of the environment.
    (2) Monitoring of environmental effects shall include determination 
of the spatial and temporal environmental changes induced by the 
exploration, testing, development, production, and processing activities 
on the flora and fauna of the sea surface, the water column, and/or the 
seafloor.
    (3) The Director may place observers onboard exploration, testing, 
mining, and processing vessels; installations; or structures to ensure 
that the provisions of the lease, the approved plan, and these 
regulations are followed and to evaluate the effectiveness of the 
approved monitoring and mitigation practices and procedures in 
protecting the environment.
    (4) The Director may order or the lessee may request a modification 
of the approved monitoring program prior to the startup of testing 
activities or commercial-scale recovery, and at other appropriate times 
as necessary, to reflect accurately the proposed operations or to 
incorporate the results of recent research or improved monitoring 
techniques.
    (5) [Reserved]
    (6) When required, the monitoring plan will specify:

[[Page 349]]

    (i) The sampling techniques and procedures to be used to acquire the 
needed data and information;
    (ii) The format to be used in analysis and presentation of the data 
and information;
    (iii) The equipment, techniques, and procedures to be used in 
carrying out the monitoring program; and
    (iv) The name and qualifications of person(s) designated to be 
responsible for carrying out the environmental monitoring.
    (d) Lessees shall develop and conduct their operations in a manner 
designed to avoid, minimize, or otherwise mitigate environmental impacts 
and to demonstrate the effectiveness of efforts to that end. Based upon 
results of the monitoring program, the Director may specify particular 
procedures for mitigating environmental impacts.
    (e) [Reserved]



Sec. Sec.  282.29-282.30  [Reserved]



Sec.  282.31  Suspension of production or other operations.

    A lessee may submit a request for a suspension of production or 
other operations. The request shall include justification for granting 
the requested suspension, a schedule of work leading to the initiation 
or restoration of production or other operations, and any other 
information the Director may require.



                           Subpart D_Payments



Sec.  282.40  [Reserved]



Sec.  282.41  Method of royalty calculation.

    In the event that the provisions of royalty management regulations 
in part 1206 of chapter XII do not apply to the specific commodities 
produced under regulations in this part, the lessee shall comply with 
procedures specified in the leasing notice.



Sec.  282.42  [Reserved]



                            Subpart E_Appeals



Sec.  282.50  Appeals.

    See 30 CFR part 290 for instructions on how to appeal any order or 
decision that we issue under this part.

                           PART 285 [RESERVED]

[[Page 350]]



                          SUBCHAPTER C_APPEALS





PART 290_APPEAL PROCEDURES--Table of Contents



    Subpart A_Bureau of Safety and Environmental Enforcement Appeal 
                               Procedures

Sec.
290.1 What is the purpose of this subpart?
290.2 Who may appeal?
290.3 What is the time limit for filing an appeal?
290.4 How do I file an appeal?
290.5 Can I obtain an extension for filing my Notice of Appeal?
290.6 Are informal resolutions permitted?
290.7 Do I have to comply with the decision or order while my appeal is 
          pending?
290.8 How do I exhaust my administrative remedies?

Subpart B [Reserved]

    Authority: 5 U.S.C. 305; 43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



    Subpart A_Bureau of Safety and Environmental Enforcement Appeal 
                               Procedures



Sec.  290.1  What is the purpose of this subpart?

    The purpose of this subpart is to explain the procedures for appeals 
of Bureau of Safety and Environmental Enforcement (BSEE) decisions and 
orders issued under 30 CFR chapter II.



Sec.  290.2  Who may appeal?

    If you are adversely affected by a BSEE official's final decision or 
order issued under 30 CFR chapter II, you may appeal that decision or 
order to the Interior Board of Land Appeals (IBLA). Your appeal must 
conform with the procedures found in this subpart and 43 CFR part 4, 
subpart E.



Sec.  290.3  What is the time limit for filing an appeal?

    You must file your appeal within 60 days after you receive BSEE's 
final decision or order. The 60-day time period applies rather than the 
time period provided in 43 CFR 4.411(a). A decision or order is received 
on the date you sign a receipt confirming delivery or, if there is no 
receipt, the date otherwise documented.



Sec.  290.4  How do I file an appeal?

    For your appeal to be filed, BSEE must receive all of the following 
within 60 days after you receive the decision or order:
    (a) A written Notice of Appeal together with a copy of the decision 
or order you are appealing in the office of the BSEE officer that issued 
the decision or order. You cannot extend the 60-day period for that 
office to receive your Notice of Appeal; and
    (b) A nonrefundable processing fee of $150 paid with the Notice of 
Appeal.
    (1) You must pay electronically through the Fees for Services page 
on the BSEE Web site at http://www.bsee.gov, and you must include a copy 
of the Pay.gov confirmation receipt page with your Notice of Appeal.
    (2) You cannot extend the 60-day period for payment of the 
processing fee.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  290.5  Can I obtain an extension for filing my Notice of Appeal?

    You cannot obtain an extension of time to file the Notice of Appeal. 
See 43 CFR 4.411(c).



Sec.  290.6  Are informal resolutions permitted?

    (a) You may seek informal resolution with the issuing officer's next 
level supervisor during the 60-day period established in Sec.  290.3.
    (b) Nothing in this subpart precludes resolution by settlement of 
any appeal or matter pending in the administrative process after the 60-
day period established in Sec.  290.3.



Sec.  290.7  Do I have to comply with the decision or order while
 my appeal is pending?

    (a) The decision or order is effective during the 60-day period for 
filing an appeal under Sec.  290.3 unless:
    (1) BSEE notifies you that the decision or order, or some portion of 
it, is suspended during this period because there is no likelihood of 
immediate and

[[Page 351]]

irreparable harm to human life, the environment, any mineral deposit, or 
property; or
    (2) You post a surety bond under 30 CFR 250.1409 pending the appeal 
challenging an order to pay a civil penalty.
    (b) This section applies rather than 43 CFR 4.21(a) for appeals of 
BSEE orders.
    (c) After you file your appeal, IBLA may grant a stay of a decision 
or order under 43 CFR 4.21(b); however, a decision or order remains in 
effect until IBLA grants your request for a stay of the decision or 
order under appeal.



Sec.  290.8  How do I exhaust my administrative remedies?

    (a) If you receive a decision or order issued under chapter II, 
subchapter B, you must appeal that decision or order to IBLA under 43 
CFR part 4, subpart E to exhaust administrative remedies.
    (b) This section does not apply if the Assistant Secretary for Land 
and Minerals Management or the IBLA makes a decision or order 
immediately effective notwithstanding an appeal.

Subpart B [Reserved]



PART 291_OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS PIPELINES
 UNDER THE OUTER CONTINENTAL SHELF LANDS ACT--Table of Contents



Sec.
291.1 What is BSEE's authority to collect information?
291.100 What is the purpose of this part?
291.101 What definitions apply to this part?
291.102 May I call the BSEE Hotline to informally resolve an allegation 
          that open and nondiscriminatory access was denied?
291.103 May I use alternative dispute resolution (ADR) to informally 
          resolve an allegation that and nondiscriminatory access was 
          denied?
291.104 Who may file a complaint or a third-party brief?
291.105 What must a complaint contain?
291.106 How do I file a complaint?
291.107 How do I answer a complaint?
291.108 How do I pay the processing fee?
291.109 Can I ask for a fee waiver or a reduced processing fee?
291.110 Who may BSEE require to produce information?
291.111 How does BSEE treat the confidential information I provide?
291.112 What process will BSEE follow in rendering a decision on whether 
          a grantee or transporter has provided open and 
          nondiscriminatory access?
291.113 What actions may BSEE take to remedy denial of open and 
          nondiscriminatory access?
291.114 How do I appeal to the IBLA?
291.115 How do I exhaust administrative remedies?

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



Sec.  291.1  What is BSEE's authority to collect information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq., and assigned OMB Control Number 1014-0012.
    (b) An agency may not conduct or sponsor, and you are not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (c) We use the information collected to determine whether or not the 
shipper has been denied open and nondiscriminatory access to Outer 
Continental Shelf (OCS) pipelines as sections of 5(e) and (f) of the OCS 
Lands Act (OCSLA) require.
    (d) Respondents are companies that ship or transport oil and gas 
production across the OCS. Responses are required to obtain or retain 
benefits. We will protect information considered proprietary under 
applicable law.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  291.100  What is the purpose of this part?

    This part:
    (a) Explains the procedures for filing a complaint with the 
Director, Bureau of Safety and Environmental Enforcement (BSEE) alleging 
that a grantee or

[[Page 352]]

transporter has denied a shipper of production from the OCS open and 
nondiscriminatory access to a pipeline;
    (b) Explains the procedures BSEE will employ to determine whether 
violations of the requirements of the OCSLA have occurred, and to remedy 
any violations; and
    (c) Provides for alternative informal means of resolving pipeline 
access disputes through either Hotline-assisted procedures or 
alternative dispute resolution (ADR).



Sec.  291.101  What definitions apply to this part?

    As used in this part:
    Accessory means a platform, a major subsea manifold, or similar 
subsea structure attached to a right-of-way (ROW) pipeline to support 
pump stations, compressors, manifolds, etc. The site used for an 
accessory is part of the pipeline ROW grant.
    Appurtenance means equipment, device, apparatus, or other object 
attached to a horizontal component or riser. Examples include anodes, 
valves, flanges, fittings, umbilicals, subsea manifolds, templates, 
pipeline end modules (PLEMs), pipeline end terminals (PLETs), anode 
sleds, other sleds, and jumpers (other than jumpers connecting subsea 
wells to manifolds).
    FERC pipeline means any pipeline within the jurisdiction of the 
Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, 
15 U.S.C. 717-717z, or the Interstate Commerce Act, 42 U.S.C. 7172(a) 
and (b).
    Grantee means any person to whom BSEE has issued an oil or gas 
pipeline permit, license, easement, right-of-way, or other grant of 
authority for transportation on or across the OCS under 30 CFR part 250, 
subpart J, or 43 U.S.C. 1337(p), and any person who has an assignment of 
a permit, license, easement, right-of-way or other grant of authority, 
or who has an assignment of any rights subject to any of those grants of 
authority under 30 CFR part 250, subpart J or 43 U.S.C. 1337(p).
    IBLA means the Interior Board of Land Appeals.
    OCSLA pipeline means any oil or gas pipeline for which BSEE has 
issued a permit, license, easement, right-of-way, or other grant of 
authority.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Party means any person who files a complaint, any person who files 
an answer, and BSEE.
    Person means an individual, corporation, government entity, 
partnership, association (including a trust or limited liability 
company), consortium, or joint venture (when established as a separate 
entity).
    Pipeline is the piping, risers, accessories and appurtenances 
installed for transportation of oil and gas.
    Serve means personally delivering a document to a person, or sending 
a document by U.S. mail or private delivery services that provide proof 
of delivery (such as return receipt requested) to a person.
    Shipper means a person who contracts or wants to contract with a 
grantee or transporter to transport oil or gas through the grantee's or 
transporter's pipeline.
    Transportation means, for purposes of this part only, the movement 
of oil or gas through an OCSLA pipeline.
    Transporter means, for purposes of this part only, any person who 
owns or operates an OCSLA oil or gas pipeline.



Sec.  291.102  May I call the BSEE Hotline to informally resolve
 an allegation that open and nondiscriminatory access was denied?

    Before filing a complaint under Sec.  291.106, you may attempt to 
informally resolve an allegation concerning open and nondiscriminatory 
access by calling the toll-free BSEE Pipeline Open Access Hotline at 1-
888-232-1713.
    (a) BSEE Hotline staff will informally seek information needed to 
resolve the dispute. BSEE Hotline staff will attempt to resolve disputes 
without litigation or other formal proceedings. The Hotline staff will 
not attempt to resolve matters that are before BSEE or FERC in docketed 
proceedings.

[[Page 353]]

    (b) BSEE Hotline staff may provide information to you and give 
informal oral advice. The advice given is not binding on BSEE, the 
Department of the Interior (DOI), or any other person.
    (c) To the extent permitted by law, the BSEE Hotline staff will 
treat all information it obtains as non-public and confidential.
    (d) You may call the BSEE Hotline anonymously.
    (e) If you contact the BSEE Hotline, you may file a complaint under 
this part if discussions assisted by BSEE Hotline staff are unsuccessful 
at resolving the matter.
    (f) You may terminate use of the BSEE Hotline procedure at any time.



Sec.  291.103  May I use alternative dispute resolution (ADR) to 
informally resolve an allegation that open and nondiscriminatory 
access was denied?

    You may ask to use ADR either before or after you file a complaint. 
To make a request, call the BSEE at 1-888-232-1713 or write to us at the 
following address: Director, Bureau of Safety and Environmental 
Enforcement, Attention: Office of Policy and Analysis, 1849 C Street, 
NW., Mail Stop 5438, Washington, DC 20240-0001.
    (a) You may request that ADR be administered by:
    (1) A contracted ADR provider agreed to by all parties;
    (2) The Department's Office of Collaborative Action and Dispute 
Resolution (CADR); or
    (3) BSEE staff trained in ADR and certified by the CADR.
    (b) Each party must pay its respective share of all costs and fees 
associated with any contracted or Departmental ADR provider. For 
purposes of this section, BSEE is not a party in an ADR proceeding.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  291.104  Who may file a complaint or a third-party brief?

    (a) You may file a complaint under this subpart if you are a shipper 
and you believe that you have been denied open and nondiscriminatory 
access to an OCSLA pipeline that is not a FERC pipeline.
    (b) Any person that believes its interests may be affected by 
precedents established by adjudication of complaints under this rule may 
submit a brief to BSEE. The brief must be served following the procedure 
set out in Sec.  291.107. After considering the brief, it is within 
BSEE's discretion as to whether BSEE may:
    (1) Address the brief in its decision;
    (2) Not address the brief in its decision; or
    (3) Include the submitter of the brief in the proceeding as a party.



Sec.  291.105  What must a complaint contain?

    For purposes of this subpart, a complaint means a comprehensive 
written brief stating the legal and factual basis for the allegation 
that a shipper was denied open and nondiscriminatory access, together 
with supporting material. A complaint must:
    (a) Clearly identify the action or inaction which is alleged to 
violate 43 U.S.C. 1334(e) or (f)(1)(A);
    (b) Explain how the action or inaction violates 43 U.S.C. 1334(e) or 
(f)(1)(A);
    (c) Explain how the action or inaction affects your interests, 
including practical, operational, or other non-financial impacts;
    (d) Estimate any financial impact or burden;
    (e) State the specific relief or remedy requested; and
    (f) Include all documents that support the facts in your complaint 
including, but not limited to, contracts and any affidavits that may be 
necessary to support particular factual allegations.



Sec.  291.106  How do I file a complaint?

    To file a complaint under this part, you must:
    (a) File your complaint with the Director, Bureau of Safety and 
Environmental Enforcement at the following address: Director, Bureau of 
Safety and Environmental Enforcement, Attention: Office of Policy and 
Analysis, 1849 C Street, NW., Mail Stop 5438, Washington, DC 20240-0001; 
and
    (b) Include a nonrefundable processing fee of $7,500 under Sec.  
291.108(a) or

[[Page 354]]

a request for reduction or waiver of the fee under Sec.  291.109(a); and
    (c) Serve your complaint on all persons named in the complaint. If 
you make a claim under Sec.  291.111 for confidentiality, serve the 
redacted copy and proposed form of a protective agreement on all persons 
named in the complaint.
    (d) Complaints shall not be filed later than 2 years from the time 
of the alleged access denial. If the complaint is filed later than 2 
years from the time of the alleged access denial, the BSEE Director will 
not consider the complaint and the case will be closed.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  291.107  How do I answer a complaint?

    (a) If you have been served a complaint under Sec.  291.106, you 
must file an answer within 60 days of receiving the complaint. If you 
miss this deadline, BSEE may disregard your answer. We consider your 
answer to be filed when the BSEE Director receives it at the following 
address: Director, Bureau of Safety and Environmental Enforcement, 
Attention: Office of Policy and Analysis, 1849 C Street, NW., Mail Stop 
5438, Washington, DC 20240-0001.
    (b) For purposes of this paragraph, an answer means a comprehensive 
written brief stating the legal and factual basis refuting the 
allegations in the complaint, together with supporting material. You 
must:
    (1) Attach to your answer a copy of the complaint or reference the 
assigned BSEE docket number (you may obtain the docket number by calling 
the Office of Policy and Analysis at (202) 208-1901);
    (2) Explain in your answer why the action or inaction alleged in the 
complaint does not violate 43 U.S.C. 1334(e) or (f)(1)(A);
    (3) Include with your answer all documents in your possession or 
that you can otherwise obtain that support the facts in your answer 
including, but not limited to, contracts and any affidavits that may be 
necessary to support particular factual allegations; and
    (4) Provide a copy of your answer to all parties named in the 
complaint including the complainant. If you make a claim under Sec.  
291.111 for confidentiality, serve the redacted copy and proposed form 
of a protective agreement to all parties named in the complaint, 
including the complainant.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  291.108  How do I pay the processing fee?

    (a) You must pay the processing fee electronically through the Fees 
for Services page on the BSEE Web site at http://www.bsee.gov, and you 
must include a copy of the Pay.gov confirmation receipt page with your 
complaint.
    (b) You must include with the payment:
    (1) Your taxpayer identification number;
    (2) Your payor identification number, if applicable; and
    (3) The complaint caption, or any other applicable identification of 
the complaint you are filing.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]



Sec.  291.109  Can I ask for a fee waiver or a reduced processing fee?

    (a) BSEE may grant a fee waiver or fee reduction in extraordinary 
circumstances. You may request a waiver or reduction of your fee by:
    (1) Sending a written request to the BSEE Office of Policy and 
Analysis when you file your complaint; and
    (2) Demonstrating in your request that you are unable to pay the fee 
or that payment of the full fee would impose an undue hardship upon you.
    (b) The BSEE Office of Policy and Analysis will send you a written 
decision granting or denying your request for a fee waiver or a fee 
reduction.
    (1) If we grant your request for a fee reduction, you must pay the 
reduced processing fee within 30 days of the date you receive our 
decision.
    (2) If we deny your request, you must pay the entire processing fee 
within 30 days of the date you receive the decision.
    (3) BSEE's decision granting or denying a fee waiver or reduction is 
final for the Department.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

[[Page 355]]



Sec.  291.110  Who may BSEE require to produce information?

    (a) BSEE may require any lessee, operator of a lease or unit, 
shipper, grantee, or transporter to provide information that BSEE 
believes is necessary to make a decision on whether open access or 
nondiscriminatory access was denied.
    (b) If you are a party and fail to provide information BSEE requires 
under paragraph (a) of this section, BSEE may:
    (1) Assess civil penalties under 30 CFR part 250, subpart N;
    (2) Dismiss your complaint or consider your answer incomplete; or
    (3) Presume the required information is adverse to you on the 
factual issues to which the information is relevant.
    (c) If you are not a party to a complaint and fail to provide 
information BSEE requires under paragraph (a) of this section, BSEE may 
assess civil penalties under 30 CFR part 250, subpart N.



Sec.  291.111  How does BSEE treat the confidential information I provide?

    (a) Any person who provides documents under this part in response to 
a request by BSEE to inform a decision on whether open access or 
nondiscriminatory access was denied may claim that some or all of the 
information contained in a particular document is confidential. If you 
claim confidential treatment, then when you provide the document to BSEE 
you must:
    (1) Provide a complete unredacted copy of the document and indicate 
on that copy that you are making a request for confidential treatment 
for some or all of the information in the document.
    (2) Provide a statement specifying the specific statutory 
justification for nondisclosure of the information for which you claim 
confidential treatment. General claims of confidentiality are not 
sufficient. You must furnish sufficient information for BSEE to make an 
informed decision on the request for confidential treatment.
    (3) Provide a second copy of the document from which you have 
redacted the information for which you wish to claim confidential 
treatment. If you do not submit a second copy of the document with the 
confidential information redacted, BSEE may assume that there is no 
objection to public disclosure of the document in its entirety.
    (b) In making data and information you submit available to the 
public, BSEE will not disclose documents exempt from disclosure under 
the Freedom of Information Act (5 U.S.C. 552) and will follow the 
procedures set forth in the implementing regulations at 43 CFR part 2 to 
give submitters an opportunity to object to disclosure.
    (c) BSEE retains the right to make the determination with regard to 
any claim of confidentiality. BSEE will notify you of its decision to 
deny a claim, in whole or in part, and, to the extent permitted by law, 
will give you an opportunity to respond at least 10 days before its 
public disclosure.



Sec.  291.112  What process will BSEE follow in rendering a decision
 on whether a grantee or transporter has provided open and 
nondiscriminatory access?

    BSEE will begin processing a complaint upon receipt of a processing 
fee or granting a waiver of the fee. The BSEE Director will review the 
complaint, answer, and other information, and will serve all parties 
with a written decision that:
    (a) Makes findings of fact and conclusions of law; and
    (b) Renders a decision determining whether the complainant has been 
denied open and nondiscriminatory access.



Sec.  291.113  What actions may BSEE take to remedy denial of open
 and nondiscriminatory access?

    If the BSEE Director's decision under Sec.  291.112 determines that 
the grantee or transporter has not provided open access or 
nondiscriminatory access, then the decision will describe the actions 
BSEE will take to require the grantee or transporter to remedy the 
denial of open access or nondiscriminatory access. The remedies BSEE 
would require must be consistent with BSEE's statutory authority, 
regulations, and any limits thereon due to Congressional delegations to 
other agencies. Actions BSEE may take include, but are not limited to:

[[Page 356]]

    (a) Ordering grantees and transporters to provide open and 
nondiscriminatory access to the complainant;
    (b) Assessing civil penalties of up to $10,000 per day under 30 CFR 
part 250, subpart N, for failure to comply with a BSEE order to provide 
open access or nondiscriminatory access. Penalties will begin to accrue 
60 days after the grantee or transporter receives the order to provide 
open and nondiscriminatory access if it has not provided such access by 
that time. However, if BSEE determines that requiring the construction 
of facilities would be an appropriate remedy under the OCSLA, penalties 
will begin to accrue 10 days after conclusion of diligent construction 
of needed facilities or 60 days after the grantee or transporter 
receives the order to provide open and nondiscriminatory access, 
whichever is later, if it has not provided such access by that time;
    (c) Requesting the Attorney General to institute a civil action in 
the appropriate United States District Court under 43 U.S.C. 1350(a) for 
a temporary restraining order, injunction, or other appropriate remedy 
to enforce the open and nondiscriminatory access requirements of 43 
U.S.C. 1334(e) and (f)(1)(A); or
    (d) Initiating a proceeding to forfeit the right-of-way grant under 
43 U.S.C. 1334(e).



Sec.  291.114  How do I appeal to the IBLA?

    Any party, except as provided in Sec.  291.115(b), adversely 
affected by a decision of the BSEE Director under this part may appeal 
to the Interior Board of Land Appeals (IBLA) under the procedures in 43 
CFR part 4, subpart E.



Sec.  291.115  How do I exhaust administrative remedies?

    (a) If the BSEE Director issues a decision under this part but does 
not expressly make the decision effective upon issuance, you must appeal 
the decision to the IBLA under 43 CFR part 4 to exhaust administrative 
remedies. Such decision will not be effective during the time in which a 
person adversely affected by the BSEE Director's decision may file a 
notice of appeal with the IBLA, and the timely filing of a notice of 
appeal will suspend the effect of the decision pending the decision on 
appeal.
    (b) This section does not apply if a decision was made effective by:
    (1) The BSEE Director; or
    (2) The Assistant Secretary for Land and Minerals Management.

                        PARTS 292	299 [RESERVED]

[[Page 357]]



        CHAPTER IV--GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------
Part                                                                Page
400

[Reserved]

401             State Water Research Institute Program......         359
402             Water-Resources Research Program and the 
                    Water-Resources Technology Development 
                    Program.................................         364
403-499

[Reserved]

[[Page 359]]

                           PART 400 [RESERVED]



PART 401_STATE WATER RESEARCH INSTITUTE PROGRAM--Table of Contents



                            Subpart A_General

Sec.
401.1 Purpose.
401.2 Delegation of authority.
401.3 Definitions.
401.4 Information collection.
401.5 [Reserved]

         Subpart B_Designation of Institutes; Institute Programs

401.6 Designation of institutes.
401.7 Programs of institutes.
401.8-401.10 [Reserved]

             Subpart C_Application and Management Procedures

401.11 Applications for grants.
401.12 Program management.
401.13-401.18 [Reserved]

                           Subpart D_Reporting

401.19 Reporting procedures.
401.20-401.25 [Reserved]

                          Subpart E_Evaluation

401.26 Evaluation of institutes.

    Authority: 42 U.S.C. 10303.

    Source: 50 FR 23114, May 31, 1985, unless otherwise noted.



                            Subpart A_General



Sec.  401.1  Purpose.

    The regulations in this part are issued pursuant to title I of the 
Water Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97) which 
authorizes appropriations to, and confers authority upon, the Secretary 
of the Interior to promote a national program of water-resources 
research.



Sec.  401.2  Delegation of authority.

    The State Water Research Institute Program, as authorized by section 
104 of the Act, has been established as a component of the U.S. 
Geological Survey (USGS). Secretary of the Interior has delegated to the 
Director of the USGS authority to take the actions and make the 
determinations that, under the Act, are the responsibility of the 
Secretary.



Sec.  401.3  Definitions.

    Act means the Water Resources Research Act of 1984 (Pub. L. 98-242, 
98 Stat. 97).
    Fiscal year means a 12-month period ending on September 30.
    Director means the Director of the USGS or a designee.
    Grant means the funds made available to an institute in a particular 
fiscal year pursuant to section 104 of the Act and the regulations in 
this chapter.
    Grantee means the college or university at which an institute is 
established.
    Granting agency means the USGS.
    Institute means a water resources research institute, center, or 
equivalent agency established in accordance with Title I of the Act.
    Region means any grouping of two or more institutes mutually chosen 
by themselves to reflect a commonality of water-resources problems.
    Scientists means individuals engaged in any professional discipline, 
including the life, physical or social sciences, and engineers.
    Secretary means the Secretary of the Interior or a designee.
    State means each of the 50 States, the Commonwealth of Puerto Rico, 
the Virgin Islands, the District of Columbia, Guam, American Samoa, the 
Commonwealth of the Mariana Islands, and the Federated States of 
Micronesia.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]



Sec.  401.4  Information collection.

    (a) The information collection requirements contained in sections 
401.11 and 401.19 have been approved by the Office of Management and 
Budget under 44 U.S.C. 3501 et seq. and assigned clearance number 1028-
0044. The information will be used to support water related research and 
provide performance reports on accomplishments achieved under Pub. L. 
98-242, 98 Stat. 97 (42 U.S.C. 10303). This information allows the 
agency to determine compliance with the objectives and criteria of

[[Page 360]]

the grant programs. Response is mandatory in accordance with 30 CFR 
401.11 and 401.19.
    (b) Public reporting burden for the collection of information is 
estimated to average 84 hours per response, including the time for 
reviewing instructions, searching existing data sources, gathering and 
maintaining the data needed, and completing and reviewing the collection 
of information. Send comments regarding this burden estimate, or any 
other suggestions for reducing the burden, to Paperwork Management 
Officer, U.S. Geological Survey, Paperwork Management Section MS 208, 
Reston, Virginia 22092 and the Office of Management and Budget, 
Paperwork Reduction Project (1028-0044), Washington, DC 20503.

[58 FR 27204, May 7, 1993]



Sec.  401.5  [Reserved]



         Subpart B_Designation of Institutes; Institute Programs



Sec.  401.6  Designation of institutes.

    (a) As a condition of recognition as an established institute under 
the provisions of this chapter, each institute shall provide to the 
Director written evidence that it conforms to the requirements of 
subsection 104(a) of the Act, in that:
    (1) The institute is established at the college or university in the 
State that was established in accordance with the Act of July 21, 1862 
(12 Stat. 503; 7 U.S.C. 301ff), i.e., a ``land-grant'' institution, or;
    (2) If established at some other institution, the institute is at a 
college or university that has been designated by act of the legislature 
for the purposes of the Act, or;
    (3) If there is more than one ``land-grant'' institution in the 
State, and no designation has been made according to paragraph (a)(2) of 
this section, the institute has been established at the one such 
institution designated by the Governor of the State to participate in 
the program, or;
    (4) The institute has been designated as an interstate or regional 
institute by two or more cooperating States as provided in the Act.
    (b) The certification of designation made pursuant to paragraph (a) 
of this section shall originate following the issuance of these 
regulations, be signed by the highest ranking officer of the college or 
university at which the institute is established and be submitted to the 
Director within 90 days of the effective date of these regulations. It 
shall be accompanied either by the evidence of establishment under the 
provisions of 30 CFR part 401 or by new evidence of establishment made 
pursuant to these regulations.
    (c) Any institute not previously established under the provisions of 
the Water Resources Act of 1964 (Pub. L. 88-379, 78 Stat. 331) or the 
Water Research and Development Act of 1978 (Pub. L. 95-467, 92 Stat. 
1305) shall also, in addition to the annual program application 
specified in Sec.  401.11 of this chapter, submit to the Director the 
following information:
    (1) Evidence of the appointment by the governing authority of the 
college or university of an officer to receive and account for all funds 
paid under the provisions of the Act and to make annual reports to the 
granting agency on work accomplished; and
    (2) A management plan for meeting the requirements of the evaluation 
mandated by Sec.  401.26.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]



Sec.  401.7  Programs of institutes.

    (a) Release of grant funds to participating institutes is 
conditioned on the ability of each receiving institute to plan, conduct, 
or otherwise arrange for:
    (1) Competent research, investigations, and experiments of either a 
basic or practical nature, or both, in relation to water resources;
    (2) Promotion of the dissemination and application of the results of 
these efforts; and
    (3) Assistance in the training of scientists in relevant fields of 
endeavor to water resources through the research, investigations, and 
experiments.
    (b) Such research, investigations, experiments and training may 
include:
    (1) Aspects of the hydrologic cycle;
    (2) Supply and demand;
    (3) Demineralization of saline and other impaired waters;

[[Page 361]]

    (4) Conservation and best use of available supplies of water and 
methods of increasing such supplies;
    (5) Water reuse;
    (6) Depletion and degradation of ground-water supplies;
    (7) Improvements in the productivity of water when used for 
agricultural, municipal, and commercial purposes;
    (8) The economic, legal, engineering, social, recreational, 
biological, geographical, ecological, or other aspects of water 
problems;
    (9) Scientific information dissemination activities, including 
identifying, assembling, and interpreting the results of scientific 
research on water resources problems, and ;
    (10) Providing means for improved communication of research results, 
having due regard for the varying conditions and needs of the respective 
States and regions.
    (c) An institute shall cooperate closely with other colleges and 
universities in the State that have demonstrated capabilities for 
research, information dissemination and graduate training in the 
development of its program. For purposes of financial management, 
reporting and other research program management and administration 
activities, the institutes shall be responsible for performance of the 
activities of other participating institutions.
    (d) Each institute shall cooperate closely with other institutes and 
other research organizations in the region to increase the effectiveness 
of the institutes, to coordinate their activities, and to avoid undue 
duplication of effort.



Sec. Sec.  401.8-401.10  [Reserved]



             Subpart C_Application and Management Procedures



Sec.  401.11  Applications for grants.

    (a) Subject to the availability of appropriated funds, but not to 
exceed a total of $10 million, an equal amount of dollars will be 
available to each qualified institute in each fiscal year to assist it 
in carrying out the purposes of the Act. If the full amount of the 
appropriated funds is not obligated by the close of the fiscal year for 
which they were appropriated, the remaining funds shall be made 
available in the succeeding fiscal year to support competitively 
selected research projects under the terms of section 104(g) of the Act. 
Selection and approval of such projects shall be based on criteria to be 
determined by the Director. Announcement of such criteria shall be made 
by notice in the Federal Register. The granting agency may retain an 
amount up to 15 percent of the total appropriation for administrative 
costs.
    (b) The granting agency will annually make available to qualified 
institutes instructions for the submittal of applications for grants. 
The instructions will include information pertinent only to a single 
fiscal year, such as the closing date for applications and the amount of 
funds initially available to each institute. They also will include 
notification of the provisions and assurances necessary to ensure that 
administration of the grant will be conducted in compliance with this 
chapter and other Federal laws and regulations applicable to grants to 
institutions of higher learning.
    (c) In making its application for funds to which it is entitled 
under the Act, each institute shall use and follow the standard form for 
Federal assistance (SF 424, Federal Assistance). No preapplication is 
required. The institute shall include in section IV of Standard Form 424 
evidence that its application was:
    (1) Developed in close consultation and collaboration with senior 
personnel of the State's department of water resources or similar 
agencies, other leading water resources officials within the State, and 
interested members of the public;
    (2) Coordinated with other institutes in the region for the purposes 
of avoiding duplication of effort and encouraging regional cooperation 
in research areas of water management, development, and conservation 
that have a regional or national character; and
    (3) Reviewed for technical merit of its research components by 
qualified scientists.
    (d) Each application shall further include:
    (1) A financial plan relating expenditures to scheduled activity and 
rate of effort to be expended and indicating

[[Page 362]]

the times at which there will be need for specified amounts of Federal 
funds; and
    (2) A description of the institute's arrangements for development, 
administration, and technical oversight of the research program.
    (e) Each annual program application is to include separately 
identifiable proposals for conduct of research to meet the needs of the 
State and region. Such proposals must set forth for each project:
    (1) The nature, scope and objectives of the project to be 
undertaken;
    (2) Its importance to the State, region, or Nation; its relation to 
other known research projects already completed or in progress; and the 
anticipated applicability of the research results;
    (3) The period during which it will be pursued;
    (4) The names and qualifications of the senior professional 
personnel who will direct and conduct the project;
    (5) Its estimated costs, with a breakdown of the costs per year; and
    (6) The extent of which it will provide opportunity for the training 
of scientists.
    (f) Each program application shall contain a plan for disseminating 
information on the results of research and promoting their application. 
Plans which require the use of grant funds shall contain:
    (1) Definition of the topics for dissemination;
    (2) Identification of the target audiences for dissemination;
    (3) Strategies for accomplishing the dissemination;
    (4) Duties and qualifications of the personnel to be involved;
    (5) Estimated costs of each identifiable element of the plan; and
    (6) Identification of cooperating entities.
    (g) The application shall provide assurance that non-Federal dollars 
will be available to share the costs of the proposed program. The 
Federal funds are to be matched on a basis of no less than two non-
Federal dollars for each Federal dollar, unless this matching 
requirement has been waived.
    (h) The granting agency will evaluate the proposals for consistency 
with the provisions of its instructions and this chapter and within no 
more than 90 days request any revisions and additions necessary for such 
consistency.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]



Sec.  401.12  Program management.

    (a) Upon approval of each fiscal year's proposed program, the 
granting agency will transmit to the grantee an award which will 
incorporate the application and assurances.
    (b) The grant is effective and constitutes an obligation of Federal 
funds in the amount and for the purpose stated in the award document at 
the time of the Director's signature.
    (c)(1) Acceptance of the award document certifies the grantee's 
assurance that the grant will be administered in compliance with OMB 
regulations, policies, guidelines, and requirements as described in:
    (i) Circular No. A-21, revised, Cost Principles of Educational 
Institutions;
    (ii) Memorandum No. M-92-01, Coordination of Water Resources 
Information;
    (iii) Circular No. A-88, revised, Indirect Cost Rates, Audit and 
Audit Follow-up at Educational Institutions;
    (iv) Circular No. A-110, Uniform Administrative Requirements for 
Grants and Agreements with Institutions of Higher Education, Hospitals 
and other Nonprofit Organizations; and
    (v) Circular No. A-124, Patents--Small Business Firms and Nonprofit 
Organizations.
    (2) Copies of the documents listed in paragraph (c)(1) of this 
section shall be available from the granting agency.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]



Sec. Sec.  401.13-401.18  [Reserved]



                           Subpart D_Reporting



Sec.  401.19  Reporting procedures.

    (a) The institutes are encouraged to publish, as technical reports 
or in the professional literature, the findings, results, and 
conclusions relating to separately identifiable research projects 
undertaken pursuant to the Act.

[[Page 363]]

    (b) Each institute shall submit to the granting agency, by a date to 
be specified in the award document, an annual program report which 
provides:
    (1) A statement concerning the relationship of the institute's 
program to the water problems and issues of the State;
    (2) A synopsis of the objectives, methods, and conclusions of each 
project completed within the period covered;
    (3) A progress report on each project continuing into the subsequent 
fiscal year;
    (4) Citations of all reports, papers, publications or other 
communicable products resulting from each project completed or in 
progress;
    (5) A description of all activities undertaken for the purpose of 
promoting the application of research results;
    (6) A description of cooperative arrangements with other educational 
institutions, State agencies, and others.
    (c) One manuscript of reproducible quality and two copies of the 
annual program report shall be furnished to the granting agency. One 
copy of a complete report on the objectives, methods, and conclusions of 
each research project shall be maintained by the institute and open to 
inspection.
    (d) Appropriate acknowledgment shall be given by institutes to the 
granting agency's participation in financing activities carried out 
under provisions of the Act. Such acknowledgment shall be included in 
all reports, publications, news releases, and other information media 
developed by institutes and others to publicize, describe, or report 
upon accomplishments and activities of the program.
    (e) An original and two copies of the final ``Financial Status 
Report,'' SF 269, shall be furnished to the granting agency within 90 
days of completion of the grant period.



Sec. Sec.  401.20-401.25  [Reserved]



                          Subpart E_Evaluation



Sec.  401.26  Evaluation of institutes.

    (a) Within 2 years of the date of its certification according to the 
provisions of Sec.  401.6, each institute will be evaluated for the 
purpose of determining whether the national interest warrants its 
continued support under the provisions of the Act. That determination 
shall be based on:
    (1) The quality and relevance of its water resources research as 
funded under the Act;
    (2) Its effectiveness as an institution for planning, conducting, or 
arranging for research;
    (3) Its demonstrated performance in making research results 
available to users in the State and elsewhere; and
    (4) Its demonstrated record in providing for the training of 
scientists through student involvement in its research program.
    (b) An evaluation team, selected by the granting agency on the basis 
of the members' knowledge of water research and administration, shall 
evaluate each institute, and may with the concurrence of the granting 
agency, visit such institutes as it considers necessary. The team is to 
include at least one individual from each of the following categories:
    (1) Employees of the Department of the Interior;
    (2) University faculty or other professionals with relevant 
experience in the conduct of water resources research;
    (3) Former directors of water research institutes; and
    (4) University faculty or other professionals with relevant 
experience in information transfer.
    (c) The granting agency may request recommendations for team 
selections from the National Research Council/National Academy of 
Sciences and from other organizations whose members include the types of 
individuals cited in paragraph (b) of this section.
    (d) The granting agency shall, as an administrative cost, provide 
the funds for travel and per diem expense of the team members, within 
the maximum limits allowable under Federal travel regulations (41 CFR 
subtitle F).
    (e) The granting agency has the right to select dates for evaluation 
visits, and notice of the team's visit shall be provided to the 
institute being evaluated at least 60 days in advance.
    (f) It shall be the responsibility of each institute to provide such 
documentation of its activities and accomplishments as the granting 
agency and

[[Page 364]]

evaluation team may reasonably request. The request for this 
documentation shall be made at least 60 days prior to the due date of 
its receipt.
    (g) The team shall, within 90 days after completion of its 
evaluation, submit a written report of its findings to the granting 
agency for transmittal to the institute. If an institute is found to 
have deficiencies in meeting the objectives of the Act, it shall be 
allowed 1 year to correct them and to report such action to the granting 
agency. The decision as to the institute's eligibility to receive 
further funding will rest with the granting agency.
    (h) After the initial evaluation, each institute shall be 
reevaluated at least every 5 years.

[58 FR 27204, May 7, 1993]



PART 402_WATER-RESOURCES RESEARCH PROGRAM AND THE WATER-RESOURCES
 TECHNOLOGY DEVELOPMENT PROGRAM--Table of Contents



                            Subpart A_General

Sec.
402.1 Purpose.
402.2 Delegation of authority.
402.3 Definitions.
402.4 Information collection.
402.5 [Reserved]

            Subpart B_Description of Water-Resources Programs

402.6 Water-Resources Research Program.
402.7 Water-Resources Technology Development Program.
402.8-402.9 [Reserved]

      Subpart C_Application, Evaluation, and Management Procedures

402.10 Research-project applications.
402.11 Technology-development project applications.
402.12 Evaluation of applications for grants and contracts.
402.13 Program management.
402.14 [Reserved]

                           Subpart D_Reporting

402.15 Reporting procedures.

    Authority: Secs. 105 and 106, Pub. L. 98-242, 98 Stat. 97 (42 U.S.C. 
10304 and 10305).

    Source: 51 FR 20963, June 10, 1986, unless otherwise noted.



                            Subpart A_General



Sec.  402.1  Purpose.

    The regulations in this part are issued pursuant to title I of the 
Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97), 
which authorizes appropriations to, and confers authority upon, the 
Secretary of the Interior to promote national programs of water-
resources research and technology development.



Sec.  402.2  Delegation of authority.

    The Water-Resources Research Program and the Water-Resources 
Technology Development Program, as authorized by sections 105 and 106 of 
the Act (42 U.S.C. 10304 and 10305), have been established as components 
of the USGS. The Secretary of the Interior has delegated to the Director 
of the USGS authority to take actions and make the determinations that, 
under the Act, are the responsibility of the Secretary.



Sec.  402.3  Definitions.

    (a) Grant is used in these rules as a generic term for a Federal 
assistance award, including project grants and cooperative agreements.
    (b) Act means the Water Resources Research Act of 1984 (Pub. L. 98-
242, 98 Stat. 97).
    (c) Educational institution means any educational institution--
privately and/or publicly owned.
    (d) Dollar-for-dollar matching grant means for each Federal dollar 
provided to support the projects, a non-Federal dollar also must be 
provided to the project.



Sec.  402.4  Information collection.

    The information-collection requirements contained in sections 
402.10, 402.11, and 402.15 have been approved by the OMB under 44 U.S.C. 
3501 et seq. and assigned clearance number 1028-0046. The application 
proposals being collected will contain technical information that will 
be used by the USGS as a basis for selection and award of grants. The 
progress reports being collected will contain a description of all work 
accomplished and results achieved on each funded project and will enable 
the USGS to carry out its

[[Page 365]]

oversight responsibilities and provide dissemination of technical 
information.



Sec.  402.5  [Reserved]



            Subpart B_Description of Water-Resources Programs



Sec.  402.6  Water-Resources Research Program.

    (a) Subject to the availability of appropriated funds, the Water-
Resources Research Program will provide support, in the form of a 
dollar-for-dollar matching grant, to educational institutions, private 
foundations, private firms, individuals, and agencies of local or State 
governments for research concerning any aspect of a water-resource 
related problem deemed to be in the national interest. Federal agencies 
are excluded from receiving matching grants. Grants may be awarded on 
other than a dollar-for-dollar matching basis in cases where the USGS 
determines that research on a high-priority subject is of a basic nature 
that otherwise would not be undertaken.
    (b) The types of research to be undertaken under this program are 
listed below, without indication of priority:
    (1) Aspects of the hydrologic cycle;
    (2) Supply and demand for water;
    (3) Demineralization of saline and other impaired waters;
    (4) Conservation and best use of available supplies of water and 
methods of increasing such supplies;
    (5) Water reuse;
    (6) Depletion and degradation of groundwater supplies;
    (7) Improvements in the productivity of water when used for 
agricultural, municipal, and commercial purposes; and
    (8) The economic, legal, engineering, social, recreational, 
biological, geographic, ecological, and other aspects of water problems.
    (9) Scientific information-dissemination activities, including 
identifying, assembling, and interpreting the results of scientific and 
engineering research on water-resources problems.
    (10) Providing means for improved communications of research 
results, having due regard for the varying conditions and needs for the 
respective States and regions.



Sec.  402.7  Water-Resources Technology Development Program.

    (a) Subject to the availability of appropriated funds, the Water-
Resources Technology Development Program will provide funds in the form 
of grants or contracts to educational institutions, private firms, 
private foundations, individuals, and agencies of local or State 
governments for technology development concerning any aspect of water-
related technology deemed to be of State, regional, and national 
importance, including technology associated with improvement of waters 
of impaired quality and the operation of test facilities. Federal 
agencies are excluded from receiving grants or contracts. The types of 
technology-development to be undertaken under this program shall include 
paragraphs 1 through 10 of Sec.  402.6(b).
    (b) The USGS may establish any condition for the matching of funds 
by the recipient of any grant or cost-sharing under a contract under the 
technology-development program which the USGS considers to be in the 
best interest of the Nation.



Sec. Sec.  402.8-402.9  [Reserved]



      Subpart C_Application, Evaluation, and Management Procedures



Sec.  402.10  Research-project applications.

    (a) Only those applications for grants that are in response to and 
meet the guidelines of specific USGS announcements will be considered 
for funding appropriated for this program.
    (b) The USGS program announcements will identify priorities, 
matching requirements, particular areas of interest, criteria for 
evaluation, OMB regulations as appropriate, assurances, closing date, 
and proposal submittal instructions. Program announcements may also 
include criteria for high-priority subjects of a basic nature that may 
be funded on other than a dollar-for-dollar basis. Program announcements 
will be distributed to names on the current USGS mailing list for the

[[Page 366]]

Water-Resources Research Program announcements, including new requests 
received in response to published notices of upcoming program 
announcements.
    (c) Notification of the availability of the program announcement 
will be published in the Commerce Business Daily and/or Federal 
Register.
    (d) The application for funds must be signed by an individual or 
official authorized to commit the applicant and it must contain:
    (1) A Standard Form 424 ``Federal Assistance,'' sections I and II 
completed by applicant, used as the cover sheet for each proposal.
    (2) A project summary of no more than one typed, single-spaced page 
providing the following specific information:
    (i) Identification of the water or water-related problems and the 
problem-solution approach;
    (ii) Identification of the proposed scientific contribution of the 
problem solution;
    (iii) Concise statement of the specific objectives of the project;
    (iv) Identification of the approach to be used to accomplish the 
work; and
    (v) Identification of potential users of the proposed work.
    (3) Narrative information, as specified in the published program 
announcement, such as project title, project objectives, background 
information, research tasks, methodology to conduct the research task, 
the relevancy of the proposed project to water-resources problems, 
qualifications of the principal investigators and their organizations, 
and proposed budget with supporting information sufficient to allow 
evaluation of costs.



Sec.  402.11  Technology-development project applications.

    (a) Grant awards will be used to support those portions of the 
program for which the principal purpose is other than as described in 
Sec.  402.11(b). Program announcements and applications will be governed 
by the same procedures provided in Sec.  402.10.
    (b) If it is determined that the principal purpose of a planned 
award (or awards) is to acquire goods or services for the direct benefit 
or use of the Government, the action must be regarded as a procurement 
contract. A competitive solicitation prepared in accordance with 
applicable acquisition regulations will be issued to interested parties. 
Notification of the availability of any contract solicitation will be 
published in the Commerce Business Daily, unless waived in accordance 
with Sec.  5.202 of the Federal Acquisition Regulation (FAR). Contracts 
may be awarded without full and open competition only if justified in 
accordance with FAR subpart 6.3.



Sec.  402.12  Evaluation of applications for grants and contracts.

    (a) Grants. (1) Each grant application will receive technical 
evaluations from Government and/or non-Government scientific or 
engineering personnel. Utilizing the criteria for evaluation identified 
in the applicable announcement, each reviewer will assign a technical 
score.
    (2) Grant applications with low technical ratings will be screened 
out, and the remaining grant applications will be rank-ordered by review 
panels.
    (3) USGS program officials will compile a single, consolidated rank-
ordered list of the grant applications based on technical scoring, 
program needs and published priorities, and the available Federal funds.
    (b) Contracts. Proposals for contract awards will be evaluated by a 
USGS panel. Contracts will be awarded according to procedures contained 
in the FAR, the Department of the Interior Acquisition Regulation, and 
in acquisition policy releases issued by the Department and by the USGS.



Sec.  402.13  Program management.

    (a) After the conclusion of negotiations, the USGS will transmit a 
grant or contract-award document, as appropriate, setting forth the 
terms of the award.
    (b) Grants. Recipients will be required to execute funded projects 
in accordance with OMB Circulars governing cost principles, 
administrative requirements, and audit, as applicable to their 
organization type. In addition, OMB Circular A-67, Coordination of 
Federal Activities in the Acquisition of Certain

[[Page 367]]

Water Data, is applicable to awards under these programs.
    (c) Contracts. Administrative requirements for performance of 
research contracts will be established in the contract clauses in 
conformance with applicable procurement regulations and other interior 
or USGS acquisition policy documents. OMB Circular A-67 will also apply 
to some contract awards under this program.



Sec.  402.14  [Reserved]



                           Subpart D_Reporting



Sec.  402.15  Reporting procedures.

    (a) Grantees or contractors will be required to submit the following 
technical reports to the USGS address identified under the terms and 
conditions of each award.
    (1) Quarterly Technical Progress Report. This report shall include a 
description of all work accomplished, results achieved, and any changes 
that affect the project's scope of work, time schedule, and personnel 
assignments.
    (2) Draft Technical Completion Report. The draft report will be 
required for review prior to submission of the final technical 
completion report.
    (3) Final Technical Completion Report. The final report and a 
camera-ready copy shall be submitted to the USGS within 90 days after 
the expiration date of the award and shall include a summary of all work 
accomplished, results achieved, conclusions, and recommendations. The 
camera-ready copy shall be prepared in a manner suitable for 
reproduction by a photographic process. Format will be specified in the 
terms and conditions of the award.
    (4) Final Report Abstract. A complete Water-Resources Scientific 
Information Center Abstract Form 102 and National Technical Information 
Service Form 79 shall be submitted with the final report.
    (b) Grantees or contractors will be required to submit financial, 
administrative, and closeout reports as identified under the terms of 
each award. Reporting requirements will conform to the procedures 
described in the Departmental Manual of the Department of the Interior 
at 505 DM 1-5.
    (c) Contracts for technology-development projects may also require 
delivery of hardware items produced and/or specifications, drawings, 
test results, or other data describing the funded technology.

                        PARTS 403	499 [RESERVED]

[[Page 369]]



CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
500-519

[Reserved]

                         SUBCHAPTER B--OFFSHORE
550             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................         372
551             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         437
552             Outer Continental Shelf (OCS) Oil and Gas 
                    Information Program.....................         451
553             Oil spill financial responsibility for 
                    offshore facilities.....................         456
556             Leasing of sulphur or oil and gas and 
                    bonding requirements in the Outer 
                    Continental Shelf.......................         471
560             Outer Continental Shelf oil and gas leasing.         510
570             Nondiscrimination in the Outer Continental 
                    Shelf...................................         518
580             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         519
581             Leasing of minerals other than oil, gas, and 
                    sulphur in the Outer Continental Shelf..         531
582             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas and 
                    sulphur.................................         544
583             Negotiated noncompetitive agreements for the 
                    use of Outer Continental Shelf sand, 
                    gravel, and/or shell resources..........         562
585             Renewable energy and alternate uses of 
                    existing facilities on the Outer 
                    Continental Shelf.......................         568
                          SUBCHAPTER C--APPEALS
590             Appeal procedures...........................         653
591-599

[Reserved]

[[Page 371]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT



                        PARTS 500	519 [RESERVED]

[[Page 372]]



                          SUBCHAPTER B_OFFSHORE





PART 550_OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL
 SHELF--Table of Contents



                            Subpart A_General

                    Authority and Definition of Terms

Sec.
550.101 Authority and applicability.
550.102 What does this part do?
550.103 Where can I find more information about the requirements in this 
          part?
550.104 How may I appeal a decision made under BOEM regulations?
550.105 Definitions.

                          Performance Standards

550.115 How do I determine well producibility?
550.116 How do I determine producibility if my well is in the Gulf of 
          Mexico?
550.117 How does a determination of well producibility affect royalty 
          status?
550.118 [Reserved]
550.119 Will BOEM approve subsurface gas storage?
550.120 What standards will BOEM use to regulate leases, rights-of-use 
          and easement, and rights-of-way?
550.121 What must I do to protect health, safety, property, and the 
          environment?
550.122 What effect does subsurface storage have on the lease term?
550.123 Will BOEM allow gas storage on unleased lands?

                                  Fees

550.125 Service fees.
550.126 Electronic payment instructions.

                        Inspection of Operations

550.130 [Reserved]

                            Disqualification

550.135 What will BOEM do if my operating performance is unacceptable?
550.136 How will BOEM determine if my operating performance is 
          unacceptable?

                       Special Types of Approvals

550.140 When will I receive an oral approval?
550.141 May I ever use alternate procedures or equipment?
550.142 How do I receive approval for departures?
550.143 How do I designate an operator?
550.144 How do I designate a new operator when a designation of operator 
          terminates?
550.146 How do I designate an agent or a local agent?
550.147 Who is responsible for fulfilling leasehold obligations?

                        Right-of-Use and Easement

550.160 When will BOEM grant me a right-of-use and easement, and what 
          requirements must I meet?
550.161 What else must I submit with my application?
550.162 May I continue my right-of-use and easement after the 
          termination of any lease on which it is situated?
550.163 If I have a State lease, will BOEM grant me a right-of-use and 
          easement?
550.164 If I have a State lease, what conditions apply for a right-of-
          use and easement?
550.165 If I have a State lease, what fees do I have to pay for a right-
          of-use and easement?
550.166 If I have a State lease, what surety bond must I have for a 
          right-of-use and easement?

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations

550.181 When may the Secretary cancel my lease and when am I compensated 
          for cancellation?
550.182 When may the Secretary cancel a lease at the exploration stage?
550.183 When may BOEM or the Secretary extend or cancel a lease at the 
          development and production stage?
550.184 What is the amount of compensation for lease cancellation?
550.185 When is there no compensation for a lease cancellation?

                 Information and Reporting Requirements

550.186 What reporting information and report forms must I submit?
550.187-550.193 [Reserved]
550.194 How must I protect archaeological resources?
550.195 [Reserved]
550.196 Reimbursements for reproduction and processing costs.
550.197 Data and information to be made available to the public or for 
          limited inspection.

                               References

550.198 [Reserved]
550.199 Paperwork Reduction Act statements--information collection.

                     Subpart B_Plans and Information

                           General Information

550.200 Definitions.

[[Page 373]]

550.201 What plans and information must I submit before I conduct any 
          activities on my lease or unit?
550.202 What criteria must the Exploration Plan (EP), Development and 
          Production Plan (DPP), or Development Operations Coordination 
          Document (DOCD) meet?
550.203 Where can wells be located under an EP, DPP, or DOCD?
550.204 When must I submit my IOP for proposed Arctic exploratory 
          drilling operations and what must the IOP include?
550.205 [Reserved]
550.206 How do I submit the IOP, EP, DPP, or DOCD?

                          Ancillary Activities

550.207 What ancillary activities may I conduct?
550.208 If I conduct ancillary activities, what notices must I provide?
550.209 What is the BOEM review process for the notice?
550.210 If I conduct ancillary activities, what reporting and data/
          information retention requirements must I satisfy?

                   Contents of Exploration Plans (EP)

550.211 What must the EP include?
550.212 What information must accompany the EP?
550.213 What general information must accompany the EP?
550.214 What geological and geophysical (G&G) information must accompany 
          the EP?
550.215 What hydrogen sulfide (H2S) information must 
          accompany the EP?
550.216 What biological, physical, and socioeconomic information must 
          accompany the EP?
550.217 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the EP?
550.218 What air emissions information must accompany the EP?
550.219 What oil and hazardous substance spills information must 
          accompany the EP?
550.220 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the EP?
550.221 What environmental monitoring information must accompany the EP?
550.222 What lease stipulations information must accompany the EP?
550.223 What mitigation measures information must accompany the EP?
550.224 What information on support vessels, offshore vehicles, and 
          aircraft you will use must accompany the EP?
550.225 What information on the onshore support facilities you will use 
          must accompany the EP?
550.226 What Coastal Zone Management Act (CZMA) information must 
          accompany the EP?
550.227 What environmental impact analysis (EIA) information must 
          accompany the EP?
550.228 What administrative information must accompany the EP?

                 Review and Decision Process for the EP

550.231 After receiving the EP, what will BOEM do?
550.232 What actions will BOEM take after the EP is deemed submitted?
550.233 What decisions will BOEM make on the EP and within what 
          timeframe?
550.234 How do I submit a modified EP or resubmit a disapproved EP, and 
          when will BOEM make a decision?
550.235 If a State objects to the EP's coastal zone consistency 
          certification, what can I do?

   Content of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)

550.241 What must the DPP or DOCD include?
550.242 What information must accompany the DPP or DOCD?
550.243 What general information must accompany the DPP or DOCD?
550.244 What geological and geophysical (G&G) information must accompany 
          the DPP or DOCD?
550.245 What hydrogen sulfide (H2S) information must 
          accompany the DPP or DOCD?
550.246 What mineral resource conservation information must accompany 
          the DPP or DOCD?
550.247 What biological, physical, and socioeconomic information must 
          accompany the DPP or DOCD?
550.248 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the DPP or 
          DOCD?
550.249 What air emissions information must accompany the DPP or DOCD?
550.250 What oil and hazardous substance spills information must 
          accompany the DPP or DOCD?
550.251 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the DPP?
550.252 What environmental monitoring information must accompany the DPP 
          or DOCD?
550.253 What lease stipulations information must accompany the DPP or 
          DOCD?
550.254 What mitigation measures information must accompany the DPP or 
          DOCD?
550.255 What decommissioning information must accompany the DPP or DOCD?

[[Page 374]]

550.256 What related facilities and operations information must 
          accompany the DPP or DOCD?
550.257 What information on the support vessels, offshore vehicles, and 
          aircraft you will use must accompany the DPP or DOCD?
550.258 What information on the onshore support facilities you will use 
          must accompany the DPP or DOCD?
550.259 What sulphur operations information must accompany the DPP or 
          DOCD?
550.260 What Coastal Zone Management Act (CZMA) information must 
          accompany the DPP or DOCD?
550.261 What environmental impact analysis (EIA) information must 
          accompany the DPP or DOCD?
550.262 What administrative information must accompany the DPP or DOCD?

             Review and Decision Process for the DPP or DOCD

550.266 After receiving the DPP or DOCD, what will BOEM do?
550.267 What actions will BOEM take after the DPP or DOCD is deemed 
          submitted?
550.268 How does BOEM respond to recommendations?
550.269 How will BOEM evaluate the environmental impacts of the DPP or 
          DOCD?
550.270 What decisions will BOEM make on the DPP or DOCD and within what 
          timeframe?
550.271 For what reasons will BOEM disapprove the DPP or DOCD?
550.272 If a State objects to the DPP's or DOCD's coastal zone 
          consistency certification, what can I do?
550.273 How do I submit a modified DPP or DOCD or resubmit a disapproved 
          DPP or DOCD?

          Post-Approval Requirements for the EP, DPP, and DOCD

550.280 How must I conduct activities under the approved EP, DPP, or 
          DOCD?
550.281 What must I do to conduct activities under the approved EP, DPP, 
          or DOCD?
550.282 Do I have to conduct post-approval monitoring?
550.283 When must I revise or supplement the approved EP, DPP, or DOCD?
550.284 How will BOEM require revisions to the approved EP, DPP, or 
          DOCD?
550.285 How do I submit revised and supplemental EPs, DPPs, and DOCDs?

                Conservation Information Documents (CID)

550.296 When and how must I submit a CID or a revision to a CID?
550.297 What information must a CID contain?
550.298 How long will BOEM take to evaluate and make a decision on the 
          CID?
550.299 What operations require approval of the CID?

               Subpart C_Pollution Prevention and Control

550.300-550.301 [Reserved]
550.302 Definitions concerning air quality.
550.303 Facilities described in a new or revised Exploration Plan or 
          Development and Production Plan.
550.304 Existing facilities.

                   Subpart D_Leasing Maps and Diagrams

550.400 Leasing maps and diagrams.

Subparts E-I [Reserved]

             Subpart J_Pipelines and Pipeline Rights of Way

550.1011 Bond requirements for pipeline right-of-way holders.

              Subpart K_Oil and Gas Production Requirements

                         Well Tests and Surveys

550.1153 When must I conduct a static bottomhole pressure survey?

                         Classifying Reservoirs

550.1154 How do I determine if my reservoir is sensitive?
550.1155 What information must I submit for sensitive reservoirs?

                           Other Requirements

550.1165 What must I do for enhanced recovery operations?
550.1166 What additional reporting is required for developments in the 
          Alaska OCS Region?
550.1167 What information must I submit with forms and for approvals?

Subparts L-M [Reserved]

            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties

550.1400 How does BOEM begin the civil penalty process?
550.1401 Index table.
550.1402 Definitions.
550.1403 What is the maximum civil penalty?
550.1404 Which violations will BOEM review for potential civil 
          penalties?
550.1405 When is a case file developed?
550.1406 When will BOEM notify me and provide penalty information?

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550.1407 How do I respond to the letter of notification?
550.1408 When will I be notified of the Reviewing Officer's decision?
550.1409 What are my appeal rights?

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

550.1450 What definitions apply to this subpart?

                   Penalties After a Period To Correct

550.1451 What may BOEM do if I violate a statute, regulation, order, or 
          lease term relating to a Federal oil and gas lease?
550.1452 What if I correct the violation?
550.1453 What if I do not correct the violation?
550.1454 How may I request a hearing on the record on a Notice of 
          Noncompliance?
550.1455 Does my request for a hearing on the record affect the 
          penalties?
550.1456 May I request a hearing on the record regarding the amount of a 
          civil penalty if I did not request a hearing on the Notice of 
          Noncompliance?

                  Penalties Without a Period To Correct

550.1460 May I be subject to penalties without prior notice and an 
          opportunity to correct?
550.1461 How will BOEM inform me of violations without a period to 
          correct?
550.1462 How may I request a hearing on the record on a Notice of 
          Noncompliance regarding violations without a period to 
          correct?
550.1463 Does my request for a hearing on the record affect the 
          penalties?
550.1464 May I request a hearing on the record regarding the amount of a 
          civil penalty if I did not request a hearing on the Notice of 
          Noncompliance?

                           General Provisions

550.1470 How does BOEM decide what the amount of the penalty should be?
550.1471 Does the penalty affect whether I owe interest?
550.1472 How will the Office of Hearings and Appeals conduct the hearing 
          on the record?
550.1473 How may I appeal the Administrative Law Judge's decision?
550.1474 May I seek judicial review of the decision of the Interior 
          Board of Land Appeals?
550.1475 When must I pay the penalty?
550.1476 Can BOEM reduce my penalty once it is assessed?
550.1477 How may BOEM collect the penalty?

                           Criminal Penalties

550.1480 May the United States criminally prosecute me for violations 
          under Federal oil and gas leases?

                          Bonding Requirements

550.1490 What standards must my BOEM-specified surety instrument meet?
550.1491 How will BOEM determine the amount of my bond or other surety 
          instrument?

                     Financial Solvency Requirements

550.1495 How do I demonstrate financial solvency?
550.1496 How will BOEM determine if I am financially solvent?
550.1497 When will BOEM monitor my financial solvency?

Subparts O-S [Reserved]

    Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General

                    Authority and Definition of Terms



Sec.  550.101  Authority and applicability.

    The Secretary of the Interior (Secretary) authorized the Bureau of 
Ocean Energy Management (BOEM) to regulate oil, gas, and sulphur 
exploration, development, and production operations on the Outer 
Continental Shelf (OCS). Under the Secretary's authority, the Director 
requires that all operations:
    (a) Be conducted according to the OCS Lands Act (OCSLA), the 
regulations in this part, BOEM orders, the lease or right-of-way, and 
other applicable laws, regulations, and amendments; and
    (b) Conform to sound conservation practice to preserve, protect, and 
develop mineral resources of the OCS to:
    (1) Make resources available to meet the Nation's energy needs;
    (2) Balance orderly energy resource development with protection of 
the human, marine, and coastal environments;
    (3) Ensure the public receives a fair and equitable return on the 
resources of the OCS;
    (4) Preserve and maintain free enterprise competition; and

[[Page 376]]

    (5) Minimize or eliminate conflicts between the exploration, 
development, and production of oil and natural gas and the recovery of 
other resources.



Sec.  550.102  What does this part do?

    (a) 30 CFR part 550 contains the regulations of the BOEM Offshore 
program that govern oil, gas, and sulphur exploration, development, and 
production operations on the OCS. When you conduct operations on the 
OCS, you must submit requests, applications, and notices, or provide 
supplemental information for BOEM approval.
    (b) The following table of general references shows where to look 
for information about these processes.

       Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
         For information about                       Refer to
------------------------------------------------------------------------
(1) Applications for permit to drill...  30 CFR 250, subpart D.
(2) Development and Production Plans     30 CFR 550, subpart B.
 (DPP).
(3) Downhole commingling...............  30 CFR 250, subpart K.
(4) Exploration Plans (EP).............  30 CFR 550, subpart B.
(5) Flaring............................  30 CFR 250, subpart K.
(6) Gas measurement....................  30 CFR 250, subpart L.
(7) Off-lease geological and             30 CFR 551.
 geophysical permits.
(8) Oil spill financial responsibility   30 CFR 553.
 coverage.
(9) Oil and gas production safety        30 CFR 250, subpart H.
 systems.
(10) Oil spill response plans..........  30 CFR 254.
(11) Oil and gas well-completion         30 CFR 250, subpart E.
 operations.
(12) Oil and gas well-workover           30 CFR 250, subpart F.
 operations.
(13) Decommissioning Activities........  30 CFR 250, subpart Q.
(14) Platforms and structures..........  30 CFR 250, subpart I.
(15) Pipelines and Pipeline Rights-of-   30 CFR 250, subpart J and 30
 Way.                                     CFR 550, subpart J.
(16) Sulphur operations................  30 CFR 250, subpart P.
(17) Training..........................  30 CFR 250, subpart O.
(18) Unitization.......................  30 CFR 250, subpart M.
------------------------------------------------------------------------



Sec.  550.103  Where can I find more information about the
 requirements in this part?

    BOEM may issue Notices to Lessees and Operators (NTLs) that clarify, 
supplement, or provide more detail about certain requirements. NTLs may 
also outline what you must provide as required information in your 
various submissions to BOEM.



Sec.  550.104  How may I appeal a decision made under BOEM regulations?

    To appeal orders or decisions issued under BOEM regulations in 30 
CFR parts 550 to 582, follow the procedures in 30 CFR part 590.



Sec.  550.105  Definitions.

    Terms used in this part will have the meanings given in the Act and 
as defined in this section:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Affected State means with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved under the provisions 
of the Act, any State:
    (1) The laws of which are declared, under section 4(a)(2) of the 
Act, to be the law of the United States for the portion of the OCS on 
which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installation or 
other device permanently or temporarily attached to the seabed;
    (3) Which is receiving, or according to the proposed activity, will 
receive oil for processing, refining, or transshipment that was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Secretary as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or

[[Page 377]]

    (5) In which the Secretary finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Air pollutant means any airborne agent or combination of agents for 
which the Environmental Protection Agency (EPA) has established, under 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analysis, laboratory analyses of physical and chemical properties, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Ancillary activities mean those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without BOEM approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas 
(for more information on these areas, see the Proposed Final OCS Oil and 
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
    Arctic OCS conditions means, for the purposes of this part, the 
conditions operators can reasonably expect during operations on the 
Arctic OCS. Such conditions, depending on the time of year, include, but 
are not limited to: extreme cold, freezing spray, snow, extended periods 
of low light, strong winds, dense fog, sea ice, strong currents, and 
dangerous sea states. Remote location, relative lack of infrastructure, 
and the existence of subsistence hunting and fishing areas are also 
characteristic of the Arctic region.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best available 
and safest technologies that the Director determines to be economically 
feasible wherever failure of equipment would have a significant effect 
on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Director will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial

[[Page 378]]

sea and extends inland from the shorelines to the extent necessary to 
control shorelands, the uses of which have a direct and significant 
impact on the coastal waters, and the inward boundaries of which may be 
identified by the several coastal States, under the authority in section 
305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures mean approvals granted by the appropriate BSEE or BOEM 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease; 
conserve natural resources, or protect life, property, or the marine, 
coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited to 
geophysical activity, drilling, platform construction, and operation of 
all directly related onshore support facilities, and which are for the 
purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities means those 
G&G and related data-gathering activities on your lease or unit that you 
conduct following discovery of oil, gas, or sulphur in paying quantities 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Director means the Director of BOEM of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the BSEE officer with authority and 
responsibility for operations or other designated program functions for 
a district within a BSEE Region.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the 
BOEM Director decides are adjacent to the State of Florida. The Eastern 
Gulf of Mexico is not the same as the Eastern Planning Area, an area 
established for OCS lease sales.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations mean pressure maintenance operations, 
secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in Sec.  550.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas sniffers, coring, 
or other systems to detect or imply the presence of oil, gas, or 
sulphur; and
    (2) Any drilling conducted for the purpose of searching for 
commercial quantities of oil, gas, and sulphur, including the drilling 
of any additional well needed to delineate any reservoir to enable the 
lessee to decide whether to proceed with development and production.
    Facility, as used in Sec.  550.303, means all installations or 
devices permanently or temporarily attached to the seabed.

[[Page 379]]

They include mobile offshore drilling units (MODUs), even while 
operating in the ``tender assist'' mode (i.e., with skid-off drilling 
units) or other vessels engaged in drilling or downhole operations. They 
are used for exploration, development, and production activities for 
oil, gas, or sulphur and emit or have the potential to emit any air 
pollutant from one or more sources. They include all floating production 
systems (FPSs), including column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. During production, multiple installations 
or devices are a single facility if the installations or devices are at 
a single site. Any vessel used to transfer production from an offshore 
facility is part of the facility while it is physically attached to the 
facility.
    Flaring means the burning of natural gas as it is released into the 
atmosphere.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations means those G&G 
surveys on your lease or unit that use seismic reflection, seismic 
refraction, magnetic, gravity, gas sniffers, coring, or other systems to 
detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or producing 
operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, often 
in the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of data 
and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines mean those pipelines owned and operated by a 
lessee or operator that are completely contained within the boundaries 
of a single lease, unit, or contiguous (not cornering) leases of that 
lessee or operator.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the BOEM-approved assignee of the lease, and 
the owner or the BOEM-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that 
will have a significant

[[Page 380]]

impact on the quality of the human environment requiring preparation of 
an environmental impact statement under section 102(2)(C) of the 
National Environmental Policy Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within the 
coastal zone and on the OCS.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Maximum efficient rate (MER) means the maximum sustainable daily oil 
or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals that are authorized by an 
Act of Congress to be produced.
    Natural resources include, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or in 
the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights mean any interest held in a lease with the right to 
explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having control 
or management of operations on the leased area or a portion thereof. An 
operator may be a lessee, the BOEM-approved or BSEE-approved designated 
agent of the lessee(s), or the holder of operating rights under a BOEM-
approved operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data collected 
under a permit or a lease that have been processed or reprocessed. 
Processing involves changing the form of data to facilitate 
interpretation. Processing operations may include, but are not limited 
to, applying corrections for known perturbing causes, rearranging or 
filtering data, and combining or transforming data elements. 
Reprocessing is the additional processing other than ordinary processing 
used in the general course of evaluation. Reprocessing operations may 
include varying identified parameters for the detailed study of a 
specific problem area.
    Production means those activities that take place after the 
successful

[[Page 381]]

completion of any means for the removal of minerals, including such 
removal, field operations, transfer of minerals to shore, operation 
monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before entering 
the transportation process.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the BOEM officer with responsibility and 
authority for a Region within BOEM.
    Regional Supervisor means the BOEM officer with responsibility and 
authority for operations or other designated program functions within a 
BOEM Region.
    Right-of-use means any authorization issued under this part to use 
OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated by a lessee or operator of that lease or unit;
    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Sensitive reservoir means a reservoir in which the production rate 
will affect ultimate recovery.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Suspension means a granted or directed deferral of the requirement 
to produce (Suspension of Production (SOP)) or to conduct leaseholding 
operations (Suspension of Operations (SOO)).
    Venting means the release of gas into the atmosphere without 
igniting it. This includes gas that is released underwater and bubbles 
to the atmosphere.
    Waste of oil, gas, or sulphur means:
    (1) The physical waste of oil, gas, or sulphur;
    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes or 
tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or excessive surface loss or 
destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations mean the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or workover 
fluid as appropriate to the particular operation being conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the BOEM Director decides are adjacent to the State of 
Florida. The Western Gulf of Mexico is not the same as the Western 
Planning Area, an area established for OCS lease sales.
    Workover operations mean the work conducted on wells after the 
initial well-completion operation for the purpose of maintaining or 
restoring the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way 
holder, or a State lessee granted a right-of-use and easement.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]

[[Page 382]]

                          Performance Standards



Sec.  550.115  How do I determine well producibility?

    You must follow the procedures in this section to determine well 
producibility if your well is not in the GOM. If your well is in the GOM 
you must follow the procedures in either this section or in Sec.  
550.116 of this subpart.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must either:
    (1) Allow the Regional Supervisor to witness each test that you 
conduct under this section; or
    (2) Receive the Regional Supervisor prior approval so that you can 
submit either test data with your affidavit or third party test data.
    (c) If the well is an oil well, you must conduct a production test 
that lasts at least 2 hours after flow stabilizes.
    (d) If the well is a gas well, you must conduct a deliverability 
test that lasts at least 2 hours after flow stabilizes, or a four-point 
back pressure test.



Sec.  550.116  How do I determine producibility if my well is in
 the Gulf of Mexico?

    If your well is in the GOM, you must follow either the procedures in 
Sec.  550.115 of this subpart or the procedures in this section to 
determine producibility.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must provide or make available to the Regional Supervisor, 
as requested, the following log, core, analyses, and test criteria that 
BOEM will consider collectively:
    (1) A log showing sufficient porosity in the producible section.
    (2) Sidewall cores and core analyses that show that the section is 
capable of producing oil or gas.
    (3) Wireline formation test and/or mud-logging analyses that show 
that the section is capable of producing oil or gas.
    (4) A resistivity or induction electric log of the well showing a 
minimum of 15 feet (true vertical thickness except for horizontal wells) 
of producible sand in one section.
    (c) No section that you count as producible under paragraph (b)(4) 
of this section may include any interval that appears to be water 
saturated.
    (d) Each section you count as producible under paragraph (b)(4) of 
this section must exhibit:
    (1) A minimum true resistivity ratio of the producible section to 
the nearest clean or water-bearing sand of at least 5:1; and
    (2) One of the following:
    (i) Electrical spontaneous potential exceeding 20-negative 
millivolts beyond the shale baseline; or
    (ii) Gamma ray log deflection of at least 70 percent of the maximum 
gamma ray deflection in the nearest clean water-bearing sand--if mud 
conditions prevent a 20-negative millivolt reading beyond the shale 
baseline.



Sec.  550.117  How does a determination of well producibility 
affect royalty status?

    A determination of well producibility invokes minimum royalty status 
on the lease as provided in 30 CFR 1202.53.



Sec.  550.118  [Reserved]



Sec.  550.119  Will BOEM approve subsurface gas storage?

    The Regional Supervisor may authorize subsurface storage of gas on 
the OCS, on and off-lease, for later commercial benefit. The Regional 
Supervisor may authorize subsurface storage of gas on the OCS, off-
lease, for later commercial benefit. To receive approval you must:
    (a) Show that the subsurface storage of gas will not result in undue 
interference with operations under existing leases; and
    (b) Sign a storage agreement that includes the required payment of a 
storage fee or rental.



Sec.  550.120  What standards will BOEM use to regulate leases,
 rights-of-use and easement, and rights-of-way?

    BOEM will regulate all activities under a lease, a right-of-use and 
easement, or a right-of-way to:
    (a) Promote the orderly exploration, development, and production of 
mineral resources;
    (b) Prevent injury or loss of life;

[[Page 383]]

    (c) Prevent damage to or waste of any natural resource, property, or 
the environment; and
    (d) Ensure cooperation and consultation with affected States, local 
governments, other interested parties, and relevant Federal agencies.

[81 FR 18152, Mar. 30, 2016]



Sec.  550.121  What must I do to protect health, safety, property,
 and the environment?

    The Director may require additional measures to ensure the use of 
Best Available and Safest Technology (BAST) as identified by BSEE:
    (a) To avoid the failure of equipment that would have a significant 
effect on safety, health, or the environment;
    (b) If it is economically feasible; and
    (c) If the incremental benefits justify the incremental costs.

[81 FR 18152, Mar. 30, 2016]



Sec.  550.122  What effect does subsurface storage have on the
 lease term?

    If you use a lease area for subsurface storage of gas, it does not 
affect the continuance or expiration of the lease.



Sec.  550.123  Will BOEM allow gas storage on unleased lands?

    You may not store gas on unleased lands unless the Regional 
Supervisor approves a right-of-use and easement for that purpose, under 
Sec. Sec.  550.160 through 550.166 of this subpart.

                                  Fees



Sec.  550.125  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to BOEM for the services listed. The fees will be adjusted periodically 
according to the Implicit Price Deflator for Gross Domestic Product by 
publication of a document in the Federal Register. If a significant 
adjustment is needed to arrive at the new actual cost for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

------------------------------------------------------------------------
  Service--processing of the
          following:                 Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of   $164.................  Sec.   550.143(d).
 Operator.
(2) Right-of-Use and Easement  $2,569...............  Sec.   550.165.
 for State lessee.
(3) [Reserved]...............
(4) Exploration Plan (EP)....  $3,442 for each        Sec.   550.211(d).
                                surface location; no
                                fee for revisions.
(5) Development and            $3,971 for each well   Sec.   550.241(e).
 Production Plan (DPP) or       proposed; no fee for
 Development Operations         revisions.
 Coordination Document (DOCD).
(6) [Reserved]...............
(7) Conservation Information   $25,629..............  Sec.   550.296(a).
 Document.
------------------------------------------------------------------------

    (b) Payment of the fees listed in paragraph (a) of this section must 
accompany the submission of the document for approval or be sent to an 
office identified by the Regional Director. Once a fee is paid, it is 
nonrefundable, even if an application or other request is withdrawn. If 
your application is returned to you as incomplete, you are not required 
to submit a new fee when you submit the amended application.
    (c) Verbal approvals are occasionally given in special 
circumstances. Any action that will be considered a verbal permit 
approval requires either a paper permit application to follow the verbal 
approval or an electronic application submittal within 72 hours. Payment 
must be made with the completed paper or electronic application.



Sec.  550.126  Electronic payment instructions.

    You must file all payments electronically through Pay.gov. This 
includes, but is not limited to, all OCS applications or filing fee 
payments. The Pay.gov Web site may be accessed through Pay.gov at 
https://www.pay.gov/paygov/.
    (a) [Reserved]
    (b) You must use credit card or automated clearing house (ACH) 
payments

[[Page 384]]

through the Pay.gov Web site, and you must include a copy of the Pay.gov 
confirmation receipt page with your application.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

                        Inspection of Operations



Sec.  550.130  [Reserved]

                            Disqualification



Sec.  550.135  What will BOEM do if my operating performance is
 unacceptable?

    If your operating performance is unacceptable, BOEM may disapprove 
or revoke your designation as operator on a single facility or multiple 
facilities. We will give you adequate notice and opportunity for a 
review by BOEM officials before imposing a disqualification.



Sec.  550.136  How will BOEM determine if my performance is 
unacceptable?

    In determining if your operating performance is unacceptable, BOEM 
will consider, individually or collectively:
    (a)-(b) [Reserved]
    (c) Incidents of noncompliance;
    (d) Civil penalties;
    (e) Failure to adhere to OCS lease obligations; or
    (f) Any other relevant factors.

                       Special Types of Approvals



Sec.  550.140  When will I receive an oral approval?

    When you apply for BOEM approval of any activity, we normally give 
you a written decision. The following table shows circumstances under 
which we may give an oral approval.

------------------------------------------------------------------------
    When you . . .           We may . . .              And . . .
------------------------------------------------------------------------
(a) Request approval    Give you an oral       You must then confirm the
 orally,                 approval,              oral request by sending
                                                us a written request
                                                within 72 hours.
(b) Request approval    Give you an oral       We will send you a
 in writing,             approval if quick      written approval
                         action is needed,      afterward. It will
                                                include any conditions
                                                that we place on the
                                                oral approval.
------------------------------------------------------------------------



Sec.  550.141  May I ever use alternate procedures or equipment?

    You may use alternate procedures or equipment after receiving 
approval as described in this section.
    (a) Any alternate procedures or equipment that you propose to use 
must provide a level of safety and environmental protection that equals 
or surpasses current BOEM requirements.
    (b) You must receive the Regional Supervisor's written approval 
before you can use alternate procedures or equipment.
    (c) To receive approval, you must either submit information or give 
an oral presentation to the appropriate Regional Supervisor. Your 
presentation must describe the site-specific application(s), performance 
characteristics, and safety features of the proposed procedure or 
equipment.



Sec.  550.142  How do I receive approval for departures?

    We may approve departures to the operating requirements. You may 
apply for a departure by writing to the Regional Supervisor.



Sec.  550.143  How do I designate an operator?

    (a) You must provide the Regional Supervisor an executed Designation 
of Operator form (Form BOEM-1123) unless you are the only lessee and are 
the only person conducting lease operations. When there is more than one 
lessee, each lessee must submit the Designation of Operator form and the 
Regional Supervisor must approve the designation before the designated 
operator may begin operations on the leasehold.
    (b) This designation is authority for the designated operator to act 
on your behalf and to fulfill your obligations under the Act, the lease, 
and the regulations in this part.
    (c) You, or your designated operator, must immediately provide the 
Regional Supervisor a written notification of any change of address.
    (d) If you change the designated operator on your lease, you must 
pay the

[[Page 385]]

service fee listed in Sec.  550.125 of this subpart with your request 
for a change in designation of operator. Should there be multiple 
lessees, all designation of operator forms must be collected by one 
lessee and submitted to BOEM in a single submittal, which is subject to 
only one filing fee.



Sec.  550.144  How do I designate a new operator when a designation
 of operator terminates?

    (a) When a Designation of Operator terminates, the Regional 
Supervisor must approve a new designated operator before you may 
continue operations. Each lessee must submit a new executed Designation 
of Operator form.
    (b) If your Designation of Operator is terminated, or a controversy 
develops between you and your designated operator, you and your 
designated operator must protect the lessor's interests.



Sec.  550.146  How do I designate an agent or a local agent?

    (a) You or your designated operator may designate for the Regional 
Supervisor's approval, or the Regional Director may require you to 
designate an agent empowered to fulfill your obligations under the Act, 
the lease, or the regulations in this part.
    (b) You or your designated operator may designate for the Regional 
Supervisor's approval a local agent empowered to receive notices and 
submit requests, applications, notices, or supplemental information.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18152, Mar. 30, 2016]



Sec.  550.147  Who is responsible for fulfilling leasehold obligations?

    (a) When you are not the sole lessee, you and your co-lessee(s) are 
jointly and severally responsible for fulfilling your obligations under 
the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582 unless otherwise provided in these regulations.
    (b) If your designated operator fails to fulfill any of your 
obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582, the Regional Supervisor may require you or any or all of 
your co-lessees to fulfill those obligations or other operational 
obligations under the Act, the lease, or the regulations.
    (c) Whenever the regulations in 30 CFR parts 250 through 282 and 30 
CFR parts 550 through 582 require the lessee to meet a requirement or 
perform an action, the lessee, operator (if one has been designated), 
and the person actually performing the activity to which the requirement 
applies are jointly and severally responsible for complying with the 
regulation.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18152, Mar. 30, 2016]

                        Right-of-Use and Easement



Sec.  550.160  When will BOEM grant me a right-of-use and easement,
 and what requirements must I meet?

    BOEM may grant you a right-of-use and easement on leased and 
unleased lands on the OCS, if you meet these requirements:
    (a) You must need the right-of-use and easement to construct and 
maintain platforms, artificial islands, and installations and other 
devices at an OCS site other than an OCS lease you own, that are:
    (1) Permanently or temporarily attached to the seabed; and
    (2) Used for conducting exploration, development, and production 
activities or other operations on or off lease; or
    (3) Used for other purposes approved by BOEM.
    (b) You must exercise the right-of-use and easement according to the 
regulations of this part;
    (c) You must meet the requirements at 30 CFR 556.35 (Qualification 
of lessees); establish a regional Company File as required by BOEM; and 
must meet bonding requirements;
    (d) If you apply for a right-of-use and easement on a leased area, 
you must notify the lessee and give her/him an opportunity to comment on 
your application; and
    (e) You must receive BOEM approval for all platforms, artificial 
islands, and installations and other devices permanently or temporarily 
attached to the seabed.
    (f) You must pay a rental amount as required by paragraph (g) of 
this section if:

[[Page 386]]

    (1) You obtain a right-of-use and easement after January 12, 2004; 
or
    (2) You ask BOEM to modify your right-of-use and easement to change 
the footprint of the associated platform, artificial island, or 
installation or device.
    (g) If you meet either of the conditions in paragraph (f) of this 
section, you must pay a rental amount to BOEM as shown in the following 
table:

------------------------------------------------------------------------
             If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your right-of-use and easement  You must pay a rental of $5 per acre
 site is located in water depths     per year with a minimum of $450 per
 of less than 200 meters;            year. The area subject to annual
                                     rental includes the areal extent of
                                     anchor chains, pipeline risers, and
                                     other equipment associated with the
                                     platform, artificial island,
                                     installation or device.
(2) Your right-of-use and easement  You must pay a rental of $7.50 per
 site is located in water depths     acre per year with a minimum of
 of 200 meters or greater;           $675 per year. The area subject to
                                     annual rental includes the areal
                                     extent of anchor chains, pipeline
                                     risers, and other equipment
                                     associated with the platform,
                                     artificial island, or installation
                                     or device.
------------------------------------------------------------------------

    (h) You may make the rental payments required by paragraph (g)(1) 
and (g)(2) of this section on an annual basis, for a 5-year period, or 
for multiples of 5 years. You must make the first payment electronically 
through Pay.gov and you must include a copy of the Pay.gov confirmation 
receipt page with your right-of-use and easement application. You must 
make all subsequent payments before the respective time periods begin.
    (i) Late payments. An interest charge will be assessed on unpaid and 
underpaid amounts from the date the amounts are due, in accordance with 
the provisions found in 30 CFR 1218.54. If you fail to make a payment 
that is late after written notice from BOEM, BOEM may initiate 
cancellation of the right-of-use grant and easement.



Sec.  550.161  What else must I submit with my application?

    With your application, you must describe the proposed use giving:
    (a) Details of the proposed uses and activities including access 
needs and special rights of use that you may need;
    (b) A description of all facilities for which you are seeking 
authorization;
    (c) A map or plat describing primary and alternate project 
locations; and
    (d) A schedule for constructing any new facilities, drilling or 
completing any wells, anticipated production rates, and productive life 
of existing production facilities.



Sec.  550.162  May I continue my right-of-use and easement after
 the termination of any lease on which it is situated?

    If your right-of-use and easement is on a lease, you may continue to 
exercise the right-of-use and easement after the lease on which it is 
situated terminates. You must only use the right-of-use and easement for 
the purpose that the grant specifies. All future lessees of that portion 
of the OCS on which your right-of-use and easement is situated must 
continue to recognize the right-of-use and easement for the purpose that 
the grant specifies.



Sec.  550.163  If I have a State lease, will BOEM grant me a
 right-of-use and easement?

    (a) BOEM may grant a lessee of a State lease located adjacent to or 
accessible from the OCS a right-of-use and easement on the OCS.
    (b) BOEM will only grant a right-of-use and easement under this 
paragraph to enable a State lessee to conduct and maintain a device that 
is permanently or temporarily attached to the seabed (i.e., a platform, 
artificial island, or installation). The lessee must use the device to 
explore for, develop, and produce oil and gas from the adjacent or 
accessible State lease and for other operations related to these 
activities.



Sec.  550.164  If I have a State lease, what conditions apply for
 a right-of-use and easement?

    (a) A right-of-use and easement granted under the heading of 
``Right-of-use and easement'' in this subpart is

[[Page 387]]

subject to BOEM regulations, 30 CFR parts 550 through 582, BSEE 
regulations, 30 CFR parts 250 through 282, and any terms and conditions 
that the BOEM Regional Director or BSEE Regional Director prescribes.
    (b) For the whole or fraction of the first calendar year, and 
annually after that, you must pay to BOEM, in advance, an annual rental 
payment.



Sec.  550.165  If I have a State lease, what fees do I have to pay for
 a right-of-use and easement?

    When you apply for a right-of-use and easement, you must pay:
    (a) A nonrefundable filing fee as specified in Sec.  550.125; and
    (b) The first year's rental as specified in Sec.  550.160(g).



Sec.  550.166  If I have a State lease, what surety bond must I have
 for a right-of-use and easement?

    (a) Before BOEM issues you a right-of-use and easement on the OCS, 
you must furnish the Regional Director a surety bond for $500,000.
    (b) The Regional Director may require additional security from you 
(i.e., security above the prescribed $500,000) to cover additional costs 
and liabilities for regulatory compliance. This additional surety:
    (1) Must be in the form of a supplemental bond or bonds meeting the 
requirements of 30 CFR 556.54 (General requirements for bonds) or an 
increase in the coverage of an existing surety bond.
    (2) Covers additional costs and liabilities for regulatory 
compliance, including well abandonment, platform and structure removal, 
and site clearance from the seafloor of the right-of-use and easement.

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations



Sec.  550.181  When may the Secretary cancel my lease and when am I
 compensated for cancellation?

    If the Secretary cancels your lease under this part or under 30 CFR 
part 556, you are entitled to compensation under Sec.  550.184. Section 
550.185 states conditions under which you will receive no compensation. 
The Secretary may cancel a lease after notice and opportunity for a 
hearing when:
    (a) Continued activity on the lease would probably cause harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposits (in areas leased or not leased), or the marine, 
coastal, or human environment;
    (b) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time;
    (c) The advantages of cancellation outweigh the advantages of 
continuing the lease in force; and
    (d) A suspension has been in effect for at least 5 years or you 
request termination of the suspension and lease cancellation.



Sec.  550.182  When may the Secretary cancel a lease at the exploration
 stage?

    BOEM may not approve an exploration plan (EP) under 30 CFR part 550, 
subpart B, if the Regional Supervisor determines that the proposed 
activities may cause serious harm or damage to life (including fish and 
other aquatic life), property, any mineral deposits, the National 
security or defense, or to the marine, coastal, or human environment, 
and that the proposed activity cannot be modified to avoid the 
condition(s). The Secretary may cancel the lease if:
    (a) The primary lease term has not expired (or if the lease term has 
been extended) and exploration has been prohibited for 5 years following 
the disapproval; or
    (b) You request cancellation at an earlier time.



Sec.  550.183  When may BOEM or the Secretary extend or cancel a lease
 at the development and production stage?

    (a) BOEM may extend your lease if you submit a DPP and the Regional 
Supervisor disapproves the plan according to the regulations in 30 CFR 
part 550, subpart B. Following the disapproval:
    (1) BOEM will allow you to hold the lease for 5 years, or less time 
at your request;

[[Page 388]]

    (2) Any time within 5 years after the disapproval, you may reapply 
for approval of the same or a modified plan; and
    (3) The Regional Supervisor will approve, disapprove, or require 
modification of the plan under 30 CFR part 550, subpart B.
    (b) If the Regional Supervisor has not approved a DPP or required 
you to submit a DPP for approval or modification, the Secretary will 
cancel the lease:
    (1) When the 5-year period in paragraph (a)(1) of this section 
expires; or
    (2) If you request cancellation at an earlier time.



Sec.  550.184  What is the amount of compensation for lease cancellation?

    When the Secretary cancels a lease under Sec. Sec.  550.181, 550.182 
or 550.183 of this subpart, you are entitled to receive compensation 
under 43 U.S.C. 1334(a)(2)(C). You must show the Director that the 
amount of compensation claimed is the lesser of paragraph (a) or (b) of 
this section:
    (a) The fair value of the cancelled rights as of the date of 
cancellation, taking into account both:
    (1) Anticipated revenues from the lease; and
    (2) Costs reasonably anticipated on the lease, including:
    (i) Costs of compliance with all applicable regulations and 
operating orders; and
    (ii) Liability for cleanup costs or damages, or both, in the case of 
an oil spill.
    (b) The excess, if any, over your revenues from the lease (plus 
interest thereon from the date of receipt to date of reimbursement) of:
    (1) All consideration paid for the lease (plus interest from the 
date of payment to the date of reimbursement); and
    (2) All your direct expenditures (plus interest from the date of 
payment to the date of reimbursement):
    (i) After the issue date of the lease; and
    (ii) For exploration or development, or both.
    (c) Compensation for leases issued before September 18, 1978, will 
be equal to the amount specified in paragraph (a) of this section.



Sec.  550.185  When is there no compensation for a lease cancellation?

    You will not receive compensation from BOEM for lease cancellation 
if:
    (a) BOEM disapproves a DPP because you do not receive concurrence by 
the State under section 307(c)(3)(B)(i) or (ii) of the CZMA, and the 
Secretary of Commerce does not make the finding authorized by section 
307(c)(3)(B)(iii) of the CZMA;
    (b) You do not submit a DPP under 30 CFR part 550, subpart B or do 
not comply with the approved DPP;
    (c) As the lessee of a nonproducing lease, you fail to comply with 
the Act, the lease, or the regulations issued under the Act, and the 
default continues for 30 days after BOEM mails you a notice by overnight 
mail;
    (d) The Regional Supervisor disapproves a DPP because you fail to 
comply with the requirements of applicable Federal law; or
    (e) The Secretary forfeits and cancels a producing lease under 
section 5(d) of the Act (43 U.S.C. 1334(d)).

                 Information and Reporting Requirements



Sec.  550.186  What reporting information and report forms must I submit?

    (a) You must submit information and reports as BOEM requires.
    (1) You may obtain copies of forms from, and submit completed forms 
to, the Regional Supervisor.
    (2) Instead of paper copies of forms available from the Regional 
Supervisor, you may use your own computer-generated forms that are equal 
in size to BOEM's forms. You must arrange the data on your form 
identical to the BOEM form. If you generate your own form and it omits 
terms and conditions contained on the official BOEM form, we will 
consider it to contain the omitted terms and conditions.
    (3) You may submit digital data when the Region is equipped to 
accept it.
    (b) When BOEM specifies, you must include, for public information, 
an additional copy of such reports.
    (1) You must mark it Public Information.

[[Page 389]]

    (2) You must include all required information, except information 
exempt from public disclosure under Sec.  550.197 or otherwise exempt 
from public disclosure under law or regulation.



Sec. Sec.  550.187-550.193  [Reserved]



Sec.  550.194  How must I protect archaeological resources?

    (a) If the Regional Director has reason to believe that an 
archaeological resource may exist in the lease area, the Regional 
Director will require in writing that your EP, DOCD, or DPP be 
accompanied by an archaeological report. If the archaeological report 
suggests that an archaeological resource may be present, you must 
either:
    (1) Locate the site of any operation so as not to adversely affect 
the area where the archaeological resource may be; or
    (2) Establish to the satisfaction of the Regional Director that an 
archaeological resource does not exist or will not be adversely affected 
by operations. This requires further archaeological investigation, 
conducted by an archaeologist and a geophysicist, using survey equipment 
and techniques the Regional Director considers appropriate. You must 
submit the investigation report to the Regional Director for review.
    (b) If the Regional Director determines that an archaeological 
resource is likely to be present in the lease area and may be adversely 
affected by operations, the Regional Director will notify you 
immediately. You must not take any action that may adversely affect the 
archaeological resource until the Regional Director has told you how to 
protect the resource.
    (c) If you discover any archaeological resource while conducting 
operations in the lease or right-of-way area, you must immediately halt 
operations within the area of the discovery and report the discovery to 
the BOEM Regional Director. If investigations determine that the 
resource is significant, the Regional Director will tell you how to 
protect it.



Sec.  550.195  [Reserved]



Sec.  550.196  Reimbursements for reproduction and processing costs.

    (a) BOEM will reimburse you for costs of reproducing data and 
information that the Regional Director requests if:
    (1) You deliver geophysical and geological (G&G) data and 
information to BOEM for the Regional Director to inspect or select and 
retain;
    (2) BOEM receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate or at the lowest commercial rate 
established in the area, whichever is less.
    (b) BOEM will reimburse you for the costs of processing geophysical 
information (that does not include cost of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business; or
    (2) If you collected the information under a permit that BOEM issued 
to you before October 1, 1985, and the Regional Director requests and 
retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) BOEM will not reimburse you for data acquisition costs or for 
the costs of analyzing or processing geological information or 
interpreting geological or geophysical information.



Sec.  550.197  Data and information to be made available to the public
 or for limited inspection.

    BOEM will protect data and information that you submit under this 
chapter, as described in this section. Paragraphs (a) and (b) of this 
section describe what data and information will be made available to the 
public without the consent of the lessee, under what circumstances, and 
in what time period. Paragraph (c) of this section describes what data 
and information will be made available for limited inspection without 
the consent of the lessee, and under what circumstances.

[[Page 390]]

    (a) All data and information you submit on BOEM forms will be made 
available to the public upon submission, except as specified in the 
following table:

------------------------------------------------------------------------
                                     Data and
                                 information not   Excepted data will be
         On form . . .             immediately      made available . . .
                                available are . .
                                        .
------------------------------------------------------------------------
(1) [Reserved]                  .................
(2) [Reserved]                  .................
(3) [Reserved]                  .................
(4) [Reserved]                  .................
(5) [Reserved]                  .................
(6) BOEM-0127, Sensitive        Items 124 through  2 years after the
 Reservoir Information Report,   168,               effective date of
                                                    the Sensitive
                                                    Reservoir
                                                    Information Report.
(7) [Reserved]                  .................
(8) [Reserved]                  .................
(9) BOEM-0137 OCS Plan          Items providing    When the well goes on
 Information,                    the bottomhole     production or
                                 location, true     according to the
                                 vertical depth,    table in paragraph
                                 and measured       (b) of this section,
                                 depth of wells,    whichever is
                                                    earlier.
(10) BOEM-0140, Bottomhole      All items,         2 years after the
 Pressure Survey Report,                            date of the survey.
------------------------------------------------------------------------

    (b) BOEM will release lease and permit data and information that you 
submit and BOEM retains, but that are not normally submitted on BOEM 
forms, according to the following table:

------------------------------------------------------------------------
                                                             Special
     If . . .      BOEM will release   At this time . .   provisions . .
                         . . .                .                 .
------------------------------------------------------------------------
(1) The Director   Geophysical data,  At any time,       BOEM will
 determines that    Geological data                       release data
 data and           Interpreted G&G                       and
 information are    information,                          information
 needed for         Processed G&G                         only if
 specific           information,                          release would
 scientific or      Analyzed                              further the
 research           geological                            National
 purposes for the   information,                          interest
 Government,                                              without unduly
                                                          damaging the
                                                          competitive
                                                          position of
                                                          the lessee.
(2) Data or        Geophysical data,  60 days after      BOEM will
 information is     Geological data,   BOEM receives      release the
 collected with     Interpreted G&G    the data or        data and
 high-resolution    information,       information, if    information
 systems (e.g.,     Processed          the Regional       earlier than
 bathymetry, side-  geological         Supervisor deems   60 days if the
 scan sonar,        information,       it necessary,      Regional
 subbottom          Analyzed                              Supervisor
 profiler, and      geological                            determines it
 magnetometer) to   information,                          is needed by
 comply with                                              affected
 safety or                                                States to make
 environmental                                            decisions
 protection                                               under subpart
 requirements,                                            B. The
                                                          Regional
                                                          Supervisor
                                                          will
                                                          reconsider
                                                          earlier
                                                          release if you
                                                          satisfy him/
                                                          her that it
                                                          would unduly
                                                          damage your
                                                          competitive
                                                          position.
(3) Your lease is  Geophysical data,  When your lease    This release
 no longer in       Geological data,   terminates,        time applies
 effect,            Processed G&G                         only if the
                    information                           provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                    Analyzed                              resolution
                    geological                            systems and
                    information,                          the provisions
                                                          in Sec.
                                                          552.7 do not
                                                          apply. The
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(4) Your lease is  Geophysical data,  10 years after     This release
 still in effect,   Processed          you submit the     time applies
                    geophysical        data and           only if the
                    information,       information,       provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                                                          resolution
                                                          systems and
                                                          the provisions
                                                          in Sec.
                                                          552.7 do not
                                                          apply. This
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.

[[Page 391]]

 
(5) Your lease is  Geological data,   Two years after    These release
 still in effect    analyzed           the required       times apply
 and within the     geological         submittal date     only if the
 primary term       information        or 60 days after   provisions in
 specified in the                      a lease sale if    this table
 lease                                 any portion of     governing high-
                                       an offered lease   resolution
                                       is within 50       systems and
                                       miles of a well,   the provisions
                                       whichever is       in Sec.
                                       later              552.7 do not
                                                          apply. If the
                                                          primary term
                                                          specified in
                                                          the lease is
                                                          extended, this
                                                          provision
                                                          applies to the
                                                          extension.
(6) Your lease is  Geological data,   2 years after the  None.
 in effect and      Analyzed           required
 beyond the         geological         submittal date,
 primary term       information,
 specified in the
 lease,
(7) Data or        Descriptions of    When the well      Directional
 information is     downhole           goes on            survey data
 submitted on       locations,         production or      may be
 well operations,   operations, and    when geological    released
                    equipment,         data is released   earlier to the
                                       according to       owner of an
                                       Sec.  Sec.         adjacent lease
                                       550.197(b)(5)      according to
                                       and (b)(6),        30 CFR 250
                                       whichever occurs   subpart D.
                                       earlier,
(8) Data and       Any data or        At any time,       None.
 information are    information
 obtained from      obtained,
 beneath unleased
 land as a result
 of a well
 deviation that
 has not been
 approved by the
 Regional
 Supervisor,
(9) Except for     G&G data,          Geological data    None.
 high-resolution    analyzed           and information:
 data and           geological         10 years after
 information        information,       BOEM issues the
 released under     processed and      permit;
 paragraph (b)(2)   interpreted G&G    Geophysical
 of this section    information,       data: 50 years
 data and                              after BOEM
 information                           issues the
 acquired by a                         permit;
 permit under 30                       Geophysical
 CFR part 551 are                      information: 25
 submitted by a                        years after BOEM
 lessee under                          issues the
 part 550, 30 CFR                      permit,
 part 203, or 30
 CFR part 250,
------------------------------------------------------------------------

    (c) BOEM may allow limited data and information inspection, but only 
by a person with a direct interest in related BOEM decisions and issues 
in a specific geographic area, and who agrees in writing to maintain the 
confidentiality of geological and geophysical (G&G) data and information 
submitted under this part that BOEM uses to:
    (1) Promote operational safety;
    (2) Protect the environment; or
    (3) Make field determinations.
    (d) No proprietary information received by BOEM under 43 U.S.C. 1352 
will be transmitted to any affected State unless the lessee, or the 
permittee and all persons to whom such permittee has sold such 
information under promise of confidentiality, agree to such transmittal.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 18152, Mar. 30, 2016]

                               References



Sec.  550.198  [Reserved]



Sec.  550.199  Paperwork Reduction Act statements--information collection.

    (a) OMB has approved the information collection requirements in part 
550 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this 
section lists the subpart in the rule requiring the information and its 
title, provides the OMB control number, and summarizes the reasons for 
collecting the information and how BOEM uses the information. The 
associated BOEM forms required by this part are listed at the end of 
this table with the relevant information.
    (b) Respondents are OCS oil, gas, and sulphur lessees and operators. 
The requirement to respond to the information collections in this part 
is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's 
Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also 
required to obtain or retain a benefit or may be voluntary. Proprietary 
information will be protected under Sec.  550.197, Data and information 
to

[[Page 392]]

be made available to the public or for limited inspection; parts 551, 
552; and the Freedom of Information Act (5 U.S.C. 552) and its 
implementing regulations at 43 CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.
    (e) BOEM is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or BOEM Form       Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform BOEM of actions taken
 including Forms BOEM-1123, Designation   to comply with general
 of Operator and BOEM-1832,               requirements on the OCS. To
 Notification of Incidents of             ensure that operations on the
 Noncompliance.                           OCS meet statutory and
                                          regulatory requirements, are
                                          safe and protect the
                                          environment, and result in
                                          diligent exploration,
                                          development, and production on
                                          OCS leases. To support the
                                          unproved and proved reserve
                                          estimation, resource
                                          assessment, and fair market
                                          value determinations.
(2) Subpart B, Exploration and           To inform BOEM, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151), including Forms BOEM-0137, OCS    development, and production
 Plan Information Form; BOEM-0138, EP     operations on the OCS. To
 Air Quality Screening Checklist; BOEM-   ensure that operations on the
 0139, DOCD Air Quality Screening         OCS are planned to comply with
 Checklist; BOEM-0141, ROV Survey         statutory and regulatory
 Report Form; and BOEM-0142,              requirements, will be safe and
 Environmental Impact Analysis            protect the human, marine, and
 Worksheet.                               coastal environment, and will
                                          result in diligent
                                          exploration, development, and
                                          production of leases.
(3) Subpart C, Pollution Prevention and  To inform BOEM of measures to
 Control (1010-0057).                     be taken to prevent air
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent air pollution.
(4) Subpart J, Pipelines and Pipeline    To provide BOEM with
 Rights-of-Way (1010-0050), including     information regarding the
 Form BOEM-2030, Outer Continental        design, installation, and
 Shelf (OCS) Pipeline Right-of-Way        operation of pipelines on the
 Grant Bond.                              OCS. To ensure that pipeline
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(5) Subpart K, Oil and Gas Production    To inform BOEM of production
 Rates (1010-0041), including Forms       rates for hydrocarbons
 BOEM-0127, Sensitive Reservoir           produced on the OCS. To ensure
 Information Report and BOEM-0140,        economic maximization of
 Bottomhole Pressure Survey Report.       ultimate hydrocarbon recovery.
(6) Subpart N, Remedies and Penalties..  The requirements in subpart N
                                          are exempt from the Paperwork
                                          Reduction Act of 1995
                                          according to 5 CFR 1320.4.
------------------------------------------------------------------------


[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]



                     Subpart B_Plans and Information

                           General Information



Sec.  550.200  Definitions.

    Acronyms and terms used in this subpart have the following meanings:
    (a) Acronyms used frequently in this subpart are listed 
alphabetically below:
    BOEM means Bureau of Ocean Energy Management.
    BSEE means Bureau of Safety and Environmental Enforcement.
    CID means Conservation Information Document.
    CZMA means Coastal Zone Management Act.
    DOCD means Development Operations Coordination Document.
    DPP means Development and Production Plan.
    DWOP means Deepwater Operations Plan.
    EIA means Environmental Impact Analysis.
    EP means Exploration Plan.
    IOP means Integrated Operations Plan.
    NPDES means National Pollutant Discharge Elimination System.
    NTL means Notice to Lessees and Operators.
    OCS means Outer Continental Shelf.
    (b) Terms used in this subpart are listed alphabetically below:

[[Page 393]]

    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before BOEM for a decision (see Sec. Sec.  550.232(d) and 
550.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see Sec.  550.233(b)(2) and Sec.  550.270(b)(2)) 
that is pending before BOEM for a decision because the OCS plan is 
inconsistent with applicable requirements.
    New or unusual technology means equipment or procedures that:
    (1) Have not been used previously or extensively in a BOEM OCS 
Region;
    (2) Have not been used previously under the anticipated operating 
conditions; or
    (3) Have operating characteristics that are outside the performance 
parameters established by this part.
    Non-conventional production or completion technology includes, but 
is not limited to, floating production systems, tension leg platforms, 
spars, floating production, storage, and offloading systems, guyed 
towers, compliant towers, subsea manifolds, and other subsea production 
components that rely on a remote site or host facility for utility and 
well control services.
    Offshore vehicle means a vehicle that is capable of being driven on 
ice.
    Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes 
you make to an OCS plan that BOEM has disapproved (see Sec. Sec.  
550.234(b), 550.272(a), and 550.273(b)).
    Revised OCS plan means an EP, DPP, or DOCD that proposes changes to 
an approved OCS plan, such as those in the location of a well or 
platform, type of drilling unit, or location of the onshore support base 
(see Sec.  550.283(a)).
    Supplemental OCS plan means an EP, DPP, or DOCD that proposes the 
addition to an approved OCS plan of an activity that requires approval 
of an application or permit (see Sec.  550.283(b)).

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]



Sec.  550.201  What plans and information must I submit before I conduct
 any activities on my lease or unit?

    (a) Plans and documents. Before you conduct the activities on your 
lease or unit listed in the following table, you must submit, and BOEM 
must approve, the listed plans and documents. Your plans and documents 
may cover one or more leases or units.

------------------------------------------------------------------------
  You must submit a(n) . . .                Before you . . .
------------------------------------------------------------------------
(1) Exploration Plan (EP),     Conduct any exploration activities on a
                                lease or unit.
(2) Development and            Conduct any development and production
 Production Plan (DPP),         activities on a lease or unit in any OCS
                                area other than the Western Gulf of
                                Mexico.
(3) Development Operations     Conduct any development and production
 Coordination Document          activities on a lease or unit in the
 (DOCD),                        Western GOM.
(4) BSEE approved Deepwater    Conduct post-drilling installation
 Operations Plan (DWOP),        activities in any water depth associated
                                with a development project that will
                                involve the use of a non-conventional
                                production or completion technology.
(5) Conservation Information   Commence production from development
 Document (CID),                projects in water depths greater than
                                1,312 feet (400 meters).
(6) EP, DPP, or DOCD,          Conduct geological or geophysical (G&G)
                                exploration or a development G&G
                                activity (see definitions under Sec.
                                550.105) on your lease or unit when:
                               (i) It will result in a physical
                                penetration of the seabed greater than
                                500 feet (152 meters);
                               (ii) It will involve the use of
                                explosives;
                               (iii) The Regional Director determines
                                that it might have a significant adverse
                                effect on the human, marine, or coastal
                                environment; or
                               (iv) The Regional Supervisor, after
                                reviewing a notice under Sec.   550.209,
                                determines that an EP, DPP, or DOCD is
                                necessary.
------------------------------------------------------------------------

    (b) Submitting additional information. On a case-by-case basis, the 
Regional Supervisor may require you to submit additional information if 
the Regional Supervisor determines that it is necessary to evaluate your 
proposed plan or document.
    (c) Limiting information. The Regional Director may limit the amount 
of information or analyses that you otherwise must provide in your 
proposed plan or document under this subpart when:

[[Page 394]]

    (1) Sufficient applicable information or analysis is readily 
available to BOEM;
    (2) Other coastal or marine resources are not present or affected;
    (3) Other factors such as technological advances affect information 
needs; or
    (4) Information is not necessary or required for a State to 
determine consistency with their CZMA Plan.
    (d) Referencing. In preparing your proposed plan or document, you 
may reference information and data discussed in other plans or documents 
you previously submitted or that are otherwise readily available to 
BOEM.



Sec.  550.202  What criteria must the Exploration Plan (EP), Development
 and Production Plan (DPP), or Development Operations Coordination
 Document (DOCD) meet?

    Your EP, DPP, or DOCD must demonstrate that you have planned and are 
prepared to conduct the proposed activities in a manner that:
    (a) Conforms to the Outer Continental Shelf Lands Act as amended 
(Act), applicable implementing regulations, lease provisions and 
stipulations, and other Federal laws;
    (b) Is safe;
    (c) Conforms to sound conservation practices and protects the rights 
of the lessor;
    (d) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense; and
    (e) Does not cause undue or serious harm or damage to the human, 
marine, or coastal environment.



Sec.  550.203  Where can wells be located under an EP, DPP, or DOCD?

    The Regional Supervisor reviews and approves proposed well location 
and spacing under an EP, DPP, or DOCD. In deciding whether to approve a 
proposed well location and spacing, the Regional Supervisor will 
consider factors including, but not limited to, the following:
    (a) Protecting correlative rights;
    (b) Protecting Federal royalty interests;
    (c) Recovering optimum resources;
    (d) Number of wells that can be economically drilled for proper 
reservoir management;
    (e) Location of drilling units and platforms;
    (f) Extent and thickness of the reservoir;
    (g) Geologic and other reservoir characteristics;
    (h) Minimizing environmental risk;
    (i) Preventing unreasonable interference with other uses of the OCS; 
and
    (j) Drilling of unnecessary wells.



Sec.  550.204  When must I submit my IOP for proposed Arctic exploratory
 drilling operations and what must the IOP include?

    If you propose exploratory drilling activities on the Arctic OCS, 
you must submit an Integrated Operations Plan (IOP) to the Regional 
Supervisor at least 90 days prior to filing your EP. Your IOP must 
describe how your exploratory drilling program will be designed and 
conducted in an integrated manner that accounts for Arctic OCS 
conditions and include the following information:
    (a) A description of how all vessels and equipment will be designed, 
built, and/or modified to account for Arctic OCS conditions;
    (b) A schedule of your exploratory drilling program, including 
contractor work on critical components of your program;
    (c) A description of your mobilization and demobilization 
operations, including tow plans that account for Arctic OCS conditions, 
as well as your general maintenance schedule for vessels and equipment;
    (d) A description of your exploratory drilling program objectives 
and timelines for each objective, including general plans for 
abandonment of the well(s), such as:
    (1) Contingency plans for temporary abandonment in the event of ice 
encroachment at the drill site;
    (2) Plans for permanent abandonment; and
    (3) Plans for temporary seasonal abandonment.
    (e) A description of your weather and ice forecasting capabilities 
for all phases of the exploration program, including a description of 
how you would respond to and manage ice hazards and weather events;
    (f) A description of work to be performed by contractors supporting 
your

[[Page 395]]

exploration drilling program (including mobilization and 
demobilization), including:
    (1) How such work will be designed or modified to account for Arctic 
OCS conditions; and
    (2) Your concepts for contractor management, oversight, and risk 
management.
    (g) A description of how you will ensure operational safety while 
working in Arctic OCS conditions, including but not limited to:
    (1) The safety principles that you intend to apply to yourself and 
your contractors;
    (2) The accountability structure within your organization for 
implementing such principles;
    (3) How you will communicate such principles to your employees and 
contractors; and
    (4) How you will determine successful implementation of such 
principles.
    (h) Information regarding your preparations and plans for staging of 
oil spill response assets;
    (i) A description of your efforts to minimize impacts of your 
exploratory drilling operations on local community infrastructure, 
including but not limited to housing, energy supplies, and services; and
    (j) A description of whether and to what extent your project will 
rely on local community workforce and spill cleanup response capacity.

[81 FR 46565, July 15, 2016]



Sec.  550.205  [Reserved]



Sec.  550.206  How do I submit the IOP, EP, DPP, or DOCD?

    (a) Number of copies. When you submit an IOP, EP, DPP, or DOCD to 
BOEM, you must provide:
    (1) Four copies that contain all required information (proprietary 
copies);
    (2) Eight copies for public distribution (public information copies) 
that omit information that you assert is exempt from disclosure under 
the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the 
implementing regulations (43 CFR part 2); and
    (3) Any additional copies that may be necessary to facilitate review 
of the IOP, EP, DPP, or DOCD by certain affected States and other 
reviewing entities.
    (b) Electronic submission. You may submit part or all of your IOP, 
EP, DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your IOP, EP, DPP, or DOCD electronically, ask the 
Regional Supervisor for further guidance.
    (c) Withdrawal after submission. You may withdraw your proposed IOP, 
EP, DPP, or DOCD at any time for any reason. Notify the appropriate BOEM 
OCS Region if you do.

[81 FR 46565, July 15, 2016]

                          Ancillary Activities



Sec.  550.207  What ancillary activities may I conduct?

    Before or after you submit an EP, DPP, or DOCD to BOEM, you may 
elect, the regulations in this part may require, or the Regional 
Supervisor may direct you to conduct ancillary activities. Ancillary 
activities include:
    (a) Geological and geophysical (G&G) explorations and development 
G&G activities;
    (b) Geological and high-resolution geophysical, geotechnical, 
archaeological, biological, physical oceanographic, meteorological, 
socioeconomic, or other surveys; or
    (c) Studies that model potential oil and hazardous substance spills, 
drilling muds and cuttings discharges, projected air emissions, or 
potential hydrogen sulfide (H2S) releases.



Sec.  550.208  If I conduct ancillary activities, what notices must
 I provide?

    At least 30 calendar days before you conduct any G&G exploration or 
development G&G activity (see Sec.  550.207(a)), you must notify the 
Regional Supervisor in writing.
    (a) When you prepare the notice, you must:
    (1) Sign and date the notice;
    (2) Provide the names of the vessel, its operator, and the person(s) 
in charge; the specific type(s) of operations you will conduct; and the 
instrumentation/techniques and vessel navigation system you will use;
    (3) Provide expected start and completion dates and the location of 
the activity; and

[[Page 396]]

    (4) Describe the potential adverse environmental effects of the 
proposed activity and any mitigation to eliminate or minimize these 
effects on the marine, coastal, and human environment.
    (b) The Regional Supervisor may require you to:
    (1) Give written notice to BOEM at least 15 calendar days before you 
conduct any other ancillary activity (see Sec.  550.207(b) and (c)) in 
addition to those listed in Sec.  550.207(a); and
    (2) Notify other users of the OCS before you conduct any ancillary 
activity.



Sec.  550.209  What is the BOEM review process for the notice?

    The Regional Supervisor will review any notice required under Sec.  
550.208(a) and (b)(1) to ensure that your ancillary activity complies 
with the performance standards listed in Sec.  550.202(a), (b), (d), and 
(e). The Regional Supervisor may notify you that your ancillary activity 
does not comply with those standards. In such a case, the Regional 
Supervisor will require you to submit an EP, DPP, or DOCD and you may 
not start your ancillary activity until the Regional Supervisor approves 
the EP, DPP, or DOCD.



Sec.  550.210  If I conduct ancillary activities, what reporting and
 data/information retention requirements must I satisfy?

    (a) Reporting. The Regional Supervisor may require you to prepare 
and submit reports that summarize and analyze data or information 
obtained or derived from your ancillary activities. When applicable, 
BOEM will protect and disclose the data and information in these reports 
in accordance with Sec.  550.197(b).
    (b) Data and information retention. You must retain copies of all 
original data and information, including navigation data, obtained or 
derived from your G&G explorations and development G&G activities (see 
Sec.  550.207(a)), including any such data and information you obtained 
from previous leaseholders or unit operators. You must submit such data 
and information to BOEM for inspection and possible retention upon 
request at any time before lease or unit termination. When applicable, 
BOEM will protect and disclose such submitted data and information in 
accordance with Sec.  550.197(b).

                   Contents of Exploration Plans (EP)



Sec.  550.211  What must the EP include?

    Your EP must include the following:
    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the exploration activities that you propose to undertake. Examples of 
exploration activities include exploration drilling, well test flaring, 
installing a well protection structure, and temporary well abandonment.
    (b) Location. A map showing the surface location and water depth of 
each proposed well and the locations of all associated drilling unit 
anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed exploration activities, 
including a brief description of its important safety and pollution 
prevention features, and a table indicating the type and the estimated 
maximum quantity of fuels, oil, and lubricants that will be stored on 
the facility (see definition of ``facility'' under Sec.  550.105(3)).
    (d) Service fee. You must include payment of the service fee listed 
in Sec.  550.125.



Sec.  550.212  What information must accompany the EP?

    The following information must accompany your EP:
    (a) General information required by Sec.  550.213;
    (b) Geological and geophysical (G&G) information required by Sec.  
550.214;
    (c) Hydrogen sulfide information required by Sec.  550.215;
    (d) Biological, physical, and socioeconomic information required by 
Sec.  550.216;
    (e) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec.  550.217;
    (f) Air emissions information required by Sec.  550.218;
    (g) Oil and hazardous substance spills information required by Sec.  
550.219;

[[Page 397]]

    (h) Alaska planning information required by Sec.  550.220;
    (i) Environmental monitoring information required by Sec.  550.221;
    (j) Lease stipulations information required by Sec.  550.222;
    (k) Mitigation measures information required by Sec.  550.223;
    (l) Support vessels and aircraft information required by Sec.  
550.224;
    (m) Onshore support facilities information required by Sec.  
550.225;
    (n) Coastal zone management information required by Sec.  550.226;
    (o) Environmental impact analysis information required by Sec.  
550.227; and
    (p) Administrative information required by Sec.  550.228.



Sec.  550.213  What general information must accompany the EP?

    The following general information must accompany your EP:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to conduct your proposed exploration 
activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water-based, oil-
based, synthetic-based) of drilling fluid you plan to use to drill your 
proposed exploration wells.
    (c) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
exploration activities. List only those chemical products you will store 
or use in quantities greater than the amounts defined as Reportable 
Quantities in 40 CFR part 302, or amounts specified by the Regional 
Supervisor.
    (d) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec.  550.200) you will 
use to carry out your proposed exploration activities. In the public 
information copies of your EP, you may exclude any proprietary 
information from this description. In that case, include a brief 
discussion of the general subject matter of the omitted information. If 
you will not use any new or unusual technology to carry out your 
proposed exploration activities, include a statement so indicating.
    (e) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your EP are or will be 
covered by an appropriate bond under 30 CFR part 556, subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your EP according to 30 CFR 
part 553; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (f) Suspensions of operations. A brief discussion of any suspensions 
of operations that you anticipate may be necessary in the course of 
conducting your activities under the EP.
    (g) Blowout scenario. A scenario for the potential blowout of the 
proposed well in your EP that you expect will have the highest volume of 
liquid hydrocarbons. Include the estimated flow rate, total volume, and 
maximum duration of the potential blowout. Also, discuss the potential 
for the well to bridge over, the likelihood for surface intervention to 
stop the blowout, the availability of a rig to drill a relief well, and 
rig package constraints. Estimate the time it would take to drill a 
relief well.
    (h) Contact. The name, address (e-mail address, if available), and 
telephone number of the person with whom the Regional Supervisor and any 
affected State(s) can communicate about your EP.



Sec.  550.214  What geological and geophysical (G&G) information must
 accompany the EP?

    The following G&G information must accompany your EP:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) drawn on the top of each prospective 
hydrocarbon-bearing reservoir showing the locations of proposed wells.
    (c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D

[[Page 398]]

seismic lines (with depth scale) intersecting at or near your proposed 
well locations. You are not required to conduct both 2-D and 3-D seismic 
surveys if you choose to conduct only one type of survey. If you have 
conducted both types of surveys, the Regional Supervisor may instruct 
you to submit the results of both surveys. You must interpret and 
display this information. Because of its volume, provide this 
information as an enclosure to only one proprietary copy of your EP.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the location and depth of each proposed well.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geological and manmade 
features and conditions that may adversely affect your proposed drilling 
operations.
    (g) High-resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your EP. You are not required to provide this 
information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of the 
prospect.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the types of G&G 
explorations and development G&G activities you may conduct for lease or 
unit purposes after your EP is approved.



Sec.  550.215  What hydrogen sulfide (H [bdi2]S) information must
 accompany the EP?

    The following H2S information, as applicable, must 
accompany your EP:
    (a) Concentration. The estimated concentration of any H2S 
you might encounter while you conduct your proposed exploration 
activities.
    (b) Classification. Under 30 CFR 250.490(c), a request that the BSEE 
Regional Supervisor classify the area of your proposed exploration 
activities as either H2S absent, H2S present, or 
H2S unknown. Provide sufficient information to justify your 
request.
    (c) H2S Contingency Plan. If you ask the Regional 
Supervisor to classify the area of your proposed exploration activities 
as either H2S present or H2S unknown, an 
H2S Contingency Plan prepared under 30 CFR 250.490(f), or a 
reference to an approved or submitted H2S Contingency Plan 
that covers the proposed exploration activities.
    (d) Modeling report. If you modeled a potential H2S 
release when developing your EP, modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.
    (1) The analysis in the modeling report must be specific to the 
particular site of your proposed exploration activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed exploration 
activities.
    (2) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 parts per million, 
the modeling analysis must be consistent with the Environmental 
Protection Agency's (EPA) risk management plan methodologies outlined in 
40 CFR part 68.



Sec.  550.216  What biological, physical, and socioeconomic information
 must accompany the EP?

    If you obtain the following information in developing your EP, or if 
the Regional Supervisor requires you to obtain it, you must include a 
report, or the information obtained, or a reference to such a report or 
information

[[Page 399]]

if you have already submitted it to the Regional Supervisor, as 
accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the Marine Mammal Protection Act 
(MMPA), sensitive underwater features, marine sanctuaries, critical 
habitat designated under the Endangered Species Act (ESA), or other 
areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec.  550.194).
    (c) Socioeconomic study reports. Socioeconomic information regarding 
your proposed exploration activities.



Sec.  550.217  What solid and liquid wastes and discharges information
 and cooling water intake information must accompany the EP?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your EP:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, and chemical product wastes) likely to be generated by your 
proposed exploration activities. Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your drilling location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard, or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed exploration 
activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. The modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes when 
developing your EP), or a reference to such report or results if you 
have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed exploration 
activities that includes a brief description of the cooling water intake 
structure, daily water intake rate, water intake through screen 
velocity, percentage of water intake used for cooling water, mitigation 
measures for reducing impingement and entrainment of aquatic organisms, 
and biofouling prevention measures.



Sec.  550.218  What air emissions information must accompany the EP?

    The following air emissions information, as applicable, must 
accompany your EP:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed exploration activities.
    (1) For each source on or associated with the drilling unit 
(including well test flaring and well protection structure 
installation), you must list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed exploration 
activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraphs (a)(1)(i) 
through (iv) of this section.
    (2) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.

[[Page 400]]

    (3) You must base the projected emissions on the maximum rated 
capacity of the equipment on the proposed drilling unit under its 
physical and operational design.
    (4) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the characteristics and the frequency, 
duration, and maximum burn rate of any well test fluids to be burned.
    (d) Distance to shore. Identification of the distance of your 
drilling unit from the mean high water mark (mean higher high water mark 
on the Pacific coast) of the adjacent State.
    (e) Non-exempt drilling units. A description of how you will comply 
with Sec.  550.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC, that will be generated by your proposed 
exploration activities, are greater than the respective emission 
exemption amounts ``E'' calculated using the formulas in Sec.  
550.303(d). When BOEM requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec.  550.303 requires you to use an approved air quality model to model 
projected air emissions in developing your EP), or a reference to such a 
report or results if you have already submitted it to the Regional 
Supervisor.



Sec.  550.219  What oil and hazardous substance spills information must
 accompany the EP?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116) as applicable, must accompany your EP:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your exploration activities prepared according to the 
requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed exploration 
activities; and
    (v) A description of the worst case discharge scenario that could 
result from your proposed exploration activities (see 30 CFR 254.26(b), 
(c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your EP, a modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.



Sec.  550.220  If I propose activities in the Alaska OCS Region, what
 planning information must accompany the EP?

    If you propose exploration activities in the Alaska OCS Region, the 
following planning information must accompany your EP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a fire, explosion, personnel evacuation,

[[Page 401]]

or loss of well control, as well as a loss or disablement of a drilling 
unit, and loss of or damage to a support vessel, offshore vehicle, or 
aircraft.
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your exploration activities. 
The procedures must identify ice conditions, weather, and other 
constraints under which the exploration activities will either be 
curtailed or not proceed.
    (c) If you propose exploration activities on the Arctic OCS, the 
following planning information must also accompany your EP:
    (1) Suitability for Arctic OCS conditions. A description of how your 
exploratory drilling activities will be designed and conducted in a 
manner that accounts for Arctic OCS conditions and how such activities 
will be managed and overseen as an integrated endeavor.
    (2) Ice and weather management. A description of your weather and 
ice forecasting and management plans for all phases of your exploratory 
drilling activities, including:
    (i) A description of how you will respond to and manage ice hazards 
and weather events;
    (ii) Your ice and weather alert procedures;
    (iii) Your procedures and thresholds for activating your ice and 
weather management system(s); and
    (iv) Confirmation that you will operate ice and weather management 
and alert systems continuously throughout the planned operations, 
including mobilization and demobilization operations to and from the 
Arctic OCS.
    (3) Source control and containment equipment capabilities. A general 
description of how you will comply with Sec.  250.471 of this title.
    (4) Deployment of a relief well rig. A general description of how 
you will comply with Sec.  250.472 of this title, including a 
description of the relief well rig, the anticipated staging area of the 
relief well rig, an estimate of the time it would take for the relief 
well rig to arrive at the site of a loss of well control, how you would 
drill a relief well if necessary, and the approximate timeframe to 
complete relief well operations.
    (5) Resource-sharing. Any agreements you have with third parties for 
the sharing of assets or the provision of mutual aid in the event of an 
oil spill or other emergency.
    (6) Anticipated end of seasonal operations dates. Your projected end 
of season dates, and the information used to identify those dates, for:
    (i) The completion of on-site operations, which is contingent upon 
your capability in terms of equipment and procedures to manage and 
mitigate risks associated with Arctic OCS conditions; and
    (ii) The termination of drilling operations consistent with the 
relief rig planning requirements under Sec.  250.472 of this title and 
with your estimated timeframe under paragraph (c)(4) of this section for 
completion of relief well operations.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]



Sec.  550.221  What environmental monitoring information must accompany
 the EP?

    The following environmental monitoring information, as applicable, 
must accompany your EP:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your exploration activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned exploration activities, you 
must describe how you will monitor for incidental take of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct exploration activities within the protective zones of 
the FGBNMS, a description of your provisions for monitoring the impacts 
of an oil spill on the environmentally sensitive resources at the 
FGBNMS.

[[Page 402]]



Sec.  550.222  What lease stipulations information must accompany the EP?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to your proposed exploration 
activities must accompany your EP.



Sec.  550.223  What mitigation measures information must accompany
 the EP?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed exploration activities, a description of the measures 
you will use must accompany your EP.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned exploration activities, you must include 
mitigation measures designed to avoid or minimize the incidental take 
of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.



Sec.  550.224  What information on support vessels, offshore vehicles,
 and aircraft you will use must accompany the EP?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your EP:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
exploration activities. The description of vessels and offshore vehicles 
must estimate the storage capacity of their fuel tanks and the frequency 
of their visits to your drilling unit.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of your drilling unit.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec.  550.213(b) and (c)) you will 
transport from the onshore support facilities you will use to your 
drilling unit.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec.  
550.217(a)) you will transport from your drilling unit.
    (e) Vicinity map. A map showing the location of your proposed 
exploration activities relative to the shoreline. The map must depict 
the primary route(s) the support vessels and aircraft will use when 
traveling between the onshore support facilities you will use and your 
drilling unit.



Sec.  550.225  What information on the onshore support facilities you
 will use must accompany the EP?

    The following information on the onshore support facilities you will 
use must accompany your EP:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed exploration 
activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded.
    (2) If the onshore support facilities are, or will be, located in 
areas not adjacent to the Western GOM, provide a timetable for acquiring 
lands (including rights-of-way and easements) and constructing or 
expanding the facilities. Describe any State or Federal permits or 
approvals (dredging, filling, etc.) that would be required for 
constructing or expanding them.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed exploration activities) likely to be generated by the onshore 
support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed exploration activities) likely to 
be generated by the onshore support facilities you will use. Unusual 
wastes are those wastes not specifically addressed in the relevant

[[Page 403]]

National Pollution Discharge Elimination System (NPDES) permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed exploration activities (see Sec.  550.217) and the types and 
quantities of such wastes.



Sec.  550.226  What Coastal Zone Management Act (CZMA) information
 must accompany the EP?

    The following CZMA information must accompany your EP:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed 
exploration activities described in detail in this EP comply with (name 
of State(s)) approved coastal management program(s) and will be 
conducted in a manner that is consistent with such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).



Sec.  550.227  What environmental impact analysis (EIA) information
 must accompany the EP?

    The following EIA information must accompany your EP:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
exploration activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the National Environmental Policy Act (NEPA) of 1969 (42 
U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and 
the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed exploration activities, or that could affect 
the construction and operation of facilities or structures, or the 
activities proposed in your EP.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat as 
defined by the Endangered Species Act of 1973;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources including employment, existing offshore 
and coastal infrastructure (including major sources of supplies, 
services, energy, and water), land use, subsistence resources and 
harvest practices, recreation, recreational and commercial fishing 
(including typical fishing seasons, location, and type), minority and 
lower income groups, and coastal zone management programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed exploration activities will have on the identified 
resources, conditions, and activities;
    (2) Analyze any potential cumulative impacts from other activities 
to those identified resources, conditions, and activities potentially 
impacted by your proposed exploration activities;
    (3) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (4) Describe potential measures to minimize or mitigate these 
potential impacts; and
    (5) Summarize the information you incorporate by reference.

[[Page 404]]

    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed exploration 
activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.



Sec.  550.228  What administrative information must accompany the EP?

    The following administrative information must accompany your EP:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your EP or its 
accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your EP or 
its accompanying information, a list of the referenced material; and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

                 Review and Decision Process for the EP



Sec.  550.231  After receiving the EP, what will BOEM do?

    (a) Determine whether deemed submitted. Within 15 working days after 
receiving your proposed EP and its accompanying information, the 
Regional Supervisor will review your submission and deem your EP 
submitted if:
    (1) The submitted information, including the information that must 
accompany the EP (refer to the list in Sec.  550.212), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec.  
550.201(b)); and
    (3) You have provided the required number of copies (see Sec.  
550.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 15 working days after the Regional 
Supervisor receives your EP and its accompanying information. The 
Regional Supervisor will not deem your EP submitted until you have 
corrected all problems or deficiencies identified in the notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when the EP is deemed submitted.



Sec.  550.232  What actions will BOEM take after the EP is deemed
 submitted?

    (a) State and CZMA consistency reviews. Within 2 working days after 
deeming your EP submitted under Sec.  550.231, the Regional Supervisor 
will use receipted mail or alternative method to send a public 
information copy of the EP and its accompanying information to the 
following:
    (1) The Governor of each affected State. The Governor has 21 
calendar days after receiving your deemed-submitted EP to submit 
comments. The Regional Supervisor will not consider comments received 
after the deadline.
    (2) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C. 
1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA agency 
receives a copy of your deemed-submitted EP, consistency certification, 
and required necessary data and information (see 15 CFR 930.77(a)(1)).
    (b) BOEM compliance review. The Regional Supervisor will review the 
exploration activities described in your proposed EP to ensure that they 
conform to the performance standards in Sec.  550.202.
    (c) BOEM environmental impact evaluation. The Regional Supervisor 
will evaluate the environmental impacts of the activities described in 
your proposed EP and prepare environmental documentation under the 
National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq.) and 
the implementing regulations (40 CFR parts 1500 through 1508).
    (d) Amendments. During the review of your proposed EP, the Regional 
Supervisor may require you, or you may elect, to change your EP. If you 
elect to amend your EP, the Regional Supervisor may determine that your 
EP, as

[[Page 405]]

amended, is subject to the requirements of Sec.  550.231.



Sec.  550.233  What decisions will BOEM make on the EP and within what
 timeframe?

    (a) Timeframe. The Regional Supervisor will take one of the actions 
shown in the table in paragraph (b) of this section within 30 calendar 
days after the Regional Supervisor deems your EP submitted under Sec.  
550.231, or receives the last amendment to your proposed EP, whichever 
occurs later.
    (b) BOEM decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

----------------------------------------------------------------------------------------------------------------
 The regional supervisor will
            . . .                                 If . . .                               And then . . .
----------------------------------------------------------------------------------------------------------------
(1) Approve your EP,           It complies with all applicable requirements,   The Regional Supervisor will
                                                                                notify you in writing of the
                                                                                decision and may require you to
                                                                                meet certain conditions,
                                                                                including those to provide
                                                                                monitoring information.
(2) Require you to modify      The Regional Supervisor finds that it is        The Regional Supervisor will
 your proposed EP,              inconsistent with the lease, the Act, the       notify you in writing of the
                                regulations prescribed under the Act, or        decision and describe the
                                other Federal laws,                             modifications you must make to
                                                                                your proposed EP to ensure it
                                                                                complies with all applicable
                                                                                requirements.
(3) Disapprove your EP,        Your proposed activities would probably cause   (i) The Regional Supervisor will
                                serious harm or damage to life (including       notify you in writing of the
                                fish or other aquatic life); property; any      decision and describe the
                                mineral (in areas leased or not leased); the    reason(s) for disapproving your
                                National security or defense; or the marine,    EP.
                                coastal, or human environment; and you cannot  (ii) BOEM may cancel your lease
                                modify your proposed activities to avoid such   and compensate you under 43
                                condition(s),                                   U.S.C. 1334(a)(2)(C) and the
                                                                                implementing regulations in Sec.
                                                                                 Sec.   550.182, 550.184, and
                                                                                550.185 and 30 CFR 556.77.
----------------------------------------------------------------------------------------------------------------



Sec.  550.234  How do I submit a modified EP or resubmit a disapproved EP,
 and when will BOEM make a decision?

    (a) Modified EP. If the Regional Supervisor requires you to modify 
your proposed EP under Sec.  550.233(b)(2), you must submit the 
modification(s) to the Regional Supervisor in the same manner as for a 
new EP. You need submit only information related to the proposed 
modification(s).
    (b) Resubmitted EP. If the Regional Supervisor disapproves your EP 
under Sec.  550.233(b)(3), you may resubmit the disapproved EP if there 
is a change in the conditions that were the basis of its disapproval.
    (c) BOEM review and timeframe. The Regional Supervisor will use the 
performance standards in Sec.  550.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted EP. The 
Regional Supervisor will make a decision within 30 calendar days after 
the Regional Supervisor deems your modified or resubmitted EP to be 
submitted, or receives the last amendment to your modified or 
resubmitted EP, whichever occurs later.



Sec.  550.235  If a State objects to the EP's coastal zone consistency
 certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed EP within the timeframe 
prescribed in Sec.  550.233(a) or Sec.  550.234(c), you may do one of 
the following:
    (a) Amend your EP. Amend your EP to accommodate the State's 
objection and submit the amendment to the Regional Supervisor for 
approval. The amendment needs to only address information related to the 
State's objection.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in 
detail in your EP is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of National security; or
    (2) Deny your appeal, in which case you may amend your EP as 
described in paragraph (a) of this section.

[[Page 406]]

    (c) Withdraw your EP. Withdraw your EP if you decide not to conduct 
your proposed exploration activities.

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)



Sec.  550.241  What must the DPP or DOCD include?

    Your DPP or DOCD must include the following:
    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the development and production activities you propose to undertake. 
Examples of development and production activities include:
    (1) Development drilling;
    (2) Well test flaring;
    (3) Installation of production platforms, satellite structures, 
subsea wellheads and manifolds, and lease term pipelines (see definition 
at Sec.  550.105); and
    (4) Installation of production facilities and conduct of production 
operations.
    (b) Location. The location and water depth of each of your proposed 
wells and production facilities. Include a map showing the surface and 
bottom-hole location and water depth of each proposed well, the surface 
location of each production facility, and the locations of all 
associated drilling unit and construction barge anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed development drilling 
activities. Include a brief description of its important safety and 
pollution prevention features, and a table indicating the type and the 
estimated maximum quantity of fuels and oil that will be stored on the 
facility (see definition of ``facility (3)'' under Sec.  550.105).
    (d) Production facilities. A description of the production 
platforms, satellite structures, subsea wellheads and manifolds, lease 
term pipelines (see definition at Sec.  550.105), production facilities, 
umbilicals, and other facilities you will use to conduct your proposed 
development and production activities. Include a brief description of 
their important safety and pollution prevention features, and a table 
indicating the type and the estimated maximum quantity of fuels and oil 
that will be stored on the facility (see definition of ``facility (3)'' 
under Sec.  550.105).
    (e) Service fee. You must include payment of the service fee listed 
in Sec.  550.125.



Sec.  550.242  What information must accompany the DPP or DOCD?

    The following information must accompany your DPP or DOCD.
    (a) General information required by Sec.  550.243;
    (b) G&G information required by Sec.  550.244;
    (c) Hydrogen sulfide information required by Sec.  550.245;
    (d) Mineral resource conservation information required by Sec.  
550.246;
    (e) Biological, physical, and socioeconomic information required by 
Sec.  550.247;
    (f) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec.  550.248;
    (g) Air emissions information required by Sec.  550.249;
    (h) Oil and hazardous substance spills information required by Sec.  
550.250;
    (i) Alaska planning information required by Sec.  550.251;
    (j) Environmental monitoring information required by Sec.  550.252;
    (k) Lease stipulations information required by Sec.  550.253;
    (l) Mitigation measures information required by Sec.  550.254;
    (m) Decommissioning information required by Sec.  550.255;
    (n) Related facilities and operations information required by Sec.  
550.256;
    (o) Support vessels and aircraft information required by Sec.  
550.257;
    (p) Onshore support facilities information required by Sec.  
550.258;
    (q) Sulphur operations information required by Sec.  550.259;
    (r) Coastal zone management information required by Sec.  550.260;
    (s) Environmental impact analysis information required by Sec.  
550.261; and
    (t) Administrative information required by Sec.  550.262.

[[Page 407]]



Sec.  550.243  What general information must accompany the DPP or DOCD?

    The following general information must accompany your DPP or DOCD:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to carry out your proposed development and 
production activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water based, oil 
based, synthetic based) of drilling fluid you plan to use to drill your 
proposed development wells.
    (c) Production. The following production information:
    (1) Estimates of the average and peak rates of production for each 
type of production and the life of the reservoir(s) you intend to 
produce; and
    (2) The chemical and physical characteristics of the produced oil 
(see definition under 30 CFR 254.6) that you will handle or store at the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
development and production activities. You need list only those chemical 
products you will store or use in quantities greater than the amounts 
defined as Reportable Quantities in 40 CFR part 302, or amounts 
specified by the Regional Supervisor.
    (e) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec.  550.200) you will 
use to carry out your proposed development and production activities. In 
the public information copies of your DPP or DOCD, you may exclude any 
proprietary information from this description. In that case, include a 
brief discussion of the general subject matter of the omitted 
information. If you will not use any new or unusual technology to carry 
out your proposed development and production activities, include a 
statement so indicating.
    (f) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your DPP or DOCD are 
or will be covered by an appropriate bond under 30 CFR part 556, subpart 
I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your DPP or DOCD, according to 
30 CFR part 553; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (g) Suspensions of production or operations. A brief discussion of 
any suspensions of production or suspensions of operations that you 
anticipate may be necessary in the course of conducting your activities 
under the DPP or DOCD.
    (h) Blowout scenario. A scenario for a potential blowout of the 
proposed well in your DPP or DOCD that you expect will have the highest 
volume of liquid hydrocarbons. Include the estimated flow rate, total 
volume, and maximum duration of the potential blowout. Also, discuss the 
potential for the well to bridge over, the likelihood for surface 
intervention to stop the blowout, the availability of a rig to drill a 
relief well, and rig package constraints. Estimate the time it would 
take to drill a relief well.
    (i) Contact. The name, mailing address, (e-mail address if 
available), and telephone number of the person with whom the Regional 
Supervisor and the affected State(s) can communicate about your DPP or 
DOCD.



Sec.  550.244  What geological and geophysical (G&G) information must
 accompany the DPP or DOCD?

    The following G&G information must accompany your DPP or DOCD:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) showing depths of expected productive 
formations and the locations of proposed wells.
    (c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of

[[Page 408]]

migrated and annotated 2-D or 3-D seismic lines (with depth scale) 
intersecting at or near your proposed well locations. You are not 
required to conduct both 2-D and 3-D seismic surveys if you choose to 
conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Provide this information as an enclosure to only one proprietary copy of 
your DPP or DOCD.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the depths of expected productive formations.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geologic and manmade features 
and conditions that may adversely affect your proposed drilling 
operations.
    (g) High resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your DPP or DOCD. You are not required to provide 
this information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of each 
proposed well.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the G&G 
explorations and development G&G activities that you may conduct for 
lease or unit purposes after your DPP or DOCD is approved.



Sec.  550.245  What hydrogen sulfide (H [bdi2]S) information must 
accompany the DPP or DOCD?

    The following H2S information, as applicable, must 
accompany your DPP or DOCD:
    (a) Concentration. The estimated concentration of any H2S 
you might encounter or handle while you conduct your proposed 
development and production activities.
    (b) Classification. Under 30 CFR 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S absent, H2S 
present, or H2S unknown. Provide sufficient information to 
justify your request.
    (c) H 2S Contingency Plan. If you request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S present or H2S 
unknown, an H2S Contingency Plan prepared under 30 CFR 
250.490(f), or a reference to an approved or submitted H2S 
Contingency Plan that covers the proposed development and production 
activities.
    (d) Modeling report. (1) If you have determined or estimated that 
the concentration of any H2S you may encounter or handle 
while you conduct your development and production activities will be 
greater than 500 parts per million (ppm), you must:
    (i) Model a potential worst case H2S release from the 
facilities you will use to conduct your proposed development and 
production activities; and
    (ii) Include a modeling report or modeling results, or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.
    (2) The analysis in the modeling report must be specific to the 
particular site of your development and production activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed activities.
    (3) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 ppm, the modeling 
analysis must be consistent with the EPA's risk management plan

[[Page 409]]

methodologies outlined in 40 CFR part 68.



Sec.  550.246  What mineral resource conservation information must 
accompany the DPP or DOCD?

    The following mineral resource conservation information, as 
applicable, must accompany your DPP or DOCD:
    (a) Technology and reservoir engineering practices and procedures. A 
description of the technology and reservoir engineering practices and 
procedures you will use to increase the ultimate recovery of oil and gas 
(e.g., secondary, tertiary, or other enhanced recovery practices). If 
you will not use enhanced recovery practices initially, provide an 
explanation of the methods you considered and the reasons why you are 
not using them.
    (b) Technology and recovery practices and procedures. A description 
of the technology and recovery practices and procedures you will use to 
ensure optimum recovery of oil and gas or sulphur.
    (c) Reservoir development. A discussion of exploratory well results, 
other reservoir data, proposed well spacing, completion methods, and 
other relevant well plan information.



Sec.  550.247  What biological, physical, and socioeconomic information 
must accompany the DPP or DOCD?

    If you obtain the following information in developing your DPP or 
DOCD, or if the Regional Supervisor requires you to obtain it, you must 
include a report, or the information obtained, or a reference to such a 
report or information if you have already submitted it to the Regional 
Supervisor, as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the MMPA, sensitive underwater 
features, marine sanctuaries, critical habitat designated under the ESA, 
or other areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec.  550.194).
    (c) Socioeconomic study reports. Socioeconomic information related 
to your proposed development and production activities.



Sec.  550.248  What solid and liquid wastes and discharges information
 and cooling water intake information must accompany the DPP or DOCD?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your DPP or DOCD:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, produced waters, and chemical product wastes) likely to be 
generated by your proposed development and production activities. 
Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your facility location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, adding to a produced water stream, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed development 
and production activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. A modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes in 
developing your DPP or DOCD), or a reference to such report or results 
if you have already submitted it to the Regional Supervisor.

[[Page 410]]

    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed development and 
production activities that includes a brief description of the cooling 
water intake structure, daily water intake rate, water intake through-
screen velocity, percentage of water intake used for cooling water, 
mitigation measures for reducing impingement and entrainment of aquatic 
organisms, and biofouling prevention measures.



Sec.  550.249  What air emissions information must accompany the DPP
 or DOCD?

    The following air emissions information, as applicable, must 
accompany your DPP or DOCD:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed development and production 
activities.
    (1) For each source on or associated with the facility you will use 
to conduct your proposed development and production activities, you must 
list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed development and 
production activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraph (a)(1)(i) through 
(iv) of this section.
    (2) If your proposed production and development activities would 
result in an increase in the emissions of an air pollutant from your 
facility to an amount greater than the amount specified in your 
previously approved DPP or DOCD, you must show the revised emission 
rates for each source as well as the incremental change for each source.
    (3) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (4) You must base the projected emissions on the maximum rated 
capacity of the equipment and the maximum throughput of the facility you 
will use to conduct your proposed development and production activities 
under its physical and operational design.
    (5) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the frequency, duration, and maximum 
burn rate of any flaring activity.
    (d) Distance to shore. Identification of the distance of the site of 
your proposed development and production activities from the mean high 
water mark (mean higher high water mark on the Pacific coast) of the 
adjacent State.
    (e) Non-exempt facilities. A description of how you will comply with 
Sec.  550.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC that will be generated by your proposed 
development and production activities are greater than the respective 
emission exemption amounts ``E'' calculated using the formulas in Sec.  
550.303(d). When BOEM requires air quality modeling, you must use the 
guidelines in appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec.  550.303 requires you to use an approved air quality model to model 
projected air emissions in developing your DPP or DOCD), or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.

[[Page 411]]



Sec.  550.250  What oil and hazardous substance spills information must
 accompany the DPP or DOCD?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your proposed development and production activities 
prepared according to the requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed development and 
production activities; and
    (v) A description of the worst case oil spill scenario that could 
result from your proposed development and production activities (see 30 
CFR 254.26(b), (c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your DPP or DOCD, a modeling report or the 
modeling results, or a reference to such report or results if you have 
already submitted it to the Regional Supervisor.



Sec.  550.251  If I propose activities in the Alaska OCS Region, what 
planning information must accompany the DPP?

    If you propose development and production activities in the Alaska 
OCS Region, the following planning information must accompany your DPP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft; and
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your development and 
production activities. The procedures must identify ice conditions, 
weather, and other constraints under which the development and 
production activities will either be curtailed or not proceed.



Sec.  550.252  What environmental monitoring information must accompany
 the DPP or DOCD?

    The following environmental monitoring information, as applicable, 
must accompany your DPP or DOCD:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your development and production activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned development and production 
activities, you must describe how you will monitor for incidental take 
of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take of marine mammals as may be necessary 
under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct development and production activities within the 
protective zones of the FGBNMS, a description of your provisions for 
monitoring the impacts of oil spill on the environmentally sensitive 
resources of the FGBNMS.



Sec.  550.253  What lease stipulations information must accompany the
 DPP or DOCD?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to

[[Page 412]]

your proposed development and production activities must accompany your 
DPP or DOCD.



Sec.  550.254  What mitigation measures information must accompany 
the DPP or DOCD?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed development and production activities, a description 
of the measures you will use must accompany your DPP or DOCD.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned development and production activities, you 
must include mitigation measures designed to avoid or minimize that 
incidental take of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.



Sec.  550.255  What decommissioning information must accompany the DPP
 or DOCD?

    A brief description of how you intend to decommission your wells, 
platforms, pipelines, and other facilities, and clear your site(s) must 
accompany your DPP or DOCD.



Sec.  550.256  What related facilities and operations information must
 accompany the DPP or DOCD?

    The following information regarding facilities and operations 
directly related to your proposed development and production activities 
must accompany your DPP or DOCD.
    (a) OCS facilities and operations. A description and location of any 
of the following that directly relate to your proposed development and 
production activities:
    (1) Drilling units;
    (2) Production platforms;
    (3) Right-of-way pipelines (including those that transport chemical 
products and produced water); and
    (4) Other facilities and operations located on the OCS (regardless 
of ownership).
    (b) Transportation system. A discussion of the transportation system 
that you will use to transport your production to shore, including:
    (1) Routes of any new pipelines;
    (2) Information concerning barges and shuttle tankers, including the 
storage capacity of the transport vessel(s), and the number of transfers 
that will take place per year;
    (3) Information concerning any intermediate storage or processing 
facilities;
    (4) An estimate of the quantities of oil, gas, or sulphur to be 
transported from your production facilities; and
    (5) A description and location of the primary onshore terminal.



Sec.  550.257  What information on the support vessels, offshore vehicles,
 and aircraft you will use must accompany the DPP or DOCD?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your DPP or DOCD:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
development and production activities. The description of vessels and 
offshore vehicles must estimate the storage capacity of their fuel tanks 
and the frequency of their visits to the facilities you will use to 
conduct your proposed development and production activities.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of the facilities you will use to conduct 
your proposed development and production activities.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec.  550.243(b) and (d)) you will 
transport from the onshore support facilities you will use to the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description

[[Page 413]]

of the composition, quantities, and destination(s) of solid and liquid 
wastes (see Sec.  550.248(a)) you will transport from the facilities you 
will use to conduct your proposed development and production activities.
    (e) Vicinity map. A map showing the location of your proposed 
development and production activities relative to the shoreline. The map 
must depict the primary route(s) the support vessels and aircraft will 
use when traveling between the onshore support facilities you will use 
and the facilities you will use to conduct your proposed development and 
production activities.



Sec.  550.258  What information on the onshore support facilities you
 will use must accompany the DPP or DOCD?

    The following information on the onshore support facilities you will 
use must accompany your DPP or DOCD:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed development and 
production activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded; and
    (2) For DPPs only, provide a timetable for acquiring lands 
(including rights-of-way and easements) and constructing or expanding 
any of the onshore support facilities.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed development and production activities) likely to be generated 
by the onshore support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed development and production 
activities) likely to be generated by the onshore support facilities you 
will use. Unusual wastes are those wastes not specifically addressed in 
the relevant National Pollution Discharge Elimination System (NPDES) 
permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed development and production activities (see Sec.  550.248(a)) 
and the types and quantities of such wastes.



Sec.  550.259  What sulphur operations information must accompany 
the DPP or DOCD?

    If you are proposing to conduct sulphur development and production 
activities, the following information must accompany your DPP or DOCD:
    (a) Bleedwater. A discussion of the bleedwater that will be 
generated by your proposed sulphur activities, including the measures 
you will take to mitigate the potential toxic or thermal impacts on the 
environment caused by the discharge of bleedwater.
    (b) Subsidence. An estimate of the degree of subsidence expected at 
various stages of your sulphur development and production activities, 
and a description of the measures you will take to mitigate the effects 
of subsidence on existing or potential oil and gas production, 
production platforms, and production facilities, and to protect the 
environment.



Sec.  550.260  What Coastal Zone Management Act (CZMA) information
 must accompany the DPP or DOCD?

    The following CZMA information must accompany your DPP or DOCD:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(c) stating that the proposed 
development and production activities described in detail in this DPP or 
DOCD comply with (name of State(s)) approved coastal management 
program(s) and will be conducted in a manner that is consistent with 
such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).



Sec.  550.261  What environmental impact analysis (EIA) information 
must accompany the DPP or DOCD?

    The following EIA information must accompany your DPP or DOCD:
    (a) General requirements. Your EIA must:

[[Page 414]]

    (1) Assess the potential environmental impacts of your proposed 
development and production activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other 
relevant Federal laws such as the ESA and the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed development and production activities, or that 
could affect the construction and operation of facilities or structures 
or the activities proposed in your DPP or DOCD.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources (including the approximate number, 
timing, and duration of employment of persons engaged in onshore support 
and construction activities), population (including the approximate 
number of people and families added to local onshore areas), existing 
offshore and onshore infrastructure (including major sources of 
supplies, services, energy, and water), types of contractors or vendors 
that may place a demand on local goods and services, land use, 
subsistence resources and harvest practices, recreation, recreational 
and commercial fishing (including seasons, location, and type), minority 
and lower income groups, and CZMA programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed development and production activities will have on 
the identified resources, conditions, and activities;
    (2) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (3) Describe potential measures to minimize or mitigate these 
potential impacts;
    (4) Describe any alternatives to your proposed development and 
production activities that you considered while developing your DPP or 
DOCD, and compare the potential environmental impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed development 
and production activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.



Sec.  550.262  What administrative information must accompany the
 DPP or DOCD?

    The following administrative information must accompany your DPP or 
DOCD:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your DPP or 
DOCD or its accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your DPP or 
DOCD or its accompanying information, a list of the referenced material; 
and

[[Page 415]]

    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

             Review and Decision Process for the DPP or DOCD



Sec.  550.266  After receiving the DPP or DOCD, what will BOEM do?

    (a) Determine whether deemed submitted. Within 25 working days after 
receiving your proposed DPP or DOCD and its accompanying information, 
the Regional Supervisor will deem your DPP or DOCD submitted if:
    (1) The submitted information, including the information that must 
accompany the DPP or DOCD (refer to the list in Sec.  550.242), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec.  
550.201(b)); and
    (3) You have provided the required number of copies (see Sec.  
550.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 25 working days after the Regional 
Supervisor receives your DPP or DOCD and its accompanying information. 
The Regional Supervisor will not deem your DPP or DOCD submitted until 
you have corrected all problems or deficiencies identified in the 
notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when your DPP or DOCD is deemed submitted.



Sec.  550.267  What actions will BOEM take after the DPP or DOCD
 is deemed submitted?

    (a) State, local government, CZMA consistency, and other reviews. 
Within 2 working days after the Regional Supervisor deems your DPP or 
DOCD submitted under Sec.  550.266, the Regional Supervisor will use 
receipted mail or alternative method to send a public information copy 
of the DPP or DOCD and its accompanying information to the following:
    (1) The Governor of each affected State. The Governor has 60 
calendar days after receiving your deemed-submitted DPP or DOCD to 
submit comments and recommendations. The Regional Supervisor will not 
consider comments and recommendations received after the deadline.
    (2) The executive of any affected local government who requests a 
copy. The executive of any affected local government has 60 calendar 
days after receipt of your deemed-submitted DPP or DOCD to submit 
comments and recommendations. The Regional Supervisor will not consider 
comments and recommendations received after the deadline. The executive 
of any affected local government must forward all comments and 
recommendations to the respective Governor before submitting them to the 
Regional Supervisor.
    (3) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 
U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA 
agency receives a copy of your deemed-submitted DPP or DOCD, consistency 
certification, and required necessary data/information (see 15 CFR 
930.77(a)(1)).
    (b) General public. Within 2 working days after the Regional 
Supervisor deems your DPP or DOCD submitted under Sec.  550.266, the 
Regional Supervisor will make a public information copy of the DPP or 
DOCD and its accompanying information available for review to any 
appropriate interstate regional entity and the public at the appropriate 
BOEM Regional Public Information Office. Any interested Federal agency 
or person may submit comments and recommendations to the Regional 
Supervisor. Comments and recommendations must be received by the 
Regional Supervisor within 60 calendar days after the DPP or DOCD 
including its accompanying information is made available.
    (c) BOEM compliance review. The Regional Supervisor will review the 
development and production activities in your proposed DPP or DOCD to 
ensure that they conform to the performance standards in Sec.  550.202.
    (d) Amendments. During the review of your proposed DPP or DOCD, the 
Regional Supervisor may require you, or you may elect, to change your 
DPP or DOCD. If you elect to amend your DPP

[[Page 416]]

or DOCD, the Regional Supervisor may determine that your DPP
 or DOCD, as amended, is subject to the requirements of
 Sec.  550.266.



Sec.  550.268  How does BOEM respond to recommendations?

    (a) Governor. The Regional Supervisor will accept those 
recommendations from the Governor that provide a reasonable balance 
between the National interest and the well-being of the citizens of each 
affected State. The Regional Supervisor will explain in writing to the 
Governor the reasons for rejecting any of his or her recommendations.
    (b) Local governments and the public. The Regional Supervisor may 
accept recommendations from the executive of any affected local 
government or the public.
    (c) Availability. The Regional Supervisor will make all comments and 
recommendations available to the public upon request.



Sec.  550.269  How will BOEM evaluate the environmental impacts 
of the DPP or DOCD?

    The Regional Supervisor will evaluate the environmental impacts of 
the activities described in your proposed DPP or DOCD and prepare 
environmental documentation under the National Environmental Policy Act 
(NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR 
parts 1500 through 1508).
    (a) Environmental impact statement (EIS) declaration. At least once 
in each OCS planning area (other than the Western and Central GOM 
Planning Areas), the Director will declare that the approval of a 
proposed DPP is a major Federal action, and BOEM will prepare an EIS.
    (b) Leases or units in the vicinity. Before or immediately after the 
Director determines that preparation of an EIS is required, the Regional 
Supervisor may require lessees and operators of leases or units in the 
vicinity of the proposed development and production activities for which 
DPPs have not been approved to submit information about preliminary 
plans for their leases or units.
    (c) Draft EIS. The Regional Supervisor will send copies of the draft 
EIS to the Governor of each affected State and to the executive of each 
affected local government who requests a copy. Additionally, when BOEM 
prepares a DPP EIS, and the Federally-approved CZMA program for an 
affected State requires a DPP NEPA document for use in determining 
consistency, the Regional Supervisor will forward a copy of the draft 
EIS to the State's CZMA agency. The Regional Supervisor will also make 
copies of the draft EIS available to any appropriate Federal agency, 
interstate regional entity, and the public.



Sec.  550.270  What decisions will BOEM make on the DPP or DOCD
 and within what timeframe?

    (a) Timeframe. The Regional Supervisor will act on your deemed-
submitted DPP or DOCD as follows:
    (1) The Regional Supervisor will make a decision within 60 calendar 
days after the latest of the day that:
    (i) The comment period provided in Sec.  550.267(a)(1), (a)(2), and 
(b) closes;
    (ii) The final EIS for a DPP is released or adopted; or
    (iii) The last amendment to your proposed DOCD is received by the 
Regional Supervisor.
    (2) Notwithstanding paragraph (a)(1) of this section, BOEM will not 
approve your DPP or DOCD until either:
    (i) All affected States with approved CZMA programs concur, or have 
been conclusively presumed to concur, with your DPP or DOCD consistency 
certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 
U.S.C. 1456(c)(3)(B)(i) and (ii)); or
    (ii) The Secretary of Commerce has made a finding authorized by 
section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) 
that each activity described in the DPP or DOCD is consistent with the 
objectives of the CZMA, or is otherwise necessary in the interest of 
National security.
    (b) BOEM decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

[[Page 417]]



------------------------------------------------------------------------
     The regional
 supervisor will . . .         If . . .              And then . . .
------------------------------------------------------------------------
(1) Approve your DPP    It complies with all   The Regional Supervisor
 or DOCD,                applicable             will notify you in
                         requirements,          writing of the decision
                                                and may require you to
                                                meet certain conditions,
                                                including those to
                                                provide monitoring
                                                information.
(2) Require you to      It fails to make       The Regional Supervisor
 modify your proposed    adequate provisions    will notify you in
 DPP or DOCD,            for safety,            writing of the decision
                         environmental          and describe the
                         protection, or         modifications you must
                         conservation of        make to your proposed
                         natural resources or   DPP or DOCD to ensure it
                         otherwise does not     complies with all
                         comply with the        applicable requirements.
                         lease, the Act, the
                         regulations
                         prescribed under the
                         Act, or other
                         Federal laws,
(3) Disapprove your     Any of the reasons in  (i) The Regional
 DPP or DOCD,            Sec.   550.271         Supervisor will notify
                         apply,                 you in writing of the
                                                decision and describe
                                                the reason(s) for
                                                disapproving your DPP or
                                                DOCD; and
                                               (ii) BOEM may cancel your
                                                lease and compensate you
                                                under 43 U.S.C.
                                                1351(h)(2)(C) and the
                                                implementing regulations
                                                in Sec.  Sec.   550.183
                                                through 550.185 and 30
                                                CFR 556.77.
------------------------------------------------------------------------



Sec.  550.271  For what reasons will BOEM disapprove the DPP or DOCD?

    The Regional Supervisor will disapprove your proposed DPP or DOCD if 
one of the four reasons in this section applies:
    (a) Non-compliance. The Regional Supervisor determines that you have 
failed to demonstrate that you can comply with the requirements of the 
Outer Continental Shelf Lands Act, as amended (Act), implementing 
regulations, or other applicable Federal laws.
    (b) No consistency concurrence. (1) An affected State has not yet 
issued a final decision on your coastal zone consistency certification 
(see 15 CFR 930.78(a)); or
    (2) An affected State objects to your coastal zone consistency 
certification, and the Secretary of Commerce, under section 
307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not 
found that each activity described in the DPP or DOCD is consistent with 
the objectives of the CZMA or is otherwise necessary in the interest of 
National security.
    (3) If the Regional Supervisor disapproved your DPP or DOCD for the 
sole reason that an affected State either has not yet issued a final 
decision on, or has objected to, your coastal zone consistency 
certification (see paragraphs (b)(1) and (2) in this section), the 
Regional Supervisor will approve your DPP or DOCD upon receipt of 
concurrence by the affected State, at the time concurrence of the 
affected State is conclusively presumed, or when the Secretary of 
Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the 
CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your 
DPP or DOCD is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of National security. In that event, 
you do not need to resubmit your DPP or DOCD for approval under Sec.  
550.273(b).
    (c) National security or defense conflicts. Your proposed activities 
would threaten National security or defense.
    (d) Exceptional circumstances. The Regional Supervisor determines 
because of exceptional geological conditions, exceptional resource 
values in the marine or coastal environment, or other exceptional 
circumstances that all of the following apply:
    (1) Implementing your DPP or DOCD would cause serious harm or damage 
to life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), the National security or 
defense, or the marine, coastal, or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of disapproving your DPP or DOCD outweigh the 
advantages of development and production.



Sec.  550.272  If a State objects to the DPP's or DOCD's coastal
 zone consistency certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification

[[Page 418]]

accompanying your proposed or disapproved DPP or DOCD, you may do one of 
the following:
    (a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP 
or DOCD to accommodate the State's objection and submit the amendment or 
resubmittal to the Regional Supervisor for approval. The amendment or 
resubmittal needs to only address information related to the State's 
objections.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in 
detail in your DPP or DOCD is consistent with the objectives of the 
CZMA, or is otherwise necessary in the interest of National security; or
    (2) Deny your appeal, in which case you may amend or resubmit your 
DPP or DOCD, as described in paragraph (a) of this section.
    (c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you 
decide not to conduct your proposed development and production 
activities.



Sec.  550.273  How do I submit a modified DPP or DOCD or resubmit
 a disapproved DPP or DOCD?

    (a) Modified DPP or DOCD. If the Regional Supervisor requires you to 
modify your proposed DPP or DOCD under Sec.  550.270(b)(2), you must 
submit the modification(s) to the Regional Supervisor in the same manner 
as for a new DPP or DOCD. You need submit only information related to 
the proposed modification(s).
    (b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves 
your DPP or DOCD under Sec.  550.270(b)(3), and except as provided in 
Sec.  550.271(b)(3), you may resubmit the disapproved DPP or DOCD if 
there is a change in the conditions that were the basis of its 
disapproval.
    (c) BOEM review and timeframe. The Regional Supervisor will use the 
performance standards in Sec.  550.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted DPP or DOCD. 
The Regional Supervisor will make a decision within 60 calendar days 
after the Regional Supervisor deems your modified or resubmitted DPP or 
DOCD to be submitted, or receives the last amendment to your modified or 
resubmitted DPP or DOCD, whichever occurs later.

          Post-Approval Requirements for the EP, DPP, and DOCD



Sec.  550.280  How must I conduct activities under the approved
 EP, DPP, or DOCD?

    (a) Compliance. You must conduct all of your lease and unit 
activities according to your approved EP, DPP, or DOCD and any approval 
conditions. If you fail to comply with your approved EP, DPP, or DOCD:
    (1) You may be subject to BOEM enforcement action, including civil 
penalties; and
    (2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited 
or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will 
not be entitled to compensation under Sec.  550.185(b) and 30 CFR 
556.77.
    (b) Emergencies. Nothing in this subpart or in your approved EP, 
DPP, or DOCD relieves you of, or limits your responsibility to take 
appropriate measures to meet emergency situations. In an emergency 
situation, the Regional Supervisor may approve or require departures 
from your approved EP, DPP, or DOCD.



Sec.  550.281  What must I do to conduct activities under the
 approved EP, DPP, or DOCD?

    (a) Approvals and permits. Before you conduct activities under your 
approved EP, DPP, or DOCD you must obtain the following approvals and or 
permits, as applicable, from the District Manager or BSEE Regional 
Supervisor:
    (1) Approval of applications for permits to drill (APDs) (see 30 CFR 
250.410);
    (2) Approval of production safety systems (see 30 CFR 250.800);
    (3) Approval of new platforms and other structures (or major 
modifications to platforms and other structures) (see 30 CFR 250.905);

[[Page 419]]

    (4) Approval of applications to install lease term pipelines (see 30 
CFR 250.1007); and
    (5) Other permits, as required by applicable law.
    (b) Conformance. The activities proposed in these applications and 
permits must conform to the activities described in detail in your 
approved EP, DPP, or DOCD.
    (c) Separate State CZMA consistency review. APDs, and other 
applications for licenses, approvals, or permits to conduct activities 
under your approved EP, DPP, or DOCD including those identified in 
paragraph (a) of this section, are not subject to separate State CZMA 
consistency review.
    (d) Approval restrictions for permits for activities conducted under 
EPs. The Regional Supervisor will not approve any APDs or other 
applications for licenses, approvals, or permits under your approved EP 
until either:
    (1) All affected States with approved coastal zone management 
programs concur, or are conclusively presumed to concur, with the 
coastal zone consistency certification accompanying your EP under 
section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) 
and (ii)); or
    (2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) 
of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by 
the EP is consistent with the objectives of the CZMA or is otherwise 
necessary in the interest of National security;
    (3) If an affected State objects to the coastal zone consistency 
certification accompanying your approved EP after BOEM has approved your 
EP, you may either:
    (i) Revise your EP to accommodate the State's objection and submit 
the revision to the Regional Supervisor for approval; or
    (ii) Appeal the State's objection to the Secretary of Commerce using 
the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce 
will either:
    (A) Grant your appeal by making the finding described in paragraph 
(d)(2) of this section; or
    (B) Deny your appeal, in which case you may revise your EP as 
described in paragraph (d)(3)(i) of this section.



Sec.  550.282  Do I have to conduct post-approval monitoring?

    After approving your EP, DPP, or DOCD, the Regional Supervisor may 
direct you to conduct monitoring programs, including monitoring in 
accordance with the ESA and the MMPA. You must retain copies of all 
monitoring data obtained or derived from your monitoring programs and 
make them available to the BOEM upon request. The Regional Supervisor 
may require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin the work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will specify requirements 
for preparing and submitting these reports.



Sec.  550.283  When must I revise or supplement the approved
 EP, DPP, or DOCD?

    (a) Revised OCS plans. You must revise your approved EP, DPP, or 
DOCD when you propose to:
    (1) Change the type of drilling rig (e.g., jack-up, platform rig, 
barge, submersible, semisubmersible, or drillship), production facility 
(e.g., caisson, fixed platform with piles, tension leg platform), or 
transportation mode (e.g., pipeline, barge);
    (2) Change the surface location of a well or production platform by 
a distance more than that specified by the Regional Supervisor;
    (3) Change the type of production or significantly increase the 
volume of production or storage capacity;
    (4) Increase the emissions of an air pollutant to an amount that 
exceeds the amount specified in your approved EP, DPP, or DOCD;
    (5) Significantly increase the amount of solid or liquid wastes to 
be handled or discharged;
    (6) Request a new H2S area classification, or increase 
the concentration of H2S to a concentration greater than that 
specified by the Regional Supervisor;
    (7) Change the location of your onshore support base either from one

[[Page 420]]

State to another or to a new base or a base requiring expansion; or
    (8) Change any other activity specified by the Regional Supervisor.
    (b) Supplemental OCS plans. You must supplement your approved EP, 
DPP, or DOCD when you propose to conduct activities on your lease(s) or 
unit that require approval of a license or permit which is not described 
in your approved EP, DPP, or DOCD. These types of changes are called 
supplemental OCS plans.



Sec.  550.284  How will BOEM require revisions to the approved
 EP, DPP, or DOCD?

    (a) Periodic review. The Regional Supervisor will periodically 
review the activities you conduct under your approved EP, DPP, or DOCD 
and may require you to submit updated information on your activities. 
The frequency and extent of this review will be based on the 
significance of any changes in available information and onshore or 
offshore conditions affecting, or affected by, the activities in your 
approved EP, DPP, or DOCD.
    (b) Results of review. The Regional Supervisor may require you to 
revise your approved EP, DPP, or DOCD based on this review. In such 
cases, the Regional Supervisor will inform you of the reasons for the 
decision.



Sec.  550.285  How do I submit revised and supplemental 
EPs, DPPs, and DOCDs?

    (a) Submittal. You must submit to the Regional Supervisor any 
revisions and supplements to approved EPs, DPPs, or DOCDs for approval, 
whether you initiate them or the Regional Supervisor orders them.
    (b) Information. Revised and supplemental EPs, DPPs, and DOCDs need 
include only information related to or affected by the proposed changes, 
including information on changes in expected environmental impacts.
    (c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those 
revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are 
likely to result in a significant change in the impacts previously 
identified and evaluated, are subject to all of the procedures under 
Sec. Sec.  550.231 through 550.235 for EPs and Sec. Sec.  550.266 
through 550.273 for DPPs and DOCDs.



Sec. Sec.  550.286-550.295  [Reserved]

                Conservation Information Documents (CID)



Sec.  550.296  When and how must I submit a CID or a revision to a CID?

    (a) You must submit one original and two copies of a CID to the 
appropriate OCS Region at the same time you first submit your DOCD or 
DPP for any development of a lease or leases located in water depths 
greater than 400 meters (1,312 feet). You must also submit a CID for a 
Supplemental DOCD or DPP when requested by the Regional Supervisor. The 
submission of your CID must be accompanied by payment of the service fee 
listed in Sec.  550.125.
    (b) If you decide not to develop a reservoir you committed to 
develop in your CID, you must submit one original and two copies of a 
revision to the CID to the appropriate OCS Region. The revision to the 
CID must be submitted within 14 calendar days after making your decision 
not to develop the reservoir and before the reservoir is bypassed. The 
Regional Supervisor will approve or disapprove any such revision to the 
original CID. If the Regional Supervisor disapproves the revision, you 
must develop the reservoir as described in the original CID.



Sec.  550.297  What information must a CID contain?

    (a) You must base the CID on wells drilled before your CID submittal 
that define the extent of the reservoirs. You must notify BOEM of any 
well that is drilled to total depth during the CID evaluation period and 
you may be required to update your CID.
    (b) You must include all of the following information if available. 
Information must be provided for each hydrocarbon-bearing reservoir that 
is penetrated by a well that would meet the producibility requirements 
of Sec.  550.115 or Sec.  550.116:
    (1) General discussion of the overall development of the reservoir;
    (2) Summary spreadsheets of well log data and reservoir parameters 
(i.e., sand tops and bases, fluid contacts, net

[[Page 421]]

pay, porosity, water saturations, pressures, formation volume factor);
    (3) Appropriate well logs, including digital well log (i.e., gamma 
ray, resistivity, neutron, density, sonic, caliper curves) curves in an 
acceptable digital format;
    (4) Sidewall core/whole core and pressure-volume-temperature 
analysis;
    (5) Structure maps, with the existing and proposed penetration 
points and subsea depths for all wells penetrating the reservoirs, fluid 
contacts (or the lowest or highest known levels in the absence of actual 
contacts), reservoir boundaries, and the scale of the map;
    (6) Interpreted structural cross sections and corresponding 
interpreted seismic lines or block diagrams, as necessary, that include 
all current wellbores and planned wellbores on the leases or units to be 
developed, the reservoir boundaries, fluid contacts, depth scale, 
stratigraphic positions, and relative biostratigraphic ages;
    (7) Isopach maps of each reservoir showing the net feet of pay for 
each well within the reservoir identified at the penetration point, 
along with the well name, labeled contours, and scale;
    (8) Estimates of original oil and gas in-place and anticipated 
recoverable oil and gas reserves, all reservoir parameters, and risk 
factors and assumptions;
    (9) Plat map at the same scale as the structure maps with existing 
and proposed well paths, as well as existing and proposed penetrations;
    (10) Wellbore schematics indicating proposed perforations;
    (11) Proposed wellbore utility chart showing all existing and 
proposed wells, with proposed completion intervals indicated for each 
borehole;
    (12) Appropriate pressure data, specified by date, and whether 
estimated or measured;
    (13) Description of reservoir development strategies;
    (14) Description of the enhanced recovery practices you will use or, 
if you do not plan to use such practices, an explanation of the methods 
you considered and reasons you do not intend to use them;
    (15) For each reservoir you do not intend to develop:
    (i) A statement explaining the reason(s) you will not develop the 
reservoir, and
    (ii) Economic justification, including costs, recoverable reserve 
estimate, production profiles, and pricing assumptions; and
    (16) Any other appropriate data you used in performing your 
reservoir evaluations and preparing your reservoir development 
strategies.



Sec.  550.298  How long will BOEM take to evaluate and make a 
decision on the CID?

    (a) The Regional Supervisor will make a decision within 150 calendar 
days of receiving your CID. If BOEM does not act within 150 calendar 
days, your CID is considered approved.
    (b) BOEM may suspend the 150-calendar-day evaluation period if there 
is missing, inconclusive, or inaccurate data, or when a well reaches 
total depth during the evaluation period. BOEM may also suspend the 
evaluation period when a well penetrating a hydrocarbon-bearing 
structure reaches total depth during the evaluation period and the data 
from that well is needed for the CID. You will receive written 
notification from the Regional Supervisor describing the additional 
information that is needed, and the evaluation period will resume once 
BOEM receives the requested information.
    (c) The Regional Supervisor will approve or deny your CID request 
based on your commitment to develop economically producible reservoirs 
according to sound conservation, engineering, and economic practices.



Sec.  550.299  What operations require approval of the CID?

    You may not begin production before you receive BOEM approval of the 
CID.



               Subpart C_Pollution Prevention and Control



Sec. Sec.  550.300-550.301  [Reserved]



Sec.  550.302  Definitions concerning air quality.

    For purposes of Sec. Sec.  550.303 and 550.304 of this part:

[[Page 422]]

    Air pollutant means any combination of agents for which the 
Environmental Protection Agency (EPA) has established, pursuant to 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Attainment area means, for any air pollutant, an area which is shown 
by monitored data or which is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The BACT shall be 
verified on a case-by-case basis by the Regional Supervisor and may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan or Development and Production 
Plan.
    Existing facility is an OCS facility described in an Exploration 
Plan or a Development and Production Plan submitted or approved prior to 
June 2, 1980.
    Facility means any installation or device permanently or temporarily 
attached to the seabed which is used for exploration, development, and 
production activities for oil, gas, or sulphur and which emits or has 
the potential to emit any air pollutant from one or more sources. All 
equipment directly associated with the installation or device shall be 
considered part of a single facility if the equipment is dependent on, 
or affects the processes of, the installation or device. During 
production, multiple installations or devices will be considered to be a 
single facility if the installations or devices are directly related to 
the production of oil, gas, or sulphur at a single site. Any vessel used 
to transfer production from an offshore facility shall be considered 
part of the facility while physically attached to it.
    Nonattainment area means, for any air pollutant, an area which is 
shown by monitored data or which is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source(s).
    Source means an emission point. Several sources may be included 
within a single facility.
    Temporary facility means activities associated with the construction 
of platforms offshore or with facilities related to exploration for or 
development of offshore oil and gas resources which are conducted in one 
location for less than 3 years.
    Volatile organic compound (VOC) means any organic compound which is 
emitted to the atmosphere as a vapor. The unreactive compounds are 
exempt from the above definition.



Sec.  550.303  Facilities described in a new or revised Exploration
 Plan or Development and Production Plan.

    (a) New plans. All Exploration Plans and Development and Production 
Plans shall include the information required to make the necessary 
findings under paragraphs (d) through (i) of this section, and the 
lessee shall comply with the requirements of this section as necessary.
    (b) Applicability of Sec.  550.303 to existing facilities. (1) The 
Regional Supervisor may review any Exploration Plan or Development and 
Production Plan to determine whether any facility described in the plan 
should be subject to review under this section and has the potential to 
significantly affect the air quality of an onshore area. To make these 
decisions, the Regional Supervisor shall consider the distance of the 
facility from shore, the size of the facility, the number of sources 
planned for the facility and their operational status, and the air 
quality status of the onshore area.
    (2) For a facility identified by the Regional Supervisor in 
paragraph (b)(1) of this section, the Regional Supervisor

[[Page 423]]

shall require the lessee to refer to the information required in Sec.  
550.218 or Sec.  550.249 of this part and to submit only that 
information required to make the necessary findings under paragraphs (d) 
through (i) of this section. The lessee shall submit this information 
within 120 days of the Regional Supervisor's determination or within a 
longer period of time at the discretion of the Regional Supervisor. The 
lessee shall comply with the requirements of this section as necessary.
    (c) Revised facilities. All revised Exploration Plans and 
Development and Production Plans shall include the information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall comply with the requirements of this section 
as necessary.
    (d) Exemption formulas. To determine whether a facility described in 
a new, modified, or revised Exploration Plan or Development and 
Production Plan is exempt from further air quality review, the lessee 
shall use the highest annual-total amount of emissions from the facility 
for each air pollutant calculated in Sec.  550.249(a) or Sec.  
550.218(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E = 3400D 2/3 for carbon monoxide (CO); 
and E = 33.3D for total suspended particulates (TSP), sulphur dioxide 
(SO2), nitrogen oxides (NOX), and VOC (where E is 
the emission exemption amount expressed in tons per year, and D is the 
distance of the proposed facility from the closest onshore area of a 
State expressed in statute miles). If the amount of these projected 
emissions is less than or equal to the emission exemption amount ``E'' 
for the air pollutant, the facility is exempt from further air quality 
review required under paragraphs (e) through (i) of this section.
    (e) Significance levels. For a facility not exempt under paragraph 
(d) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether the projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

                                Significance Levels--Air Pollutant Concentrations
                                                 [[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
                                                              Averaging time (hours)
          Air pollutant          -------------------------------------------------------------------------------
                                      Annual            24               8               3               1
----------------------------------------------------------------------------------------------------------------
SO2.............................               1               5  ..............              25
TSP.............................               1               5  ..............  ..............
NO2.............................               1  ..............  ..............  ..............
CO..............................  ..............  ..............             500  ..............           2,000
----------------------------------------------------------------------------------------------------------------

    (f) Significance determinations. (1) The projected emissions of any 
air pollutant other than VOC from any facility which result in an 
onshore ambient air concentration above the significance level 
determined under paragraph (e) of this section for that air pollutant, 
shall be deemed to significantly affect the air quality of the onshore 
area for that air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (d) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (g) Controls required. (1) The projected emissions of any air 
pollutant other than VOC from any facility, except a temporary facility, 
which significantly affect the quality of a nonattainment area, shall be 
fully reduced. This shall be done through the application of BACT and, 
if additional reductions are necessary, through the application of 
additional emission controls or through the acquisition of offshore or 
onshore offsets.
    (2) The projected emissions of any air pollutant other than VOC from 
any facility which significantly affect the air quality of an attainment 
or unclassifiable area shall be reduced through the application of BACT.
    (i)(A) Except for temporary facilities, the lessee also shall use an 
approved

[[Page 424]]

air quality model to determine whether the emissions of TSP or 
SO2 that remain after the application of BACT cause the 
following maximum allowable increases over the baseline concentrations 
established in 40 CFR 52.21 to be exceeded in the attainment or 
unclassifiable area:

                                    Maximum Allowable Concentration Increases
                                                 [[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
                                                                                  Averaging times
                                                                 -----------------------------------------------
                          Air pollutant                             Annual mean       24-hour
                                                                        \1\           maximum     3-hour maximum
----------------------------------------------------------------------------------------------------------------
Class I:
    TSP.........................................................               5              10
    SO2.........................................................               2               5              25
Class II:
    TSP.........................................................              19              37
    SO2.........................................................              20              91             512
Class III:
    TSP.........................................................              37              75
    SO2.........................................................              40             182             700
----------------------------------------------------------------------------------------------------------------
\1\ For TSP--geometric; For SO2--arithmetric.

    (B) No concentration of an air pollutant shall exceed the 
concentration permitted under the national secondary ambient air quality 
standard or the concentration permitted under the national primary air 
quality standard, whichever concentration is lowest for the air 
pollutant for the period of exposure. For any period other than the 
annual period, the applicable maximum allowable increase may be exceeded 
during one such period per year at any one onshore location.
    (ii) If the maximum allowable increases are exceeded, the lessee 
shall apply whatever additional emission controls are necessary to 
reduce or offset the remaining emissions of TSP or SO2 so 
that concentrations in the onshore ambient air of an attainment or 
unclassifiable area do not exceed the maximum allowable increases.
    (3)(i) The projected emissions of VOC from any facility, except a 
temporary facility, which significantly affect the onshore air quality 
of a nonattainment area shall be fully reduced. This shall be done 
through the application of BACT and, if additional reductions are 
necessary, through the application of additional emission controls or 
through the acquisition of offshore or onshore offsets.
    (ii) The projected emissions of VOC from any facility which 
significantly affect the onshore air quality of an attainment area shall 
be reduced through the application of BACT.
    (4)(i) If projected emissions from a facility significantly affect 
the onshore air quality of both a nonattainment and an attainment or 
unclassifiable area, the regulatory requirements applicable to projected 
emissions significantly affecting a nonattainment area shall apply.
    (ii) If projected emissions from a facility significantly affect the 
onshore air quality of more than one class of attainment area, the 
lessee must reduce projected emissions to meet the maximum allowable 
increases specified for each class in paragraph (g)(2)(i) of this 
section.
    (h) Controls required on temporary facilities. The lessee shall 
apply BACT to reduce projected emissions of any air pollutant from a 
temporary facility which significantly affects the air quality of an 
onshore area of a State.
    (i) Emission offsets. When emission offsets are to be obtained, the 
lessee must demonstrate that the offsets are equivalent in nature and 
quantity to the projected emissions that must be reduced after the 
application of BACT; a binding commitment exists between the lessee and 
the owner or owners of the source or sources; the appropriate air 
quality control jurisdiction has been notified of the need to revise the 
State Implementation Plan to include the information regarding the 
offsets; and the required offsets come from sources which affect the air 
quality of

[[Page 425]]

the area significantly affected by the lessee's offshore operations.
    (j) Review of facilities with emissions below the exemption amount. 
If, during the review of a new, modified, or revised Exploration Plan or 
Development and Production Plan, the Regional Supervisor determines or 
an affected State submits information to the Regional Supervisor which 
demonstrates, in the judgment of the Regional Supervisor, that projected 
emissions from an otherwise exempt facility will, either individually or 
in combination with other facilities in the area, significantly affect 
the air quality of an onshore area, then the Regional Supervisor shall 
require the lessee to submit additional information to determine whether 
emission control measures are necessary. The lessee shall be given the 
opportunity to present information to the Regional Supervisor which 
demonstrates that the exempt facility is not significantly affecting the 
air quality of an onshore area of the State.
    (k) Emission monitoring requirements. The lessee shall monitor, in a 
manner approved or prescribed by the Regional Supervisor, emissions from 
the facility. The lessee shall submit this information monthly in a 
manner and form approved or prescribed by the Regional Supervisor.
    (l) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.



Sec.  550.304  Existing facilities.

    (a) Process leading to review of an existing facility. (1) An 
affected State may request that the Regional Supervisor supply basic 
emission data from existing facilities when such data are needed for the 
updating of the State's emission inventory. In submitting the request, 
the State must demonstrate that similar offshore and onshore facilities 
in areas under the State's jurisdiction are also included in the 
emission inventory.
    (2) The Regional Supervisor may require lessees of existing 
facilities to submit basic emission data to a State submitting a request 
under paragraph (a)(1) of this section.
    (3) The State submitting a request under paragraph (a)(1) of this 
section may submit information from its emission inventory which 
indicates that emissions from existing facilities may be significantly 
affecting the air quality of the onshore area of the State. The lessee 
shall be given the opportunity to present information to the Regional 
Supervisor which demonstrates that the facility is not significantly 
affecting the air quality of the State.
    (4) The Regional Supervisor shall evaluate the information submitted 
under paragraph (a)(3) of this section and shall determine, based on the 
basic emission data, available meteorological data, and the distance of 
the facility or facilities from the onshore area, whether any existing 
facility has the potential to significantly affect the air quality of 
the onshore area of the State.
    (5) If the Regional Supervisor determines that no existing facility 
has the potential to significantly affect the air quality of the onshore 
area of the State submitting information under paragraph (a)(3) of this 
section, the Regional Supervisor shall notify the State of and explain 
the reasons for this finding.
    (6) If the Regional Supervisor determines that an existing facility 
has the potential to significantly affect the air quality of an onshore 
area of the State submitting information under paragraph (a)(3) of this 
section, the Regional Supervisor shall require the lessee to refer to 
the information requirements under Sec.  550.218 or Sec.  550.249 of 
this part and submit only that information required to make the 
necessary findings under paragraphs (b) through (e) of this section. The 
lessee shall submit this information within 120 days of the Regional 
Supervisor's determination or within a longer period of time at the 
discretion of the Regional Supervisor. The lessee shall comply with the 
requirements of this section as necessary.
    (b) Exemption formulas. To determine whether an existing facility is 
exempt from further air quality review, the lessee shall use the highest 
annual

[[Page 426]]

total amount of emissions from the facility for each air pollutant 
calculated in Sec.  550.218(a) or Sec.  550.249(a) of this part and 
compare these emissions to the emission exemption amount ``E'' for each 
air pollutant calculated using the following formulas: E = 
3400D2/3 for CO; and E = 33.3D for TSP, SO2, 
NOX, and VOC (where E is the emission exemption amount 
expressed in tons per year, and D is the distance of the facility from 
the closest onshore area of the State expressed in statute miles). If 
the amount of projected emissions is less than or equal to the emission 
exemption amount ``E'' for the air pollutant, the facility is exempt for 
that air pollutant from further air quality review required under 
paragraphs (c) through (e) of this section.
    (c) Significance levels. For a facility not exempt under paragraph 
(b) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

                                Significance Levels--Air Pollutant Concentrations
                                                 [[micro]G/M\3\]
----------------------------------------------------------------------------------------------------------------
                                                              Averaging time (hours)
          Air pollutant          -------------------------------------------------------------------------------
                                      Annual            24               8               3               1
----------------------------------------------------------------------------------------------------------------
SO2.............................               1               5  ..............              25
TSP.............................               1               5  ..............  ..............
NO2.............................               1  ..............  ..............  ..............
CO..............................  ..............  ..............             500  ..............           2,000
----------------------------------------------------------------------------------------------------------------

    (d) Significance determinations. (1) The projected emissions of any 
air pollutant other than VOC from any facility which result in an 
onshore ambient air concentration above the significance levels 
determined under paragraph (c) of this section for that air pollutant 
shall be deemed to significantly affect the air quality of the onshore 
area for that air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (b) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (e) Controls required. (1) The projected emissions of any air 
pollutant which significantly affect the air quality of an onshore area 
shall be reduced through the application of BACT.
    (2) The lessee shall submit a compliance schedule for the 
application of BACT. If it is necessary to cease operations to allow for 
the installation of emission controls, the lessee may apply for a 
suspension of operations under the provisions of 30 CFR 250.174.
    (f) Review of facilities with emissions below the exemption amount. 
If, during the review of the information required under paragraph (a)(6) 
of this section, the Regional Supervisor determines or an affected State 
submits information to the Regional Supervisor which demonstrates, in 
the judgment of the Regional Supervisor, that projected emissions from 
an otherwise exempt facility will, either individually or in combination 
with other facilities in the area, significantly affect the air quality 
of an onshore area, then the Regional Supervisor shall require the 
lessee to submit additional information to determine whether control 
measures are necessary. The lessee shall be given the opportunity to 
present information to the Regional Supervisor which demonstrates that 
the exempt facility is not significantly affecting the air quality of an 
onshore area of the State.
    (g) Emission monitoring requirements. The lessee shall monitor, in a 
manner approved or prescribed by the Regional Supervisor, emissions from 
the facility following the installation of emission controls. The lessee 
shall submit this information monthly in a manner and form approved or 
prescribed by the Regional Supervisor.
    (h) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of

[[Page 427]]

time and in a manner approved or prescribed by the Regional Supervisor, 
and submit meteorological data from a facility.



                   Subpart D_Leasing Maps and Diagrams



Sec.  550.400  Leasing maps and diagrams.

    (a) Any area of the OCS, which has been appropriately platted as 
provided in paragraph (b) of this section, may be leased for any mineral 
not included in an existing lease issued under the Act or meeting the 
requirements of subsection (a) of section 6 of the Act. Before any lease 
is offered or issued an area may be:
    (1) Withdrawn from disposition pursuant to section 12(a) of the Act; 
or
    (2) Designated as an area or part of an area restricted from 
operation under section 12(d) of the Act.
    (b) BOEM will prepare leasing maps and official protraction diagrams 
of areas of the OCS. The areas included in each mineral lease will be in 
accordance with the appropriate leasing map or official protraction 
diagram.

[81 FR 18152, Mar. 30, 2016]

Subparts E-I [Reserved]



             Subpart J_Pipelines and Pipeline Rights-of-Way



Sec.  550.1011  Bond requirements for pipeline right-of-way holders.

    (a) When you apply for, or are the holder of, a right-of-way, you 
must:
    (1) Provide and maintain a $300,000 bond (in addition to the bond 
coverage required in 30 CFR part 256 and 30 CFR part 556) that 
guarantees compliance with all the terms and conditions of the rights-
of-way you hold in an OCS area; and
    (2) Provide additional security if the Regional Director determines 
that a bond in excess of $300,000 is needed.
    (b) For the purpose of this paragraph, there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast;
    (2) The areas offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.
    (c) If, as the result of a default, the surety on a right-of-way 
grant bond makes payment to the Government of any indebtedness under a 
grant secured by the bond, the face amount of such bond and the surety's 
liability shall be reduced by the amount of such payment.
    (d) After a default, a new bond in the amount of $300,000 shall be 
posted within 6 months or such shorter period as the Regional Supervisor 
may direct. Failure to post a new bond shall be grounds for forfeiture 
of all grants covered by the defaulted bond.



             Subpart K_Oil and Gas Production Requirements.

                         Well Tests and Surveys



Sec.  550.1153  When must I conduct a static bottomhole pressure survey?

    (a) You must conduct a static bottomhole pressure survey under the 
following conditions:

----------------------------------------------------------------------------------------------------------------
                  If you have . . .                                   Then you must conduct . . .
----------------------------------------------------------------------------------------------------------------
(1) A new producing reservoir,                        A static bottomhole pressure survey within 90 days after
                                                       the date of first continuous production.
(2) A reservoir with three or more producing          Annual static bottomhole pressure surveys in a sufficient
 completions,                                          number of key wells to establish an average reservoir
                                                       pressure. The Regional Supervisor may require that
                                                       bottomhole pressure surveys be performed on specific
                                                       wells.
----------------------------------------------------------------------------------------------------------------

    (b) Your bottomhole pressure survey must meet the following 
requirements:
    (1) You must shut-in the well for a minimum period of 4 hours to 
ensure stabilized conditions; and
    (2) The bottomhole pressure survey must consist of a pressure 
measurement at mid-perforation, and pressure measurements and gradient 
information for at least four gradient stops coming out of the hole.
    (c) You must submit to the Regional Supervisor the results of all 
static bottomhole pressure surveys on Form

[[Page 428]]

BOEM-140, Bottomhole Pressure Survey Report, within 60 days after the 
date of the survey.
    (d) The Regional Supervisor may grant a departure from the 
requirement to run a static bottomhole pressure survey. To request a 
departure, you must submit a justification, along with Form BOEM-0140, 
Bottomhole Pressure Survey Report, showing a calculated bottomhole 
pressure or any measured data.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

                         Classifying Reservoirs



Sec.  550.1154  How do I determine if my reservoir is sensitive?

    (a) You must determine whether each reservoir is sensitive. You must 
classify the reservoir as sensitive if:
    (1) Under initial conditions it is an oil reservoir with an 
associated gas cap;
    (2) At any time there are near-critical fluids; or
    (3) The reservoir is undergoing enhanced recovery.
    (b) For the purposes of this subpart, near-critical fluids are:
    (1) Those fluids that occur in high temperature, high-pressure 
reservoirs where it is not possible to define the liquid-gas contact; or
    (2) Fluids in reservoirs that are near bubble point or dew point 
conditions.
    (c) The Regional Supervisor may reclassify a reservoir when 
available information warrants reclassification.
    (d) If available information indicates that a reservoir previously 
classified as non-sensitive is now sensitive, you must submit a request 
to the Regional Supervisor to reclassify the reservoir. You must include 
supporting information, as listed in the table in Sec.  550.1167, with 
your request.
    (e) If information indicates that a reservoir previously classified 
as sensitive is now non-sensitive, you may submit a request to the 
Regional Supervisor to reclassify the reservoir. You must include 
supporting information, as listed in the table in Sec.  550.1167, with 
your request.



Sec.  550.1155  What information must I submit for sensitive reservoirs?

    You must submit to the Regional Supervisor an original and two 
copies of Form BOEM-0127; one of the copies must be a public information 
copy in accordance with Sec. Sec.  550.186 and 550.197, and marked 
``Public Information.'' You must also submit two copies of the 
supporting information, as listed in the table in Sec.  550.1167. You 
must submit this information:
    (a) Within 45 days after beginning production from the reservoir or 
discovering that it is sensitive;
    (b) At least once during the calendar year, but you do not need to 
resubmit unrevised structure maps (Sec.  550.1167(a)(2)) or previously 
submitted well logs (Sec.  550.1167(c)(1));
    (c) Within 45 days after you revise reservoir parameters; and
    (d) Within 45 days after the Regional Supervisor classifies the 
reservoir as sensitive under Sec.  550.1154(c).

                           Other Requirements



Sec.  550.1165  What must I do for enhanced recovery operations?

    (a) [Reserved]
    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the BSEE Regional Supervisor and receive approval for 
pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas from a reservoir. The proposed plan must include, for 
each project reservoir, a geologic and engineering overview, Form BOEM-
0127 (submitted to BOEM) and supporting data as required in Sec.  
550.1167, 30 CFR 250.1167, and any additional information required by 
the BSEE Regional Supervisor.
    (c) [Reserved]



Sec.  550.1166  What additional reporting is required for developments
 in the Alaska OCS Region?

    (a)-(b) [Reserved]
    (c) Every time you are required to submit Form BOEM-0127 under Sec.  
550.1155, you must request an MER for each producing sensitive reservoir 
in

[[Page 429]]

the Alaska OCS Region, unless otherwise instructed by the Regional 
Supervisor.



Sec.  550.1167  What information must I submit with forms and for approvals?

    You must submit the supporting information listed in the following 
table with the form identified in column 1 and for the approval required 
under this subpart identified in column 2:

----------------------------------------------------------------------------------------------------------------
                                                                                                Reservoir
                                                              SRI BOEM-0127 (2 copies)      reclassification
----------------------------------------------------------------------------------------------------------------
(a) Maps:                                                     ........................  ........................
    (1) Base map with surface, bottomhole, and completion     ........................
     locations with respect to the unit or lease line and
     the orientation of representative seismic lines or
     cross-sections.........................................
    (2) Structure maps with penetration point and subsea                      [radic]                   [radic]
     depth for each well penetrating the reservoirs,
     highlighting subject wells; reservoir boundaries; and
     original and current fluid levels......................
    (3) Net sand isopach with total net sand penetrated for                         *
     each well, identified at the penetration point.........
    (4) Net hydrocarbon isopach with net feet of pay for                            *
     each well, identified at the penetration point.........
(b) Seismic data:                                             ........................  ........................
    (1) Representative seismic lines, including strike and    ........................
     dip lines that confirm the structure; indicate polarity
    (2) Amplitude extraction of seismic horizon, if           ........................                  [radic]
     applicable.............................................
(c) Logs:                                                     ........................  ........................
    (1) Well log sections with tops and bottoms of the                        [radic]                   [radic]
     reservoir(s) and proposed or existing perforations.....
    (2) Structural cross-sections showing the subject well    ........................                  [radic]
     and nearby wells.......................................
(d) Engineering data:                                         ........................  ........................
    (1) Estimated recoverable reserves for each well                          [radic]
     completion in the reservoir; total recoverable reserves
     for each reservoir; method of calculation; reservoir
     parameters used in volumetric and decline curve
     analysis...............................................
    (2) Well schematics showing current and proposed          ........................
     conditions.............................................
    (3) The drive mechanism of each reservoir...............                  [radic]                   [radic]
    (4) Pressure data, by date, and whether they are          ........................                  [radic]
     estimated or measured..................................
    (5) Production data and decline curve analysis            ........................                  [radic]
     indicative of the reservoir performance................
    (6) Reservoir simulation with the reservoir parameters    ........................                        *
     used, history matches, and prediction runs (include
     proposed development scenario).........................
(e) General information:                                      ........................  ........................
    (1) Detailed economic analysis..........................  ........................  ........................
    (2) Reservoir name and whether or not it is competitive                   [radic]                   [radic]
     as defined under Sec.   250.105........................
    (3) Operator name, lessee name(s), block, lease number,   ........................
     royalty rate, and unit number (if applicable) of all
     relevant leases........................................
    (4) Geologic overview of project........................  ........................                  [radic]
    (5) Explanation of why the proposed completion scenario   ........................
     will maximize ultimate recovery........................
    (6) List of all wells in subject reservoirs that have     ........................                  [radic]
     ever produced or been used for injection...............
----------------------------------------------------------------------------------------------------------------
[radic] Required.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
  submittal of some of the required data on a case-by-case basis.


[[Page 430]]

    (f) Depending on the type of approval requested, you must submit the 
appropriate payment of the service fee(s) listed in Sec.  550.125, 
according to the instructions in Sec.  550.126.

Subparts L-M [Reserved]



            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties



Sec.  550.1400  How does BOEM begin the civil penalty process?

    This subpart explains BOEM's civil penalty procedures whenever a 
lessee, operator or other person engaged in oil, gas, sulphur or other 
minerals operations in the OCS has a violation. Whenever BOEM 
determines, on the basis of available evidence, that a violation 
occurred and a civil penalty review is appropriate, it will prepare a 
case file. BOEM will appoint a Reviewing Officer.



Sec.  550.1401  Index table.

    The following table is an index of the sections in this subpart:

------------------------------------------------------------------------
 
------------------------------------------------------------------------
(a) Definitions.........................  Sec.   550.1402
(b) What is the maximum civil penalty?..  Sec.   550.1403
(c) Which violations will BOEM review     Sec.   550.1404
 for potential civil penalties?.
(d) When is a case file developed?......  Sec.   550.1405
(e) When will BOEM notify me and provide  Sec.   550.1406
 penalty information?.
(f) How do I respond to the letter of     Sec.   550.1407
 notification?.
(g) When will I be notified of the        Sec.   550.1408
 Reviewing Officer's decision?.
(h) What are my appeal rights?..........  Sec.   550.1409
------------------------------------------------------------------------



Sec.  550.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means a BOEM document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is a BOEM regulatory enforcement tool 
used in addition to Notices of Incidents of Noncompliance and directed 
suspensions of production or other operations.
    Reviewing Officer means a BOEM employee assigned to review case 
files and assess civil penalties.
    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.



Sec.  550.1403  What is the maximum civil penalty?

    The maximum civil penalty is $44,675 per day per violation.

[84 FR 11224, Mar. 26, 2019]



Sec.  550.1404  Which violations will BOEM review for potential
 civil penalties?

    BOEM will review each of the following violations for potential 
civil penalties:
    (a) Violations that you do not correct within the period BOEM 
grants;
    (b)-(c) [Reserved]
    (d) Violations of the oil spill financial responsibility 
requirements at 30 CFR part 553.



Sec.  550.1405  When is a case file developed?

    BOEM will develop a case file during its investigation of the 
violation, and forward it to a Reviewing Officer if any of the 
conditions in Sec.  550.1404 exist. The Reviewing Officer will review 
the case file and determine if a civil penalty is appropriate. The 
Reviewing Officer

[[Page 431]]

may administer oaths and issue subpoenas requiring witnesses to attend 
meetings, submit depositions, or produce evidence.



Sec.  550.1406  When will BOEM notify me and provide penalty information?

    If the Reviewing Officer determines that a civil penalty should be 
assessed, the Reviewing Officer will send the violator a letter of 
notification. The letter of notification will include:
    (a) The amount of the proposed civil penalty;
    (b) Information on the violation(s); and
    (c) Instruction on how to obtain a copy of the case file, schedule a 
meeting, submit information, or pay the penalty.



Sec.  550.1407  How do I respond to the letter of notification?

    You have 30 calendar days after you receive the Reviewing Officer's 
letter to either:
    (a) Request, in writing, a meeting with the Reviewing Officer;
    (b) Submit additional information; or
    (c) Pay the proposed civil penalty.



Sec.  550.1408  When will I be notified of the Reviewing Officer's
 decision?

    At the end of the 30 calendar days or after the meeting and 
submittal of additional information, the Reviewing Officer will review 
the case file, including all information you submitted, and send you a 
decision. The decision will include the amount of any final civil 
penalty, the basis for the civil penalty, and instructions for paying or 
appealing the civil penalty.



Sec.  550.1409  What are my appeal rights?

    (a) When you receive the Reviewing Officer's final decision, you 
have 60 days to either pay the penalty or file an appeal in accordance 
with 30 CFR part 590, subpart A.
    (b) If you file an appeal, you must either:
    (1) Submit a surety bond in the amount of the penalty to the 
appropriate Leasing Office in the Region where the penalty was assessed, 
following instructions that the Reviewing Officer will include in the 
final decision; or
    (2) Notify the appropriate Leasing Office, in the Region where the 
penalty was assessed, that you want your lease-specific/area-wide bond 
on file to be used as the bond for the penalty amount.
    (c) If you choose the alternative in paragraph (b)(2) of this 
section, the BOEM Regional Director may require additional security 
(i.e., security in excess of your existing bond) to ensure sufficient 
coverage during an appeal. In that event, the Regional Director will 
require you to post the supplemental bond with the regional office in 
the same manner as under Sec.  556.53(d) through (f) of this chapter. If 
the Regional Director determines the appeal should be covered by a 
lease-specific abandonment account then you must establish an account 
that meets the requirements of Sec.  556.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
BOEM will take one or more of the following actions:
    (1) We will collect the amount you were assessed, plus interest, 
late payment charges, and other fees as provided by law, from the date 
you received the Reviewing Officer's final decision until the date we 
receive payment;
    (2) We may initiate additional enforcement, including, if 
appropriate, cancellation of the lease, right-of-way, license, permit, 
or approval, or the forfeiture of a bond under this part; or
    (3) We may bar you from doing further business with the Federal 
Government according to Executive Orders 12549 and 12689, and section 
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 
6101. The Department of the Interior's regulations implementing these 
authorities are found at 43 CFR part 12, subpart D.

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions



Sec.  550.1450  What definitions apply to this subpart?

    The terms used in this subpart have the same meaning as in 30 U.S.C. 
1702.

[[Page 432]]

                   Penalties After a Period to Correct



Sec.  550.1451  What may BOEM do if I violate a statute, regulation,
 order, or lease term relating to a Federal oil and gas lease?

    (a) If we believe that you have not followed any requirement of a 
statute, regulation, order, or lease term for any Federal oil or gas 
lease, we may send you a Notice of Noncompliance informing you what the 
violation is and what you need to do to correct it to avoid civil 
penalties under 30 U.S.C. 1719(a) and (b).
    (b) We will serve the Notice of Noncompliance by registered mail or 
personal service using the most current address on file as maintained by 
the BOEM Leasing Office in your respective Region.



Sec.  550.1452  What if I correct the violation?

    The matter will be closed if you correct all of the violations 
identified in the Notice of Noncompliance within 20 days after you 
receive the Notice (or within a longer time period specified in the 
Notice).



Sec.  550.1453  What if I do not correct the violation?

    (a) We may send you a Notice of Civil Penalty if you do not correct 
all of the violations identified in the Notice of Noncompliance within 
20 days after you receive the Notice of Noncompliance (or within a 
longer time period specified in that Notice). The Notice of Civil 
Penalty will tell you how much penalty you must pay. The penalty may be 
up to $500 per day, beginning with the date of the Notice of 
Noncompliance, for each violation identified in the Notice of 
Noncompliance for as long as you do not correct the violations.
    (b) If you do not correct all of the violations identified in the 
Notice of Noncompliance within 40 days after you receive the Notice of 
Noncompliance (or 20 days following the expiration of a longer time 
period specified in that Notice), we may increase the penalty to up to 
$5,000 per day, beginning with the date of the Notice of Noncompliance, 
for each violation for as long as you do not correct the violations.



Sec.  550.1454  How may I request a hearing on the record on a Notice
 of Noncompliance?

    You may request a hearing on the record on a Notice of Noncompliance 
by filing a request within 30 days of the date you received the Notice 
of Noncompliance with the Hearings Division (Departmental), Office of 
Hearings and Appeals, U.S. Department of the Interior, 351 South West 
Temple, Suite 6.300, Salt Lake City, Utah 84101. You may do this 
regardless of whether you correct the violations identified in the 
Notice of Noncompliance.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]



Sec.  550.1455  Does my request for a hearing on the record affect
 the penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance, the penalties will continue to accrue even if you request 
a hearing on the record.
    (b) You may petition the Hearings Division (Departmental) of the 
Office of Hearings and Appeals, to stay the accrual of penalties pending 
the hearing on the record and a decision by the Administrative Law Judge 
under Sec.  550.1472.
    (1) You must file your petition within 45 calendar days of receiving 
the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  550.1490 through 
550.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

[[Page 433]]



Sec.  550.1456  May I request a hearing on the record regarding the
 amount of a civil penalty if I did not request a hearing on the
 Notice of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty, if 
you did not previously request a hearing on the record under Sec.  
550.1454. If you did not request a hearing on the record on the Notice 
of Noncompliance under Sec.  550.1454, you may not contest your 
underlying liability for civil penalties.
    (b) You must file your request within 10 days after you receive the 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 351 
South West Temple, Suite 6.300, Salt Lake City, Utah 84101.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

                  Penalties Without a Period to Correct



Sec.  550.1460  May I be subject to penalties without prior notice and
 an opportunity to correct?

    The Federal Oil and Gas Royalty Management Act sets out several 
specific violations for which penalties accrue without an opportunity to 
first correct the violation.
    (a) [Reserved]
    (b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties 
of up to $25,000 per day for each day each violation continues if you:
    (1) Knowingly or willfully prepare, maintain, or submit false, 
inaccurate, or misleading reports, notices, affidavits, records, data, 
or other written information;
    (2)-(3) [Reserved]



Sec.  550.1461  How will BOEM inform me of violations without a period
 to correct?

    We will inform you of any violation, without a period to correct, by 
issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using your address of record as specified under 30 CFR 
part 1218, subpart H.



Sec.  550.1462  How may I request a hearing on the record on a Notice
 of Noncompliance regarding violations without a period to correct?

    You may request a hearing on the record of a Notice of Noncompliance 
regarding violations without a period to correct by filing a request 
within 30 days after you receive the Notice of Noncompliance with the 
Hearings Division (Departmental), Office of Hearings and Appeals, U.S. 
Department of the Interior, 351 South West Temple, Suite 6.300, Salt 
Lake City, Utah 84101. You may do this regardless of whether you correct 
the violations identified in the Notice of Noncompliance.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]



Sec.  550.1463  Does my request for a hearing on the record affect
 the penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance regarding violations without a period to correct, the 
penalties will continue to accrue even if you request a hearing on the 
record.
    (b) You may ask the Hearings Division (Departmental) to stay the 
accrual of penalties pending the hearing on the record and a decision by 
the Administrative Law Judge under Sec.  550.1472.
    (1) You must file your petition within 45 calendar days after you 
receive the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  550.1490 through 
550.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

[[Page 434]]



Sec.  550.1464  May I request a hearing on the record regarding the
 amount of a civil penalty if I did not request a hearing on the
 Notice of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty 
regarding violations without a period to correct, if you did not 
previously request a hearing on the record under Sec.  550.1462. If you 
did not request a hearing on the record on the Notice of Noncompliance 
under Sec.  550.1462, you may not contest your underlying liability for 
civil penalties.
    (b) You must file your request within 10 days after you receive 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 351 
South West Temple, Suite 6.300, Salt Lake City, Utah 84101.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

                           General Provisions



Sec.  550.1470  How does BOEM decide what the amount of the penalty
 should be?

    We determine the amount of the penalty by considering the severity 
of the violations, your history of compliance, and if you are a small 
business.



Sec.  550.1471  Does the penalty affect whether I owe interest?

    If you do not pay the penalty by the date required under Sec.  
550.1475(d), BOEM will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.



Sec.  550.1472  How will the Office of Hearings and Appeals conduct
 the hearing on the record?

    If you request a hearing on the record under Sec.  550.1454, Sec.  
550.1456, Sec.  550.1462, or Sec.  550.1464, the hearing will be 
conducted by a Departmental Administrative Law Judge from the Office of 
Hearings and Appeals. After the hearing, the Administrative Law Judge 
will issue a decision in accordance with the evidence presented and 
applicable law.



Sec.  550.1473  How may I appeal the Administrative Law Judge's
 decision?

    If you are adversely affected by the Administrative Law Judge's 
decision, you may appeal that decision to the Interior Board of Land 
Appeals under 43 CFR part 4, subpart E.



Sec.  550.1474  May I seek judicial review of the decision of the
 Interior Board of Land Appeals?

    Under 30 U.S.C. 1719(j), you may seek judicial review of the 
decision of the Interior Board of Land Appeals. A suit for judicial 
review in the District Court will be barred unless filed within 90 days 
after the final order.



Sec.  550.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec.  550.1453 or Sec.  550.1461, if you do not request a hearing 
on the record under Sec.  550.1454, Sec.  550.1456, Sec.  550.1462, or 
Sec.  550.1464
    (b) If you request a hearing on the record under Sec.  550.1454, 
Sec.  550.1456, Sec.  550.1462, or Sec.  550.1464, but you do not appeal 
the determination of the Administrative Law Judge to the Interior Board 
of Land Appeals under Sec.  550.1473, you must pay the amount assessed 
by the Administrative Law Judge.
    (c) If you appeal the determination of the Administrative Law Judge 
to the Interior Board of Land Appeals, you must pay the amount assessed 
in the IBLA decision.
    (d) You must pay the penalty assessed within 40 days after:
    (1) You received the Notice of Civil Penalty, if you did not request 
a hearing on the record under either Sec.  550.1454, Sec.  550.1456, 
Sec.  550.1462, or Sec.  550.1464;
    (2) You received an Administrative Law Judge's decision under Sec.  
550.1472, if you obtained a stay of the accrual of penalties pending the 
hearing on the record under Sec.  550.1455(b) or Sec.  550.1463(b) and 
did not appeal the Administrative Law Judge's determination to the IBLA 
under Sec.  550.1473;
    (3) You received an IBLA decision under Sec.  550.1473 if the IBLA 
continued the stay of accrual of penalties pending its decision and you 
did not seek judicial review of the IBLA's decision; or

[[Page 435]]

    (4) A final non-appealable judgment of a court of competent 
jurisdiction is entered, if you sought judicial review of the IBLA's 
decision and the Department or the appropriate court suspended 
compliance with the IBLA's decision pending the adjudication of the 
case.
    (e) If you do not pay, that amount is subject to collection under 
the provisions of Sec.  550.1477.



Sec.  550.1476  Can BOEM reduce my penalty once it is assessed?

    Under 30 U.S.C. 1719(g), the Director or his or her delegate may 
compromise or reduce civil penalties assessed under this part.



Sec.  550.1477  How may BOEM collect the penalty?

    (a) BOEM may use all available means to collect the penalty 
including, but not limited to:
    (1) Requiring the lease surety, for amounts owed by lessees, to pay 
the penalty;
    (2) Deducting the amount of the penalty from any sums the United 
States owes to you; and
    (3) Using judicial process to compel your payment under 30 U.S.C. 
1719(k).
    (b) If the Department uses judicial process, or if you seek judicial 
review under Sec.  550.1474 and the court upholds assessment of a 
penalty, the court shall have jurisdiction to award the amount assessed 
plus interest assessed from the date of the expiration of the 90-day 
period referred to in Sec.  550.1474. The amount of any penalty, as 
finally determined, may be deducted from any sum owing to you by the 
United States.

                           Criminal Penalties



Sec.  550.1480  May the United States criminally prosecute me for
 violations under Federal oil and gas leases?

    If you commit an act for which a civil penalty is provided at 30 
U.S.C. 1719(d) and Sec.  550.1460(b), the United States may pursue 
criminal penalties as provided at 30 U.S.C. 1720, in addition to any 
authority for prosecution under other statutes.

                          Bonding Requirements



Sec.  550.1490  What standards must my BOEM-specified surety
 instrument meet?

    (a) A BOEM-specified surety instrument must be in a form specified 
in BOEM instructions. BOEM will give you written information and 
standard forms for BOEM-specified surety instrument requirements.
    (b) BOEM will use a bank-rating service to determine whether a 
financial institution has an acceptable rating to provide a surety 
instrument adequate to indemnify the lessor from loss or damage.
    (1) Administrative appeal bonds must be issued by a qualified surety 
company which the Department of the Treasury has approved.
    (2) Irrevocable letters of credit or certificates of deposit must be 
from a financial institution acceptable to BOEM with a minimum 1-year 
period of coverage subject to automatic renewal up to 5 years.



Sec.  550.1491  How will BOEM determine the amount of my bond or
 other surety instrument?

    (a) BOEM bond-approving officer may approve your surety if he or she 
determines that the amount is adequate to guarantee payment. The amount 
of your surety may vary depending on the form of the surety and how long 
the surety is effective.
    (1) The amount of the BOEM-specified surety instrument must include 
the principal amount owed under the Notice of Noncompliance or Notice of 
Civil Penalty plus any accrued interest we determine is owed plus 
projected interest for a 1-year period.
    (2) Treasury book-entry bond or note amounts must be equal to at 
least 120 percent of the required surety amount.
    (b) If your appeal is not decided within 1 year from the filing 
date, you must increase the surety amount to cover additional estimated 
interest for another 1-year period. You must continue to do this 
annually on the date your appeal was filed. We will determine the 
additional estimated interest and notify you of the amount so you can 
amend your surety instrument.

[[Page 436]]

    (c) You may submit a single surety instrument that covers multiple 
appeals. You may change the instrument to add new amounts under appeal 
or remove amounts that have been adjudicated in your favor or that you 
have paid, if you:
    (1) Amend the single surety instrument annually on the date you 
filed your first appeal; and
    (2) Submit a separate surety instrument for new amounts under appeal 
until you amend the instrument to cover the new appeals.

                     Financial Solvency Requirements



Sec.  550.1495  How do I demonstrate financial solvency?

    (a) To demonstrate financial solvency under this part, you must 
submit an audited consolidated balance sheet, and, if requested by the 
BOEM bond-approving officer, up to 3 years of tax returns to BOEM using 
the U.S. Postal Service, private delivery, courier, or overnight 
delivery at:
    (1) For Alaska OCS: BOEM Alaska OCS Region, 3801 Centerpoint Drive, 
Suite 500, Anchorage, AK 99503, (907) 334-5200.
    (2) For Gulf of Mexico and Atlantic OCS: BOEM Gulf of Mexico OCS 
Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123-2394, (800) 
200-4853.
    (3) For Pacific OCS: BOEM Pacific OCS Region, 760 Paseo Camarillo, 
Suite 102 (CM 102), Camarillo, CA 93010, (805) 384-6305.
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date BOEM first 
determined that you demonstrated financial solvency as long as you have 
active appeals, or whenever BOEM requests.
    (c) If you demonstrate financial solvency in the current calendar 
year, you are not required to redemonstrate financial solvency for new 
appeals of orders during that calendar year unless you file for 
protection under any provision of the U.S. Bankruptcy Code (Title 11 of 
the United States Code), or BOEM notifies you that you must 
redemonstrate financial solvency.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]



Sec.  550.1496  How will BOEM determine if I am financially solvent?

    (a) BOEM bond-approving officer will determine your financial 
solvency by examining your total net worth, including, as appropriate, 
the net worth of your affiliated entities.
    (b) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  550.1490 and 550.1491 for all orders you have appealed 
is greater than $300 million, you are presumptively deemed financially 
solvent, and we will not require you to post a bond or other surety 
instrument.
    (c) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  550.1490 and 550.1491 for all orders you have appealed 
is less than $300 million, you must submit the following to BOEM by one 
of the methods in Sec.  550.1495(a):
    (1) A written request asking us to consult a business-information, 
or credit-reporting service or program to determine your financial 
solvency; and
    (2) A nonrefundable $50 processing fee:
    (i) You must pay the processing fee to us following the requirements 
for making payments found in 30 CFR 550.126. You are required to use 
Electronic Funds Transfer (EFT) for these payments;
    (ii) You must submit the fee with your request under paragraph 
(c)(1) of this section, and then annually on the date we first 
determined that you demonstrated financial solvency, as long as you are 
not able to demonstrate financial solvency under paragraph (a) of this 
section and you have active appeals.
    (d) If you request that we consult a business-information or credit-
reporting service or program under paragraph (c) of this section:
    (1) We will use criteria similar to that which a potential creditor 
would use to lend an amount equal to the bond or other surety instrument 
we would require under Sec. Sec.  550.1490 and 550.1491;
    (2) For us to consider you financially solvent, the business-
information or credit-reporting service or program must demonstrate your 
degree of risk as low to moderate:

[[Page 437]]

    (i) If our bond-approving officer determines that the business-
information or credit-reporting service or program information 
demonstrates your financial solvency to our satisfaction, our bond-
approving officer will not require you to post a bond or other surety 
instrument under Sec. Sec.  550.1490 and 550.1491;
    (ii) If our bond-approving officer determines that the business-
information or credit-reporting service or program information does not 
demonstrate your financial solvency to our satisfaction, our bond-
approving officer will require you to post a bond or other surety 
instrument under Sec. Sec.  550.1490 and 550.1491 or pay the obligation.



Sec.  550.1497  When will BOEM monitor my financial solvency?

    (a) If you are presumptively financially solvent under Sec.  
550.1496(b), BOEM will determine your net worth as described under 
Sec. Sec.  550.1496(b) and (c) to evaluate your financial solvency at 
least annually on the date we first determined that you demonstrated 
financial solvency as long as you have active appeals and each time you 
appeal a new order.
    (b) If you ask us to consult a business-information or credit-
reporting service or program under Sec.  550.1496(c), we will consult a 
service or program annually as long as you have active appeals and each 
time you appeal a new order.
    (c) If our bond-approving officer determines that you are no longer 
financially solvent, you must post a bond or other BOEM-specified surety 
instrument under Sec. Sec.  550.1490 and 550.1491.

Subparts O-S [Reserved]



PART 551_GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER
 CONTINENTAL SHELF--Table of Contents



Sec.
551.1 Definitions.
551.2 Purpose of this part.
551.3 Authority and applicability of this part.
551.4 Types of G&G activities that require permits or Notices.
551.5 Applying for permits or filing Notices.
551.6 Obligations and rights under a permit or a Notice.
551.7 Test drilling activities under a permit.
551.8 Inspection and reporting requirements for activities under a 
          permit.
551.9 Temporarily stopping, canceling, or relinquishing activities 
          approved under a permit.
551.10 Penalties and appeals.
551.11 Submission, inspection, and selection of geological data and 
          information collected under a permit and processed by 
          permittees or third parties.
551.12 Submission, inspection, and selection of geophysical data and 
          information collected under a permit and processed by 
          permittees or third parties.
551.13 Reimbursement for the costs of reproducing data and information 
          and certain processing costs.
551.14 Protecting and disclosing data and information submitted to BOEM 
          under a permit.
551.15 Authority for information collection.

    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



Sec.  551.1  Definitions.

    Terms used in this part have the following meaning:
    Act means the Outer Continental Shelf Lands Act (OCSLA), as amended 
(43 U.S.C. 1331 et seq.).
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurements, 
controlled collection, analysis, interpretation, and explanation.

[[Page 438]]

    Archaeological resources mean any material remains of human life or 
activities that are at least 50 years of age and of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal Zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder), strongly influenced by each other and in 
proximity to the shorelines of the several coastal States and extends 
seaward to the outer limit of the U.S. territorial sea.
    Coastal Zone Management Act means the Coastal Zone Management Act of 
1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts, statistics, measurements, or samples that have not 
been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the penetration 
into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Ocean Energy 
Management, U.S. Department of the Interior, or a subordinate authorized 
to act on the Director's behalf.
    Exploration means the commercial search for oil, gas, and sulphur. 
Activities classified as exploration include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, 
coring, or other systems are used to detect or imply the presence of 
oil, gas, or sulphur; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical scientific research means any oil, gas, 
or sulphur related investigation conducted in the OCS for scientific 
and/or research purposes. Geological, geophysical, and geochemical data 
and information gathered and analyzed are made available to the public 
for inspection and reproduction at the earliest practicable time. The 
term does not include commercial geological or geophysical exploration 
or research.
    Geological exploration means exploration that uses geological and 
geochemical techniques (e.g., coring and test drilling, well logging, 
and bottom sampling) to produce data and information on oil, gas, and 
sulphur resources in support of possible exploration and development 
activities. The term does not include geological scientific research.
    Geological information means geological or geochemical data that 
have been analyzed, processed, or interpreted.
    Geophysical data means measurements that have not been processed or 
interpreted.
    Geophysical exploration means exploration that utilizes geophysical 
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to 
produce data and information on oil, gas, and sulphur resources in 
support of possible exploration and development activities. The term 
does not include geophysical scientific research.
    Geophysical information means geophysical data that have been 
processed or interpreted.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a Governor 
pursuant to the Act.
    Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Hydrocarbon occurrence means the direct or indirect detection during 
drilling operations of any liquid or gaseous hydrocarbons by examination 
of well cuttings, cores, gas detector readings, formation fluid tests, 
wireline logs, or by any other means. The term does not include 
background gas, minor accumulations of gas, or heavy oil residues on 
cuttings and cores.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological

[[Page 439]]

significance of geological data and analyzed and processed geologic 
information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and maps, 
developed by determining the geological significance of geophysical data 
and processed geophysical information.
    Lease means an agreement which is issued under section 8 or 
maintained under section 6 of the Act and which authorizes exploration 
for, and development and production of, minerals or the area covered by 
that authorization, whichever is required by the context.
    Lessee means a person who has entered into, or is the BOEM approved 
assignee of, a lease with the United States to explore for, develop, and 
produce the leased minerals. The term ``lessee'' also includes an owner 
of operating rights.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
quality of the marine ecosystem in the coastal zone and in the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals mean oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from public lands as defined in section 
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 
1702).
    Notice means a written statement of intent to conduct geological or 
geophysical scientific research related to oil, gas, and sulphur in the 
OCS other than under a permit.
    Oil, gas, and sulphur means oil, gas, sulphur, geopressured-
geothermal, and associated resources.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
pursuant to this part, under which a person acquires the right to 
conduct on the OCS, in accordance with appropriate statutes, 
regulations, and stipulations:
    (1) Geological exploration for mineral resources;
    (2) Geophysical exploration for mineral resources;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued pursuant to 
this part to conduct activities on the OCS.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residence in the United States as 
defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; and associations of such citizens, 
nationals, resident aliens, or private, public, or municipal 
corporations, States, or political subdivisions of States or anyone 
operating in a manner provided for by treaty or other applicable 
international agreements. The term does not include Federal agencies.
    Processed geological or geophysical information means data collected 
under a permit and later processed or reprocessed. Processing involves 
changing the form of data so as to facilitate interpretation. Processing 
operations may include, but are not limited to, applying corrections for 
known perturbing causes, rearranging or filtering data, and combining or 
transforming data elements. Reprocessing is the additional processing 
other than ordinary processing used in the general course of evaluation. 
Reprocessing operations may include varying identified parameters for 
the detailed study of a specific problem area. Reprocessing may occur 
several years after the original processing date. Reprocessing is 
determined to be completed on the date that the reprocessed information 
is first available in a useable format for in-house interpretation by 
BOEM or the permittee, or becomes first available to

[[Page 440]]

third parties via sale, trade, license agreement, or other means.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4.
    Third Party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    Violation means a failure to comply with any provision of the Act, 
or a provision of a regulation or order issued under the Act, or any 
provision of a lease, license, or permit issued under the Act.
    You means a person who applies for and/or obtains a permit, or files 
a Notice to conduct geological or geophysical exploration or scientific 
research related to oil, gas, and sulphur in the OCS.



Sec.  551.2  Purpose of this part.

    (a) To allow you to conduct G&G activities in the OCS related to 
oil, gas, and sulphur on unleased lands or on lands under lease to a 
third party.
    (b) To ensure that you carry out G&G activities in a safe and 
environmentally sound manner so as to prevent harm or damage to, or 
waste of, any natural resources (including any mineral deposit in areas 
leased or not leased), any life (including fish and other aquatic life), 
property, or the marine, coastal, or human environment.
    (c) To inform you and third parties of your legal and contractual 
obligations.
    (d) To inform you and third parties of the U.S. Government's rights 
to access G&G data and information collected under permit in the OCS, 
reimbursement for submittal of data and information, and the proprietary 
terms of data and information submitted to, and retained by, BOEM.



Sec.  551.3  Authority and applicability of this part.

    BOEM authorizes you to conduct exploration or scientific research 
activities under this part in accordance with the Act, the regulations 
in this part, orders of the Director/Regional Director, and other 
applicable statutes, regulations, and amendments.
    (a) This part does not apply to G&G exploration conducted by or on 
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if 
you plan to conduct G&G activities related to oil, gas, or sulphur under 
terms of a lease.
    (b) Federal agencies are exempt from the regulations in this part.
    (c) G&G exploration or G&G scientific research related to minerals 
other than oil, gas, and sulphur is covered by regulations at 30 CFR 
part 580.



Sec.  551.4  Types of G&G activities that require permits or Notices.

    (a) Exploration. You must have a BOEM-approved permit to conduct G&G 
exploration, including deep stratigraphic tests, for oil, gas, or 
sulphur resources. If you conduct both geological and geophysical 
exploration, you must have a separate permit for each.
    (b) Scientific research. You may only conduct G&G scientific 
research related to oil, gas, and sulphur in the OCS after you obtain a 
BOEM-approved permit or file a Notice.
    (1) Permit. You must obtain a permit if the research activities you 
propose to conduct involve:
    (i) Using solid or liquid explosives;
    (ii) Drilling a deep stratigraphic test; or
    (iii) Developing data and information for proprietary use or sale.
    (2) Notice. Any other G&G scientific research that you conduct 
related to oil, gas, and sulphur in the OCS requires you to file a 
Notice with the Regional Director at least 30 days before you begin. If 
circumstances preclude a 30-day Notice, you must provide oral 
notification and followup in writing. You must also inform BOEM in 
writing when you conclude your work.

[[Page 441]]



Sec.  551.5  Applying for permits or filing Notices.

    (a) Permits. You must submit a signed original and three copies of 
the BOEM permit application form (Form BOEM-0327). The form includes 
names of persons; the type, location, purpose, and dates of activity; 
and environmental and other information. A nonrefundable service fee of 
$2,012 must be paid electronically through Pay.gov at: https://
www.pay.gov/paygov/, and you must include a copy of the Pay.gov 
confirmation receipt page with your application.
    (b) Disapproval of permit application. If BOEM disapproves your 
application for a permit, the Regional Director will state the reasons 
for the denial and will advise you of the changes needed to obtain 
approval.
    (c) Notices. You must sign and date a Notice and state:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;
    (2) The name(s) of any other person(s) participating in the proposed 
research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) The location in the OCS, indicated on a map, plat, or chart, 
where you will conduct research;
    (5) The proposed dates you project for your research activity to 
start and end;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practicable time you expect to make the data and 
information resulting from your research activity available to the 
public;
    (8) Your plan of how you will make the data and information you 
collected available to the public;
    (9) That you and others involved will not sell or withhold for 
exclusive use the data and information resulting from your research; and
    (10) At your option, you may submit (as a substitute for the 
material required in paragraphs (c)(7), (c)(8), and (c)(9) of this 
section) the nonexclusive use agreement for scientific research 
attachment to Form BOEM-0327.
    (d) Filing locations. You must apply for a permit or file a Notice 
at one of the following locations:
    (1) For the OCS off the State of Alaska--the Regional Supervisor for 
Resource Evaluation, Bureau of Ocean Energy Management, Alaska OCS 
Region, 3801 Centerpoint Drive, Suite 500, Anchorage, Alaska 99503.
    (2) For the OCS off the Atlantic Coast and in the Gulf of Mexico--
the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy 
Management, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New 
Orleans, Louisiana 70123-2394.
    (3) For the OCS off the coast of the States of California, Oregon, 
Washington, or Hawaii--the Regional Supervisor for Resource Evaluation, 
Bureau of Ocean Energy Management, Pacific OCS Region, 760 Paseo 
Camarillo, Suite 102 (CM 102), Camarillo, California 93010.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]



Sec.  551.6  Obligations and rights under a permit or a Notice.

    While conducting G&G exploration or scientific research activities 
under BOEM permit or Notice:
    (a) You must not:
    (1) Interfere with or endanger operations under any lease, right-of-
way, easement, right-of-use, Notice, or permit issued or maintained 
under the Act;
    (2) Cause harm or damage to life (including fish and other aquatic 
life), property, or to the marine, coastal, or human environment;
    (3) Cause harm or damage to any mineral resource (in areas leased or 
not leased);
    (4) Cause pollution;
    (5) Disturb archaeological resources;
    (6) Create hazardous or unsafe conditions; or
    (7) Unreasonably interfere with or cause harm to other uses of the 
area.
    (b) You must immediately report to the Regional Director if you:
    (1) Detect hydrocarbon occurrences;
    (2) Detect environmental hazards which imminently threaten life and 
property; or
    (3) Adversely affect the environment, aquatic life, archaeological 
resources, or other uses of the area where you are conducting 
exploration or scientific research activities.

[[Page 442]]

    (c) You must also consult and coordinate your G&G activities with 
other users of the area for navigation and safety purposes.
    (d) Any persons conducting shallow test drilling or deep 
stratigraphic test drilling activities under a permit must use the best 
available and safest technologies that the Regional Director determines 
to be economically feasible.
    (e) You may not claim any oil, gas, sulphur, or other minerals you 
discover while conducting operations under a permit or Notice.



Sec.  551.7  Test drilling activities under a permit.

    (a) Shallow test drilling. Before you begin shallow test drilling 
under a permit, the Regional Director may require you to:
    (1) Gather and submit seismic, bathymetric, sidescan sonar, 
magnetometer, or other geophysical data and information to determine 
shallow structural detail across and in the vicinity of the proposed 
test.
    (2) Submit information for coastal zone consistency certification 
according to paragraphs (b)(3) and (4) of this section, and for 
protecting archaeological resources according to paragraph (b)(5) of 
this section.
    (3) Allow all interested parties the opportunity to participate in 
the shallow test according to paragraph (c) of this section, and meet 
bonding requirements according to paragraph (d) of this section.
    (b) Deep stratigraphic tests. You must submit to the appropriate 
BOEM or BSEE Regional Director, at the address in Sec.  551.7(d), a 
drilling plan (submitted to BOEM), an environmental report (submitted to 
BOEM), an Application for Permit to Drill (Form BSEE-0123) (submitted to 
BSEE), and a Supplemental APD Information Sheet (Form BSEE-0123S) 
(submitted to BSEE) as follows:
    (1) Drilling plan. The drilling plan must include:
    (i) The proposed type, sequence, and timetable of drilling 
activities;
    (ii) A description of your drilling rig, indicating the important 
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
    (iii) The location of each deep stratigraphic test you will conduct, 
including the location of the surface and projected bottomhole of the 
borehole;
    (iv) The types of geological and geophysical survey instruments you 
will use before and during drilling;
    (v) Seismic, bathymetric, sidescan sonar, magnetometer, or other 
geophysical data and information sufficient to evaluate seafloor 
characteristics, shallow geologic hazards, and structural detail across 
and in the vicinity of the proposed test to the total depth of the 
proposed test well; and
    (vi) Other relevant data and information that the BOEM Regional 
Director requires.
    (2) Environmental report. The environmental report must include all 
of the following material:
    (i) A summary with data and information available at the time you 
submitted the related drilling plan. BOEM will consider site-specific 
data and information developed since the most recent environmental 
impact statement or other environmental impact analysis in the immediate 
area. The summary must meet the following requirements:
    (A) You must concentrate on the issues specific to the site(s) of 
drilling activity. However, you only need to summarize data and 
information discussed in any environmental reports, analyses, or impact 
statements prepared for the geographic area of the drilling activity.
    (B) You must list referenced material. Include brief descriptions 
and a statement of where the material is available for inspection.
    (C) You must refer only to data that are available to BOEM.
    (ii) Details about your project such as:
    (A) A list and description of new or unusual technologies;
    (B) The location of travel routes for supplies and personnel;
    (C) The kinds and approximate levels of energy sources;
    (D) The environmental monitoring systems; and

[[Page 443]]

    (E) Suitable maps and diagrams showing details of the proposed 
project layout.
    (iii) A description of the existing environment. For this section, 
you must include the following information on the area:
    (A) Geology;
    (B) Physical oceanography;
    (C) Other uses of the area;
    (D) Flora and fauna;
    (E) Existing environmental monitoring systems; and
    (F) Other unusual or unique characteristics that may affect or be 
affected by the drilling activities.
    (iv) A description of the probable impacts of the proposed action on 
the environment and the measures you propose for mitigating these 
impacts.
    (v) A description of any unavoidable or irreversible adverse effects 
on the environment that could occur.
    (vi) Other relevant data that the BOEM Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the BOEM Regional Director for 
transmittal to the Governor of each affected coastal State and the 
coastal zone management agency of each affected coastal State that has 
an approved program under the Coastal Zone Management Act. (BOEM 
Regional Director will make the drilling plan and environmental report 
available to appropriate Federal agencies and the public according to 
the Department of the Interior's policies and procedures).
    (4) Certification of coastal zone management program consistency and 
State concurrence. When required under an approved coastal zone 
management program of an affected State, your drilling plan must include 
a certification that the proposed activities described in the plan 
comply with enforceable policies of, and will be conducted in a manner 
consistent with such State's program. BOEM Regional Director may not 
approve any of the activities described in the drilling plan unless the 
State concurs with the consistency certification or the Secretary of 
Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of 
the Coastal Zone Management Act.
    (5) Protecting archaeological resources. If the Regional Director 
believes that an archaeological resource may exist in the area that may 
be affected by drilling, the Regional Director will notify you of the 
need to prepare an archaeological report.
    (i) If the evidence suggests that an archaeological resource may be 
present, you must:
    (A) Locate the site of the drilling so as to not adversely affect 
the area where the archaeological resources may be, or
    (B) Establish to the satisfaction of the BOEM Regional Director that 
an archaeological resource does not exist or will not be adversely 
affected by drilling. This must be done by further archaeological 
investigation, conducted by an archaeologist and a geophysicist, using 
survey equipment and techniques deemed necessary by the Regional 
Director. A report on the investigation must be submitted to the BOEM 
Regional Director for review.
    (ii) If the BOEM Regional Director determines that an archaeological 
resource is likely to be present in the area that may be affected by 
drilling, and may be adversely affected by drilling, the BOEM Regional 
Director will notify you immediately. You must take no action that may 
adversely affect the archaeological resource unless an investigation by 
BOEM determines that the resource is not archaeologically significant.
    (iii) If you discover any archaeological resource while drilling, 
you must immediately halt drilling and report the discovery to the BOEM 
Regional Director. If investigations determine that the resource is 
significant, the BOEM Regional Director will inform you how to protect 
it.
    (6) [Reserved]
    (7) Revising an approved drilling plan. Before you revise an 
approved drilling plan, you must obtain the BOEM Regional Director's 
approval.
    (8) [Reserved]
    (9) Deadline for completing a deep stratigraphic test. If your deep 
stratigraphic test well is within 50 geographic miles of a tract that 
BOEM has identified for a future lease sale, as listed on the currently 
approved OCS leasing schedule,

[[Page 444]]

you must complete all drilling activities and submit the data and 
information to the BOEM Regional Director at least 60 days before the 
first day of the month in which BOEM schedules the lease sale. However, 
the BOEM Regional Director may extend your permit duration to allow you 
to complete drilling activities and submit data and information if the 
extension is in the National interest.
    (c) Group participation in test drilling. BOEM encourages group 
participation for deep stratigraphic tests.
    (1) Purpose of group participation. The purpose is to minimize 
duplicative G&G activities involving drilling into the seabed of the 
OCS.
    (2) Providing opportunity for participation in a deep stratigraphic 
test. When you propose to drill a deep stratigraphic test, you must give 
all interested persons an opportunity to participate in the test 
drilling through a signed agreement on a cost-sharing basis. You may 
include a penalty for late participation of not more than 100 percent of 
the cost to each original participant in addition to the original share 
cost.
    (i) The participants must assess and distribute late participation 
penalties in accordance with the terms of the agreement.
    (ii) For a significant hydrocarbon occurrence that the Regional 
Director announces to the public, the penalty for subsequent late 
participants may be raised to not more than 300 percent of the cost of 
each original participant in addition to the original share cost.
    (3) Providing opportunity for participation in a shallow test 
drilling project. When you apply to conduct shallow test drilling 
activities, you must, if ordered by the Regional Director or required by 
the permit, give all interested persons an opportunity to participate in 
the test activity on a cost-sharing basis. You may include a penalty 
provision for late participation of not more than 50 percent of the cost 
to each original participant in addition to the original share cost.
    (4) Procedures for group participation in drilling activities. You 
must:
    (i) Publish a summary statement that describes the approved activity 
in a relevant trade publication;
    (ii) Forward a copy of the published statement to the Regional 
Director;
    (iii) Allow at least 30 days from the summary statement publication 
date for other persons to join as original participants;
    (iv) Compute the estimated cost by dividing the estimated total cost 
of the program by the number of original participants; and
    (v) Furnish the Regional Director with a complete list of all 
participants before starting operations, or at the end of the 
advertising period if you begin operations before the advertising period 
is over. The names of any subsequent or late participants must also be 
furnished to the Regional Director.
    (5) Changes to the original application for test drilling. If you 
propose changes to the original application and the Regional Director 
determines that the changes are significant, the Regional Director will 
require you to publish the changes for an additional 30 days to give 
other persons a chance to join as original participants.
    (d) Bonding requirements. You must submit a bond under this part 
before you may start a deep stratigraphic test.
    (1) Before BOEM issues a permit authorizing the drilling of a deep 
stratigraphic test, you must either:
    (i) Furnish to BOEM a bond of not less than $200,000 that guarantees 
compliance with all the terms and conditions of the permit; or
    (ii) Maintain a $1 million bond that guarantees compliance with all 
the terms and conditions of the permit you hold for the OCS area where 
you propose to drill.
    (2) You must provide additional security to BOEM if the Regional 
Director determines that it is necessary for the permit or area.
    (3) The Regional Director may require you to provide a bond, in an 
amount the Regional Director prescribes, before authorizing you to drill 
a shallow test well.
    (4) Your bond must be on a form approved by the Deputy Director.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]

[[Page 445]]



Sec.  551.8  Inspection and reporting requirements for activities
 under a permit.

    (a) Inspection of permit activities. You must allow BOEM 
representatives to inspect your exploration or scientific research 
activities under a permit. They will determine whether operations are 
adversely affecting the environment, aquatic life, archaeological 
resources, or other uses of the area. BOEM will reimburse you for food, 
quarters, and transportation that you provide for BOEM representatives 
if you send in your reimbursement request to the Region that issued the 
permit within 90 days of the inspection.
    (b) Approval for modifications. Before you begin modified 
operations, you must submit a written request describing the 
modifications and receive the Regional Director's oral or written 
approval. If circumstances preclude a written request, you must make an 
oral request and follow up in writing.
    (c) Reports. (1) You must submit status reports on a schedule 
specified in the permit and include a daily log of operations.
    (2) You must submit a final report of exploration or scientific 
research activities under a permit within 30 days after the completion 
of acquisition activities under the permit. You may combine the final 
report with the last status report and must include each of the 
following:
    (i) A description of the work performed.
    (ii) Charts, maps, plats, and digital navigational data in a format 
specified by the Regional Director, showing the areas and blocks in 
which any exploration or permitted scientific research activities were 
conducted. Identify the lines of geophysical traverses and their 
locations including a reference sufficient to identify the data produced 
during each activity.
    (iii) The dates on which you conducted the actual exploration or 
scientific research activities.
    (iv) A summary of any:
    (A) Hydrocarbon or sulphur occurrences encountered;
    (B) Environmental hazards; and
    (C) Adverse effects of the exploration or scientific research 
activities on the environment, aquatic life, archaeological resources, 
or other uses of the area in which the activities were conducted.
    (v) Other descriptions of the activities conducted as specified by 
the Regional Director.



Sec.  551.9  Temporarily stopping, canceling, or relinquishing 
activities approved under a permit.

    (a) BOEM may temporarily stop exploration or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, any mineral deposit (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order, 
or provision of the permit. This would include BOEM's required 
submission of reports, well records or logs, and G&G data and 
information within the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.
    (b) Procedures to temporarily stop activities. (1) The Regional 
Director will advise you either orally or in writing. BOEM will confirm 
an oral notification in writing and deliver all written notifications by 
courier or certified or registered mail. You must halt all activities 
under a permit as soon as you receive an oral or written notification.
    (2) The Regional Director will advise you when you may start your 
permit activities again.
    (c) Procedure to cancel or relinquish a permit. The Regional 
Director may cancel, or a permittee may relinquish, a permit at any 
time.
    (1) If BOEM cancels your permit, the Regional Director will advise 
you by certified or registered mail 30 days before the cancellation date 
and will state the reason.
    (2) You may relinquish the permit by advising the Regional Director 
by certified or registered mail 30 days in advance.

[[Page 446]]

    (3) After BOEM cancels your permit or you relinquish it, you are 
still responsible for proper abandonment of any drill sites in 
accordance with the requirements of 30 CFR 251.7(b)(8). You must also 
comply with all other obligations specified in this part or in the 
permit.



Sec.  551.10  Penalties and appeals.

    (a) Penalties for noncompliance under a permit issued by BOEM. You 
are subject to the penalty provisions of:
    (1) Section 24 of the Act (43 U.S.C. 1350); and
    (2) The procedures contained in 30 CFR part 550, subpart N, for 
noncompliance with:
    (i) Any provision of the Act;
    (ii) Any provision of a G&G or drilling permit; or
    (iii) Any regulation or order issued under the Act.
    (b) Penalties under other laws and regulations. The penalties 
prescribed in this section are in addition to any other penalty imposed 
by any other law or regulation.
    (c) Procedures to appeal orders or decisions BOEM issues. See 30 CFR 
part 590 for instructions on how to appeal any order or decision that we 
issue under this part.



Sec.  551.11  Submission, inspection, and selection of geological
 data and information collected under a permit and processed by
 permittees or third parties.

    (a) Availability of geological data and information collected under 
a permit. (1) You must notify the Regional Director, in writing, when 
you complete the initial analysis, processing, or interpretation of any 
geological data and information. Initial analysis and processing are the 
stages of analysis or processing where the data and information first 
become available for in-house interpretation by the permittee, or become 
available commercially to third parties via sale, trade, license 
agreement, or other means.
    (2) The Regional Director may ask if you have further analyzed, 
processed, or interpreted any geological data and information. When so 
asked, you must respond to BOEM in writing within 30 days.
    (b) Submission, inspection, and selection of geological data and 
information. The Regional Director may request the permittee or third 
party to submit the analyzed, processed, and interpreted geologic data 
and information for inspection and/or permanent retention by BOEM. The 
data and information must be submitted within 30 days after such 
request.
    (c) Requirements for submission of geological data and information 
collected under a permit. Unless the Regional Director specifies 
otherwise, geological data and information must include:
    (1) An accurate and complete record of all geological (including 
geochemical) data and information describing each operation of analysis, 
processing, and interpretation;
    (2) Paleontological reports identifying microscopic fossils by 
depth, including the reference datum to which paleontological sample 
depths are related and, if the Regional Director requests, washed 
samples that you maintain for paleontological determinations;
    (3) Copies of well logs or charts in a digital format, if available;
    (4) Results and data obtained from formation fluid tests;
    (5) Analyses of core or bottom samples and/or a representative cut 
or split of the core or bottom sample;
    (6) Detailed descriptions of any hydrocarbons or hazardous 
conditions encountered during operations, including near losses of well 
control, abnormal geopressures, and losses of circulation; and
    (7) Other geological data and information that the Regional Director 
may specify.
    (d) Obligations when geological data and information collected under 
permit are obtained by a third party. A third party may obtain 
geological data and information from a permittee, or from another third 
party, by sale, trade, license agreement, or other means. If this 
happens:
    (1) The third party recipient of the data and information assumes 
the obligations under this section, except for the notification 
provisions of paragraph (a)(1), and is subject to the penalty provisions 
of 30 CFR part 550, subpart N; and

[[Page 447]]

    (2) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and
    (3) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director, in writing and within 30 days, 
of the sale, trade, or other agreement, including the identity of the 
recipient of the data and information; or
    (4) For license agreements a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the Regional Director, advise the Regional Director, in writing, of 
the license agreement, including the identity of the recipient of the 
data and information.



Sec.  551.12  Submission, inspection, and selection of geophysical
 data and information collected under a permit and processed by
 permittees or third parties.

    (a) Availability of geophysical data and information collected under 
a permit. (1) You must notify the Regional Director, in writing, when 
you complete the initial processing and interpretation of any 
geophysical data and information. Initial processing is the stage of 
processing where the data and information become available for in-house 
interpretation by the permittee, or become available commercially to 
third parties via sale, trade, license agreement, or other means.
    (2) The Regional Director may ask if you have further processed or 
interpreted any geophysical data and information. When so asked, you 
must respond to BOEM in writing within 30 days.
    (b) Submission, inspection and selection of geophysical data and 
information collected under a permit. The Regional Director may request 
that the permittee or third party submit geophysical data and 
information before making a final selection for retention. BOEM 
representatives may inspect and select the data and information on your 
premises, or the Regional Director can request delivery of the data and 
information to the appropriate BOEM regional office for review.
    (1) You must submit the geophysical data and information within 30 
days of receiving the request, unless the Regional Director extends the 
delivery time.
    (2) At any time before final selection, the Regional Director may 
return any or all geophysical data and information following review. You 
will be notified in writing of all or portions of those data the 
Regional Director decides to retain.
    (c) Requirements for submission of geophysical data and information 
collected under a permit. Unless the Regional Director specifies 
otherwise, you must include:
    (1) An accurate and complete record of each geophysical survey 
conducted under the permit, including digital navigational data and 
final location maps;
    (2) All seismic data collected under a permit presented in a format 
and of a quality suitable for processing;
    (3) Processed geophysical information derived from seismic data with 
extraneous signals and interference removed, presented in a quality 
format suitable for interpretive evaluation, reflecting state-of-the-art 
processing techniques; and
    (4) Other geophysical data, processed geophysical information, and 
interpreted geophysical information including, but not limited to, 
shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity 
and magnetic surveys, and special studies such as refraction and 
velocity surveys.
    (d) Obligations when geophysical data and information collected 
under a permit are obtained by a third party. A third party may obtain 
geophysical data, processed geophysical information, or interpreted 
geophysical information from a permittee, or from another third party, 
by sale, trade, license agreement, or other means. If this happens:
    (1) The third party recipient of the data and information assumes 
the obligations under this section, except for

[[Page 448]]

the notification provisions of paragraph (a)(1), and is subject to the 
penalty provisions of 30 CFR part 550, subpart N; and
    (2) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and
    (3) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director, in writing and within 30 days, 
of the sale, trade, or other agreement, including the identity of the 
recipient of the data and information; or
    (4) For license agreements, a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the Regional Director, advise the Regional Director, in writing, of 
the license agreement, including the identity of the recipient of the 
data and information.



Sec.  551.13  Reimbursement for the costs of reproducing data and
 information and certain processing costs.

    (a) BOEM will reimburse you or a third party for reasonable costs of 
reproducing data and information that the Regional Director requests if:
    (1) You deliver G&G data and information to BOEM for the Regional 
Director to inspect or select and retain (according to Sec.  551.11 or 
Sec.  551.12);
    (2) BOEM receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate (or a third party's) or at the 
lowest commercial rate established in the area, whichever is less.
    (b) BOEM will reimburse you or the third party for the reasonable 
costs of processing geophysical information (which does not include cost 
of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business; or
    (2) If you collected the information under a permit that BOEM issued 
to you before October 1, 1985, and the Regional Director requests and 
retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) BOEM will not reimburse you or a third party for data 
acquisition costs or for the costs of analyzing or processing geological 
information or interpreting geological or geophysical information.



Sec.  551.14  Protecting and disclosing data and information submitted 
to BOEM under a permit.

    (a) Disclosure of data and information to the public by BOEM. (1) In 
making data and information available to the public, the Regional 
Director will follow the applicable requirements of:
    (i) The Freedom of Information Act (5 U.S.C. 552);
    (ii) The implementing regulations at 43 CFR part 2;
    (iii) The Act; and
    (iv) The regulations at 30 CFR parts 550 and 552.
    (2) Except as specified in this section or in 30 CFR parts 550 and 
552, if the Regional Director determines any data or information is 
exempt from public disclosure under this paragraph (a), BOEM will not 
provide the data and information to any State or to the executive of any 
local government or to the public, unless you and all third parties 
agree to the disclosure.
    (3) BOEM will keep confidential the identity of third party 
recipients of data and information collected under a permit. BOEM will 
not release the identity unless you and the third parties agree to the 
disclosure.
    (4) When you detect any significant hydrocarbon occurrences or 
environmental hazards on unleased lands during drilling operations, the 
Regional Director will immediately issue a public announcement. The 
announcement must further the National interest, but without unduly 
damaging your competitive position.

[[Page 449]]

    (b) Timetable for release of G&G data and information related to 
oil, gas, and sulphur that BOEM acquires. Except for high-resolution 
data and information released under 30 CFR 550.197(b)(2), BOEM will 
release or disclose acquired data and information in accordance with 
paragraphs (b)(1) through (7) of this section.
    (1) If the data and information are not related to a deep 
stratigraphic test, BOEM will release them to the public in accordance 
with the following table:

------------------------------------------------------------------------
                                            The Regional Director will
If you or a third party submit and BOEM   release them to the public . .
             retains . . .                              .
------------------------------------------------------------------------
(i) Geological data and information,     10 years after BOEM issued the
                                          permit.
(ii) Geophysical data,                   50 years after BOEM issued the
                                          permit.
(iii) Geophysical information processed  25 years after BOEM issued the
 or reprocessed less than 20 years        permit.
 after BOEM issued the germane permit,
(iv) Geophysical information processed   25 years after BOEM issued the
 or reprocessed 20 or more years after    permit; or, if you or a third
 BOEM issued the germane permit,          party applied for an extension
                                          of the proprietary term, 5
                                          years after BOEM approved the
                                          application for an extension.
                                          In any case BOEM will release
                                          the information no later than
                                          50 years after BOEM issued the
                                          permit.
------------------------------------------------------------------------

    (2) Permittees and third parties may apply to BOEM for an extension 
of the 25-year proprietary term for geophysical information reprocessed 
20 or more years after BOEM issued the germane permit. You must submit 
the application to BOEM within 90 days after completion of the 
reprocessing, except during the initial 1-year grace period as provided 
in paragraph (b)(5) below. Filing locations are listed in Sec.  
551.5(d). Your application must include:
    (i) Name and address of the permittee or third party;
    (ii) Product name;
    (iii) Identification of the geophysical information area;
    (iv) Identification of originating permit number and date;
    (v) Description of reprocessing performed;
    (vi) Identification of the date of completion of reprocessing the 
geophysical information;
    (vii) Certification that the product meets the definition of 
processed geophysical information and that all other information in the 
application is accurate; and
    (viii) Signature and date.
    (3) With each new reprocessing of permitted data, you may apply for 
an extension of up to 5 years. However, the maximum proprietary term for 
geophysical information is 50 years after the permit was issued. Once 
the maximum term is reached, the BOEM Regional Director will release the 
information to the public.
    (4) Geophysical information processed or reprocessed 20 or more 
years after the germane permit was issued and granted the extension will 
be subject to submission, inspection, and selection criteria under Sec.  
551.12 and reimbursement criteria identified under Sec.  551.13.
    (5) There was a 1-year grace period, that started September 14, 
2009, that allowed permittees and third parties sufficient time to meet 
the above requirements and apply for all eligible extensions. During 
that time, BOEM did not release geophysical information which was 
reprocessed 20 or more years after the date that the germane permit was 
issued.
    (6) Since September 14, 2010, BOEM has resumed releasing eligible 
reprocessed information. If an application for extension was not filed, 
not filed on time, or not approved by BOEM, the original 25-year 
proprietary term applies to the release date of the reprocessed 
geophysical information.
    (7) If the data and information are related to a deep stratigraphic 
test, BOEM will release them to the public at the earlier of the 
following times:
    (i) Twenty-five years after you complete the test; or
    (ii) If a lease sale is held after you complete a test well, 60-
calendar days after BOEM issues the first lease, any portion of which is 
located within 50 geographic miles (92.7 kilometers) of the test.
    (8) BOEM may allow limited inspection, but only by persons with a 
direct

[[Page 450]]

interest in related BOEM decisions and issues in specific geographic 
areas, and who agree in writing to its confidentiality, of G&G data and 
information submitted under this part that BOEM uses to:
    (i) Make unitization determinations on two or more leases;
    (ii) Make competitive reservoir determinations;
    (iii) Ensure proper plans of development for competitive reservoirs;
    (iv) Promote operational safety;
    (v) Protect the environment;
    (vi) Make field determinations; or
    (vii) Determine eligibility for royalty relief.
    (c) Procedure that BOEM follows to disclose acquired data and 
information to a contractor for reproduction, processing, and 
interpretation. (1) When practical, the Regional Director will advise 
the person who submitted data and information under Sec.  551.11 or 
Sec.  551.12 of the intent to disclose the data or information to an 
independent contractor or agent.
    (2) The person so notified will have at least 5 working days to 
comment on the action.
    (3) When the Regional Director advises the person who submitted the 
data and information, all other owners of the data or information will 
be considered to have been so notified.
    (4) Before disclosure, the contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the Regional Director's consent.
    (d) Sharing data and information with coastal States. (1) When BOEM 
solicits nominations for leasing lands located within 3 geographic miles 
(5.6 kilometers) of the seaward boundary of any coastal State, the 
Regional Director, in accordance with 30 CFR 552.7(a)(4) and (b) and 
subsections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), 
will provide the Governor with:
    (i) All information on the geographical, geological, and ecological 
characteristics of the areas and regions BOEM proposes to offer for 
lease;
    (ii) An estimate of the oil and gas reserves in the areas proposed 
for leasing; and
    (iii) An identification of any field, geological structure, or trap 
on the OCS within 3 geographic miles (5.6 kilometers) of the seaward 
boundary of the State.
    (2) After receiving nominations for leasing an area of the OCS 
within 3 geographic miles of the seaward boundary of any coastal State, 
BOEM will carry out a tentative area identification according to 30 CFR 
part 556, subparts D and E. At that time, the Regional Director will 
consult with the Governor to determine whether any tracts further 
considered for leasing may contain any oil or gas reservoirs that 
underlie both the OCS and lands subject to the jurisdiction of the 
State.
    (3) Before a sale, if a Governor requests, the Regional Director, in 
accordance with 30 CFR 552.7(a)(4) and (b) and sections 8(g) and 26(e) 
of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the Governor 
information that identifies potential and/or proven common hydrocarbon 
bearing areas within 3 geographic miles of the seaward boundary of that 
State.
    (4) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to applicable 
confidentiality requirements of:
    (i) The Act; and
    (ii) The regulations at 30 CFR parts 550, 551, and 552.



Sec.  551.15  Authority for information collection.

    (a) The Office of Management and Budget has approved the information 
collection requirements in this part under 44 U.S.C. 3501 et seq. and 
assigned OMB control number 1010-0048. The title of this information 
collection is ``30 CFR part 551, Geological and Geophysical (G&G) 
Explorations of the OCS.''
    (b) We may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number.
    (c) We use the information collected under this part to:
    (1) Evaluate permit applications and monitor scientific research 
activities for environmental and safety reasons.

[[Page 451]]

    (2) Determine that explorations do not harm resources, result in 
pollution, create hazardous or unsafe conditions, or interfere with 
other users in the area.
    (3) Approve reimbursement of certain expenses.
    (4) Monitor the progress and activities carried out under an OCS G&G 
permit.
    (5) Inspect and select G&G data and information collected under an 
OCS G&G permit.
    (d) Respondents are Federal OCS permittees and Notice filers. 
Responses are mandatory or are required to obtain or retain a benefit. 
We will protect information considered proprietary under applicable law 
and under regulations at Sec.  551.14 and part 550 of this chapter.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]



PART 552_OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION 
PROGRAM--Table of Contents



Sec.
552.1 Purpose.
552.2 Definitions.
552.3 Oil and gas data and information to be provided for use in the OCS 
          Oil and Gas Information Program.
552.4 Summary Report to affected States.
552.5 Information to be made available to affected States.
552.6 Freedom of Information Act requirements.
552.7 Privileged and proprietary data and information to be made 
          available to affected States.

    Authority: OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92 
Stat. 629; Freedom of Information Act, 5 U.S.C. 552; Sec.  252.3 also 
issued under Pub. L. 99-190 making continuing appropriations for Fiscal 
Year 1986, and for other purposes.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



Sec.  552.1  Purpose.

    The purpose of this part is to implement the provisions of section 
26 of the Act (43 U.S.C. 1352). This part supplements the procedures and 
requirements contained in 30 CFR parts 250, 251, 550, and 551 and 
provides procedures and requirements for the submission of oil and gas 
data and information resulting from exploration, development, and 
production operations on the Outer Continental Shelf (OCS) to the 
Director, Bureau of Ocean Energy Management. In addition, this part 
establishes procedures for the Director to make available certain 
information to the Governors of affected States and, upon request, to 
the executives of affected local governments in accordance with the 
provisions of the Freedom of Information Act and the Act.



Sec.  552.2  Definitions.

    When used in the regulations in this part, the following terms shall 
have the meanings given below:
    Act refers to the Outer Continental Shelf Lands Act, as amended (43 
U.S.C. 1331 et seq.).
    Affected local government means the principal governing body of a 
locality which is in an affected State and is identified by the Governor 
of that State as a locality which will be significantly affected by oil 
and gas activities on the OCS.
    Affected State means, with respect to any program, plan, lease sale, 
or other activity, proposed, conducted, or approved pursuant to the 
provisions of the Act, any State:
    (1) The laws of which are declared, pursuant to section 4(a)(2)(A) 
of the Act, to be the law of the United States for the portion of the 
OCS on which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installations and 
other devices permanently, or temporarily attached to the seabed;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the OCS and transported directly to such State by means 
of vessels or by

[[Page 452]]

a combination of means including vessels;
    (4) Which is designated by the Director as a State in which there is 
a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Director finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Analyzed geological information means data collected under a permit 
or a lease which have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, logs 
or charts of electrical, radioactive, sonic, and other well logs, and 
descriptions of hydrocarbon shows or hazardous conditions.
    Area adjacent to a State means all of that portion of the OCS 
included within a planning area if such planning area is bordered by 
that State. The portion of the OCS in the Navarin Basin Planning Area is 
deemed to be adjacent to the State of Alaska. The States of New York and 
Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning 
Area and the North Atlantic Planning Area.
    Data means facts and statistics or samples which have not been 
analyzed or processed.
    Development means those activities which take place following 
discovery of oil or natural gas in paying quantities, including 
geophysical activity, drilling, platform construction, and operation of 
all onshore support facilities, and which are for the purpose of 
ultimately producing the oil and gas discovered.
    Director means the Director of the Bureau of Ocean Energy Management 
of the U.S. Department of the Interior or a designee of the Director.
    Exploration means the process of searching for oil and natural gas, 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of such oil or natural 
gas, and
    (2) Any drilling, whether on or off known geological structures, 
including the drilling of a well in which a discovery of oil or natural 
gas in paying quantities is made and the drilling of any additional 
delineation well after such discovery which is needed to delineate any 
reservoir and to enable the lessee to determine whether to proceed with 
development and production.
    Governor means the Governor of a State, or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to a Governor pursuant to the Act.
    Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of data and analyzed geological information.
    Interpreted geophysical information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of geophysical data and processed geophysical 
information.
    Lease means any form of authorization which is issued under section 
8 or maintained under section 6 of the Act and which authorizes 
exploration for, and development and production of, oil or natural gas, 
or the land covered by such authorization, whichever is required by the 
context.
    Lessee means the party authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in part 550 of this chapter, 
including all parties holding such authority by or through the lessee.

[[Page 453]]

    Outer Continental Shelf (OCS) means all submerged lands which lie 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (67 Stat. 29) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Permittee means the party authorized by a permit issued pursuant to 
part 551 of this chapter to conduct activities on the OCS.
    Processed geophysical information means data collected under a 
permit or a lease which have been processed. Processing involves 
changing the form of data so as to facilitate interpretation. Processing 
operations may include, but are not limited to, applying corrections for 
known perturbing causes, rearranging or filtering data, and combining or 
transforming data elements.
    Production means those activities which take place after the 
successful completion of any means for the removal of oil or natural 
gas, including such removal, field operations, transfer of oil or 
natural gas to shore, operation monitoring, maintenance, and workover 
drilling.
    Secretary means the Secretary of the Interior or a designee of the 
Secretary.



Sec.  552.3  Oil and gas data and information to be provided for use
 in the OCS Oil and Gas Information Program.

    (a) Any permittee or lessee engaging in the activities of 
exploration for, or development and production of, oil and gas on the 
OCS shall provide the Director access to all data and information 
obtained or developed as a result of such activities, including 
geological data, geophysical data, analyzed geological information, 
processed and reprocessed geophysical information, interpreted 
geophysical information, and interpreted geological information. Copies 
of these data and information and any interpretation of these data and 
information shall be provided to the Director upon request. No permittee 
or lessee submitting an interpretation of data or information, where 
such interpretation has been submitted in good faith, shall be held 
responsible for any consequence of the use of or reliance upon such 
interpretation.
    (b)(1) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program in a form and manner of 
processing which is utilized by the lessee or permittee in the normal 
conduct of business, the Director shall pay the reasonable cost of 
reproducing the data and information if the lessee or permittee requests 
reimbursement. The cost shall be computed and paid in accordance with 
the applicable provisions of paragraph (e)(1) of this section.
    (2) Whenever a lessee or permittee provides any data or information, 
at the request of the Director and specifically for use in the OCS Oil 
and Gas Information Program, in a form and manner of processing not 
normally utilized by the lessee or permittee in the normal conduct of 
business, the Director shall pay the lessee or permittee, if the lessee 
or permittee requests reimbursement, the reasonable cost of processing 
and reproducing the requested data and information. The cost is to be 
computed and paid in accordance with the applicable provisions of 
paragraph (e)(2) of this section.
    (c) Data or information requested by the Director shall be provided 
as soon as practicable, but not later than 30 days following receipt of 
the Director's request, unless, for good reason, the Director authorizes 
a longer time period for the submission of the requested data or 
information.
    (d) The Director reserves the right to disclose any data or 
information acquired from a lessee or permittee to an independent 
contractor or agent for the purpose of reproducing, processing, 
reprocessing, or interpreting such data or information. When 
practicable, the Director shall notify the lessee(s) or permittee(s) who 
provided the data or information of the intent to disclose the data or 
information to an independent contractor or agent. The Director's notice 
of intent will afford the permittee(s) or lessee(s) a period of not less 
than 5 working days within which to comment on the intended action. When 
the Director so notifies a lessee or permittee of the intent to disclose 
data or information to an independent

[[Page 454]]

contractor or agent, all other owners of such data or information shall 
be deemed to have been notified of the Director's intent. Prior to any 
such disclosure, the contractor or agent shall be required to execute a 
written commitment not to disclose any data or information to anyone 
without the express consent of the Director, and not to make any 
disclosure or use of the data or information other than that provided in 
the contract. Contracts between BOEM and independent contractors shall 
be available to the lessee(s) or permittee(s) for inspection. In the 
event of any unauthorized use or disclosure of data or information by 
the contractor or agent, or by an employee thereof, the responsible 
contractor or agent or employee thereof shall be liable for penalties 
pursuant to section 24 of the Act.
    (e)(1) After delivery of data or information in accordance with 
paragraph (b)(1) of this section and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of reproducing the data or information at the lessee's or 
permittee's lowest rate or at the lowest commercial rate established in 
the area, whichever is less. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information requested 
under paragraph (b)(1) of this section.
    (2) After delivery of data or information in accordance with 
paragraph (b)(3) of this section, and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed for 
the cost of processing or reprocessing and of reproducing the requested 
data or information. Requests for reimbursement must be made within 60 
days of the delivery date of the data or information and shall be for 
only the costs attributable to processing or reprocessing and 
reproducing, as distinguished from the costs of data acquisition.
    (3) Requests for reimbursement are to contain a breakdown of costs 
in sufficient detail to allow separation of reproduction, processing, 
and reprocessing costs from acquisition and other costs.
    (f) Each Federal Department or Agency shall provide the Director 
with any data which it has obtained pursuant to section 11 of the Act 
and any other information which may be necessary or useful to assist the 
Director in carrying out the provisions of the Act.



Sec.  552.4  Summary Report to affected States.

    (a) The Director, as soon as practicable after analysis, 
interpretation, and compilation of oil and gas data and information 
developed by BOEM or furnished by lessees, permittees, or other 
government agencies, shall make available to affected States and, upon 
request, to the executive of any affected local government, a Summary 
Report of data and information designed to assist them in planning for 
the onshore impacts of potential OCS oil and gas development and 
production. The Director shall consult with affected States and other 
interested parties to define the nature, scope, content, and timing of 
the Summary Report. The Director may consult with affected States and 
other interested parties regarding subsequent revisions in the 
definition of the nature, scope, content, and timing of the Summary 
Report. The Summary Report shall not contain data or information which 
the Director determines is exempt from disclosure in accordance with 
this part. The Summary Report shall not contain data or information the 
release of which the Director determines would unduly damage the 
competitive position of the lessee or permittee who provided the data or 
information which the Director has processed, analyzed, or interpreted 
during the development of the Summary Report. The Summary Report shall 
include:
    (1) Estimates of oil and gas reserves; estimates of the oil and gas 
resources that may be found within areas which the Secretary has leased 
or plans to offer for lease; and when available, projected rates and 
volumes of oil and gas to be produced from leased areas;
    (2) Magnitude of the approximate projections and timing of 
development,

[[Page 455]]

if and when oil or gas, or both, is discovered;
    (3) Methods of transportation to be used, including vessels and 
pipelines and approximate location of routes to be followed; and
    (4) General location and nature of near-shore and onshore facilities 
expected to be utilized.
    (b) When the Director determines that significant changes have 
occurred in the information contained in a Summary Report, the Director 
shall prepare and make available the new or revised information to each 
affected State, and, upon request, to the executive of any affected 
local government.



Sec.  552.5  Information to be made available to affected States.

    (a) The Director shall prepare an index of OCS information (see 30 
CFR 556.10). The index shall list all relevant actual or proposed 
programs, plans, reports, environmental impact statements, nominations 
information, environmental study reports, lease sale information, and 
any similar type of relevant information, including modifications, 
comments, and revisions prepared or directly obtained by the Director 
under the Act. The index shall be sent to affected States and, upon 
request, to any affected local government. The public shall be informed 
of the availability of the index.
    (b) Upon request, the Director shall transmit to affected States, 
affected local governments, and the public a copy of any information 
listed in the index which is subject to the control of BOEM, in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552) and implementing regulations. 
The Director shall not transmit or make available any information which 
he determines is exempt from disclosure in accordance with this part.



Sec.  552.6  Freedom of Information Act requirements.

    (a) The Director shall make data and information available in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552), the regulations contained in 
43 CFR part 2 (Records and Testimony), the requirements of the Act, and 
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and 
Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 551 
(Geological and Geophysical Explorations of the Outer Continental 
Shelf).
    (b) Except as provided in Sec.  552.7 or in 30 CFR parts 250, 251, 
550, and 551 of this chapter, no data or information determined by the 
director to be exempt from public disclosure under paragraph (a) of this 
section shall be provided to any affected State or be made available to 
the executive of any affected local government or to the public unless 
the lessee, or the permittee and all persons to whom such permittee has 
sold such data or information under promise of confidentiality, agree to 
such action.



Sec.  552.7  Privileged and proprietary data and information to be made
 available to affected States.

    (a)(1) The Governor of any affected State may designate an 
appropriate State official to inspect, at a regional location which the 
Director shall designate, any privileged or proprietary data or 
information received by the Director regarding any activity in an area 
adjacent to such State, except that no such inspection shall take place 
prior to the sale of a lease covering the area in which such activity 
was conducted.
    (2)(i) Except as provided for in 30 CFR 250.197, 550.197, and 
551.14, no privileged or proprietary data or information will be 
transmitted to any affected State unless the lessee who provided the 
privileged or proprietary data or information agrees in writing to the 
transmittal of the data or information.
    (ii) Except as provided for in 30 CFR 250.197, 550.197, and 551.14, 
no privileged or proprietary data or information will be transmitted to 
any affected State unless the permittee and all persons to whom the 
permittee has sold the data or information under promise of 
confidentiality agree in writing to the transmittal of the data or 
information.
    (3) Knowledge obtained by a State official who inspects data or 
information under paragraph (a)(1) of this section or who receives data 
or information under paragraph (a)(2) of this section

[[Page 456]]

shall be subject to the requirements and limitations of the Freedom of 
Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 
2 (Records and Testimony), the Act (92 Stat. 629), the regulations 
contained in 30 CFR parts 250 and 550 (Oil and Gas and Sulphur 
Operations in the Outer Continental Shelf), the regulations contained in 
30 CFR parts 251 and 551 (Geological and Geophysical Explorations of the 
Outer Continental Shelf), and the regulations contained in 30 CFR parts 
252 and 552 (Outer Continental Shelf Oil and Gas Information Program).
    (4) Prior to the transmittal of any privileged or proprietary data 
or information to any State, or the grant of access to a State official 
to such data or information, the Secretary shall enter into a written 
agreement with the Governor of the State in accordance with section 
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall 
agree, as a condition precedent to receiving or being granted access to 
such data or information to:
    (i) Protect and maintain the confidentiality of privileged or 
proprietary data and information in accordance with the laws and 
regulations listed in paragraph (a)(3) of this section;
    (ii) Waive the defenses as set forth in paragraph (b)(2) of this 
section; and
    (iii) Hold the United States harmless from any violations of the 
agreement to protect the confidentiality of privileged or proprietary 
data or information by the State or its employees or contractors.
    (b)(1) Whenever any employee of the Federal Government or of any 
State reveals in violation of the Act or of the provisions of the 
regulations implementing the Act, privileged or proprietary data or 
information obtained pursuant to the regulations in this chapter, the 
lessee or permittee who supplied such information to the Director or any 
other Federal official, and any person to whom such lessee or permittee 
has sold such data or information under the promise of confidentiality, 
may commence a civil action for damages in the appropriate district 
court of the United States against the Federal Government or such State, 
as the case may be. Any Federal or State employee who is found guilty of 
failure to comply with any of the requirements of this section shall be 
subject to the penalties described in section 24 of the Act (43 U.S.C. 
1350).
    (2) In any action commenced against the Federal Government or a 
State pursuant to paragraph (b)(1) of this section, the Federal 
Government or such State, as the case may be, may not raise as a defense 
any claim of sovereign immunity, or any claim that the employee who 
revealed the privileged or proprietary data or information which is the 
basis of such suit was acting outside the scope of the person's 
employment in revealing such data or information.
    (c) If the Director finds that any State cannot or does not comply 
with the conditions described in the agreement entered into pursuant to 
paragraph (a)(4) of this section, the Director shall thereafter withhold 
transmittal and deny access for inspection of privileged or proprietary 
data or information to such State until the Director finds that such 
State can and will comply with those conditions.



PART 553_OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE 
FACILITIES--Table of Contents



                            Subpart A_General

Sec.
553.1 What is the purpose of this part?
553.3 How are the terms used in this regulation defined?
553.5 What is the authority for collecting Oil Spill Financial 
          Responsibility (OSFR) information?

               Subpart B_Applicability and Amount of OSFR

553.10 What facilities does this part cover?
553.11 Who must demonstrate OSFR?
553.12 May I ask BOEM for a determination of whether I must demonstrate 
          OSFR?
553.13 How much OSFR must I demonstrate?
553.14 How do I determine the worst case oil-spill discharge volume?
553.15 What are my general OSFR compliance responsibilities?

[[Page 457]]

                Subpart C_Methods for Demonstrating OSFR

553.20 What methods may I use to demonstrate OSFR?
553.21 How can I use self-insurance as OSFR evidence?
553.22 How do I apply to use self-insurance as OSFR evidence?
553.23 What information must I submit to support my net worth 
          demonstration?
553.24 When I submit audited annual financial statements to verify my 
          net worth, what standards must they meet?
553.25 What financial test procedures must I use to determine the amount 
          of self-insurance allowed as OSFR evidence based on net worth?
553.26 What information must I submit to support my unencumbered assets 
          demonstration?
553.27 When I submit audited annual financial statements to verify my 
          unencumbered assets, what standards must they meet?
553.28 What financial test procedures must I use to evaluate the amount 
          of self-insurance allowed as OSFR evidence based on 
          unencumbered assets?
553.29 How can I use insurance as OSFR evidence?
553.30 How can I use an indemnity as OSFR evidence?
553.31 How can I use a surety bond as OSFR evidence?
553.32 Are there alternative methods to demonstrate OSFR?

         Subpart D_Requirements for Submitting OSFR Information

553.40 What OSFR evidence must I submit to BOEM?
553.41 What terms must I include in my OSFR evidence?
553.42 How can I amend my list of COFs?
553.43 When is my OSFR demonstration or the amendment to my OSFR 
          demonstration effective?
553.44 [Reserved]
553.45 Where do I send my OSFR evidence?

                   Subpart E_Revocation and Penalties

553.50 How can BOEM refuse or invalidate my OSFR evidence?
553.51 What are the penalties for not complying with this part?

        Subpart F_Claims for Oil-Spill Removal Costs and Damages

553.60 To whom may I present a claim?
553.61 When is a guarantor subject to direct action for claims?
553.62 What are the designated applicant's notification obligations 
          regarding a claim?

          Subpart G_Limit of Liability for Offshore Facilities

553.700 What is the scope of this subpart?
553.701 To which entities does this subpart apply?
553.702 What limit of liability applies to my offshore facility?
553.703 What is the procedure for calculating the limit of liability 
          adjustment for inflation?
553.704 How will BOEM publish the offshore facility limit of liability 
          adjustment?

Appendix to Part 553--List of U.S. Geological Survey Topographic Maps

    Authority: 33 U.S.C. 2704, 2716; E.O. 12777, as amended.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General



Sec.  553.1  What is the purpose of this part?

    This part establishes the requirements for demonstrating Oil Spill 
Financial Responsibility for covered offshore facilities (COF), sets 
forth the procedures for claims against COF guarantors, and sets forth 
the limit of liability for offshore facilities, as adjusted, un der 
Title I of the Oil Pollution Act of 1990, as amended, 33 U.S.C. 2701 et 
seq. (OPA).

[79 FR 73839, Dec. 12, 2014]



Sec.  553.3  How are the terms used in this regulation defined?

    Terms used in this part have the following meaning:
    Advertise means publication of the notice of designation of the 
source of the incident and the procedures by which the claims may be 
presented, according to 33 CFR part 136, subpart D.
    Annual CPI-U means the annual ``Consumer Price Index-All Urban 
Consumers, Not Seasonally Adjusted, U.S. City Average, All items, 1982 - 
84 = 100,'' published by the U.S. Department of Labor, Bureau of Labor 
Statistics.
    Bay means a body of water included in the Geographic Names 
Information System (GNIS) bay feature class. A GNIS bay includes an arm, 
bay, bight, cove, estuary, gulf, inlet, or sound.

[[Page 458]]

    Claim means a written request, for a specific sum, for compensation 
for damages or removal costs resulting from an oil-spill discharge or a 
substantial threat of the discharge of oil.
    Claimant means any person or government who presents a claim for 
compensation under OPA.
    Coastline means the line of ordinary low water along that portion of 
the coast that is in direct contact with the open sea which marks the 
seaward limit of inland waters.
    Covered offshore facility (COF) means a facility:
    (1) That includes any structure and all its components (including 
wells completed at the structure and the associated pipelines), 
equipment, pipeline, or device (other than a vessel or other than a 
pipeline or deepwater port licensed under the Deepwater Port Act of 1974 
(33 U.S.C. 1501 et seq.)) used for exploring for, drilling for, or 
producing oil or for transporting oil from such facilities. This 
includes a well drilled from a mobile offshore drilling unit (MODU) and 
the associated riser and well control equipment from the moment a drill 
shaft or other device first touches the seabed for purposes of exploring 
for, drilling for, or producing oil, but it does not include the MODU; 
and
    (2) That is located:
    (i) Seaward of the coastline; or
    (ii) In any portion of a bay that is:
    (A) Connected to the sea, either directly or through one or more 
other bays; and
    (B) Depicted in whole or in part on any USGS map listed in the 
Appendix to this part, or on any map published by the USGS that is a 
successor to and covers all or part of the same area as a listed map. 
Where any portion of a bay is included on a listed map, this rule 
applies to the entire bay; and
    (3) That has a worst case oil-spill discharge potential of more than 
1,000 bbls of oil, or a lesser volume if the Director determines in 
writing that the oil-spill discharge risk justifies the requirement to 
demonstrate OSFR.
    Current period means the year in which the Annual CPI-U was most 
recently published by the U.S. Department of Labor, Bureau of Labor 
Statistics.
    Designated applicant means a person the responsible parties 
designate to demonstrate OSFR for a COF on a lease, permit, or right-of-
use and easement.
    Director means the Director of the Bureau of Ocean Energy 
Management.
    Fund means the Oil Spill Liability Trust Fund established by section 
9509 of the Internal Revenue Code of 1986 as amended (26 U.S.C. 9509).
    Geographic Names Information System (GNIS) means the database 
developed by the USGS in cooperation with the U.S. Board of Geographic 
Names which contains the federally-recognized geographic names for all 
known places, features, and areas in the United States that are 
identified by a proper name. Each feature is located by state, county, 
and geographic coordinates and is referenced to the appropriate 
1:24,000-scale or 1:63,360-scale USGS topographic map on which it is 
shown.
    Guarantor means a person other than a responsible party who provides 
OSFR evidence for a designated applicant.
    Guaranty means any acceptable form of OSFR evidence provided by a 
guarantor including an indemnity, insurance, or surety bond.
    Incident means any occurrence or series of occurrences having the 
same origin that results in the discharge or substantial threat of the 
discharge of oil.
    Indemnity means an agreement to indemnify a designated applicant 
upon its satisfaction of a claim.
    Indemnitor means a person providing an indemnity for a designated 
applicant.
    Independent accountant means a certified public accountant who is 
certified by a state, or a chartered accountant certified by the 
government of jurisdiction within the country of incorporation of the 
company proposing to use one of the self-insurance evidence methods 
specified in this subpart.
    Insolvent has the meaning set forth in 11 U.S.C. 101, and generally 
refers to a financial condition in which the sum of a person's debts is 
greater than the value of the person's assets.
    Lease means any form of authorization issued under the Outer 
Continental Shelf Lands Act or state law

[[Page 459]]

which allows oil and gas exploration and production in the area covered 
by the authorization.
    Lessee means a person holding a leasehold interest in an oil or gas 
lease including an owner of record title or a holder of operating rights 
(working interest owner).
    Oil means oil of any kind or in any form, except as excluded by 
paragraph (2) of this definition.
    (1) Oil includes:
    (i) Petroleum, fuel oil, sludge, oil refuse, and oil mixed with 
wastes other than dredged spoil;
    (ii) Hydrocarbons produced at the wellhead in liquid form;
    (iii) Gas condensate that has been separated from gas before 
pipeline injection.
    (2) Oil does not include petroleum, including crude oil or any 
fraction thereof, which is specifically listed or designated as a 
hazardous substance under subparagraphs (A) through (F) of section 
101(14) of the Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA) (42 U.S.C. 9601).
    Oil Spill Financial Responsibility (OSFR) means the capability and 
means by which a responsible party for a covered offshore facility will 
meet removal costs and damages for which it is liable under Title I of 
the Oil Pollution Act of 1990, as amended (33 CFR 2701 et seq.), with 
respect to both oil-spill discharges and substantial threats of the 
discharge of oil.
    Outer Continental Shelf (OCS) has the same meaning as the term 
``Outer Continental Shelf'' defined in section 2(a) of the OCS Lands Act 
(OCSLA) (43 U.S.C. 1331(a)).
    Permit means an authorization, license, or permit for geological 
exploration issued under section 11 of the OCSLA (43 U.S.C. 1340) or 
applicable state law.
    Person means an individual, corporation, partnership, association 
(including a trust or limited liability company), state, municipality, 
commission or political subdivision of a state, or any interstate body.
    Pipeline means the pipeline segments and any associated equipment or 
appurtenances used or intended for use in the transportation of oil or 
natural gas.
    Previous period means the year in which the previous limit of 
liability was established, or last adjusted by statute or regulation, 
whichever is later.
    Responsible party, for purposes of subparts B through F, has the 
following meanings:
    (1) For a COF that is a pipeline, responsible party means any person 
owning or operating the pipeline;
    (2) For a COF that is not a pipeline, responsible party means either 
the lessee or permittee of the area in which the COF is located, or the 
holder of a right-of-use and easement granted under applicable State law 
or the OCSLA (43 U.S.C. 1301-1356) for the area in which the COF is 
located (if the holder is a different person than the lessee or 
permittee). A Federal agency, State, municipality, commission, or 
political subdivision of a State, or any interstate body that as owner 
transfers possession and right to use the property to another person by 
lease, assignment, or permit is not a responsible party; and
    (3) For an abandoned COF, responsible party means any person who 
would have been a responsible party for the COF immediately before 
abandonment.
    Responsible party, for purposes of subpart G, has the meaning in 33 
U.S.C. 2701(32)(C), (E) and (F). This definition includes, as 
applicable, lessees as defined in this subpart, permittees, right-of-use 
and easement holders, and pipeline owners and operators.
    Right-of-use and easement (RUE) means any authorization to use the 
OCS or submerged land for purposes other than those authorized by a 
lease or permit, as defined herein. It includes pipeline rights-of-way.
    Source of the incident means the facility from which oil was 
discharged or which poses a substantial threat of discharging oil, as 
designated by the Director, National Pollution Funds Center, according 
to 33 CFR part 136, subpart D.
    State means the several States of the United States, the District of 
Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the 
United

[[Page 460]]

States Virgin Islands, the Commonwealth of the Northern Marianas, and 
any other territory or possession of the United States.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 73839, Dec. 12, 2014]



Sec.  553.5  What is the authority for collecting Oil Spill Financial
 Responsibility (OSFR) information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part 553 under 44 U.S.C. 
3501 et seq., and assigned OMB control number 1010-0106.
    (b) BOEM collects the information to ensure that the designated 
applicant for a COF has the financial resources necessary to pay for 
cleanup and damages that could be caused by oil discharges from the COF. 
BOEM uses the information to ensure compliance of offshore lessees, 
owners, and operators of covered facilities with OPA; to establish 
eligibility of designated applicants for OSFR certification (OSFRC); and 
to establish a reference source of names, addresses, and telephone 
numbers of responsible parties for covered facilities and their 
designated agents, guarantors, and U.S. agents for service of process 
for claims associated with oil pollution from designated covered 
facilities. The requirement to provide the information is mandatory. No 
information submitted for OSFRC is confidential or proprietary.
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]



               Subpart B_Applicability and Amount of OSFR



Sec.  553.10  What facilities does this part cover?

    (a) This part applies to any COF on any lease or permit issued or on 
any RUE granted under the OCSLA or applicable State law.
    (b) For a pipeline COF that extends onto land, this part applies to 
that portion of the pipeline lying seaward of the first accessible flow 
shut-off device on land.



Sec.  553.11  Who must demonstrate OSFR?

    (a) A designated applicant must demonstrate OSFR. A designated 
applicant may be a responsible party or another person authorized under 
this section. Each COF must have a single designated applicant.
    (1) If there is more than one responsible party, those responsible 
parties must use Form BOEM-1017 to select a designated applicant. The 
designated applicant must submit Form BOEM-1016 and agree to demonstrate 
OSFR on behalf of all the responsible parties.
    (2) If you are a designated applicant who is not a responsible 
party, you must agree to be liable for claims made under OPA jointly and 
severally with the responsible parties.
    (b) The designated applicant for a COF on a lease must be either:
    (1) A lessee; or
    (2) The designated operator for the OCS lease under 30 CFR 550.143 
or the unit operator designated under a Federally approved unit 
including the OCS lease. For a lease or unit not in the OCS, the 
operator designated under the lease or unit operating agreement for the 
lease may be the designated applicant only if the operator has agreed to 
be responsible for compliance with all the laws and regulations 
applicable to the lease or unit.
    (c) The designated applicant for a COF on a permit must be the 
permittee.
    (d) The designated applicant for a COF on a RUE must be the holder 
of the RUE or, if there is a pipeline on the RUE, the owner or operator 
of the pipeline.
    (e) BOEM may require the designated applicant for a lease, permit, 
or RUE to

[[Page 461]]

be a person other than a person identified in paragraphs (b) through (d) 
of this section if BOEM determines that a person identified in 
paragraphs (b) through (d) cannot adequately demonstrate OSFR.
    (f) If you are a responsible party and you fail to designate an 
applicant, then you must demonstrate OSFR under the requirements of this 
part.



Sec.  553.12  May I ask BOEM for a determination of whether I must
 demonstrate OSFR?

    You may submit to BOEM a request for a determination of OSFR 
applicability. Address the request to the office identified in Sec.  
553.45. You must include in your request any information that will 
assist BOEM in making the determination. BOEM may require you to submit 
other information before making a determination of OSFR applicability.



Sec.  553.13  How much OSFR must I demonstrate?

    (a) The following general parameters apply to the amount of OSFR 
that you must demonstrate:

------------------------------------------------------------------------
 If you are the designated applicant for .   Then you must demonstrate .
                    . .                                  . .
------------------------------------------------------------------------
Only one COF,                               The amount of OSFR that
                                             applies to the COF.
More than one COF,                          The highest amount of OSFR
                                             that applies to any one of
                                             the COFs.
------------------------------------------------------------------------

    (b) You must demonstrate OSFR in the amounts specified in this 
section:
    (1) For a COF located wholly or partially in the OCS you must 
demonstrate OSFR in accordance with the following table:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 35,000 bbls...........     $35,000,000
Over 35,000 but not more than 70,000 bbls...............      70,000,000
Over 70,000 but not more than 105,000 bbls..............     105,000,000
Over 105,000 bbls.......................................     150,000,000
------------------------------------------------------------------------

    (2) For a COF not located in the OCS you must demonstrate OSFR in 
accordance with the following table:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 10,000 bbls...........     $10,000,000
Over 10,000 but not more than 35,000 bbls...............      35,000,000
Over 35,000 but not more than 70,000 bbls...............      70,000,000
Over 70,000 but not more than 105,000 bbls..............     105,000,000
Over 105,000 bbls.......................................     150,000,000
------------------------------------------------------------------------

    (3) The Director may determine that you must demonstrate an amount 
of OSFR greater than the amount in paragraphs (b)(1) and (2) of this 
section based on the relative operational, environmental, human health, 
and other risks that your COF poses. The Director may require an amount 
that is one or more levels higher than the amount indicated in paragraph 
(b)(1) or (2) of this section for your COF. The Director will not 
require an OSFR demonstration that exceeds $150 million.
    (4) You must demonstrate OSFR in the lowest amount specified in the 
applicable table in paragraph (b)(1) or (2) of this section for a 
facility with a potential worst case oil-spill discharge of 1,000 bbls 
or less if the Director notifies you in writing that the demonstration

[[Page 462]]

is justified by the risks of the potential oil-spill discharge.



Sec.  553.14  How do I determine the worst case oil-spill discharge
 volume?

    (a) To calculate the amount of OSFR you must demonstrate for a 
facility under Sec.  553.13(b), you must use the worst case oil-spill 
discharge volume that you determined under whichever of the following 
regulations applies:
    (1) 30 CFR part 254--Response Plans for Facilities Located Seaward 
of the Coast Line, except that the volume of the worst case oil-spill 
discharge for a well must be four times the uncontrolled flow volume 
that you estimate for the first 24 hours.
    (2) 40 CFR part 112--Oil Pollution Prevention; or
    (3) 49 CFR part 194--Response Plans for Onshore Oil Pipelines.
    (b) If you are a designated applicant and you choose to demonstrate 
$150 million in OSFR, you are not required to determine any worst case 
oil-spill discharge volumes, since that is the maximum amount of OSFR 
required under this part.



Sec.  553.15  What are my general OSFR compliance responsibilities?

    (a) You must maintain continuous OSFR coverage for all your leases, 
permits, and RUEs with COFs for which you are the designated applicant.
    (b) You must ensure that new OSFR evidence is submitted before your 
current evidence lapses or is canceled and that coverage for your new 
COF is submitted before the COF goes into operation.
    (c) If you use self-insurance to demonstrate OSFR and find that you 
no longer qualify to self-insure the required OSFR amount based upon 
your latest audited annual financial statements, then you must 
demonstrate OSFR using other methods acceptable to BOEM by whichever of 
the following dates comes first:
    (1) Sixty calendar days after you receive your latest audited annual 
financial statement; or
    (2) The first calendar day of the 5th month after the close of your 
fiscal year.
    (d) You may use a surety bond to demonstrate OSFR. If you find that 
your bonding company has lost its state license or has had its U.S. 
Treasury Department certification revoked, then you must replace the 
surety bond within 15 calendar days using a method of OSFR that is 
acceptable to BOEM.
    (e) You must notify BOEM in writing within 15 calendar days after a 
change occurs that would prevent you from meeting your OSFR obligations 
(e.g., if you or your indemnitor petition for bankruptcy under chapters 
7 or 11 of Title 11, U.S.C.). You must take any action BOEM directs to 
ensure an acceptable OSFR demonstration.
    (f) If you deny payment of a claim presented to you under Sec.  
553.60, then you must give the claimant a written explanation for your 
denial.



                Subpart C_Methods for Demonstrating OSFR



Sec.  553.20  What methods may I use to demonstrate OSFR?

    As the designated applicant, you may satisfy your OSFR requirements 
by using one or a combination of the following methods to demonstrate 
OSFR:
    (a) Self-insurance under Sec. Sec.  553.21 through 553.28;
    (b) Insurance under Sec.  553.29;
    (c) An indemnity under Sec.  553.30;
    (d) A surety bond under Sec.  553.31; or
    (e) An alternative method the Director approves under Sec.  553.32.



Sec.  553.21  How can I use self-insurance as OSFR evidence?

    (a) If you use self-insurance to satisfy all or part of your 
obligation to demonstrate OSFR, you must annually pass either a net 
worth test under Sec.  553.25 or an unencumbered net asset test under 
Sec.  553.28.
    (b) To establish the amount of self-insurance allowed, you must 
submit evidence of your net worth under Sec.  553.23 or evidence of your 
unencumbered assets under Sec.  553.26.
    (c) You must identify a U.S. agent for service of process.



Sec.  553.22  How do I apply to use self-insurance as OSFR evidence?

    (a) You must submit a complete Form BOEM-1018 with each application 
to demonstrate OSFR using self-insurance.

[[Page 463]]

    (b) You must submit your application to renew OSFR using self-
insurance by the first calendar day of the 5th month after the close of 
your fiscal year. You may submit to BOEM your initial application to 
demonstrate OSFR using self-insurance at any time.



Sec.  553.23  What information must I submit to support my net worth
 demonstration?

    You must support your net worth evaluation with information 
contained in your previous fiscal year's audited annual financial 
statement.
    (a) Audited annual financial statements must be in the form of:
    (1) An annual report, prepared in accordance with the generally 
accepted accounting practices (GAAP) of the United States or other 
international accounting practices determined to be equivalent by BOEM; 
or
    (2) A Form 10-K or Form 20-F, prepared in accordance with Securities 
and Exchange Commission regulations.
    (b) Audited annual financial statements must be submitted together 
with a letter signed by your treasurer highlighting:
    (1) The State or the country of incorporation;
    (2) The total amount of the stockholders' equity as shown on the 
balance sheet;
    (3) The net amount of the plant, property, and equipment shown on 
the balance sheet; and
    (4) The net amount of the identifiable U.S. assets and the 
identifiable total assets in the auditor's notes to the financial 
statement (i.e., a geographic segmented business note).



Sec.  553.24  When I submit audited annual financial statements to
 verify my net worth, what standards must they meet?

    (a) Your audited annual financial statements must be bound.
    (b) Your audited annual financial statements must include the 
unqualified opinion of an independent accountant that states:
    (1) The financial statements are free from material misstatement, 
and
    (2) The audit was conducted in accordance with the generally 
accepted auditing standards (GAAS) of the United States, or other 
international auditing standards that BOEM determines to be equivalent.
    (c) The financial information you submit must be expressed in U.S. 
dollars. If this information was originally reported in another form of 
currency, you must convert it to U.S. dollars using the conversion 
factor that was effective on the last day of the fiscal year pertinent 
to your financial statements. You also must identify the source of the 
currency exchange rate.



Sec.  553.25  What financial test procedures must I use to determine
 the amount of self-insurance allowed as OSFR evidence based on net
 worth?

    (a) Divide the total amount of the stockholders'/owners' equity 
listed on the balance sheet by ten.
    (b) Divide the net amount of the identifiable U.S. assets by the net 
amount of the identifiable total assets.
    (c) Multiply the net amount of plant, property, and equipment shown 
on the balance sheet by the number calculated under paragraph (b) of 
this section and divide the resultant product by ten.
    (d) The smaller of the numbers calculated under paragraphs (a) or 
(c) of this section is the maximum allowable amount you may use to 
demonstrate OSFR under this method.



Sec.  553.26  What information must I submit to support my unencumbered
 assets demonstration?

    You must support your unencumbered assets evaluation with the 
information required by Sec.  553.23(a) and a list of reserved, 
unencumbered, and unimpaired U.S. assets whose value will not be 
affected by an oil discharge from a COF. The assets must be plant, 
property, or equipment held for use. You must submit a letter signed by 
your treasurer:
    (a) Identifying which assets are reserved;
    (b) Certifying that the assets are unencumbered, including 
contingent encumbrances;
    (c) Promising that the identified assets will not be sold, subjected 
to a security interest, or otherwise encumbered throughout the specified 
fiscal year; and
    (d) Specifying:
    (1) The State or the country of incorporation;

[[Page 464]]

    (2) The total amount of the stockholders'/owners' equity listed on 
the balance sheet;
    (3) The identification and location of the reserved U.S. assets; and
    (4) The value of the reserved U.S. assets less accumulated 
depreciation and amortization, using the same valuation method used in 
your audited annual financial statement and expressed in U.S. dollars. 
The net value of the reserved assets must be at least two times the 
self-insurance amount requested for demonstration.



Sec.  553.27  When I submit audited annual financial statements to 
verify my unencumbered assets, what standards must they meet?

    Any audited annual financial statements that you submit must:
    (a) Meet the standards in Sec.  553.24; and
    (b) Include a certification by the independent accountant who 
audited the financial statements that states:
    (1) The value of the unencumbered assets is reasonable and uses the 
same valuation method used in your audited annual financial statements;
    (2) Any existing encumbrances are noted;
    (3) The assets are long-term assets held for use; and
    (4) The valuation method used in the audited annual financial 
statements is for long-term assets held for use.



Sec.  553.28  What financial test procedures must I use to evaluate
 the amount of self-insurance allowed as OSFR evidence based on
 unencumbered assets?

    (a) Divide the total amount of the stockholders'/owners' equity 
listed on the balance sheet by 4.
    (b) Divide the value of the unencumbered U.S. assets by 2.
    (c) The smaller number calculated under paragraphs (a) or (b) of 
this section is the maximum allowable amount you may use to demonstrate 
OSFR under this method.



Sec.  553.29  How can I use insurance as OSFR evidence?

    (a) If you use insurance to satisfy all or part of your obligation 
to demonstrate OSFR, you may use only insurance certificates issued by 
insurers that have achieved a ``Secure'' rating for claims paying 
ability in their latest review by A.M. Best's Insurance Reports, 
Standard & Poor's Insurance Rating Services, or other equivalent rating 
made by a rating service acceptable to BOEM.
    (b) You must submit information about your insurers to BOEM on a 
completed and unaltered Form BOEM-1019. The information you submit must:
    (1) Include all the information required by Sec.  553.41 and
    (2) Be executed on one original insurance certificate (i.e., Form 
BOEM-1019) for each OSFR layer (see paragraph (c) of this section), 
showing all participating insurers and their proportion (quota share) of 
this risk. The certificate must bear the original signatures of each 
insurer's underwriter or of their lead underwriters, underwriting 
managers, or delegated brokers, depending on who is authorized to bind 
the underwriter.
    (3) For each insurance company on the insurance certificate, 
indicate the insurer's claims-paying-ability rating and the rating 
service that issued the rating.
    (c) The insurance evidence you provide to BOEM as OSFR evidence may 
be divided into layers, subject to the following restrictions:
    (1) The total amount of OSFR evidence must equal the total amount 
you must demonstrate under Sec.  553.13;
    (2) No more than one insurance certificate may be used to cover each 
OSFR layer specified in Sec.  553.13(b) (i.e., four layers for an OCS 
COF, and five layers for a non-OCS COF);
    (3) You may use one insurance certificate to cover any number of 
consecutive OSFR layers;
    (4) Each insurer's participation in the covered insurance risk must 
be on a proportional (quota share) basis, must be expressed as a 
percentage of a whole layer, and the certificate must not contain 
intermediate, horizontal layers;
    (5) You may use an insurance deductible. If you use more than one 
insurance certificate, the deductible amount must apply only to the 
certificate that covers the base OSFR amount layer. To satisfy an 
insurance deductible, you may use only those methods that are

[[Page 465]]

acceptable as evidence of OSFR under this part; and
    (6) You must identify a U.S. agent for service of process on each 
insurance certificate you submit to BOEM. The agent may be different for 
each insurance certificate.
    (d) You may submit to BOEM a temporary insurance confirmation (fax 
binder) for each insurance certificate you use as OSFR evidence. Submit 
your fax binder on Form BOEM-1019, and each form must include the 
signature of an underwriter for at least one of the participating 
insurers. BOEM will accept your fax binder as OSFR evidence during a 
period that ends 90 days after the date that you need the insurance to 
demonstrate OSFR.



Sec.  553.30  How can I use an indemnity as OSFR evidence?

    (a) You may use only one indemnity issued by only one indemnitor to 
satisfy all or part of your obligation to demonstrate OSFR.
    (b) Your indemnitor must be your corporate parent or affiliate.
    (c) Your indemnitor must complete a Form BOEM-1018 and provide an 
indemnity that:
    (1) Includes all the information required by Sec.  553.41; and
    (2) Does not exceed the amounts calculated using the net worth or 
unencumbered assets tests specified under Sec. Sec.  553.21 through 
553.28.
    (d) You must submit your application to renew OSFR using an 
indemnity by the first calendar day of the 5th month after the close of 
your indemnitor's fiscal year. You may submit to BOEM your initial 
application to demonstrate OSFR using an indemnity at any time.
    (e) Your indemnitor must identify a U.S. agent for service of 
process.



Sec.  553.31  How can I use a surety bond as OSFR evidence?

    (a) Each bonding company that issues a surety bond that you submit 
to BOEM as OSFR evidence must:
    (1) Be licensed to do business in the State in which the surety bond 
is executed;
    (2) Be certified by the U.S. Treasury Department as an acceptable 
surety for Federal obligations and listed in the current Treasury 
Circular No. 570;
    (3) Provide the surety bond on Form BOEM-1020; and
    (4) Be in compliance with applicable statutes regulating surety 
company participation in insurance-type risks.
    (b) A surety bond that you submit as OSFR evidence must include all 
the information required by Sec.  553.41.



Sec.  553.32  Are there alternative methods to demonstrate OSFR?

    The Director may accept other methods to demonstrate OSFR that 
provide equivalent assurance of timely satisfaction of claims. This may 
include pooling, letters of credit, pledges of treasury notes, or other 
comparable methods. Submit your proposal, together with all the 
supporting documents, to the Director at the address listed in Sec.  
553.45. The Director's decision whether to approve your alternative 
method to evidence OSFR is by this rule committed to the Director's sole 
discretion and is not subject to administrative appeal under 30 CFR part 
590 or 43 CFR part 4.



         Subpart D_Requirements for Submitting OSFR Information



Sec.  553.40  What OSFR evidence must I submit to BOEM?

    (a) You must submit to BOEM:
    (1) A single demonstration of OSFR that covers all the COFs for 
which you are the designated applicant;
    (2) A completed and unaltered Form BOEM-1016;
    (3) BOEM forms that identify your COFs (Form BOEM-1021, Form BOEM-
1022), and the methods you will use to demonstrate OSFR (Form BOEM-1018, 
Form BOEM-1019, Form BOEM-1020). Forms are available from the address 
listed in Sec.  553.45;
    (4) Any insurance certificates, indemnities, and surety bonds used 
as OSFR evidence for the COFs for which you are the designated 
applicant;
    (5) A completed Form BOEM-1017 for each responsible party, unless 
you are the only responsible party for the COFs covered by your OSFR 
demonstration; and
    (6) Other financial instruments and information the Director 
requires to support your OSFR demonstration under Sec.  553.32.

[[Page 466]]

    (b) Each BOEM form you submit to BOEM as part of your OSFR 
demonstration must be signed. You also must attach to Form BOEM-1016 
proof of your authority to sign.



Sec.  553.41  What terms must I include in my OSFR evidence?

    (a) Each instrument you submit as OSFR evidence must specify:
    (1) The effective date, and except for a surety bond, the expiration 
date;
    (2) That termination of the instrument will not affect the liability 
of the instrument issuer for claims arising from an incident (i.e., oil-
spill discharge or substantial threat of the discharge of oil) that 
occurred on or before the effective date of termination;
    (3) That the instrument will remain in force until the termination 
date or until the earlier of:
    (i) Thirty calendar days after BOEM and the designated applicant 
receive from the instrument issuer a notification of intent to cancel; 
or
    (ii) BOEM receives from the designated applicant other acceptable 
OSFR evidence; or
    (iii) All the COFs to which the instrument applies are permanently 
abandoned in compliance with 30 CFR part 250 or equivalent State 
requirements;
    (4) That the instrument issuer agrees to direct action for claims 
made under OPA up to the guaranty amount, subject to the defenses in 
paragraph (a)(6) of this section and following the procedures in Sec.  
553.60 of this part;
    (5) An agent in the United States for service of process; and
    (6) That the instrument issuer will not use any defenses against a 
claim made under OPA except:
    (i) The rights and defenses that would be available to a designated 
applicant or responsible party for whom the guaranty was provided; and
    (ii) The incident (i.e., oil-spill discharge or a substantial threat 
of the discharge of oil) leading to the claim for removal costs or 
damages was caused by willful misconduct of a responsible party for whom 
the designated applicant demonstrated OSFR.
    (b) You may not change, omit, or add limitations or exceptions to 
the terms and conditions in a BOEM form that you submit as part of your 
OSFR demonstration. If you attempt to do this, BOEM will disregard the 
changes, omissions, additions, limitations, or exceptions and by 
operation of this rule BOEM will consider the form to contain all the 
terms and conditions included on the original BOEM form.



Sec.  553.42  How can I amend my list of COFs?

    (a) If you want to add a COF that is not identified in your current 
OSFR demonstration, you must submit to BOEM a completed Form BOEM-1022. 
If applicable, you also must submit any additional indemnities, surety 
bonds, insurance certificates, or other instruments required to extend 
the coverage of your original OSFR demonstration to the COFs to be 
added. You do not need to resubmit previously accepted audited annual 
financial statements for the current fiscal year.
    (b) If you want to drop a COF identified in your current OSFR 
demonstration, you must submit to BOEM a completed Form BOEM-1022. You 
must continue to demonstrate OSFR for the COF until BOEM approves OSFR 
evidence for the COF from another designated applicant, or OSFR is no 
longer required (e.g., until a well that is a COF is properly plugged 
and abandoned).



Sec.  553.43  When is my OSFR demonstration or the amendment to my
 OSFR demonstration effective?

    (a) BOEM will notify you in writing when we approve your OSFR 
demonstration. If we find that you have not submitted all the 
information needed to demonstrate OSFR, we may require you to provide 
additional information before we determine whether your OSFR evidence is 
acceptable.
    (b) Except in the case of self-insurance or an indemnity, BOEM 
acceptance of OSFR evidence is valid until the surety bond, insurance 
certificate, or other accepted OSFR instrument expires or is canceled. 
In the case of self-insurance or indemnity, acceptance is valid until 
the first day of the 5th month after the close of your or your 
indemnitor's current fiscal year.

[[Page 467]]



Sec.  553.44  [Reserved]



Sec.  553.45  Where do I send my OSFR evidence?

    Address all correspondence and required submissions related to this 
part to: U.S. Department of the Interior, Bureau of Ocean Energy 
Management, Gulf of Mexico Region, Oil Spill Financial Responsibility 
Program, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123.



                   Subpart E_Revocation and Penalties



Sec.  553.50  How can BOEM refuse or invalidate my OSFR evidence?

    (a) If BOEM determines that any OSFR evidence you submit fails to 
comply with the requirements of this part, we may not accept it. If we 
do not accept your OSFR evidence, then we will send you a written 
notification stating:
    (1) That your evidence is not acceptable;
    (2) Why your evidence is unacceptable; and
    (3) The amount of time you are allowed to submit acceptable evidence 
without being subject to civil penalty under Sec.  553.51.
    (b) BOEM may immediately and without prior notice invalidate your 
OSFR demonstration if you:
    (1) Are no longer eligible to be the designated applicant for a COF 
included in your demonstration; or
    (2) Permit the cancellation or termination of the insurance policy, 
surety bond, or indemnity upon which the continued validity of the 
demonstration is based.
    (c) If BOEM determines you are not complying with the requirements 
of this part for any reason other than paragraph (b) of this section, we 
will notify you of our intent to invalidate your OSFR demonstration and 
specify the corrective action needed. Unless you take the corrective 
action BOEM specifies within 15 calendar days from the date you receive 
such a notice, we will invalidate your OSFR demonstration.



Sec.  553.51  What are the penalties for not complying with this part?

    (a) If you fail to comply with the financial responsibility 
requirements of OPA at 33 U.S.C. 2716 or with the requirements of this 
part, then you may be liable for a civil penalty of up to $47,357 per 
COF per day of violation (that is, each day a COF is operated without 
acceptable evidence of OSFR).
    (b) BOEM will determine the date of a noncompliance. BOEM will 
assess penalties in accordance with an OSFR penalty schedule using the 
procedures found at 30 CFR part 550, subpart N. You may obtain a copy of 
the penalty schedule from BOEM at the address in Sec.  553.45.
    (c) BOEM may assess a civil penalty against you that is greater or 
less than the amount in the penalty schedule after taking into account 
the factors in section 4303(a) of OPA (33 U.S.C. 2716a).
    (d) If you fail to correct a deficiency in the OSFR evidence for a 
COF, then the Director may suspend operation of a COF in the OCS under 
30 CFR 250.170 or seek judicial relief, including an order suspending 
the operation of any COF.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 43069, July 1, 2016; 82 
FR 10711, Feb. 15, 2017; 83 FR 8933, Mar. 2, 2018; 84 FR 11224, Mar. 26, 
2019]



        Subpart F_Claims for Oil-Spill Removal Costs and Damages



Sec.  553.60  To whom may I present a claim?

    (a) If you are a claimant, you must present your claim first to the 
designated applicant for the COF that is the source of the incident 
resulting in your claim. If, however, the designated applicant has filed 
a petition for bankruptcy under 11 U.S.C. chapter 7 or 11, you may 
present your claim first to any of the designated applicant's 
guarantors.
    (b) If the claim you present to the designated applicant or 
guarantor is denied or not paid within 90 days after you first present 
it or advertising begins, whichever is later, then you may seek any of 
the following remedies that apply:

[[Page 468]]



------------------------------------------------------------------------
 If the reason for denial or nonpayment is
                   . . .                     Then you may elect to . . .
------------------------------------------------------------------------
(1) Not an assertion of insolvency or       (i) Present your claim to
 petition in bankruptcy under 11 U.S.C.      any of the responsible
 chapter 7 or 11,                            parties for the COF; or
                                            (ii) Initiate a lawsuit
                                             against the designated
                                             applicant and/or any of the
                                             responsible parties for the
                                             COF; or
                                            (iii) Present your claim to
                                             the Fund using the
                                             procedures at 33 CFR part
                                             136.
(2) An assertion of insolvency or petition  (i) Pursue any of the
 in bankruptcy under 11 U.S.C. chapter 7     remedies in items (1)(i)
 or 11,                                      through (iii) of this
                                             table; or
                                            (ii) Present your claim to
                                             any of the designated
                                             applicant's guarantors; or
                                            (iii) Initiate a lawsuit
                                             against any of the
                                             designated applicant's
                                             guarantors.
------------------------------------------------------------------------

    (c) If no one has resolved your claim to your satisfaction using the 
remedy that you elected under paragraph (b) of this section, then you 
may pursue another available remedy, unless the Fund has denied your 
claim or a court of competent jurisdiction has ruled against your claim. 
You may not pursue more than one remedy at a time.
    (d) You may ask BOEM to assist you in determining whether a 
guarantor may be liable for your claim. Send your request for assistance 
to the address listed in Sec.  553.45. You must include any information 
you have regarding the existence or identity of possible guarantors.



Sec.  553.61  When is a guarantor subject to direct action for claims?

    (a) If you are a guarantor, then you are subject to direct action 
for any claim asserted by:
    (1) The United States for any compensation paid by the Fund under 
OPA, including compensation claim processing costs; and
    (2) A claimant other than the United States if the designated 
applicant has:
    (i) Denied or failed to pay a claim because of being insolvent; or
    (ii) Filed a petition in bankruptcy under 11 U.S.C. chapters 7 or 
11.
    (b) If you participate in an insurance guaranty for a COF incident 
(i.e., oil-spill discharge or substantial threat of the discharge of 
oil) that is subject to claims under this part, then your maximum, 
aggregate liability for those claims is equal to your quota share of the 
insurance guaranty.



Sec.  553.62  What are the designated applicant's notification 
obligations regarding a claim?

    If you are a designated applicant, and you receive a claim for 
removal costs and damages, then within 15 calendar days of receipt of a 
claim you must notify:
    (a) Your guarantors; and
    (b) The responsible parties for whom you are acting as the 
designated applicant.



          Subpart G_Limit of Liability for Offshore Facilities

    Source: 79 FR 73840, Dec. 12, 2014, unless otherwise noted.



Sec.  553.700  What is the scope of this subpart?

    This subpart sets forth the limit of liability for damages for 
offshore facilities under Title I of the Oil Pollution Act of 1990, as 
amended (33 U.S.C. 2701 et seq.) (OPA), as adjusted, under section 
1004(d) of OPA (33 U.S.C. 2704(d)). This subpart also sets forth the 
method for adjusting the limit of liability for damages for offshore 
facilities for inflation, by regulation, under section 1004(d) of OPA 
(33 U.S.C. 2704(d)).



Sec.  553.701  To which entities does this subpart apply?

    This subpart applies to you if you are a responsible party for an 
offshore facility, other than a deepwater port under the Deepwater Port 
Act of 1974 (33 U.S.C. 1501-1524), but including an offshore pipeline, 
or an abandoned offshore facility, including any abandoned offshore 
pipeline, unless your liability is unlimited under OPA 90 (33 U.S.C. 
2704(c)).

[[Page 469]]



Sec.  553.702  What limit of liability applies to my offshore facility?

    Except as provided in 33 U.S.C. 2704(c), the limit of liability 
under OPA for a responsible party for any offshore facility, including 
any offshore pipeline, is the total of all removal costs plus $137.6595 
million for damages with respect to each incident.

[83 FR 2542, Jan. 18, 2018]



Sec.  553.703  What is the procedure for calculating the limit of
 liability adjustment for inflation?

    The procedure for calculating limit of liability adjustments for 
inflation is as follows:
    (a) Formula for calculating a cumulative percent change in the 
Annual CPI-U. BOEM calculates the cumulative percent change in the 
Annual CPI-U from the year the limit of liability was established by 
statute, or last adjusted by regulation, whichever is later (i.e., the 
Previous Period), to the year in which the Annual CPI-U is most recently 
published (i.e., the Current Period), using the following formula: 
Percent change in the Annual CPI-U = [(Annual CPI-U for Current Period - 
Annual CPI-U for Previous Period) / Annual CPI-U for Previous Period] x 
100. This cumulative percent change value is rounded to one decimal 
place.
    (b) Significance threshold. (1) A cumulative increase in the Annual 
CPI-U equal to three percent or more constitutes a significant increase 
in the Consumer Price Index within the meaning of 33 U.S.C. 2704(d)(4).
    (2) Not later than every three years from the year the limit of 
liability was last adjusted for inflation, BOEM will evaluate whether 
the cumulative percent change in the Annual CPI-U since that year has 
reached a significance threshold of three percent or greater.
    (3) For any three-year period evaluated under paragraph (b)(2) of 
this section in which the cumulative percent increase in the Annual CPI-
U is less than three percent, if BOEM has not issued an inflation 
adjustment during that period, BOEM will publish a notice of no 
inflation adjustment to the offshore facility limit of liability for 
damages in the Federal Register.
    (4) Once the three-percent threshold is reached, BOEM will increase 
by final rule the offshore facility limit of liability for damages in 
Sec.  553.702 by an amount equal to the cumulative percent change in the 
Annual CPI-U from the year the limit was established by statute, or last 
adjusted by regulation, whichever is later. After this adjustment is 
made, BOEM will resume its process of conducting a review every three 
years.
    (5) Nothing in this section will prevent BOEM, in BOEM's sole 
discretion, from adjusting the offshore facility limit of liability for 
damages for inflation by regulation issued more frequently than every 
three years.
    (c) Formula for calculating inflation adjustments. BOEM calculates 
adjustments to the offshore facility limit of liability in 30 CFR 
553.702 for inflation using the following formula:

New limit of liability = Previous limit of liability + (Previous limit 
of liability x the decimal equivalent of the percent change in the 
Annual CPI-U calculated under paragraph (a) of this section), then 
rounded to the closest $100.



Sec.  553.704  How will BOEM publish the offshore facility limit of 
liability adjustment?

    BOEM will publish the inflation-adjusted limit of liability, and any 
statutory amendments to that limit of liability in the Federal Register, 
as amendments to Sec.  553.702. Updates to the limit of liability under 
this section are effective on the 90th day after publication in the 
Federal Register of the amendments to Sec.  553.702, unless otherwise 
specified by statute (in the event of a statutory amendment to the limit 
of liability), or in the Federal Register rule amending Sec.  553.702.



 Sec. Appendix to Part 553--List of U.S. Geological Survey Topographic 
                                  Maps

    Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; Bridgehead; 
Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; Grand Bay SW; 
Gulf Shores; Heron Bay; Hollingers Island; Isle Aux Herbes; Kreole; 
Lillian; Little Dauphin Island; Little Point Clear; Magnolia Springs; 
Mobile; Orange Beach; Perdido Beach; Petit Bois Island; Petit Bois Pass; 
Pine Beach; Point Clear; Saint Andrews Bay; West Pensacola.

[[Page 470]]

    Alaska (1:63,360 scale): Afognak (A-1, A-2, A-3, A-4, A-5, A-0&B-0, 
B-1, B-2, B-3, C-1&2, C-2&3, C-5, C-6, D-1, D-4, D-5); Anchorage (A-1, 
A-2, A-3, A-4, A-8, B-7, B-8); Barrow (A-1, A-2, A-3, A-4, A-5, B-3, B-
4); Baird Mts. (A-6); Barter Island (A-3, A-4, A-5); Beechy Point (A-1, 
A-2, B-1, B-2, B-3, B-4, B-5, C-4, C-5); Bering Glacier (A-1, A-2, A-3, 
A-4, A-5, A-6, A-7, A-8); Black (A-1, A-2, B-1, C-1); Blying Sound (C-7, 
C-8, D-1&2, D-3, D-4, D-5, D-6, D-7, D-8); Candle (D-6); Cordova (A-1, 
A-2, A-3, A-4, A-7&8, B-2, B-3, B-4, B-5, B-6, B-7, B-8, C-5, C-6, C-7, 
C-8, D-6, D-7, D-8); De Long Mts. (D-4, D-5); Demarcation Point (C-1, C-
2, D-2, D-3); Flaxman Island (A-1, A-3, A-4, A-5, B-5); Harrison Bay (B-
1, B-2, B-3, B-4, C-1, C-3, C-4, C-5, D-4, D-5); Icy Bay (D1, D-2&3); 
Iliamna (A-2, A-3, A-4, B-2, B-3, C-1, C-2, D-1); Karluk (A-1, A-2, B-2, 
B-3, C-1, C-2, C-4&5, C-6); Kenai (A-4, A-5, A-7, A-8, B-4, B-6, B-7, B-
8, C-4, C-5, C-6, C-7, D-1, D-2, D-3, D-4, D-5); Kodiak (A-3, A-4, A-5, 
A-6, B-1&2, B-3, B-4, B-6, C-1, C-2, C-3, C-5, C-6, D-1, D-2, D-3, D-4, 
D-5, D-6); Kotzebue (A-1, A-2, A-3, A-4, B-4, B-6, C-1, C-4, C-5, C-6, 
D-1, D-2); Kwiguk (C-6, D-6); Meade River (D-1, D-3, D-4, D-5); 
Middleton Island (B-7, D-1&2); Mt. Katmai (A-1, A-2, A-3; B-1); Mt. 
Michelson (D-1, D-2, D-3); Mt. St. Elias (A-5); Noatak (A-1, A-2, A-3, 
A-4, B-4, C-4, C-5, D-6, D-7); Nome (B-1, C-1, C-2, C-3, D-3, D-4, D-7); 
Norton Bay (A-4, B-4, B-5, B-6, C-4, C-5, C-6, D-4, D-5, D-6); Point 
Hope (A-1, A-2, B-2, B-3, C-2, C-3, D-1, D-2); Point Lay (A-3&4, B-2&3, 
C-2, D-1, D-2); Selawik (A-5, A-6, B-5, B-6, C-5, C-6, D-6); Seldovia 
(A-3, A-4, A-5, A-6, B-1, B-2, B-3, B-4, B-5, B-6, C-1, C-2, C-3, C-4, 
C-5, D-1, D-3, D-4, D-5, D-8); Seward (A-1, A-2, A-3, A-4, A-5, A-6, A-
7, B-1, B-2, B-3, B-4, B-5, C-1, C-2, C-3, C-4, C-5, D-1, D-2, D-3, D-4, 
D-5, D-6, D-7, D-8); Shishmaref (A-2, A-3, A-4, B-1, B-2, B-3); Solomon 
(B-2, B-3, B-6, C-1, C-2, C-3, C-4, C-5, C-6); St. Michael (A-2, A-3, A-
4, A-5, A-6, B-1, B-2, C-1, C-2); Teller (A-2, A-3, A-4, B-3, B-4, B-5, 
B-6, C-6, C-7, D-4, D-5, D-6, D-8); Teshekpuk (D-1, D-2, D-3, D-4, D-5); 
Tyonek (A-1, A-2, A-3, A-4, B-1, B-2); Unalakleet (B-5, B-6, C-4, C-5, 
D-4); Valdez (A-7, A-8); Wainwright (A-5, A-6&7, B-2, B-3, B-4, B-5&6, 
C-2, C-3, D-1, D-2; Yakutat (A-1, A-2, A-2, B-3, B-4, B-5, C-4, C-5, C-
6, C-7, C-8, D-3, D-4, D-5, D-6, D-8).
    California (1:24,000 scale): Arroyo Grande NE; Beverly Hills; 
Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon; 
Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; La 
Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; Malibu 
Beach; Morro Bay South; National City; Newport Beach; Oceano; Oceanside; 
Oxnard; Pismo Beach; Pitas Point; Point Arguello; Point Conception; 
Point Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho 
Santa Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San 
Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal 
Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; Triunfo 
Pass; Tustin; Venice; Ventura; White Ledge Peak.
    Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria; 
Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee Ridge; 
Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird Keys; 
Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; Bunker; 
Cape Romano; Cape Saint George; Cape San Blas; Captiva; Carrabelle; 
Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland SW; Choctaw 
Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; Cockroach Bay; 
Crawfordville East; Crooked Island; Crooked Point; Cross City SW; 
Crystal River; Destin; Dog Island; Dunedin; East Pass; Egmont Key; El 
Jobean; Elfers; Englewood; Englewood NW; Estero; Everglades City; Fivay 
Junction; Flamingo; Fort Barrancas; Fort Myers Beach; Fort Myers SW; 
Fort Walton Beach; Freeport; Gandy Bridge; Garcon Point; Gator Hook 
Swamp; Gibsonton; Goose Island; Grayton Beach; Green Point; Gulf Breeze; 
Harney River; Harold SE; Holley; Holt SW; Homosassa; Horseshoe Beach; 
Indian Pass; Jackson River; Jena; Keaton Beach; Laguna Beach; Lake 
Ingraham East; Lake Ingraham West; Lake Wimico; Laurel; Lebanon Station; 
Lighthouse Point; Lillian; Long Point; Lostmans River Ranger Station; 
Manlin Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton 
South; Miramar Beach; Myakka River; Naples North; Naples South; Navarre; 
New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee Slough; Oldsmar; 
Orange Beach; Oriole Beach; Overstreet; Ozello; Pace; Palmetto; Panama 
City; Panama City Beach; Panther Key; Pass-A-Grille Beach; Pavillion 
Key; Pensacola; Perdido Bay; Pickett Bay; Pine Island Center; Placida; 
Plover Key; Point Washington; Port Boca Grande; Port Richey; Port Richey 
NE; Port Saint Joe; Port Tampa; Punta Gorda; Punta Gorda SE; Punta Gorda 
SW; Red Head; Red Level; Rock Islands; Royal Palm Hammock; Safety 
Harbor; Saint Joseph Point; Saint Joseph Spit; Saint Marks; Saint Marks 
NE; Saint Petersburg; Saint Teresa Beach; Salem SW; Sandy Key; Sanibel; 
Sarasota; Seahorse Key; Seminole; Seminole Hills; Shark Point; Shark 
River Island; Shired Island; Snipe Island; Sopchoppy; South of Holley; 
Southport; Sprague Island; Spring Creek; Springfield; Steinhatchee; 
Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; Tampa; 
Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; Ward Basin; 
Warrior Swamp; Weavers Station; Weeki Wachee Spring; West Bay; West 
Pass; West Pensacola; Whitewater Bay West; Withlacoochee Bay; Wulfert; 
Yankeetown.
    Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; Bastian 
Bay; Bay Batiste;

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Bay Coquette; Bay Courant; Bay Dosgris; Bay Ronquille; Bay Tambour; 
Bayou Blanc; Bayou Lucien; Belle Isle; Belle Pass; Big Constance Lake; 
Black Bay North; Black Bay South; Breton Islands; Breton Islands SE; 
Buras; Burrwood Bayou East; Burwood Bayou West; Calumet Island; Cameron; 
Caminada Pass; Cat Island; Cat Island Pass; Central Isles Dernieres; 
Chandeleur Light; Chef Mentur; Cheniere Au Tigre; Cocodrie; Coquille 
Point; Cow Island; Creole; Cypremort Point; Deep Lake; Dixon Bay; Dog 
Lake; Door Point; East Bay Junop; Eastern Isles; Dernieres; Ellerslie; 
Empire; English Lookout; False Mouth Bayou; Fearman Lake; Floating Turf 
Bayou; Fourleague Bay; Franklin; Freemason Island; Garden Island Pass; 
Grand Bayou; Grand Bayou du Large; Grand Chenier; Grand Gosier Islands; 
Grand Isle; Hackberry Beach; Hammock Lake; Happy Jack; Hebert Lake; Hell 
Hole Bayou; Hog Bayou; Holly Beach; Intercoastal City; Isle Au Pitre; 
Jacko Bay; Johnson Bayou; Kemper; Lake Athanasio; Lake Cuatro Caballo; 
Lake Eloi; Lake Eugene; Lake Felicity; Lake La Graisse; Lake Merchant; 
Lake Point; Lake Salve; Lake Tambour; Leeville; Lena Lagoon; Lost Lake; 
Main Pass; Malheureux Point; Marone Point; Martello Castle; Mink Bayou; 
Mitchell Key; Morgan City SW; Morgan Harbor; Mound Point; Mulberry 
Island East; Mulberry Island West; New Harbor Islands; North Islands; 
Oak Mound Bayou; Oyster Bayou; Pass A Loutre East; Pass A Loutre West; 
Pass du Bois; Pass Tante Phine; Pecan Island; Pelican Pass; Peveto 
Beach; Pilottown; Plumb Bayou; Point Au Fer; Point Au Fer NE; Point 
Chevreuil; Point Chicot; Port Arthur South; Port Sulphur; Pte. Aux 
Marchuttes; Proctor Point; Pumpkin Islands; Redfish Point; Rollover 
Lake; Sabine Pass; Saint Joe Pass; Smith Bayou; South of South Pass; 
South Pass; Stake Islands; Taylor Pass; Texas Point; Three Mile Bay; 
Tigre Lagoon; Timbalier Island; Triumph; Venice; Weeks; West of Johnson 
Bayou; Western Isles Dernieres; Wilkinson Bay; Yscloskey.
    Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island; 
Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier 
North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW; 
Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre; 
Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass 
Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.
    Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; 
Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; 
Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; 
Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; 
Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport; 
Frozen Point; Galveston; Green Island; Hawk Island; High Island; 
Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La 
Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake 
Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria 
Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay; 
Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of 
Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek 
NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE; 
Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point 
Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar; 
Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port 
Mansfield; Port O'Connor; Portland; Potrero Cortado; Potrero Lopeno NW; 
Potrero Lopeno SE; Potrero Lopeno SW; Rockport; Sabine Pass; San Luis 
Pass; Sargent; Sea Isle; Seadrift; Seadrift NE; Smith Point; South Bird 
Island; South Bird Island NW; South Bird Island SE; South of Palacios 
Point; South of Potrero Lopeno NE; South of Potrero Lopeno NW; South of 
Potrero Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay 
SE; St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties; 
Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia Point; 
West of Johnson Bayou; Whites Ranch; Yarborough Pass.



PART 556_LEASING OF SULFUR OR OIL AND GAS AND BONDING REQUIREMENTS
 IN THE OUTER CONTINENTAL SHELF--Table of Contents



                      Subpart A_General Provisions

Sec.
556.100 Statement of policy.
556.101 Purpose.
556.102 Authority.
556.103 Cross references.
556.104 Information collection and proprietary information.
556.105 Acronyms and definitions.
556.106 Service fees.
556.107 Corporate seal requirements.

             Subpart B_Oil and Gas Five Year Leasing Program

556.200 What is the Five Year leasing program?
556.201 Does BOEM consider multiple uses of the OCS?
556.202 How does BOEM start the Five Year program preparation process?
556.203 What does BOEM do before publishing a proposed Five Year 
          program?

[[Page 472]]

556.204 How do Governments and citizens comment on a proposed Five Year 
          program?
556.205 What does BOEM do before approving a proposed final Five Year 
          program or a significant revision of a previously-approved 
          Five Year program?

               Subpart C_Planning and Holding a Lease Sale

556.300 What reports may BOEM and other Federal agencies prepare before 
          a lease sale?
556.301 What is a Call for Information and Nominations?
556.302 What does BOEM do with the information from the Call?
556.303 What does BOEM do if an area proposed for leasing is within 
          three nautical miles of the seaward boundary of a coastal 
          State?
556.304 How is a proposed notice of sale prepared?
556.305 How does BOEM coordinate and consult with States regarding a 
          proposed notice of sale?
556.306 What if a potentially oil or gas bearing area underlies both the 
          OCS and lands subject to State jurisdiction?
556.307 What does BOEM do with comments and recommendations received on 
          the proposed notice of sale?
556.308 How does BOEM conduct a lease sale?
556.309 Does BOEM offer blocks in a sale that is not on the Five Year 
          program schedule (called a Supplemental Sale)?

                        Subpart D_Qualifications

556.400 When must I demonstrate that I am qualified to hold a lease on 
          the OCS?
556.401 What do I need to show to become qualified to hold a lease on 
          the OCS and obtain a qualification number?
556.402 How do I make the necessary showing to qualify and obtain a 
          qualification number?
556.403 Under what circumstances may I be disqualified from holding a 
          lease on the OCS?
556.404 What do the non-procurement debarment rules require that I do?
556.405 When must I notify BOEM of mergers, name changes, or changes of 
          business form?

                      Subpart E_Issuance of a Lease

                               How To Bid

556.500 Once qualified, how do I submit a bid?
556.501 What information do I need to submit with my bid?

                      Restrictions on Joint Bidding

556.511 Are there restrictions on bidding with others and do those 
          restrictions affect my ability to bid?
556.512 What bids may be disqualified?
556.513 When must I file a statement of production?
556.514 How do I determine my production for purposes of the restricted 
          joint bidders list?
556.515 May a person be exempted from joint bidding restrictions?

                       How does BOEM act on bids?

556.516 What does BOEM do with my bid?
556.517 What may I do if my bid is rejected?

                           Awarding the Lease

556.520 What happens if I am the successful high bidder and BOEM accepts 
          my bid?
556.521 When is my lease effective?
556.522 What are the terms and conditions of the lease and when are they 
          published?

                  Subpart F_Lease Terms and Obligations

                             Length of Lease

556.600 What is the primary term of my oil and gas lease?
556.601 How may I maintain my oil and gas lease beyond the primary term?
556.602 What is the primary term of my sulfur lease?
556.603 How may I maintain my sulfur lease beyond the primary term?

                            Lease Obligations

56.604 What are my rights and obligations as a record title owner?
556.605 What are my rights and obligations as an operating rights owner?

                                 Helium

556.606 What must a lessee do if BOEM elects to extract helium from a 
          lease?

  Subpart G_Transferring All or Part of the Record Title Interest in a 
                                  Lease

556.700 May I assign or sublease all or any part of the record title 
          interest in my lease?
556.701 How do I seek approval of an assignment of the record title 
          interest in my lease, or a severance of operating rights from 
          that record title interest?
556.702 When will my assignment result in a segregated lease?
556.703 What is the effect of the approval of the assignment of 100 
          percent of the record title in a particular aliquot(s) of my 
          lease and the resulting lease segregation?

[[Page 473]]

556.704 When would BOEM disapprove an assignment or sublease of an 
          interest in my lease?
556.705 How do I transfer the interest of a deceased natural person who 
          was a lessee?
556.706 What if I want to transfer record title interests in more than 
          one lease at the same time, but to different parties?
556.707 What if I want to transfer different types of lease interests 
          (not only record title interests) in the same lease to 
          different parties?
556.708 What if I want to transfer my record title interests in more 
          than one lease to the same party?
556.709 What if I want to transfer my record title interest in one lease 
          to multiple parties?
556.710 What is the effect of an assignment of a lease on an assignor's 
          liability under the lease?
556.711 What is the effect of a record title holder's sublease of 
          operating rights on the record title holder's liability?
556.712 What is the effective date of a transfer?
556.713 What is the effect of an assignment of a lease on an assignee's 
          liability under the lease?
556.714 As a restricted joint bidder, may I transfer an interest to 
          another restricted joint bidder?
556.715 Are there any interests I may transfer or record without BOEM 
          approval?
556.716 What must I do with respect to the designation of operator on a 
          lease when a transfer of record title is submitted?

    Subpart H_Transferring Operating Rights in All or Part of a Lease

556.800 As an operating rights owner, may I assign all or part of my 
          operating rights interest?
556.801 How do I seek approval of an assignment of my operating rights?
556.802 When would BOEM disapprove the assignment of all or part of my 
          operating rights interest?
556.803 What if I want to assign operating rights interests in more than 
          one lease at the same time, but to different parties?
556.804 What if I want to assign my operating rights interest in a lease 
          to multiple parties?
556.805 What is the effect of an operating rights owner's assignment of 
          operating rights on the assignor's liability?
556.806 What is the effective date of an assignment of operating rights?
556.807 What is the effect of an assignment of operating rights on an 
          assignee's liability?
556.808 As an operating rights owner, are there any interests I may 
          assign without BOEM approval?
556.809 [Reserved]
556.810 What must I do with respect to the designation of operator on a 
          lease when a transfer of operating rights ownership is 
          submitted?

             Subpart I_Bonding or Other Financial Assurance

556.900 Bond requirements for an oil and gas or sulfur lease.
556.901 Additional bonds.
556.902 General requirements for bonds.
556.903 Lapse of bond.
556.904 Lease-specific abandonment accounts.
556.905 Using a third-party guarantee instead of a bond.
556.906 Termination of the period of liability and cancellation of a 
          bond.
556.907 Forfeiture of bonds and/or other securities.

    Subpart J_Bonus or Royalty Credits for Exchange of Certain Leases

556.1000 Leases formerly eligible for a bonus or royalty credit.

                        Subpart K_Ending a Lease

556.1100 How does a lease expire?
556.1101 May I relinquish my lease or an aliquot part thereof?
556.1102 Under what circumstances will BOEM cancel my lease?

          Subpart L_Leases Maintained Under Section 6 of OCSLA

556.1200 Effect of regulations on lease.
556.1201 Section 6(a) leases and leases other than those for oil, gas, 
          or sulfur.

                     Subpart M_Environmental Studies

556.1300 Environmental studies.

    Authority: 30 U.S.C. 1701 note, 30 U.S.C. 1711, 31 U.S.C. 9701, 42 
U.S.C. 6213, 43 U.S.C. 1331 note, 43 U.S.C. 1334, 43 U.SC. 1801-1802.

    Source: 81 FR 18152, Mar. 30, 2016, unless otherwise noted.



                      Subpart A_General Provisions



Sec.  556.100  Statement of policy.

    The management of Outer Continental Shelf (OCS) resources is to be 
conducted in accordance with the findings, purposes, and policy 
directions provided by the Outer Continental Shelf Lands Act Amendments 
of 1978 (OCSLA or the Act) (43 U.S.C. 1332,

[[Page 474]]

1801, 1802), and other executive, legislative, judicial and departmental 
guidance. The Secretary of the Interior (the Secretary) will consider 
available environmental information in making decisions affecting OCS 
resources.



Sec.  556.101  Purpose.

    The purpose of the regulations in this part is to establish the 
procedures under which the Secretary will exercise the authority to 
administer a leasing program for oil and gas, and sulfur. The 
regulations pertaining to the procedures under which the Secretary will 
exercise the authority to administer a program to grant rights-of-use 
and easements are found in part 550 of this chapter.



Sec.  556.102  Authority.

    (a) The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1334) 
authorizes the Secretary of the Interior to issue, on a competitive 
basis, leases for oil and gas, and sulfur, in submerged lands of the 
OCS. The Act authorizes the Secretary to grant rights-of-way and 
easements through the submerged lands of the OCS.
    (b) The Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA) 
(30 U.S.C. 1711) governs oil and gas royalty management and requires the 
development of enforcement practices to ensure the prompt and proper 
collection of oil and gas revenues owed to the U.S.
    (c) The Independent Offices Appropriations Act of 1952 (IOAA) (31 
U.S.C. 9701) authorizes fees and charges for Federal government 
services.
    (d) The Energy Policy and Conservation Act of 1975 (42 U.S.C. 6213) 
prohibits joint bidding by major oil and gas producers.
    (e) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) (Pub. L. 
109-432, 43 U.S.C. 1331 note):
    (1) Shares leasing revenues with Gulf producing states and the Land 
& Water Conservation Fund for coastal restoration projects; and
    (2) Allows companies to exchange certain existing leases in 
moratorium areas for bonus and royalty credits to be used on other Gulf 
of Mexico leases.



Sec.  556.103  Cross references.

    The following includes some of the major regulations relevant to 
offshore oil and gas development:
    (a) For other applicable Bureau of Ocean Energy Management (BOEM) 
oil and gas regulations, see 30 CFR parts 550 through 560.
    (b) For Bureau of Safety and Environmental Enforcement (BSEE) 
regulations governing exploration, development and production, and oil 
spill response, see 30 CFR chapter II.
    (c) For Office of Natural Resources Revenue (ONRR) regulations 
related to rentals, royalties, and fees, see 30 CFR chapter XII.
    (d) For BOEM regulations governing the appeal of an order or 
decision issued under the regulations in this part, see 30 CFR part 590.
    (e) For regulations on the National Environmental Policy Act (NEPA), 
see 40 CFR 1500-1508 and 43 CFR part 46.
    (f) For ocean dumping sites, see the U.S. Environmental Protection 
Agency (USEPA) listing--40 CFR part 228.
    (g) For air quality, see USEPA regulations at 40 CFR part 55 and 
BOEM regulations at 30 CFR part 550 subparts B and C.
    (h) For related National Oceanic and Atmospheric Administration 
(NOAA) programs, see:
    (1) Marine Sanctuary regulations, 15 CFR part 922;
    (2) Fishermen's Contingency Fund, 50 CFR part 296;
    (3) Coastal Zone Management Act (CZMA), 15 CFR part 930;
    (4) Essential Fish Habitat, 50 CFR 600.90.
    (i) For U.S. Coast Guard (USCG) regulations on the oil spill 
liability of vessels and operators, see 33 CFR parts 132, 135, and 136.
    (j) For USCG regulations on port access routes, see 33 CFR part 164.
    (k) For Department of Transportation regulations on offshore 
pipeline facilities, see 49 CFR part 195.
    (1) For Department of Defense regulations on military activities on 
offshore areas, see 32 CFR part 252.



Sec.  556.104  Information collection and proprietary information.

    (a) Information collection. (1) The Office of Management and Budget 
(OMB)

[[Page 475]]

approved the collection of information under 44 U.S.C. 3501-3521), and 
assigned OMB Control Number 1010-0006. The title of this collection of 
information is ``Leasing of Sulfur or Oil and Gas in the Outer 
Continental Shelf (30 CFR part 550, part 556, and part 560).''
    (2) BOEM collects this information to determine if an applicant 
seeking to obtain a lease or right-of-use and easement (RUE) on the OCS 
is qualified to hold such a lease or RUE and to determine whether any 
such applicant can meet the monetary and non-monetary requirements 
associated with a lease or RUE. Responses to this information collection 
are either required to obtain or retain a benefit or are mandatory under 
OCSLA (43 U.S.C. 1331-1356a). BOEM will protect proprietary information 
collected according to section 26 of OCSLA (43 U.S.C. 1352), and this 
section.
    (3) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521) 
requires us to inform the public that an agency may not conduct or 
sponsor, and that no one is required to respond to, a collection of 
information unless it displays a current and valid OMB control number.
    (4) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, by mail at 45600 Woodland Road, Sterling, VA 20166 or 
by email to [email protected], or by phone at (703) 787-1025.
    (b) Proprietary information. (1) Any proprietary information 
maintained by BOEM will be subject to the requirements of 43 CFR part 2.
    (2) No proprietary information received by BOEM under 43 U.S.C. 
1352(c) will be transmitted to any affected State unless the lessee, to 
whom such information applies, or the permittee and all persons, to whom 
such permittee has sold such information under promise of 
confidentiality, agree to such transmittal.
    (c) Proprietary information in response to a Call for Information 
and Nominations (Call).
    (1) A specific indication of interest in an area received in 
response to a Call issued by the Secretary is proprietary information.
    (2) Notwithstanding paragraph (c)(1) of this section, BOEM may 
provide a summary of indications of interest in areas received in 
response to a Call for a proposed sale.



Sec.  556.105  Acronyms and definitions.

    (a) Acronyms and terms used in this part have the following 
meanings:

ASTM American Society for Testing and Materials
BAST Best Available and Safest Technology
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
CFR Code of Federal Regulations
CPA Central Planning Area of the GOM
CZMA Coastal Zone Management Act
DOI Department of the Interior
DOCD Development Operations Coordination Document
DOO Designation of Operator
DPP Development and Production Plan
EIA Environmental Impact Analysis
EP Exploration Plan
EPA Eastern Planning Area of the GOM
EPAct Energy Policy Act of 2005
FNOS Final Notice of Sale
FOGRMA Federal Oil and Gas Royalty Management Act of 1982
G&G Geological and Geophysical
GDIS Geophysical Data and Information Statement
GOM Gulf of Mexico
GOMESA Gulf of Mexico Energy Security Act of 2006
IOAA Independent Offices Appropriations Act of 1952
LLC Limited Liability Company
MBB Mapping and Boundary Branch
NAD North American Datum
NEPA National Environmental Policy Act of 1969
NGPA Natural Gas Processors Association
NOAA National Oceanic and Atmospheric Administration
NTL Notice to Lessees
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OMB Office of Management and Budget
ONRR Office of Natural Resources Revenue
OPD Official Protraction Diagram
PNOS Proposed Notice of Sale
PRA Paperwork Reduction Act
ROW Right of way
RSV Royalty Suspension Volume
RUE Right of Use and Easement
SLA Submerged Lands Act of 1953
U.S. United States
U.S.C. United States Code
USCG U.S. Coast Guard

[[Page 476]]

USEPA U.S. Environmental Protection Agency
UTM Universal Transverse Mercator coordinate system
WPA Western Planning Area of the GOM

    (b) As used in this part, each of the terms and phrases listed below 
has the meaning given in the Act or as defined in this section.
    Act means the Outer Continental Shelf Lands Act, as amended (OCSLA) 
(43 U.S.C. 1331-1356a).
    Affected State means, with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved pursuant to the 
provisions of OCSLA, any State:
    (i) The laws of which are declared, pursuant to section 4(a)(2) of 
OCSLA (43 U.S.C. 1333(a)(2)), to be the law of the United States for the 
portion of the OCS on which such activity is, or is proposed to be, 
conducted;
    (ii) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or structure referred 
to in section 4(a)(1) of OCSLA (43 U.S.C. 1333(a)(1));
    (iii) Which is receiving, or in accordance with the proposed 
activity will receive, oil for processing, refining, or transshipment 
that was extracted from the OCS and transported directly to that State 
by means of one or more vessels or by a combination of means, including 
a vessel;
    (iv) Which is designated by the Secretary as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment; or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (v) In which the Secretary finds that because of such activity, 
there is, or will be, a significant risk of serious damage, due to 
factors such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil or 
gas from one or more vessels, pipelines, or other transshipment 
facilities.
    Aliquot or Aliquot part means an officially designated subdivision 
of a lease's area, which can be a half of a lease (\1/2\), a quarter of 
a lease (\1/4\), a quarter of a quarter of a lease (\1/4\ \1/4\), or a 
quarter of a quarter of a quarter of a lease (\1/4\ \1/4\ \1/4\).
    Authorized officer means any person authorized by law or by 
delegation of authority to or within BOEM to perform the duties 
described in this part.
    Average daily production means the total of all production in an 
applicable production period that is chargeable under Sec.  556.514 
divided by the exact number of calendar days in the applicable 
production period.
    Barrel means 42 U.S. gallons. All measurements of crude oil and 
natural gas liquids under this section must be at 60 [deg]F.
    (i) For purposes of computing production and reporting of natural 
gas, 5,626 cubic feet of natural gas at 14.73 pounds per square inch 
equals one barrel.
    (ii) For purposes of computing production and reporting of natural 
gas liquids, 1.454 barrels of natural gas liquids at 60 [deg]F equals 
one barrel of crude oil.
    Bidding unit means one or more OCS blocks, or any portion thereof, 
that may be bid upon as a single administrative unit and will become a 
single lease. The term `tract,'' as defined in this section, may be used 
interchangeably with the term ``bidding unit.''
    BOEM means Bureau of Ocean Energy Management of the U.S. Department 
of the Interior.
    Bonus or royalty credit means a legal instrument or other written 
documentation approved by BOEM, or an entry in an account managed by the 
Secretary, that a bidder or lessee may use in lieu of any other monetary 
payment for a bonus or a royalty due on oil or gas production from 
certain leases, as specified in, and permitted by, the Gulf of Mexico 
Energy Security Act of 2006, Pub. L. 109-432 (Div. C, Title 1), 120 
Stat. 3000 (2006), codified at 43 U.S.C. 1331, note.
    BSEE means Bureau of Safety and Environmental Enforcement of the 
U.S. Department of the Interior.
    Central Planning Area (CPA) means that portion of the Gulf of Mexico 
that lies southerly of Louisiana, Mississippi, and Alabama. Precise 
boundary information is available from the BOEM

[[Page 477]]

Leasing Division, Mapping and Boundary Branch (MBB).
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inland to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the water therein 
and thereunder), strongly influenced by each other and in proximity to 
the shorelines of one or more of the several coastal States, and 
includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches, whose zone extends seaward to the outer limit of 
the United States territorial sea and extends inland from the shore 
lines to the extent necessary to control shorelands, the uses of which 
have a direct and significant impact on the coastal waters, and the 
inland boundaries of which may be identified by the several coastal 
States, under section 305(b)(1) of the Coastal Zone Management Act 
(CZMA) of 1972, 16 U.S.C. 1454(b)(1).
    Coastline means the line of mean ordinary low water along that 
portion of the coast in direct contact with the open sea and the line 
marking the seaward limit of inland waters.
    Crude oil means a mixture of liquid hydrocarbons, including 
condensate that exists in natural underground reservoirs and remains 
liquid at atmospheric pressure after passing through surface separating 
facilities, but does not include liquid hydrocarbons produced from tar 
sand, gilsonite, oil shale, or coal.
    Designated operator means a person authorized to act on your behalf 
and fulfill your obligations under the Act, the lease, and the 
regulations, who has been designated as an operator by all record title 
holders and all operating rights owners that own an operating rights 
interest in the aliquot/depths in which the designated operator, to 
which the Designation of Operator form applies, will be operating, and 
who has been approved by BOEM to act as designated operator.
    Desoto Canyon OPD means the Official Protraction Diagram (OPD) 
designated as Desoto Canyon that has a western edge located at the 
universal transverse mercator (UTM) X coordinate 1,346,400 in the North 
American Datum of 1927 (NAD27).
    Destin Dome OPD means the Official Protraction Diagram (OPD) 
designated as Destin Dome that has a western edge located at the 
Universal Transverse Mercator (UTM) X coordinate 1,393,920 in the NAD27.
    Development block means a block, including a block susceptible to 
drainage, which is located on the same general geologic structure as an 
existing lease having a well with indicated hydrocarbons; a reservoir 
may or may not be interpreted to extend on to the block.
    Director means the Director of the BOEM of the U.S. Department of 
the Interior, or an official authorized to act on the Director's behalf.
    Eastern Planning Area (EPA) means that portion of the Gulf of Mexico 
that lies southerly and westerly of Florida. Precise boundary 
information is available from the BOEM Leasing Division, Mapping and 
Boundary Branch.
    Economic interest means any right to, or any right dependent upon, 
production of crude oil, natural gas, or natural gas liquids and 
includes, but is not limited to: a royalty interest; an overriding 
royalty interest, whether payable in cash or kind; a working interest 
that does not include a record title interest or an operating rights 
interest; a carried working interest; a net profits interest; or a 
production payment.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Initial period or primary term means the initial period referred to 
in 43 U.S.C. 1337(b)(2).
    Joint bid means a bid submitted by two or more persons for an oil 
and gas lease under section 8(a) of the Act.
    Lease means an agreement that is issued under section 8 or 
maintained

[[Page 478]]

under section 6 of the Act and that authorizes exploration for, and 
development and production of, minerals on the OCS. The term also means 
the area covered by that agreement, whichever the context requires.
    Lease interest means one or more of the following ownership 
interests in an OCS oil and gas or sulfur lease: a record title 
interest, an operating rights interest, or an economic interest.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals and is 
therefore a record title owner of the lease, or the BOEM-approved 
assignee-owner of a record title interest. The term lessee also includes 
the BOEM-approved sublessee- or assignee-owner of an operating rights 
interest in a lease.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, conditions, and quality of the marine ecosystem, 
including the waters of the high seas, the contiguous zone, transitional 
and intertidal areas, salt marshes, and wetlands within the coastal zone 
and on the OCS.
    Mineral means oil, gas, and sulfur; it also includes sand, gravel, 
and salt used to facilitate the development and production of oil, gas, 
and sulfur.
    Natural gas means a mixture of hydrocarbons and varying quantities 
of non-hydrocarbons that exist in the gaseous phase.
    Natural gas liquids means liquefied petroleum products produced from 
reservoir gas and liquefied at surface separators, field facilities, or 
gas processing plants worldwide, including any of the following:
    (i) Condensate--natural gas liquids recovered from gas well gas 
(associated and non-associated) in separators or field facilities; or
    (ii) Gas plant products--natural gas liquids recovered from natural 
gas in gas processing plants and from field facilities. Gas plant 
products include the following, as classified according to the standards 
of the Natural Gas Processors Association (NGPA) or the American Society 
for Testing and Materials (ASTM):
    (A) Ethane--C2H6
    (B) Propane--C3H8
    (C) Butane--C4H10, including all products 
covered by NGPA specifications for commercial butane, including 
isobutane, normal butane, and other butanes--all butanes not included as 
isobutane or normal butane;
    (D) Butane-Propane Mixtures--All products covered by NGPA 
specifications for butane-propane mixtures;
    (E) Natural Gasoline--A mixture of hydrocarbons extracted from 
natural gas, that meets vapor pressure, end point, and other 
specifications for natural gasoline set by NGPA;
    (F) Plant Condensate--A natural gas plant product recovered and 
separated as a liquid at gas inlet separators or scrubbers in processing 
plants or field facilities; and
    (G) Other Natural Gas plant products meeting refined product 
standards (i.e., gasoline, kerosene, distillate, etc.).
    Operating rights means an interest created by sublease out of the 
record title interest in an oil and gas lease, authorizing the owner to 
explore for, develop, and/or produce the oil and gas contained within a 
specified area and depth of the lease (i.e., operating rights tract).
    Operating rights owner means the holder of operating rights.
    Operating rights tract means the area within the lease from which 
the operating rights have been severed on an aliquot basis from the 
record title interest, defined by a beginning and ending depth.
    Operator means the person designated as having control or management 
of operations on the leased area or a portion thereof. An operator may 
be a lessee, the operating rights owner, or a designated agent of the 
lessee or the operating rights owner.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (43 U.S.C. 1301-1315) and of which 
the subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Outer Continental Shelf Lands Act (OCSLA) means the Outer 
Continental Shelf Lands Act (43 U.S.C. 1331-1356a), as amended.

[[Page 479]]

    Owned, as used in the context of restricted joint bidding or a 
statement of production, means:
    (i) With respect to crude oil--having either an economic interest in 
or a power of disposition over the production of crude oil;
    (ii) With respect to natural gas--having either an economic interest 
in or a power of disposition over the production of natural gas; and
    (iii) With respect to natural gas liquids--having either an economic 
interest in or a power of disposition over any natural gas liquids at 
the time of completion of the liquefaction process.
    Pensacola OPD means the Official Protraction Diagram (OPD) 
designated as Pensacola that has a western edge located at the UTM X 
coordinate 1,393,920 in the NAD27.
    Person means a natural person, where so designated, or an entity, 
such as a partnership, association, State, political subdivision of a 
State or territory, or a private, public, or municipal corporation.
    Planning area means a large portion of the OCS, consisting of 
contiguous OCS blocks, defined for administrative planning purposes.
    Primary term or initial period means the initial period referred to 
in 43 U.S.C. 1337(b)(2).
    Regional Director means the BOEM officer with responsibility and 
authority for a Region within BOEM.
    Regional Supervisor means the BOEM officer with responsibility and 
authority for leasing or other designated program functions within a 
BOEM Region.
    Right-of-Use and Easement (RUE) means a right to use a portion of 
the seabed at an OCS site other than on a lease you own, for the 
construction and/or use of artificial islands, facilities, 
installations, and other devices, established to support the 
exploration, development or production of oil and gas, mineral, or 
energy resources from an OCS or State submerged lands lease.
    Right-of-Way (ROW) means an authorization issued by BSEE under the 
authority of section 5(e) of the OCSLA (43 U.S.C. 1334(e)) for the use 
of submerged lands of the Outer Continental Shelf for pipeline purposes.
    Secretary means the Secretary of the Interior or an official or a 
designated employee authorized to act on the Secretary's behalf.
    Security or securities means any note, stock, treasury stock, bond, 
debenture, evidence of indebtedness, certificate of interest or 
participation in any profit-sharing agreement; collateral-trust 
certificate; pre-organization certificate or subscription; transferable 
share; investment contract; voting-trust certificate; certificate of 
deposit for a security; fractional undivided interest in oil, gas, or 
other mineral rights; or, in general, any interest or instrument 
commonly known as a ``security'' or any certificate of interest or 
participation in, temporary or interim certificate for, receipt for, 
guarantee of, or warrant or right to subscribe to or purchase any of the 
foregoing.
    Single bid means a bid submitted by one person for an oil and gas 
lease under section 8(a) of the Act.
    Six-month bidding period means the 6-month period of time:
    (i) From May 1 through October 31; or
    (ii) from November 1 through April 30.
    Statement of production means, in the context of joint restricted 
bidders, the following production during the applicable prior production 
period:
    (i) The average daily production in barrels of crude oil, natural 
gas, and natural gas liquids which it owned worldwide;
    (ii) The average daily production in barrels of crude oil, natural 
gas, and natural gas liquids owned worldwide by every subsidiary of the 
reporting person;
    (iii) The average daily production in barrels of crude oil, natural 
gas, and natural gas liquids owned worldwide by any person or persons of 
which the reporting person is a subsidiary; and
    (iv) The average daily production in barrels of crude oil, natural 
gas, and natural gas liquids owned worldwide by any subsidiary, other 
than the reporting person, of any person or persons of which the 
reporting person is a subsidiary.
    Tract means one or more OCS blocks, or any leasable portion thereof, 
that will be part of a single oil and gas lease. The term tract may be 
used

[[Page 480]]

interchangeably with the term ``bidding unit.''
    We, us, and our mean BOEM or the Department of the Interior, 
depending on the context in which the word is used.
    Western Planning Area (WPA) means that portion of the Gulf of Mexico 
that lies south and east of Texas. Precise boundary information is 
available from the Leasing Division, Mapping and Boundary Branch.
    You, depending on the context of the regulations, means a bidder, a 
prospective bidder, a lessee (record title owner), an operating rights 
owner, an applicant seeking to become an assignee of record title or 
operating rights, a designated operator or agent of the lessee, a 
predecessor lessee, a RUE holder for a State or Federal lease, or a 
pipeline ROW holder.

[81 FR 18152, Mar. 30, 2016, as amended at 81 FR 70358, Oct. 12, 2016]



Sec.  556.106  Service fees.

    (a) The table in this paragraph shows the fees you must pay to BOEM 
for the services listed. BOEM will adjust the fees periodically 
according to the Implicit Price Deflator for Gross Domestic Product and 
publish a document showing the adjustment in the Federal Register. If a 
significant adjustment is needed to arrive at a new fee for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

                            Service Fee Table
------------------------------------------------------------------------
    Service--processing of the
            following:                  Fee amount      30 CFR Citation
------------------------------------------------------------------------
(1) Assignment of record title                   $198  Sec.   556.701(a)
 interest in Federal oil and gas
 lease(s) for BOEM approval.......
(2) Sublease or Assignment of                     198  Sec.   556.801(a)
 operating rights interest in
 Federal oil and gas lease(s) for
 BOEM approval....................
(3) Required document filing for                   29  Sec.   556.715(a)
 record purpose, but not for BOEM                      Sec.   556.808(a)
 approval.........................
(4) Non-required document filing                   29  Sec.   556.715(b)
 for record purposes..............                     Sec.   556.808(b)
------------------------------------------------------------------------

    (b) Evidence of payment via pay.gov of the fees listed in paragraph 
(a) of this section must accompany the submission of a document for 
approval or filing, or be sent to an office identified by the Regional 
Director.
    (c) Once a fee is paid, it is nonrefundable, even if your service 
request is withdrawn.
    (d) If your request is returned to you as incomplete, you are not 
required to submit a new fee with the amended submission.
    (e) The pay.gov Web site is accessible at https://www.pay.gov/
paygov/ or through the BOEM Web site at http://www.boem.gov/Fees-for-
Services.
    (f) The fees listed in the table above apply equally to any document 
or information submitted electronically pursuant to part 560, subpart E, 
of this chapter.



Sec.  556.107  Corporate seal requirements.

    (a) If you electronically submit to BOEM any document or information 
referenced in Sec.  560.500 of this chapter, any requirement to use a 
corporate seal under this chapter will be satisfied, and you will not 
need to affix your corporate seal to such document or information, if:
    (1) You properly file with BOEM a paper, with a corporate seal and 
the signature of the authorized person(s), stating that electronic 
submissions made by you will be legally binding, as set forth in Sec.  
560.502 of this chapter; and
    (2) You make electronic submissions to BOEM through a secure 
electronic filing system that conforms to the requirements of Sec.  
560.500; or,
    (b) You may file with BOEM a non-electronic document, containing a 
corporate seal and the signature of an authorized person(s), attesting 
that future documents and information filed by you by electronic or non-
electronic means will be legally binding without an affixed corporate 
seal. If you file such a non-electronic attestation document with BOEM, 
any requirement for use of a corporate seal under the regulations of 
this chapter will be satisfied,

[[Page 481]]

and you will not need to affix your corporate seal to submissions where 
they would have been otherwise required.
    (c) If the State or territory in which you are incorporated does not 
issue or require corporate seals, the document referred to in paragraphs 
(a) and (b) of this section need not contain a corporate seal, but must 
still contain the signature of the authorized person(s), a statement 
that the State in which you are incorporated does not issue or require 
corporate seals, and a statement that submissions made by you will be 
legally binding.
    (d) Any document, or information submitted without corporate seal 
must still contain the signature of an individual qualified to sign who 
has the requisite authority to act on your behalf.
    (e) Any document or information submitted pursuant to this section 
is submitted subject to the penalties of 18 U.S.C. 1001, as amended by 
the False Statements Accountability Act of 1996.



             Subpart B_Oil and Gas Five Year Leasing Program



Sec.  556.200  What is the Five Year leasing program?

    Section 18(a) of OCSLA (43 U.S.C. 1344(a)), requires the Secretary 
to prepare an oil and gas leasing program that consists of a five-year 
schedule of proposed lease sales to best meet national energy needs, 
showing the size, timing, and location of leasing activity as precisely 
as possible. BOEM prepares the five year schedule of proposed lease 
sales consistent with the principles set out in section 18(a)(1) and 
(2)(A)-(H) of OCSLA (43 U.S.C. 1344(a)(1) and (2)(A)-(H)) to obtain a 
proper balance among the potential for environmental damage, the 
potential for the discovery of oil and gas, and the potential for 
adverse impact on the coastal zone, as required by OCSLA section 
18(a)(3) (43 U.S.C. 1344(a)(3)).



Sec.  556.201  Does BOEM consider multiple uses of the OCS?

    BOEM gathers information about multiple uses of the OCS in order to 
assist the Secretary in making decisions on the 5-year program pursuant 
to provisions of 43 U.S.C. 1344. For this purpose, BOEM invites and 
considers suggestions from States and local governments, industry, and 
any other interested parties, primarily through public notice and 
comment procedures. BOEM also invites and considers suggestions from 
Federal agencies.



Sec.  556.202  How does BOEM start the Five Year program preparation process?

    To begin preparation of the Five Year program, BOEM invites and 
considers nominations for any areas to be included or excluded from 
leasing, by doing the following:
    (a) BOEM prepares and makes public official protraction diagrams and 
leasing maps of OCS areas. In any area properly included in the official 
Five Year diagrams and maps, any area not already leased for oil and gas 
may be offered for lease.
    (b) BOEM invites and considers suggestions and relevant information 
from governors of States, local governments, industry, Federal agencies, 
and other interested parties, through a publication of a request for 
information in the Federal Register. Any local government must first 
submit its comments on the request for information to its State governor 
before sending the comments to BOEM.
    (c) BOEM sends a letter to the governor of each affected State 
asking the governor to identify specific laws, goals, and policies that 
should be considered. Each State governor, as well as the Department of 
Commerce, is requested to identify the relationship between any oil and 
gas activity and the State under sections 305 and 306 of the CZMA, 16 
U.S.C. 1454 and 1455.
    (d) BOEM asks the Department of Energy for information on regional 
and national energy markets and transportation networks.



Sec.  556.203  What does BOEM do before publishing a proposed
 Five Year program?

    After considering the comments and information described in Sec.  
556.202, BOEM will prepare a draft proposed Five Year program.
    (a) At least 60 days before publication of a proposed program, BOEM 
will send

[[Page 482]]

a letter, together with the draft proposed program, to the governor of 
each affected State, inviting the governor to comment on the draft 
proposed program.
    (b) A governor, whether for purposes of preparing that State's 
comments or otherwise, may solicit comments from local governments that 
he determines may be affected by an oil and gas leasing program.
    (c) If a governor's comments on the draft proposed program are 
received by BOEM at least 15 days before submission of the proposed 
program to Congress and its publication for comment in the Federal 
Register, BOEM will reply to the governor in writing.



Sec.  556.204  How do governments and citizens comment on a proposed
 Five Year program?

    BOEM publishes the proposed program in the Federal Register for 
comment by the public. At the same time, BOEM sends the proposed program 
to the governors of the affected States and to Congress and the Attorney 
General of the United States for review and comment.
    (a) Governors are responsible for providing a copy of the proposed 
program to affected local governments in their States. Local governments 
may comment directly to BOEM, but must also send their comments to the 
governor of their State.
    (b) All comments from any party are due within 90 days after 
publication of the request for comments in the Federal Register.



Sec.  556.205  What does BOEM do before approving a proposed final
 Five Year program or a significant revision of a previously-approved
 Five Year program?

    At least 60 days before the Secretary may approve a proposed final 
Five Year program or a significant revision to a previously approved 
final Five Year program, BOEM will submit a proposed final program or 
proposed significant revision to the President and Congress. BOEM will 
also submit comments received and indicate the reasons why BOEM did or 
did not accept any specific recommendation of the Attorney General of 
the United States, the governor of a State, or the executive of a local 
government.



               Subpart C_Planning and Holding a Lease Sale



Sec.  556.300  What reports may BOEM and other Federal agencies prepare
 before a lease sale?

    For an oil and gas lease sale in a Five Year program, and as the 
need arises for other mineral leasing pursuant to part 581 of this 
chapter, BOEM will prepare a report describing the general geology and 
potential mineral resources of the area under consideration. The 
Director may request other interested Federal agencies to prepare 
reports describing, to the extent known, any other valuable resources 
contained within the general area and the potential effect of mineral 
operations upon the resources or upon the total environment or other 
uses of the area.



Sec.  556.301  What is a Call for Information and Nominations?

    BOEM issues a Call for Information and Nominations (``Call'') on an 
area proposed for leasing in the Five Year program through publication 
in the Federal Register and other publications. A Call may include more 
than one proposed sale. Comments are requested from industry and the 
public on:
    (a) Industry interest in the area proposed for leasing, including 
nominations or indications of interest in specific blocks within the 
area;
    (b) Geological conditions, including bottom hazards;
    (c) Archaeological sites on the seabed or near shore;
    (d) Potential multiple uses of the proposed leasing area, including 
navigation, recreation, and fisheries;
    (e) Areas that should receive special concern and analysis; and
    (f) Other socioeconomic, biological, and environmental information.



Sec.  556.302  What does BOEM do with the information from the Call?

    (a) Based upon information and nominations received in response to 
the Call, and in consultation with appropriate Federal agencies, the 
Director will develop a recommendation of

[[Page 483]]

areas proposed for leasing for the Secretary for further consideration 
for leasing and/or environmental analysis.
    (1) In developing the recommendation, the Director will consider 
available information concerning the environment, conflicts with other 
uses, resource potential, industry interest, and other relevant 
information, including comments received from State and local 
governments and other interested parties in response to the Call.
    (2) The Director, on his/her own motion, may include in the 
recommendation areas in which interest has not been indicated in 
response to a Call. In making a recommendation, the Director will 
consider all available environmental information.
    (3) Upon approval by the Secretary, the Director will announce the 
area identified in the Federal Register.
    (b) BOEM will evaluate the area(s) identified for further 
consideration for the potential effects of leasing on the human, marine, 
and coastal environments, and may develop measures to mitigate adverse 
impacts, including lease stipulations, for the options to be analyzed. 
The Director may hold public hearings on the environmental analysis 
after an appropriate notice.
    (c) BOEM will seek to inform the public, as soon as possible, of 
changes from the area(s) proposed for leasing that occur after the Call 
process.
    (d) Upon request, the Director will provide relative indications of 
interest in areas, as well as any comments filed in response to a Call 
for a proposed sale. However, no information transmitted will identify 
any particular area with the name of any particular party so as not to 
compromise the competitive position of any participants in the process 
of indicating interest.
    (e) For supplemental sales provided for by Sec.  556.308, the 
Director's recommendation will be replaced by a statement describing the 
results of the Director's consideration of the factors specified above 
in this section.



Sec.  556.303  What does BOEM do if an area proposed for leasing is
 within three nautical miles of the seaward boundary of a coastal State?

    For an area proposed for leasing that is within three nautical miles 
of the seaward boundary of a coastal State, as governed by section 
8(g)(1) of OCSLA (43 U.S.C. 1337(g)(1)):
    (a) BOEM provides the governor of the coastal State, subject to the 
confidentiality requirements in this chapter:
    (1) A schedule for leasing; and
    (2) An estimate of the potential oil and gas resources.
    (b) At the request of the governor of a coastal State, BOEM will 
provide to that governor, subject to the confidentiality requirements in 
this chapter:
    (1) Information concerning geographical, geological, and ecological 
characteristics; and
    (2) An identification of any field, geological structure, or trap, 
or portion thereof, that lies within three nautical miles of the State's 
boundary.



Sec.  556.304  How is a proposed notice of sale prepared?

    (a) The Director will, in consultation with appropriate Federal 
agencies, develop measures, including lease stipulations and conditions, 
to mitigate adverse impacts on the environment, which will be contained, 
or referenced, in the proposed notice of sale.
    (b) A proposed notice of sale will be submitted to the Secretary for 
approval. All comments and recommendations received and the Director's 
findings or actions thereon, will also be forwarded to the Secretary.
    (c) Upon approval by the Secretary, BOEM will send a proposed notice 
of sale to the governors of affected States and publish the notice of 
its availability in the Federal Register. The proposed notice of sale 
references or provides a link to the lease form, and contains a 
description of the area proposed for leasing, the proposed lease terms 
and conditions of sale, and proposed stipulations to mitigate potential 
adverse impacts on the environment.

[[Page 484]]



Sec.  556.305  How does BOEM coordinate and consult with States 
regarding a proposed notice of sale?

    (a) Within 60 days after receiving the proposed notice of sale, 
governors of affected States may submit comments and recommendations to 
BOEM regarding the size, timing, and location of the proposed sale. 
Local governments may comment to BOEM directly, but must also send their 
comments to the governor of their State.
    (b) BOEM will provide a consistency determination under the Coastal 
Zone Management Act (CZMA) (16 U.S.C. 1456) to each State with an 
approved coastal zone management program that will determine whether the 
proposed sale is consistent, to the maximum extent practicable, with the 
enforceable policies of the State's approved coastal zone management 
program.



Sec.  556.306  What if a potentially oil- or gas-bearing area 
underlies both the OCS and lands subject to State jurisdiction?

    (a) Whenever the Director or the governor of a coastal State 
determines that a common potentially hydrocarbon-bearing area may 
underlie the Federal OCS and State submerged lands, the Director or the 
governor will notify the other party in writing of the determination.
    (b) Thereafter the Director will provide to the governor of the 
coastal State, subject to the confidentiality requirements in this 
chapter:
    (1) An identification of the areas proposed for leasing and a 
schedule for, leasing; and
    (2) An estimate of the oil and gas resources.
    (c) At the request of the governor of the coastal State, the 
Director will provide to such governor, subject to the confidentiality 
requirements in this chapter:
    (1) All geographical, geological, and ecological characteristics of 
the areas proposed for leasing; and
    (2) An identification of any field, geological structure, or trap 
that lies within 3 miles of the State's seaward boundary.
    (d) If BOEM intends to lease such blocks or tracts, the Director and 
the governor of the coastal State may enter into an agreement for the 
equitable disposition of the revenues from production of any common 
potentially hydrocarbon-bearing area, pursuant to OCSLA section 8(g)(3) 
(43 U.S.C. 1337(g)(3)). Any revenues received by the United States under 
such an agreement are subject to the requirements of OSCLA section 
8(g)(2) (43 U.S.C. 1337(g)(2)).
    (e) If the Director and the governor do not enter into an agreement 
under paragraph (d) of this section within 90 days, BOEM may 
nevertheless proceed with the leasing of the tracts, in which case all 
revenues will be deposited in a separate account in the Treasury of the 
United States, pending disposition of 27% (twenty-seven percent) of the 
revenues to the relevant coastal state(s), pursuant to the requirements 
of OCSLA section 8(g)(2). (43 U.S.C. 1337(g)(2)).



Sec.  556.307  What does BOEM do with comments and recommendations
 received on the proposed notice of sale?

    (a) BOEM will consider all comments and recommendations received in 
response to the proposed notice of sale.
    (b) If the Secretary determines, after providing opportunity for 
consultation, that a governor's comments, and those of any affected 
local government, provide a reasonable balance between the national 
interest and the well-being of the citizens of the State, the Secretary 
will accept the recommendations of a State and/or local government(s). 
Any such determination of the national interest will be based on the 
findings, purposes and policies of the Act set forth in 43 U.S.C. 1332 
and 43 U.S.C. 1801.
    (c) BOEM will send to each governor written reasons for its 
determination to accept or reject each governor's recommendation, and/or 
to implement any alternative means to provide for a reasonable balance 
between the national interest and the interests of the citizens of the 
State.



Sec.  556.308  How does BOEM conduct a lease sale?

    (a) BOEM publishes a final notice of sale in the Federal Register 
and in

[[Page 485]]

other publications, as appropriate, at least 30 days before the date of 
the sale. The final notice:
    (1) States the place, time, and method for filing bids and the 
place, date, and hour for opening bids; and
    (2) Contains or references a description of the areas offered for 
lease, the lease terms and conditions of sale, and stipulations to 
mitigate potential adverse impacts on the environment.
    (b) Oil and gas tracts are offered for lease by competitive sealed 
bid in accordance with the terms and conditions in the final notice of 
sale and applicable laws and regulations.
    (c) Unless BOEM finds that a larger area is necessary for reasonable 
economic production, no individual tract for oil and gas leasing will 
exceed 5,760 acres in area. If BOEM finds that an area larger than 5,760 
acres is necessary in any particular area, the size of any such tract 
will be specified in the final notice of sale.
    (d) The final notice of sale references, or provides a link to, the 
OCS lease form which will be issued to successful bidders.



Sec.  556.309  Does BOEM offer blocks in a sale that is not on the 
Five Year program schedule (called a Supplemental Sale)?

    (a) Except as provided in paragraph (c) of this section, BOEM may 
offer a block within a planning area included in the Five Year program 
in an otherwise unscheduled sale, if the block:
    (1) Received a bid that was rejected in an earlier sale;
    (2) Had a high bid that was forfeited in a scheduled sale; or
    (3) Is a development block subject to drainage.
    (b) For an unscheduled sale, BOEM may disclose the classification of 
the block as a development block.
    (c) Blocks in the Central or Western Gulf of Mexico Planning Areas 
cannot be offered in a sale that is not on the schedule.



                        Subpart D_Qualifications



Sec.  556.400  When must I demonstrate that I am qualified to hold
 a lease on the OCS?

    In order to bid on, own, hold, or operate a lease on the OCS, 
bidders, record title holders, and operating rights owners must first 
obtain a qualification number from BOEM.



Sec.  556.401  What do I need to show to become qualified to hold a
 lease on the OCS and obtain a qualification number?

    (a) You may become qualified to hold a lease on the OCS and obtain a 
qualification number in accordance with Sec.  556.402, if you submit 
evidence demonstrating that you are:
    (1) A natural person who is a citizen or national of the United 
States;
    (2) A natural person who is an alien lawfully admitted for permanent 
residence in the United States, as defined in 8 U.S.C. 1101(a)(20);
    (3) A private, public, or municipal corporation or Limited Liability 
Company or Limited Liability Corporation (either/both sometimes herein 
referred to as ``LLC'') organized under the laws of any State of the 
United States, the District of Columbia, or any territory or insular 
possession subject to United States jurisdiction;
    (4) An association of such citizens, nationals, resident aliens, or 
corporations;
    (5) A State, the District of Columbia, or any territory or insular 
possession subject to United States jurisdiction;
    (6) A political subdivision of a State, the District of Columbia, or 
any territory or insular possession subject to United States 
jurisdiction; or
    (7) A Trust organized under the laws of any State of the United 
States, the District of Columbia, or any territory or insular possession 
subject to United States jurisdiction;
    (b) Statements and evidence submitted to demonstrate qualification 
under paragraphs (a)(1) through (6) of this section are subject to the 
penalties of 18 U.S.C. 1001.
    (b) BOEM may issue you a qualification number after you have 
provided evidence acceptable to BOEM.

[[Page 486]]



Sec.  556.402  How do I make the necessary showing to qualify and 
obtain a qualification number?

    (a) If BOEM has already issued you a qualification number, you may 
present that number to BOEM. If not, in order to become qualified, you 
must provide the information in paragraph (b) or (c) of this section 
before BOEM will issue you a BOEM qualification number.
    (b) A natural person must be a citizen or national of the United 
States, or a resident alien, to qualify. A United States citizen or 
national must submit written evidence acceptable to BOEM attesting to 
United States citizenship or national status. A resident alien must 
submit an original or a photocopy of the United States Citizenship and 
Immigration Services form evidencing legal status as a resident alien.
    (c) A person who is not a natural person must submit evidence (refer 
to paragraph (d) of this section) acceptable to BOEM that:
    (1) It is authorized to conduct business under the laws of a State, 
the District of Columbia, or any territory or insular possession subject 
to United States jurisdiction under which it is organized;
    (2) Under the operating rules of its business, it is authorized to 
hold OCS leases; and
    (3) Includes an up-to-date list of persons, and their titles, who 
are authorized to bind the corporation, association or other entity when 
conducting business on the OCS. It is up to you, in accordance with your 
organizational structure or rules, to identify the individual, or group 
of individuals, who has actual authority to bind your organization, and 
the title(s) they will use when they sign documents to bind the 
organization. You must maintain and regularly update the information as 
to who has the authority to bind the organization whenever that 
information changes.
    (d) Acceptable evidence under paragraph (c) of this section 
includes, but is not limited to:
    (1) For a corporation,
    (i) A statement by the Secretary of the corporation, over corporate 
seal, certifying that the corporation is authorized to hold OCS leases; 
and
    (ii) Evidence of authority of holders of positions entitled to bind 
the corporation, certified by Secretary of the corporation, over 
corporate seal, such as:
    (A) Certified copy of resolution of the board of directors with 
titles of officers authorized to bind corporation;
    (B) Certified copy of resolutions granting corporate officer 
authority to issue a power of attorney; or
    (C) Certified copy of power of attorney or certified copy of 
resolution granting power of attorney.
    (2) For a Limited or General Partnership,
    (i) A statement by an authorized party certifying that the 
partnership is authorized to hold OCS leases;
    (ii) A copy of your signed partnership formation documents, 
including a partnership agreement;
    (iii) A statement from each partner indicating, as appropriate, U.S. 
citizenship or incorporation or organization under the laws of a State, 
the District of Columbia, or any territory or insular possession subject 
to U.S. jurisdiction; and
    (iv) Documentation evidencing the existence of the partnership and 
that it was properly created, either from the Secretary of State of the 
State in which the partnership is registered or by an equivalent State 
or governmental office.
    (3) For a Limited Liability Company or Limited Liability 
Corporation,
    (i) A certificate of formation of the LLC;
    (ii) A statement by an individual authorized to bind the LLC, as 
listed under (c)(4) above, certifying that the LLC is authorized to hold 
OCS leases;
    (iii) A statement from each member indicating, as appropriate, U.S. 
citizenship, or incorporation or organization under the laws of a State, 
the District of Columbia, or any territory or insular possession subject 
to U.S. jurisdiction; and
    (iv) Evidence of authority of holders of positions entitled to bind 
the LLC, certified by an individual authorized to bind the LLC.
    (4) For a Trust,
    (i) A copy of the trust agreement or document establishing the trust 
and all

[[Page 487]]

amendments, properly certified by the trustee; and
    (ii) A statement indicating the law under which the trust is 
established and that the trust is authorized to hold OCS leases.
    (e) In the event that a person may be eligible to hold OCS leases, 
but that type of person is not listed in paragraphs (c) or (d) of this 
section, evidence of such eligibility will be submitted and certified by 
the highest level of management of the person authorized to do so 
pursuant to its operating agreement or governance documents.
    (f) Any person who obtains a qualification number from BOEM is 
responsible to ensure that it is not using the qualification number 
approved by BOEM for any purpose that its operating rules do not allow.
    (g) Any evidence submitted in response to paragraphs (c), (d), or 
(e) of this section is submitted subject to 18 U.S.C. 1001.
    (h) A person may not hold leases on the OCS until the evidence 
requested in this section has been accepted and approved by BOEM and 
BOEM has issued a qualification number to that person.
    (i) If use of a corporate seal is required by this section, you may 
meet the requirement as specified in Sec.  556.107.



Sec.  556.403  Under what circumstances may I be disqualified from 
acquiring a lease or an interest in a lease on the OCS?

    You may be disqualified from acquiring a lease or an interest in a 
lease on the OCS if:
    (a) You or your principals are excluded or disqualified from 
participating in a transaction covered by Federal non-procurement 
debarment and suspension (2 CFR parts 180 and 1400), unless the 
Department explicitly approves an exception for a transaction pursuant 
to the regulations in those parts;
    (b) The Secretary finds, after notice and hearing, that you or your 
principals (including in the meaning of ``you,'' for purposes of this 
subparagraph, a bidder or prospective bidder) fail to meet due diligence 
requirements or to exercise due diligence under section 8(d) of OCSLA 
(43 U.S.C. 1337(d)) on any OCS lease; or
    (c) BOEM disqualifies you from acquiring a lease or an interest in a 
lease on the OCS based on your unacceptable operating performance. BOEM 
will give you adequate notice and opportunity for a hearing before 
imposing a disqualification, unless BSEE has already provided such 
notice and opportunity for a hearing.

[81 FR 34275, May 31, 2016]



Sec.  556.404  What do the non-procurement debarment rules require
 that I do?

    You must comply with the Department's non-procurement debarment 
regulations at 2 CFR parts 180 and 1400.
    (a) You must notify BOEM if you know that you or your principals are 
excluded, disqualified, have been convicted or are indicted of a crime 
as described in 2 CFR part 180, subpart C. You must make this 
notification before you sign a lease, sublease, or an assignment of 
record title interest or operating rights interest, or become a lease or 
unit operator. This paragraph does not apply if you have previously 
provided a statement disclosing this information, and you have received 
an exception from the Department, as described in 2 CFR 180.135 and 2 
CFR 1400.137.
    (b) If you wish to enter into a covered transaction with another 
person at a lower tier, as described in 2 CFR 180.200, you must first:
    (1) Verify that the person is not excluded or disqualified under 2 
CFR part 180; and
    (2) Require the person to:
    (i) Comply with 2 CFR part 180, subpart C; and
    (ii) Include the obligation to comply with 2 CFR part 180, subpart C 
in its contracts and other transactions.
    (c) After you enter into a covered transaction, you must immediately 
notify BOEM in writing if you learn that:
    (1) You failed to disclose pertinent information earlier; or
    (2) Due to changed circumstances, you or your principals now meet 
any of the criteria in 2 CFR 180.800.

[[Page 488]]



Sec.  556.405  When must I notify BOEM of mergers, name changes, or
 changes of business form?

    You must notify BOEM of any merger, name change, or change of 
business form as soon as practicable, but in no case later than one year 
after the earlier of the effective date or the date of filing the change 
or action with the Secretary of State or other authorized official in 
the State of original registry.



                      Subpart E_Issuance of a Lease

                               How To Bid



Sec.  556.500  Once qualified, how do I submit a bid?

    (a) You must submit a separate sealed bid for each tract or bidding 
unit to the address provided and by the time specified in the final 
notice of sale. You may not bid on less than an entire tract or bidding 
unit.
    (b) BOEM requires a deposit for each bid. The final notice of sale 
will specify the amount and method of payment.
    (c) Unless otherwise specified in the final notice of sale, the bid 
deposit amount will be 20 percent of the amount of the bid for any given 
tract or bidding unit.
    (d) You may not submit a bid on an OCS tract if, after notice and 
hearing under section 8(d) of OCSLA (43 U.S.C. 1337(d)), the Secretary 
finds that you are not meeting the diligence requirements on any OCS 
lease.
    (e) If the authorized officer within BOEM rejects your high bid, the 
decision is final for the Department, subject only to reconsideration 
upon your written request as set out in Sec.  556.517.



Sec.  556.501  What information do I need to submit with my bid?

    In accordance with OCSLA section 18(a)(4) (43 U.S.C. 1344(a)(4)), 
BOEM must evaluate every bid to ensure that the federal government 
receives fair market value for every lease. Section 26(a)(1)(A) of OCSLA 
(43 U.S.C. 1352(a)(1)(A)) provides that, in accordance with regulations 
prescribed by the Secretary, any lessee or permittee conducting any 
exploration for, or development or production of, oil or gas must 
provide the Secretary access to all data and information (including 
processed, analyzed, and interpreted information) obtained from that 
activity and must provide copies of that data and information as the 
Secretary may request.
    (a) As part of the lease sale process, every bidder submitting a bid 
on a tract, or participating as a joint bidder in such a bid, may at the 
time of bid be required to submit various information, including a 
Geophysical Data and Information Statement (GDIS) corresponding to that 
tract, as well as the bidder's exclusive/proprietary geophysical data in 
order for BOEM to properly evaluate the bid. If a GDIS required, each 
GDIS must include, as required by Sec.  551.12(b) and (c) of this 
chapter:
    (1) A list of geophysical surveys or other information used as part 
of the decision to bid or participate in a bid on the block.
    (2) An accurate and complete record of each geophysical survey 
conducted, including digital navigational data and final location maps. 
The bidder and any joint bidder must include a map for each survey 
identified in the GDIS that illustrates the actual areal extent of the 
proprietary geophysical data.
    (b) If a bidder is required to submit a GDIS, the GDIS must be 
submitted even if the bidder did not rely on proprietary geophysical 
data and information in deciding to bid or participate as a joint bidder 
in the bid for any particular block, and must include entries for all 
such blocks.
    (c) The bidder must submit each GDIS in a separate and sealed 
envelope, or in an electronically readable spreadsheet format, with 
proprietary seismic data maps also available in an electronic format. 
Each bidder must submit the GDIS even if its joint bidder or bidders on 
a specific block also have submitted a GDIS.
    (d) If BOEM requires additional information related to bidding, it 
will describe the additional information requirements in the final 
notice of sale.
    (e) BOEM will reimburse bidders for the costs of complying with the 
requirements of this section, in accordance with Sec.  550.196 (on 
lease) and/or Sec.  551.13 (off lease) of this chapter.

[[Page 489]]

    (f) Bids that are not made in compliance with this section will be 
considered incomplete and invalid.

                      Restrictions on Joint Bidding



Sec.  556.511  Are there restrictions on bidding with others and do
 those restrictions affect my ability to bid?

    The Energy Policy and Conservation Act of 1975, 42 U.S.C. 6213, 
prohibits joint bidding by major oil and gas producers under certain 
circumstances. BOEM implements 42 U.S.C. 6213 as follows:
    (a) BOEM publishes twice yearly in the Federal Register a restricted 
joint bidders list. A person appearing on this list is limited in its 
ability to submit a joint bid. The list:
    (1) Consists of the persons chargeable with an average worldwide 
daily production in excess of 1.6 million barrels of crude oil and/or 
its equivalent in natural gas liquids and natural gas for the prior 
production period; and
    (2) Is based upon the statement of production that filed as required 
by Sec.  556.513.
    (b) If BOEM places you on the restricted joint bidders list, BOEM 
will send you a copy of the order placing you on the list. You may 
appeal this order to the Interior Board of Land Appeals under 30 CFR 
part 590, subpart A.
    (c) If you are listed in the Federal Register in any group of 
restricted bidders, you may not bid:
    (1) Jointly with another person in any other group of restricted 
bidders for the applicable 6-month bidding period; or
    (2) Separately during the 6-month bidding period if you have an 
agreement with another restricted bidder that will result in joint 
ownership in an OCS lease.
    (d) If you are listed in the Federal Register in any group of 
restricted bidders, you may not make any pre-bidding agreement for the 
conveyance of any potential lease interest, whether by assignment, sale, 
transfer, or other means, to any person on the list of restricted joint 
bidders.
    (e) Even if you are not listed in the Federal Register in any group 
of restricted bidders, you are prohibited from making any pre-bidding 
agreement for the assignment, sale, transfer, or other conveyance of any 
potential lease interest to two or more persons in different groups on 
the list of restricted joint bidders.
    (f) As a bidder, you are prohibited from unlawful combination with, 
or intimidation of, bidders under 18 U.S.C. 1860.



Sec.  556.512  What bids may be disqualified?

    The following bids for any oil and gas lease will be disqualified 
and rejected in their entirety:
    (a) A joint bid submitted by two or more persons who are on the 
effective List of Restricted Joint Bidders; or
    (b) A joint bid submitted by two or more persons when:
    (1) One or more of those persons is chargeable for the prior 
production period with an average daily production in excess of 1.6 
million barrels of crude oil, natural gas and natural gas liquids and 
has not filed a Statement of Production, as required by Sec.  556.513 of 
this part for the applicable 6-month bidding period, or
    (2) Any of those persons have failed or refused to file a detailed 
report of production when required to do so under Sec.  556.513, or
    (c) A single or joint bid submitted pursuant to an agreement 
(whether written or oral, formal or informal, entered into or arranged 
prior to or simultaneously with the submission of such single or joint 
bid, or prior to or simultaneously with the award of the bid upon the 
tract) that provides:
    (1) For the assignment, transfer, sale, or other conveyance of less 
than a 100 percent interest in the entire tract on which the bid is 
submitted, by a person or persons on the List of Restricted Joint 
Bidders, effective on the date of submission of the bid, to another 
person or persons on the same List of Restricted Joint Bidders; or
    (2) For the assignment, sale, transfer or other conveyance of less 
than a 100 percent interest in any fractional interest in the entire 
tract (which fractional interest was originally acquired by the person 
making the assignment, sale, transfer or other conveyance, under the 
provisions of the act) by a person or persons on the List of Restricted 
Joint Bidders, effective on the

[[Page 490]]

date of submission of the bid, to another person or persons on the same 
List of Restricted Joint Bidders; or
    (3) For the assignment, sale, transfer, or other conveyance of any 
interest in a tract by a person or persons not on the List of Restricted 
Joint Bidders, effective on the date of submission of the bid, to two or 
more persons on the same List of Restricted Joint Bidders; or
    (4) For any of the types of conveyances described in paragraphs 
(c)(1), (2), or (3) of this section where any party to the conveyance is 
chargeable for the prior production period with an average daily 
production in excess of 1.6 million barrels of crude oil, natural gas 
and natural gas liquids and has not filed a Statement of Production 
pursuant to Sec.  556.513 for the applicable six-month bidding period. 
Assignments expressly required by law, regulation, lease or lease 
stipulation will not disqualify an otherwise qualified bid; or
    (d) A bid submitted by or in conjunction with a person who has filed 
a false, fraudulent or otherwise intentionally false or misleading 
detailed Report of Production.



Sec.  556.513  When must I file a statement of production?

    (a) You must file a statement of production if your average 
worldwide daily production exceeded 1.6 million barrels for the prior 
production period, as determined using the method set forth in Sec.  
556.514. Your statement of production must specify that you were 
chargeable with an average daily production in excess of 1.6 million 
barrels for the prior production period.
    (b) The prior production periods are as follows:

------------------------------------------------------------------------
                                             The prior production period
         For the bidding period of                is the preceding
------------------------------------------------------------------------
(1) May through October...................  July through December.
(2) November through April................  January through June.
------------------------------------------------------------------------

    (c) You must file the statement of production by the following 
deadlines:

------------------------------------------------------------------------
                                             You must file the statement
         For the bidding period of                       by
------------------------------------------------------------------------
(1) May through October...................  March 17.
(2) November through April................  September 17.
------------------------------------------------------------------------

    (d) If you are required to file a statement of production, BOEM may 
require you to submit a detailed report of production.
    (1) The detailed report of production must list crude oil, natural 
gas liquids, and natural gas produced worldwide from reservoirs during 
the prior production period, and therefore chargeable to the prior 
production period.
    (i) The amount of crude oil chargeable to the prior production 
period will be established by measurement of volumes delivered at the 
point of custody transfer (e.g., from storage tanks to pipelines, 
trucks, tankers, or other media for transport to refineries or 
terminals), with adjustments for net differences between opening and 
closing inventories, and basic sediment and water.
    (ii) The amount of natural gas liquids chargeable to the prior 
production period must include gas liquefied at surface separators, 
field facilities, or gas processing plants.
    (iii) The amount of natural gas chargeable to the prior production 
period must include adjustments, where applicable, to reflect the volume 
of gas returned to natural reservoirs, and the reduction of volume 
resulting from the removal of natural gas liquids and non-hydrocarbon 
gases.
    (2) You must submit the detailed report of production within 30 days 
after receiving BOEM's request.
    (3) BOEM may inspect and copy any document, record of production, 
analysis, and other material to verify the accuracy of any earlier 
statement of production.
    (e) If you submit a statement of production that misrepresents your 
chargeable production, the Department may cancel any lease awarded in 
reliance upon the statement.



Sec.  556.514  How do I determine my production for purposes of the
 restricted joint bidders list?

    (a) To determine the amount of production chargeable to you, add 
together:
    (1) Your average daily production in barrels of crude oil, natural 
gas liquids, and natural gas worldwide, all measured at 60 [deg]F, using 
the equivalency or

[[Page 491]]

conversion factors for natural gas liquids and natural gas set out in 42 
U.S.C. 6213(b)(2) and (3); and
    (2) Your proportionate share of the average daily production owned 
by any person that has an interest in you and/or in which you have an 
interest.
    (b) For the purpose of paragraph (a)(1) of this section, your 
production includes 100 percent of production owned by:
    (1) You;
    (2) Every subsidiary of yours;
    (3) Every person of which you are a subsidiary; and
    (4) Every subsidiary of any person of which you are a subsidiary.
    (c) For purposes of paragraph (a)(2) of this section, interest means 
at least a five percent ownership or control of you or the reporting 
person and includes any interest:
    (1) From ownership of securities or other evidence of ownership; or,
    (2) By participation in any contract, agreement, or understanding 
regarding control of the person or their production of crude oil, 
natural gas liquids, or natural gas.
    (d) For purposes of this section, subsidiary means a person, 50 
percent or more of whose stock or other interest having power to vote 
for the election of a controlling body, such as directors or trustees, 
is directly or indirectly owned or controlled by another person.
    (e) For purposes of this section, production chargeable to you 
includes, but is not limited to, production obtained as a result of a 
production payment or a working, net profit, royalty, overriding 
royalty, or carried interest.
    (f) For purposes of this section, production must be measured with 
appropriate adjustments for:
    (1) Basic sediment and water;
    (2) Removal of natural gas liquids and non-hydrocarbon gases; and
    (3) Volume of gas returned to natural reservoirs.



Sec.  556.515  May a person be exempted from joint bidding restrictions?

    BOEM may exempt you from some or all of the reporting requirements 
listed in Sec.  556.513, and/or some or all of the joint bidding 
restrictions listed in Sec. Sec.  556.511 and/or 556.512(a), (b), and/or 
(c), if, after opportunity for a hearing, BOEM determines that the 
extremely high costs in an area will preclude exploration and 
development without an exemption.

                       How Does BOEM Act on Bids?



Sec.  556.516  What does BOEM do with my bid?

    (a) BOEM opens the sealed bids at the place, date, and hour 
specified in the final notice of sale for the sole purpose of publicly 
announcing and recording the bids. BOEM does not accept or reject any 
bids at that time.
    (b) BOEM reserves the right to reject any and all bids received, 
regardless of the amount offered. BOEM accepts or rejects all bids 
within 90 days of opening. BOEM reserves the right to extend that time 
if necessary, and in that event, BOEM will notify bidder(s) in writing 
prior to the expiration of the initial 90-day period, or of any 
extension. Any bid not accepted within the prescribed 90-day period, or 
any extension thereof, will be deemed rejected. If your bid is rejected, 
BOEM will refund any money deposited with your bid, plus any interest 
accrued.
    (c) If the highest bids are a tie, BOEM will notify the bidders who 
submitted the tie bids. Within 15 days after notification, those 
bidders, if qualified, and not otherwise prohibited from bidding 
together, may:
    (1) Agree to accept the lease jointly. The bidders must notify BOEM 
of their decision and submit a copy of their agreement to accept the 
lease jointly.
    (2) Agree between/among themselves which bidder will accept the 
lease. The bidders must notify BOEM of their decision.
    (d) If no agreement is submitted pursuant to paragraph (c) of this 
section, BOEM will reject all the tie bids.
    (e) The Attorney General, in consultation with the Federal Trade 
Commission, has 30 days to review the results of the lease sale before 
BOEM may accept the bid(s) and issue the lease(s).



Sec.  556.517  What may I do if my high bid is rejected?

    (a) The decision of the authorized officer on bids is the final 
action of the

[[Page 492]]

Department, subject only to reconsideration of the rejection of the high 
bid by the Director, in accordance with paragraph (b) of this section.
    (b) Within 15 days of bid rejection, you may file a written request 
for reconsideration with the Director, with a copy to the authorized 
officer. Such request must provide evidence as to why the Director 
should reconsider your bid. You will receive a written response either 
affirming or reversing the rejection of your bid.
    (c) The Director's decision on the request for reconsideration is 
not subject to appeal to the Interior Board of Land Appeals in the 
Department's Office of Hearings and Appeals.

                           Awarding the Lease



Sec.  556.520  What happens if I am the successful high bidder and 
BOEM accepts my bid?

    (a) If BOEM accepts your bid, BOEM will provide you with the 
appropriate number of copies of the lease for you to execute and return 
to BOEM. Within 11 business days after you receive the lease copies, you 
must:
    (1) Execute all copies of the lease;
    (2) Pay the first year's rental;
    (3) Pay the balance of the bonus bid, unless deferred under 
paragraph (b) below;
    (4) Comply with subpart I of this part; and,
    (5) Return all copies of the executed lease, including any required 
bond or other form of security approved by the Regional Director, to 
BOEM.
    (b) If provided for in the final notice of sale, BOEM may defer any 
part of the bonus and bid payment for up to five years after the sale 
according to a schedule included in the final notice of sale. You must 
provide a bond acceptable to BOEM to guarantee payment of a deferred 
bonus bid.
    (c) If you do not make the required payments and execute and return 
all copies of the lease and any required bond within 11 business days 
after receipt, or if you otherwise fail to comply with applicable 
regulations, your deposit will be forfeited. However, BOEM will return 
any deposit with interest if the tract is withdrawn from leasing before 
you execute the lease.
    (d) If you use an agent to execute the lease, you must include 
evidence with the executed copies of the lease that a person who is on 
the list of persons referenced in Sec.  556.402(c)(3) authorized the 
agent to act for you.
    (e) After you comply with all requirements in this section, and 
after BOEM has executed the lease, BOEM will send you a fully executed 
lease.



Sec.  556.521  When is my lease effective?

    Your lease is effective on the first day of the month following the 
date that BOEM executes the lease. You may request in writing, before 
BOEM executes the lease, that your lease be effective as of the first 
day of the month in which BOEM executes the lease. If BOEM agrees to 
make the lease effective as of the earlier date, BOEM will so indicate 
when it executes the lease.



Sec.  556.522  What are the terms and conditions of the lease and
 when are they published?

    The terms and conditions of the lease will be stated in the final 
notice of sale and contained in the lease instrument itself. Oil and gas 
leases and leases for sulfur will be issued on forms approved by the 
Director.



                  Subpart F_Lease Term and Obligations

                             Length of Lease



Sec.  556.600  What is the primary term of my oil and gas lease?

    (a) The primary term of an oil and gas lease will be five years, 
unless BOEM determines that:
    (1) The lease is located in unusually deep water or involves other 
unusually adverse conditions; and,
    (2) A lease term longer than five years is necessary to explore and 
develop the lease.
    (b) If BOEM determines that the criteria in paragraphs (a)(1) and 
(2) of this section are met, it may specify a longer primary term, not 
to exceed 10 years.
    (c) BOEM will specify the primary term in the final notice of sale 
and in the lease instrument.

[[Page 493]]

    (d) The lease will expire at the end of the primary term, unless 
maintained beyond that term in accordance with the provisions of Sec.  
556.601.



Sec.  556.601  How may I maintain my oil and gas lease beyond the
 primary term?

    You may maintain your oil and gas lease beyond the expiration of the 
primary term as long as:
    (a) You are producing oil or gas in paying quantities;
    (b) You are conducting approved drilling or well reworking 
operations with the objective of establishing production in paying 
quantities, in accordance with 30 CFR 250.180;
    (c) You are producing from, or drilling or reworking, an approved 
well adjacent to or adjoining your lease that extends directionally into 
your lease in accordance with 30 CFR 256.71;
    (d) You make compensatory payments on your lease in accordance with 
30 CFR 256.72;
    (e) Your lease is included in a BSEE-approved unit, in accordance 
with 30 CFR part 250, subpart M; or
    (f) Your lease is subject to a suspension of production or a 
suspension of operations, in accordance with 30 CFR 250.168 through 
250.180, for reasons other than gross negligence or a willful violation 
of a provision of your lease or any governing regulations.



Sec.  556.602  What is the primary term of my sulfur lease?

    (a) Your sulfur lease will have a primary term of not more than 10 
years, as specified in the lease.
    (b) BOEM will announce the primary term prior to the lease sale.
    (c) The lease will expire at the end of the primary term unless 
maintained beyond that term in accordance with the provisions of Sec.  
556.603.



Sec.  556.603  How may I maintain my sulfur lease beyond the
 primary term?

    You may maintain your sulfur lease after the primary term as long as 
you are producing sulfur in paying quantities, conducting drilling, well 
reworking or plant construction, or other operations for the production 
of sulfur or you are granted a suspension by BSEE; or your lease is 
subject to a suspension directed by BSEE for reasons other than gross 
negligence or a willful violation of a provision of your lease or 
governing regulations.

                            Lease Obligations



Sec.  556.604  What are my rights and obligations as a record
 title owner?

    (a) As a record title owner, you are responsible for all 
administrative and operating performance on the lease, including paying 
any rent and royalty due.
    (b)(1) A record title owner owns operating rights to the lease, 
unless and until he or she severs the operating rights by subleasing 
them to someone else.
    (2) A sublease of operating rights from record title may be for a 
whole or undivided fractional interest in the entire lease or a 
described aliquot portion of the lease and/or a depth interval. The 
sublease creates an operating rights interest in the sublessee, herein 
referred to as the operating rights owner.
    (c) Within any given aliquot, the record title owner may sublease 
operating rights for up to a maximum of two depth divisions, which may 
result in a maximum of three different depth intervals. But, if the one, 
or two, depth divisions to which operating rights are subleased do not 
include the entire depth of the lease, whatever depth division(s) has 
not been subleased, remains part of the lessee/sublessor's record title 
interest. The depth intervals for which operating rights are subleased 
must be defined by a beginning and ending depth and the ending of one 
depth level must abut the beginning of the next depth level, with no gap 
in between.
    (d) Every current and prior record title owner is jointly and 
severally liable, along with all other record title owners and all prior 
and current operating rights owners, for compliance with all non-
monetary terms and conditions of the lease and all regulations issued 
under OCSLA, as well as for fulfilling all non-monetary obligations, 
including decommissioning obligations, which accrue while it holds 
record title interest.

[[Page 494]]

    (e) Record title owners that acquired their record title interests 
through assignment from a prior record title owner are also responsible 
for remedying all existing environmental or operational problems on any 
lease in which they own record title interests, with subrogation rights 
against prior lessees.
    (f) For monetary obligations, your obligation depends on the source 
of the monetary obligation and whether you have retained or severed your 
operating rights.
    (1) With respect to those operating rights that you have retained, 
you are primarily liable under 30 U.S.C. 1712(a) for your pro-rata share 
of all other monetary obligations pertaining to that portion of the 
lease subject to the operating rights you have retained, based on your 
share of operating rights in that portion of the lease.
    (2) With respect to all monetary obligations arising from or in 
connection with those operating rights that have been severed from your 
record title interest, your obligation is secondary to that of the 
sublessee(s) or later assignee(s) of the operating rights that were 
severed from your record title interest, as prescribed in 30 U.S.C. 
1712(a).



Sec.  556.605  What are my rights and obligations as an operating
 rights owner?

    (a) As an operating rights owner, you have the right to enter the 
leased area to explore for, develop, and produce oil and gas resources, 
except helium gas, contained within the aliquot(s) and depths within 
which you own operating rights, according to the lease terms, applicable 
regulations, and BOEM's approval of the sublease or subsequent 
assignment of the operating rights.
    (b) Unless otherwise prohibited, you have the right to authorize 
another party to conduct operations on the part of the lease to which 
your operating rights appertain.
    (c) An owner of operating rights who is designating a new designated 
operator must file a designation of operator under Sec.  550.143 of this 
chapter.
    (d) An operating rights owner is only liable for obligations arising 
from that portion of the lease to which its operating rights appertain 
and that accrue during the period in which the operating rights owner 
owned the operating rights.
    (e) You are jointly and severally liable with other operating rights 
owners and the record title owners for all non-monetary lease 
obligations pertaining to that portion of the lease subject to your 
operating rights, which accrued during the time you held your operating 
rights interest.
    (f) An operating rights owner that acquires its operating rights 
interests through assignment from a prior operating rights owner is also 
responsible, with subrogation rights against prior operating rights 
owners, for remedying existing environmental or operational problems, to 
the extent that such problems arise from that portion of the lease to 
which its operating rights appertain, on any lease in which it owns 
operating rights.
    (g) You are primarily liable for monetary obligations pertaining to 
that portion of the lease subject to your operating rights, and the 
record title owners are secondarily liable. If there is more than one 
operating rights owner in a lease, each operating rights owner is 
primarily liable for its pro-rata share of the monetary obligations that 
pertain to the portion of the lease that is subject to its operating 
rights.

                                 Helium



Sec.  556.606  What must a lessee do if BOEM elects to extract
 helium from a lease?

    (a) BOEM reserves the ownership of, and the right to extract, helium 
from all gas produced from your OCS lease. Under section 12(f) of OCSLA 
(43 U.S.C. 1341(f)), upon our request, you must deliver all or a 
specified portion of the gas containing helium to BOEM at a point on the 
leased area or at an onshore processing facility that BOEM designates.
    (b) BOEM will determine reasonable compensation and pay you for any 
loss caused by the extraction of helium, except for the value of the 
helium itself. BOEM may erect, maintain, and operate on your lease any 
reduction work and other equipment necessary for helium extraction. Our 
extraction of helium will be conducted in a manner to

[[Page 495]]

not cause substantial delays in the delivery of gas to your purchaser.



  Subpart G_Transferring All or Part of the Record Title Interest in a 
                                  Lease



Sec.  556.700  May I assign or sublease all or any part of the 
record title interest in my lease?

    (a) With BOEM approval, you may assign your whole, or a partial 
record title interest in your entire lease, or in any aliquot(s) 
thereof.
    (b) With BOEM approval, you may sever all, or a portion of, your 
operating rights.
    (c) You must request approval of each assignment of a record title 
interest and each sublease of an operating rights interest. Each 
instrument that transfers a record title interest must describe, by 
aliquot parts, the interest you propose to transfer. Each instrument 
that severs an operating rights interest must describe, by officially 
designated aliquot parts and depth levels, the interest proposed to be 
transferred.



Sec.  556.701  How do I seek approval of an assignment of the
record title interest in my lease, or a severance of operating
 rights from that record title interest?

    (a) The Regional Director will provide the form to record an 
assignment of record title interest in a Federal OCS oil and gas or 
sulfur lease, or a severance of operating rights from that record title 
interest. You must submit to BOEM two originals of each instrument that 
transfers ownership of record title within 90 days after the last party 
executes the transfer instrument. You must pay the service fee listed in 
Sec.  556.106 with your request and your submission must include 
evidence of payment via pay.gov.
    (b) Before BOEM approves an assignment or transfer, it must consult 
with, and consider the views of, the Attorney General. The Secretary may 
act on an assignment or transfer if the Attorney General has not 
responded to a request for consultation within 30 days of said request.
    (c) A new record title owner or sublessee must file a designation of 
operator, in accordance with Sec.  550.143 of this chapter, along with 
the request for the approval of the assignment.



Sec.  556.702  When will my assignment result in a segregated lease?

    (a) When there is an assignment by all record title owners of 100 
percent of the record title to one or more aliquots in a lease, the 
assigned and retained portions become segregated into separate and 
distinct leases. In such case, both the new lease and the remaining 
portion of the original lease are referred to as ``segregated leases'' 
and the assignee(s) becomes the record title owner(s) of the new lease, 
which is subject to all the terms and conditions of the original lease.
    (b) If a record title holder transfers an undivided interest, i.e., 
less than 100 percent of the record title interest in any given 
aliquot(s), that transfer will not segregate the portions of the 
aliquots, or the whole aliquots, in which part of the record title was 
transferred, into separate leases from the portion(s) in which no 
interest was transferred. Instead, that transfer will create a joint 
ownership between the assignee(s) and assignor(s) in the portions of the 
lease in which part of the record title interest was transferred. Any 
transfer of an undivided interest is subject to approval by BOEM.



Sec.  556.703  What is the effect of the approval of the assignment
 of 100 percent of the record title in a particular aliquot(s) of
 my lease and of the resulting lease segregation?

    (a) The bonding/financial assurance requirements of subpart I of 
this part apply separately to each segregated lease.
    (b) The royalty, minimum royalty, and rental provisions of the 
original lease will apply separately to each segregated lease.
    (c) BOEM will allocate among the segregated leases, on a basis that 
is equitable under the circumstances, any remaining unused royalty 
suspension volume or other form of royalty suspension or royalty relief 
that had been granted to the original lease, not to exceed in aggregate 
the total remaining amount.
    (d) Each segregated lease will continue in full force and effect for 
the

[[Page 496]]

primary term of the original lease and so long thereafter as each 
segregated lease meets the requirements outlined in Sec.  556.601. A 
segregated lease that does not meet the requirements of Sec.  556.601 
does not continue in force even if another segregated lease, which was 
part of the original lease, continues to meet those requirements.



Sec.  556.704  When would BOEM disapprove an assignment or sublease
 of an interest in my lease?

    (a) BOEM may disapprove an assignment or sublease of all or part of 
your lease interest(s):
    (1) When the transferor or transferee has unsatisfied obligations 
under this chapter or 30 CFR chapters II or XII;
    (2) When a transferor attempts a transfer that is not acceptable as 
to form or content (e.g., not on standard form, containing incorrect 
legal description, not executed by a person authorized to bind the 
corporation, transferee does not meet the requirements of Sec.  556.401, 
etc.); or,
    (3) When the transfer does not conform to these regulations, or any 
other applicable laws or regulations (e.g., departmental debarment 
rules).
    (b) A transfer will be void if it is made pursuant to any prelease 
agreement that would cause a bid to be disqualified, such as those 
described in Sec.  556.511(c), (d), or (e).



Sec.  556.705  How do I transfer the interest of a deceased natural
 person who was a lessee?

    (a) An heir or devisee must submit evidence by means of a certified 
copy of an appropriate court order or decree that the person is 
deceased; or, if no court action is necessary, a certified copy of the 
will and death certificate or notarized affidavits of two disinterested 
parties with knowledge of the facts.
    (b) The heir or devisee, if the lawful successor in interest, must 
submit evidence that he/she is the person named in the will or evidence 
from an appropriate judgment of a court or decree that he/she is the 
lawful successor in interest, along with the required evidence of his/
her qualifications to hold a lease under subpart D of this part.
    (c) If the heir or devisee does not qualify to hold a lease under 
subpart D of this part, he/she will be recognized as the successor in 
interest, but he/she must divest him/herself of this interest in the 
lease, to a person qualified to be a hold a lease, within two years.



Sec.  556.706  What if I want to transfer record title interests in
 more than one lease at the same time, but to different parties?

    You may not transfer interests in more than one lease to different 
parties using the same instrument. If you want to transfer the interest 
in more than one lease at the same time, you must submit duplicate, 
originally executed forms for each transfer. The forms used for each 
transfer must be accompanied by a cover letter executed by one of the 
parties to the transfer (or an authorized agent thereof) and evidence of 
payment via pay.gov.



Sec.  556.707  What if I want to transfer different types of lease
 interests (not only record title interests) in the same lease to
 different parties?

    You may not transfer different types of lease interests in a lease 
to different parties using the same instrument. You must submit 
duplicate, originally executed forms for each transfer, to a different 
party, of a different type of lease interest. The form used to transfer 
each type of lease interest must be accompanied by a cover letter 
executed by one of the parties to the transfer (or an authorized agent 
thereof) and evidence of payment via pay.gov.



Sec.  556.708  What if I want to transfer my record title interests
 in more than one lease to the same party?

    You may not transfer your record title interests in more than one 
lease to the same party using the same instrument. If you want to 
transfer record title interests in more than one lease at the same time, 
you must submit separate, originally executed forms for each transfer. 
The forms used for each transfer must be accompanied by a cover letter 
executed by one of the parties to the transfer (or an authorized agent 
thereof), and evidence of payment via pay.gov. A separate fee applies to 
each individual transfer of interest.

[[Page 497]]



Sec.  556.709  What if I want to transfer my record title interest
 in one lease to multiple parties?

    You may transfer your record title interest in one lease to multiple 
parties using the same instrument. That instrument must be submitted in 
duplicate originals, accompanied by a cover letter executed by one of 
the parties to the transfer (or an authorized agent thereof). In such a 
multiple transfer of interests using a single instrument, a separate fee 
applies to each individual transfer of interest, and evidence of payment 
via pay.gov must accompany the instrument.



Sec.  556.710  What is the effect of an assignment of a lease on an
 assignor's liability under the lease?

    If you assign your record title interest, as an assignor you remain 
liable for all obligations, monetary and non-monetary, that accrued in 
connection with your lease during the period in which you owned the 
record title interest, up to the date BOEM approves your assignment. 
BOEM's approval of the assignment does not relieve you of these accrued 
obligations. Even after assignment, BOEM or BSEE may require you to 
bring the lease into compliance if your assignee or any subsequent 
assignee fails to perform any obligation under the lease, to the extent 
the obligation accrued before approval of your assignment. Until there 
is a BOEM-approved assignment of interest, you, as the assignor, remain 
liable for the performance of all lease obligations that accrued while 
you held record title interest, until all such obligations are 
fulfilled.



Sec.  556.711  What is the effect of a record title holder's sublease
 of operating rights on the record title holder's liability?

    (a) A record title holder who subleases operating rights remains 
liable for all obligations of the lease, including those obligations 
accruing after BOEM's approval of the sublease, subject to Sec.  
556.604(e) and (f).
    (b) Neither the sublease of operating rights, nor subsequent 
assignment of those rights by the original sublessee, nor by any 
subsequent assignee of the operating rights, alters in any manner the 
liability of the record title holder for nonmonetary obligations.
    (c) Upon approval of the sublease of the operating rights, the 
sublessee and subsequent assignees of the operating rights become 
primarily liable for monetary obligations, but the record title holder 
remains secondarily liable for them, as prescribed in 30 U.S.C. 1712(a) 
and Sec.  556.604(f)(2).



Sec.  556.712  What is the effective date of a transfer?

    Any transfer is effective at 12:01 a.m. on the first day of the 
month following the date on which BOEM approves your request, unless you 
request an earlier effective date and BOEM approves that earlier date, 
but such earlier effective date, if prior to the date of BOEM's 
approval, does not relieve you of obligations accrued between that 
earlier effective date and the date of approval.



Sec.  556.713  What is the effect of an assignment of a lease on an
 assignee's liability under the lease?

    As assignee, you and any subsequent assignees are liable for all 
obligations that accrue after the effective date of your assignment. As 
assignee, you must comply with all the terms and conditions of the lease 
and regulations issued under OCSLA, and in addition, you must remedy all 
existing environmental and operational problems on the lease, properly 
abandon all wells, and reclaim the site, as required under 30 CFR part 
250.



Sec.  556.714  As a restricted joint bidder, may I transfer an
 interest to another restricted joint bidder?

    (a) Where the proposed assignment or transfer is by a person who, at 
the time of acquisition of an interest in the lease, was on the List of 
Restricted Joint Bidders, and that assignment or transfer is of less 
than the entire interest held by the assignor or transferor and to a 
person or persons on the same List of Restricted Joint Bidders, the 
assignor or transferor must file, prior to the approval of the 
assignment, a copy of all agreements applicable to the acquisition of 
that lease or fractional interest, or a description of the timing and 
nature of the agreement(s)

[[Page 498]]

by which the assignor or transferor acquired the interest it now
 wishes 
to transfer.
    (b) Such description of the timing and nature of the transfer 
agreement must be submitted together with a certified statement that 
attests to the truth and accuracy of any information reported concerning 
that agreement, subject to the penalties of 18 U.S.C. 1001.
    (c) If you wish to transfer less than your entire interest to 
another restricted joint bidder, BOEM may request the opinion of the 
Attorney General before acting on your request.
    (d) You may request that any submission to BOEM made pursuant to 
this part be treated confidentially. Please note such a request on your 
submission. BOEM will treat this request for confidentiality in 
accordance with the regulations at Sec.  556.104 and the regulations at 
43 CFR part 2.



Sec.  556.715  Are there any interests I may transfer or record
 without BOEM approval?

    (a) You may create, transfer, or assign economic interests without 
BOEM approval. However, for record purposes, you must send BOEM a copy 
of each instrument creating or transferring such interests within 90 
days after the last party executes the transfer instrument. For each 
lease affected, you must pay the service fee listed in Sec.  556.106 
with your documents submitted for record purposes and your submission 
must include evidence of payment via pay.gov.
    (b) For recordkeeping purposes, you may also submit other legal 
documents to BOEM for transactions that do not require BOEM approval. If 
you submit such documents for record purposes not required by this part, 
you must pay the service fee listed in Sec.  556.106 with your document 
submissions for each lease affected. Your submission must include 
evidence of payment via pay.gov.



Sec.  556.716  What must I do with respect to the designation of
 operator on a lease when a transfer of record title is submitted?

    (a) If a transfer of ownership of the record title interest only 
changes the percentage ownership of the record title, no new parties or 
new aliquots are involved in the transaction, and no change of 
designated operator is made, you will not need to submit a new 
designation of operator form.
    (b) In all cases other than that in paragraph (a) of this section, 
you must submit new designation of operator forms in accordance with 
Sec.  550.143 of this chapter. In the event that you are transferring 
multiple record title interests, you must comply with this requirement 
for each interest that does not fall within paragraph (a) of this 
section.



  Subpart H_Transferring All or Part of the Operating Rights in
 a Lease



Sec.  556.800  As an operating rights owner, may I assign all or
part of my operating rights interest?

    An operating rights owner may assign all or part of its operating 
rights interests, subject to BOEM approval. Each instrument that 
transfers an interest must describe, by officially designated aliquot 
parts and depth levels, the interest proposed to be transferred.



Sec.  556.801  How do I seek approval of an assignment of my
 operating rights?

    (a) The Regional Director will provide the form to document the 
assignment of an operating rights interest. You must request approval of 
each assignment of operating rights and submit to BOEM two originals of 
each instrument that transfers ownership of operating rights within 90 
days after the last party executes the transfer instrument. You must pay 
the service fee listed in Sec.  556.106 with your request and your 
submission must include evidence of payment via pay.gov.
    (b) A new operating rights owner must file a designation of 
operator, in accordance with Sec.  550.143, along with the request for 
the approval of the assignment.
    (c) If an operating rights owner assigns an undivided ownership 
interest in its operating rights, that assignment creates a joint 
ownership in the operating rights.
    (d) Before BOEM approves a sublease or re-assignment of operating 
rights, BOEM may consult with and consider the views of the Attorney 
General.

[[Page 499]]



Sec.  556.802  When would BOEM disapprove the assignment of all
 or part of my operating rights interest?

    BOEM may disapprove an assignment of all or part of your operating 
rights interest:
    (a) When the transferor or transferee has outstanding or unsatisfied 
obligations under this chapter or 30 CFR chapter II or XII;
    (b) When a transferor attempts a transfer that is not acceptable as 
to form or content (e.g., not on standard form, containing incorrect 
legal description, not executed in accordance with corporate governance, 
transferee does not meet the requirements of Sec.  556.401, etc.); or
    (c) When the transfer does not conform to these regulations, or any 
other applicable laws or regulations (e.g., departmental debarment 
rules).



Sec.  556.803  What if I want to assign operating rights interests
 in more than one lease at the same time, but to different parties?

    You may not assign operating rights interests in more than one lease 
to different parties using the same instrument. If you want to transfer 
operating rights interests in more than one lease at the same time, you 
must submit two originally executed forms for each transfer. Each 
request for a transfer of operating rights interest must be accompanied 
by a cover letter executed by one of the parties to the transfer (or an 
authorized agent thereof) and evidence of payment via pay.gov.



Sec.  556.804  What if I want to assign my operating rights interest
 in a lease to multiple parties?

    You may assign your operating rights interest in one lease to 
multiple parties using the same instrument. That instrument must be 
submitted in duplicate originals, accompanied by a cover letter executed 
by one of the parties to the transfer (or an authorized agent thereof). 
In such a multiple transfer of interests using a single instrument, a 
separate fee applies to each individual transfer of interest and 
evidence of payment via pay.gov must accompany the instrument.



Sec.  556.805  What is the effect of an operating rights owner's
 assignment of operating rights on the assignor's liability?

    An operating rights owner (who does not hold record title) who 
assigns the operating rights remains liable for all obligations of the 
lease that accrued during the period in which the assignor owned the 
operating rights, up to the effective date of the assignment, including 
decommissioning obligations that accrued during that period. BOEM's 
approval of the assignment does not alter that liability. Even after 
assignment, BOEM or BSEE may require the assignor to bring the lease 
into compliance if the assignee or any subsequent assignee fails to 
perform any obligation under the lease, to the extent the obligation 
accrued before approval of the assignment.



Sec.  556.806  What is the effective date of an assignment of
 operating rights?

    An assignment is effective at 12:01 a.m. on the first day of the 
month following the date on which BOEM approves your request, unless you 
request an earlier effective date and BOEM approves that earlier date. 
Such an earlier effective date, if prior to the date of BOEM's approval, 
does not relieve you of obligations accrued between that earlier 
effective date and the date of approval.



Sec.  556.807  What is the effect of an assignment of operating
 rights on an assignee's liability?

    As assignee, you and any subsequent assignees are liable for all 
obligations that accrue after the effective date of your assignment. As 
assignee, you must comply with all the terms and conditions of the lease 
and regulations issued under OCSLA. In addition, you must remedy all 
existing environmental and operational problems on the lease, properly 
abandon all wells, and reclaim the site, as required under 30 CFR part 
250.



Sec.  556.808  As an operating rights owner, are there any interests
 I may assign without BOEM approval?

    (a) You may create, transfer, or assign economic interests without 
BOEM approval. However, for record purposes,

[[Page 500]]

you must send BOEM a copy of each instrument creating or transferring 
such interests within 90 days after the last party executes the transfer 
instrument. For each lease affected, you must pay the service fee listed 
in Sec.  556.106 with your documents submitted for record purposes, and 
your submission must include evidence of payment via pay.gov.
    (b) For record keeping purposes, you may also submit other legal 
documents to BOEM for transactions that do not require BOEM approval. If 
you submit such documents for record purposes that are not required by 
these regulations, for each lease affected, you must pay the service fee 
listed in Sec.  556.106 with your document submissions, and your 
submission must include evidence of payment via pay.gov.



Sec.  556.809  [Reserved]



Sec.  556.810  What must I do with respect to the designation of 
operator on a lease when a transfer of operating rights ownership 
is submitted?

    (a) If a transfer of ownership of operating rights only changes the 
percentage ownership; no new parties, new aliquots, or new depths are 
involved in the transaction; and no change of designated operator is 
made, you will not need to submit a new designation of operator form.
    (b) In all cases other than that in paragraph (a) of this section, 
you must submit new designation of operator forms, in accordance with 
Sec.  550.143 of this chapter. In the event that you are transferring 
multiple operating rights interests, you must comply with this 
requirement for each interest that does not fall within paragraph (a) of 
this section.



             Subpart I_Bonding or Other Financial Assurance



Sec.  556.900  Bond requirements for an oil and gas or sulfur lease.

    This section establishes bond requirements for the lessee of an OCS 
oil and gas or sulfur lease.
    (a) Before BOEM will issue a new lease or approve the assignment of 
an existing lease to you as lessee, you or another record title owner 
for the lease must:
    (1) Maintain with the Regional Director a $50,000 lease bond that 
guarantees compliance with all the terms and conditions of the lease; or
    (2) Maintain a $300,000 area-wide bond that guarantees compliance 
with all the terms and conditions of all your oil and gas and sulfur 
leases in the area where the lease is located; or
    (3) Maintain a lease or area-wide bond in the amount required in 
Sec.  556.901(a) or (b).
    (b) For the purpose of this section, there are three areas. The 
three areas are:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast;
    (2) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.
    (c) The requirement to maintain a lease bond (or substitute security 
instrument) under paragraph (a)(1) of this section and Sec.  556.901(a) 
and (b) may be satisfied if your operator or an operating rights owner 
provides a lease bond in the required amount that guarantees compliance 
with all the terms and conditions of the lease. Your operator or an 
operating rights owner may use an areawide bond under this paragraph to 
satisfy your bond obligation.
    (d) If a surety makes payment to the United States under a bond or 
alternative form of security maintained under this section, the surety's 
remaining liability under the bond or alternative form of security is 
reduced by the amount of that payment. See paragraph (e) of this section 
for the requirement to replace the reduced bond coverage.
    (e) If the value of your surety bond or alternative security is 
reduced because of a default or for any other reason, you must provide 
additional bond coverage sufficient to meet the security required under 
this subpart within 6 months, or such shorter period of time as the 
Regional Director may direct.
    (f) You may pledge United States Department of the Treasury 
(Treasury)

[[Page 501]]

securities instead of a bond. The Treasury securities you pledge must be 
negotiable for an amount of cash equal to the value of the bond they 
replace.
    (1) If you pledge Treasury securities under this paragraph (f), you 
must monitor their value. If their market value falls below the level of 
bond coverage required under this subpart, you must pledge additional 
Treasury securities to raise the value of the securities pledged to the 
required amount.
    (2) If you pledge Treasury securities, you must include authority 
for the Regional Director to sell them and use the proceeds in the event 
that the Regional Director determines that you fail to satisfy any lease 
obligation.
    (g) You may pledge alternative types of security instruments instead 
of providing a bond if the Regional Director determines that the 
alternative security protects the interests of the United States to the 
same extent as the required bond.
    (1) If you pledge an alternative type of security under this 
paragraph, you must monitor the security's value. If its market value 
falls below the level of bond coverage required under this subpart, you 
must pledge additional securities to raise the value of the securities 
pledged to the required amount.
    (2) If you pledge an alternative type of security, you must include 
authority for the Regional Director to sell the security and use the 
proceeds when the Regional Director determines that you failed to 
satisfy any lease obligation.
    (h) If you fail to replace a deficient bond or to provide additional 
bond coverage upon demand, the Regional Director may:
    (1) Assess penalties under part 550, subpart N of this chapter;
    (2) Suspend production and other operations on your leases in 
accordance with 30 CFR 250.173; and
    (3) Initiate action to cancel your lease.



Sec.  556.901  Additional bonds.

    (a) This paragraph explains what bonds you must provide before lease 
exploration activities commence.
    (1)(i) You must furnish the Regional Director a $200,000 bond that 
guarantees compliance with all the terms and conditions of the lease by 
the earliest of:
    (A) The date you submit a proposed exploration plan (EP) for 
approval; or
    (B) The date you submit a request for approval of the assignment of 
a lease on which an EP has been approved.
    (ii) The Regional Director may authorize you to submit the $200,000 
lease exploration bond after you submit an EP, but before approval of 
drilling activities under the EP.
    (iii) You may satisfy the bond requirement of this paragraph (a) by 
providing a new bond or by increasing the amount of your existing bond.
    (2) A $200,000 lease exploration bond pursuant to paragraph (a)(1) 
of this section need not be submitted and maintained if the lessee 
either:
    (i) Furnishes and maintains an areawide bond in the sum of $1 
million issued by a qualified surety and conditioned on compliance with 
all the terms and conditions of oil and gas and sulfur leases held by 
the lessee on the OCS for the area in which the lease is situated; or
    (ii) Furnishes and maintains a bond pursuant to paragraph (b)(2) of 
this section.
    (b) This paragraph explains what bonds you (the lessee) must provide 
before lease development and production activities commence.
    (1)(i) You must furnish the Regional Director a $500,000 bond that 
guarantees compliance with all the terms and conditions of the lease by 
the earliest of:
    (A) The date you submit a proposed development and production plan 
(DPP) or development operations coordination document (DOCD) for 
approval; or
    (B) The date you submit a request for approval of the assignment of 
a lease on which a DPP or DOCD has been approved.
    (ii) The Regional Director may authorize you to submit the $500,000 
lease development bond after you submit a DPP or DOCD, but before he/she 
approves the installation of a platform or the commencement of drilling 
activities under the DPP or DOCD.

[[Page 502]]

    (iii) You may satisfy the bond requirement of this paragraph by 
providing a new bond or by increasing the amount of your existing bond.
    (2) You need not submit and maintain a $500,000 lease development 
bond pursuant to paragraph (b)(1) of this section if you furnish and 
maintain an areawide bond in the sum of $3 million issued by a qualified 
surety and conditioned on compliance with all the terms and conditions 
of oil and gas and sulfur leases you hold on the OCS for the area in 
which the lease is located.
    (c) If you can demonstrate to the satisfaction of the authorized 
officer that you can satisfy your decommissioning obligations for less 
than the amount of lease bond coverage required under paragraph (b)(1) 
of this section, the authorized officer may accept a lease surety bond 
in an amount less than the prescribed amount, but not less than the 
amount of the cost for decommissioning.
    (d) The Regional Director may determine that additional security 
(i.e., security above the amounts prescribed in Sec.  556.900(a) and 
paragraphs (a) and (b) of this section) is necessary to ensure 
compliance with the obligations under your lease, the regulations in 
this chapter, and the regulations in 30 CFR chapters II and XII.
    (1) The Regional Director's determination will be based on his/her 
evaluation of your ability to carry out present and future financial 
obligations demonstrated by:
    (i) Financial capacity substantially in excess of existing and 
anticipated lease and other obligations, as evidenced by audited 
financial statements (including auditor's certificate, balance sheet, 
and profit and loss sheet);
    (ii) Projected financial strength significantly in excess of 
existing and future lease obligations based on the estimated value of 
your existing OCS lease production and proven reserves for future 
production;
    (iii) Business stability based on five years of continuous operation 
and production of oil and gas or sulfur in the OCS or in the onshore oil 
and gas industry;
    (iv) Reliability in meeting obligations based on:
    (A) Credit rating; or
    (B) Trade references, including names and addresses of other 
lessees, drilling contractors, and suppliers with whom you have dealt; 
and
    (v) Record of compliance with laws, regulations, and lease terms.
    (2) You may satisfy the Regional Director's demand for additional 
security by increasing the amount of your existing bond or by providing 
additional bond or bonds.
    (e) The Regional Director will determine the amount of additional 
bond required to guarantee compliance. The Regional Director will 
consider potential underpayment of royalty and cumulative 
decommissioning obligations.
    (f) If your cumulative potential obligations and liabilities either 
increase or decrease, the Regional Director may adjust the amount of 
additional bond required.
    (1) If the Regional Director proposes an adjustment, the Regional 
Director will:
    (i) Notify you and the surety of any proposed adjustment to the 
amount of bond required; and
    (ii) Give you an opportunity to submit written or oral comment on 
the adjustment.
    (2) If you request a reduction of the amount of additional bond 
required, you must submit evidence to the Regional Director 
demonstrating that the projected amount of royalties due the Government 
and the estimated costs of decommissioning are less than the required 
bond amount. If the Regional Director finds that the evidence you submit 
is convincing, the Regional Director may reduce the amount of additional 
bond required.



Sec.  556.902  General requirements for bonds.

    (a) Any bond or other security that you, as lessee, operating rights 
owner or operator, provide under this part must:
    (1) Be payable upon demand to the Regional Director;
    (2) Guarantee compliance with all of your obligations under the 
lease, regulations in this chapter, and regulations under 30 CFR 
chapters II and XII; and
    (3) Guarantee compliance with the obligations of all lessees, 
operating

[[Page 503]]

rights owners and operators on the lease.
    (b) All bonds and pledges you furnish under this part must be on a 
form or in a form approved by the Director. Surety bonds must be issued 
by a surety that the Treasury certifies as an acceptable surety on 
Federal bonds and that is listed in the current Treasury Circular No. 
570. You may obtain a copy of the current Treasury Circular No. 570 from 
the Surety Bond Branch, Financial Management Service, Department of the 
Treasury, East-West Highway, Hyattsville, MD 20782.
    (c) You and a qualified surety must execute your bond. When either 
party is a corporation, an authorized official for the party must sign 
the bond and attest to it by an imprint of the corporate seal.
    (d) Bonds must be non-cancellable, except as provided in Sec.  
556.906 of this part. Bonds must continue in full force and effect even 
though an event occurs that could diminish, terminate, or cancel a 
surety obligation under State surety law.
    (e) Lease bonds must be:
    (1) A surety bond;
    (2) Treasury securities as provided in Sec.  556.900(f);
    (3) Another form of security approved by the Regional Director; or
    (4) A combination of these security methods.
    (f) You may submit a bond to the Regional Director executed on a 
form approved under paragraph (b) of this section that you have 
reproduced or generated by use of a computer. If you do, and if the 
document omits terms or conditions contained on the form approved by the 
Director, the bond you submit will be deemed to contain the omitted 
terms and conditions.



Sec.  556.903  Lapse of bond.

    (a) If your surety becomes bankrupt, insolvent, or has its charter 
or license suspended or revoked, any bond coverage from that surety 
terminates immediately. In that event, you must promptly provide a new 
bond in the amount required under Sec. Sec.  556.900 and 556.901 to the 
Regional Director and advise the Regional Director of the lapse in your 
previous bond.
    (b) You must notify the Regional Director of any action filed 
alleging that you, your surety, or your guarantor are insolvent or 
bankrupt. You must notify the Regional Director within 72 hours of 
learning of such an action. All bonds must require the surety to provide 
this information to you and directly to BOEM.



Sec.  556.904  Lease-specific abandonment accounts.

    (a) The Regional Director may authorize you to establish a lease-
specific abandonment account in a federally insured institution in lieu 
of the bond required under Sec.  556.901(d). The account must provide 
that, except as provided in paragraph (a)(3) of this section, funds may 
not be withdrawn without the written approval of the Regional Director.
    (1) Funds in a lease-specific abandonment account must be payable 
upon demand to BOEM and pledged to meet your decommissioning 
obligations.
    (2) You must fully fund the lease-specific abandonment account to 
cover all decommissioning costs as estimated by BOEM within the 
timeframe the Regional Director prescribes.
    (3) You must provide binding instructions under which the 
institution managing the account is to purchase Treasury securities 
pledged to BOEM under paragraph (d) of this section.
    (b) Any interest paid on funds in a lease-specific abandonment 
account will be treated as other funds in the account unless the 
Regional Director authorizes in writing the payment of interest to the 
party who deposits the funds.
    (c) The Regional Director may allow you to pledge Treasury 
securities that are made payable upon demand to the Regional Director to 
satisfy your obligation to make payments into a lease-specific 
abandonment account.
    (d) Before the amount of funds in a lease-specific abandonment 
account equals the maximum insurable amount as determined by the Federal 
Deposit Insurance Corporation or the Federal Savings and Loan Insurance 
Corporation, the institution managing the account must use the funds in 
the account to purchase Treasury securities pledged to BOEM under 
paragraph (c)

[[Page 504]]

of this section. The institution managing the lease specific-abandonment 
account will join with the Regional Director to establish a Federal 
Reserve Circular 154 account to hold these Treasury securities, unless 
the Regional Director authorizes the managing institution to retain the 
pledged Treasury securities in a separate trust account. You may obtain 
a copy of the current Treasury Circular No. 154 from the Surety Bond 
Branch, Financial Management Service, Department of the Treasury, East-
West Highway, Hyattsville, MD 20782.
    (e) The Regional Director may require you to create an overriding 
royalty or production payment obligation for the benefit of a lease-
specific account pledged for the decommissioning of a lease. The 
required obligation may be associated with oil and gas or sulfur 
production from a lease other than the lease bonded through the lease-
specific abandonment account.



Sec.  556.905  Using a third-party guarantee instead of a bond.

    (a) When the Regional Director may accept a third-party guarantee. 
The Regional Director may accept a third-party guarantee instead of an 
additional bond under Sec.  556.901(d) if:
    (1) The guarantee meets the criteria in paragraph (c) of this 
section;
    (2) The guarantee includes the terms specified in paragraph (d) of 
this section;
    (3) The guarantor's total outstanding and proposed guarantees do not 
exceed 25 percent of its unencumbered net worth in the United States; 
and
    (4) The guarantor submits an indemnity agreement meeting the 
criteria in paragraph (e) of this section.
    (b) What to do if your guarantor becomes unqualified. If, during the 
life of your third-party guarantee, your guarantor no longer meets the 
criteria of paragraphs (a)(3) and (c)(3) of this section, you must:
    (1) Notify the Regional Director immediately; and
    (2) Cease production until you comply with the bond coverage 
requirements of this subpart.
    (c) Criteria for acceptable guarantees. If you propose to furnish a 
third party's guarantee, that guarantee must ensure compliance with all 
lessees' lease obligations, the obligations of all operating rights 
owners, and the obligations of all operators on the lease. The Regional 
Director will base acceptance of your third-party guarantee on the 
following criteria:
    (1) The period of time that your third-party guarantor (guarantor) 
has been in continuous operation as a business entity where:
    (i) Continuous operation is the time that your guarantor conducts 
business immediately before you post the guarantee; and
    (ii) Continuous operation excludes periods of interruption in 
operations that are beyond your guarantor's control and that do not 
affect your guarantor's likelihood of remaining in business during 
exploration, development, production, and decommissioning.
    (2) Financial information available in the public record or 
submitted by your guarantor, on your guarantor's own initiative, in 
sufficient detail to show to the Regional Director's satisfaction that 
your guarantor is qualified based on:
    (i) Your guarantor's current rating for its most recent bond 
issuance by either Moody's Investor Service or Standard and Poor's 
Corporation;
    (ii) Your guarantor's net worth, taking into account liabilities 
under its guarantee of compliance with all the terms and conditions of 
your lease, the regulations in this chapter and 30 CFR chapters II and 
XII, and your guarantor's other guarantees;
    (iii) Your guarantor's ratio of current assets to current 
liabilities, taking into account liabilities under its guarantee of 
compliance with all the terms and conditions of your lease, the 
regulations in this chapter and 30 CFR chapters II and XII, and your 
guarantor's other guarantees; and
    (iv) Your guarantor's unencumbered fixed assets in the United 
States.
    (3) When the information required by paragraph (c) of this section 
is not publicly available, your guarantor may submit the information in 
the following table. Your guarantor must update the information annually 
within 90 days of the end of the fiscal year or by the date prescribed 
by the Regional Director.

[[Page 505]]



------------------------------------------------------------------------
     The guarantor should submit                      That
------------------------------------------------------------------------
(i) Financial statements for the most  Include a report by an
 recently completed fiscal year,        independent certified public
                                        accountant containing the
                                        accountant's audit opinion or
                                        review opinion of the
                                        statements. The report must be
                                        prepared in conformance with
                                        generally accepted accounting
                                        principles and contain no
                                        adverse opinion.
(ii) Financial statements for          Your guarantor's financial
 completed quarters in the current      officer certifies to be correct.
 fiscal year, and
(iii) Additional information as        Your guarantor's financial
 requested by the Regional Director.    officer certifies to be correct.
------------------------------------------------------------------------

    (d) Provisions required in all third-party guarantees. Your third-
party guarantee must contain each of the following provisions.
    (1) If you, your operator, or an operating rights owner fails to 
comply with any lease term or regulation, your guarantor must either:
    (i) Take corrective action; or,
    (ii) Be liable under the indemnity agreement to provide, within 7 
calendar days, sufficient funds for the Regional Director to complete 
corrective action.
    (2) If your guarantor complies with paragraph (d)(1) of this 
section, this compliance will not reduce its liability.
    (3) If your guarantor wishes to terminate the period of liability 
under its guarantee, it must:
    (i) Notify you and the Regional Director at least 90 days before the 
proposed termination date;
    (ii) Obtain the Regional Director's approval for the termination of 
the period of liability for all or a specified portion of your 
guarantor's guarantee; and
    (iii) Remain liable for all work and workmanship performed during 
the period that your guarantor's guarantee is in effect.
    (4) You must provide a suitable replacement security instrument 
before the termination of the period of liability under your third-party 
guarantee.
    (e) Required criteria for indemnity agreements. If the Regional 
Director approves your third-party guarantee, the guarantor must submit 
an indemnity agreement.
    (1) The indemnity agreement must be executed by your guarantor and 
all persons and parties bound by the agreement.
    (2) The indemnity agreement must bind each person and party 
executing the agreement jointly and severally.
    (3) When a person or party bound by the indemnity agreement is a 
corporate entity, two corporate officers who are authorized to bind the 
corporation must sign the indemnity agreement.
    (4) Your guarantor and the other corporate entities bound by the 
indemnity agreement must provide the Regional Director copies of:
    (i) The authorization of the signatory corporate officials to bind 
their respective corporations;
    (ii) An affidavit certifying that the agreement is valid under all 
applicable laws; and
    (iii) Each corporation's corporate authorization to execute the 
indemnity agreement.
    (5) If your third-party guarantor or another party bound by the 
indemnity agreement is a partnership, joint venture, or syndicate, the 
indemnity agreement must:
    (i) Bind each partner or party who has a beneficial interest in your 
guarantor; and
    (ii) Provide that, upon demand by the Regional Director under your 
third-party guarantee, each partner is jointly and severally liable for 
compliance with all terms and conditions of your lease.
    (6) When forfeiture is called for under Sec.  556.907, the indemnity 
agreement must provide that your guarantor will either:
    (i) Bring your lease into compliance; or
    (ii) Provide, within 7 calendar days, sufficient funds to permit the 
Regional Director to complete corrective action.
    (7) The indemnity agreement must contain a confession of judgment. 
It must provide that, if the Regional Director determines that you, your 
operator, or an operating rights owner is in default of the lease, the 
guarantor:

[[Page 506]]

    (i) Will not challenge the determination; and
    (ii) Will remedy the default.
    (8) Each indemnity agreement is deemed to contain all terms and 
conditions contained in this paragraph (e), even if the guarantor has 
omitted them.



Sec.  556.906  Termination of the period of liability and
 cancellation of a bond.

    This section defines the terms and conditions under which BOEM will 
terminate the period of liability of a bond or cancel a bond. 
Terminating the period of liability of a bond ends the period during 
which obligations continue to accrue, but does not relieve the surety of 
the responsibility for obligations that accrued during the period of 
liability. Canceling a bond relieves the surety of all liability. The 
liabilities that accrue during a period of liability include obligations 
that started to accrue prior to the beginning of the period of liability 
and had not been met, and obligations that begin accruing during the 
period of liability.
    (a) When you or the surety under your bond requests termination:
    (1) The Regional Director will terminate the period of liability 
under your bond within 90 days after BOEM receives the request; and
    (2) If you intend to continue operations, or have not met all 
decommissioning obligations, you must provide a replacement bond of an 
equivalent amount.
    (b) If you provide a replacement bond, the Regional Director will 
cancel your previous bond and the surety that provided your previous 
bond will not retain any liability, provided that:
    (1) The new bond is equal to or greater than the bond that was 
terminated, or you provide an alternative form of security, and the 
Regional Director determines that the alternative form of security 
provides a level of security equal to or greater than that provided for 
by the bond that was terminated;
    (2) For a base bond submitted under Sec.  556.900(a) or under Sec.  
556.901(a) or (b), the surety issuing the new bond agrees to assume all 
outstanding liabilities that accrued during the period of liability that 
was terminated; and
    (3) For additional bonds submitted under Sec.  556.901(d), the 
surety issuing the new additional bond agrees to assume that portion of 
the outstanding liabilities that accrued during the period of liability 
that was terminated and that the Regional Director determines may exceed 
the coverage of the base bond, and of which the Regional Director 
notifies the provider of the bond.
    (c) This paragraph applies if the period of liability is terminated 
for a bond, but the bond is not replaced by a bond of an equivalent 
amount. The surety that provided your terminated bond will continue to 
be responsible for accrued obligations:
    (1) Until the obligations are satisfied; and
    (2) For additional periods of time in accordance with paragraph (d) 
of this section.
    (d) When your lease expires or is terminated, the surety that issued 
a bond will continue to be responsible, and the Regional Director will 
retain other forms of security as shown in the following table:

------------------------------------------------------------------------
                                  The period of
For the following type of bond    liability will     Your bond will be
                                       end               cancelled
------------------------------------------------------------------------
(1) Base bonds submitted under  When the Regional  Seven years after the
 Sec.   556.900(a), Sec.         Director           termination of the
 556.901(a), or (b).             determines that    lease, 6 years after
                                 you have met all   completion of all
                                 of your            bonded obligations,
                                 obligations        or at the conclusion
                                 under the lease,   of any appeals or
                                                    litigation related
                                                    to your bonded
                                                    obligation,
                                                    whichever is the
                                                    latest. The Regional
                                                    Director will reduce
                                                    the amount of your
                                                    bond or return a
                                                    portion of your
                                                    security if the
                                                    Regional Director
                                                    determines that you
                                                    need less than the
                                                    full amount of the
                                                    base bond to meet
                                                    any possible future
                                                    problems.
(2) Additional bonds submitted  When the Regional  When you meet your
 under Sec.   556.901(d).        Director           bonded obligations,
                                 determines that    unless the Regional
                                 you have met all   Director: (i)
                                 your obligations   Determines that the
                                 covered by the     future potential
                                 additional bond,   liability resulting
                                                    from any undetected
                                                    problem is greater
                                                    than the amount of
                                                    the base bond; and
                                                   (ii) Notifies the
                                                    provider of the bond
                                                    that the Regional
                                                    Director will wait 7
                                                    years before
                                                    cancelling all or a
                                                    part of the bond (or
                                                    longer period as
                                                    necessary to
                                                    complete any appeals
                                                    or judicial
                                                    litigation related
                                                    to your bonding
                                                    obligation).
------------------------------------------------------------------------


[[Page 507]]

    (e) For all bonds, the Regional Director may reinstate your bond as 
if no cancellation or release had occurred if:
    (1) A person makes a payment under the lease and the payment is 
rescinded or must be repaid by the recipient because the person making 
the payment is insolvent, bankrupt, subject to reorganization, or placed 
in receivership; or
    (2) The responsible party represents to BOEM that it has discharged 
its obligations under the lease, and the representation was materially 
false when the bond was canceled or released.



Sec.  556.907  Forfeiture of bonds and/or other securities.

    This section explains how a bond or other security may be forfeited.
    (a) The Regional Director will call for forfeiture of all or part of 
the bond, other form of security, or guarantee you provide under this 
part if:
    (1) You (the party who provided the bond) refuse, or the Regional 
Director determines that you are unable to comply with any term or 
condition of your lease; or
    (2) You default on one of the conditions under which the Regional 
Director accepts your bond, third-party guarantee, and/or other form of 
security.
    (b) The Regional Director may pursue forfeiture of your bond without 
first making demands for performance against any lessee, operating 
rights owner, or other person authorized to perform lease obligations.
    (c) The Regional Director will:
    (1) Notify you, the surety on your bond or other form of security, 
and any third-party guarantor of a determination to call for forfeiture 
of the bond, security, or guarantee under this section.
    (i) This notice will be in writing, and will provide the reason for 
the forfeiture and the amount to be forfeited.
    (ii) The Regional Director must base the amount he/she determines is 
forfeited upon his/her estimate of the total cost of corrective action 
to bring your lease into compliance.
    (2) Advise you, your third-party guarantor, and any surety that you, 
your guarantor, and any surety may avoid forfeiture if, within five 
working days:
    (i) You agree to, and demonstrate that you will bring your lease 
into compliance within the timeframe that the Regional Director 
prescribes;
    (ii) Your third-party guarantor agrees to and demonstrates that it 
will complete the corrective action to bring your lease into compliance 
within the timeframe that the Regional Director prescribes; or
    (iii) Your surety agrees to and demonstrates that it will bring your 
lease into compliance within the timeframe that the Regional Director 
prescribes, even if the cost of compliance exceeds the face amount of 
the bond or other surety instrument.
    (d) If the Regional Director finds you are in default, he/she may 
cause the forfeiture of any bonds and other security deposited as your 
guarantee of compliance with the terms and conditions of your lease and 
the regulations in this chapter and 30 CFR chapters II and XII.
    (e) If the Regional Director determines that your bond and/or other 
security is forfeited, the Regional Director will:
    (1) Collect the forfeited amount; and
    (2) Use the funds collected to bring your leases into compliance and 
to correct any default.
    (f) If the amount the Regional Director collects under your bond and 
other security is insufficient to pay the full cost of corrective 
actions he/she may:
    (1) Take or direct action to obtain full compliance with your lease 
and the regulations in this chapter; and
    (2) Recover from you, any co-lessee, operating rights owner, and/or 
any third-party guarantor responsible under this subpart all costs in 
excess of the amount he/she collects under your forfeited bond and other 
security.
    (g) The amount that the Regional Director collects under your 
forfeited bond and other security may exceed the costs of taking the 
corrective actions required to obtain full compliance with the terms and 
conditions of your lease and the regulations in this chapter and 30 CFR 
chapters II and XII. In this case, the Regional Director will return the 
excess funds to the party from whom they were collected.

[[Page 508]]



    Subpart J_Bonus or Royalty Credits for Exchange of Certain Leases



Sec.  556.1000  Leases formerly eligible for a bonus or royalty credit.

    Bonus or royalty credits were available to lessees with leases:
    (a) In effect on December 20, 2006, and located in:
    (1) The Eastern Planning Area and within 125 miles of the coastline 
of the State of Florida; or,
    (2) The Central Planning Area and within the Desoto Canyon OPD, the 
Destin Dome OPD, or the Pensacola OPD and within 100 miles of the 
coastline of the State of Florida.
    (b) The deadline for applying for such a bonus or royalty credit was 
October 14, 2010; therefore, lessees may no longer apply for such 
credits.



                        Subpart K_Ending a Lease



Sec.  556.1100  How does a lease expire?

    (a) Your oil and gas lease will automatically expire at the end of 
its primary term unless you have taken action, as set forth in Sec.  
556.601, to maintain the lease beyond the primary term.
    (b) Your sulfur lease will automatically expire at the end of its 
primary term unless you have taken action, as set forth in Sec.  
556.603, to maintain the lease beyond the primary term.



Sec.  556.1101  May I relinquish my lease or an aliquot part thereof?

    (a) A record title owner may relinquish a lease or an aliquot part 
of a lease if all record title owners of a lease or any aliquot part(s) 
of the lease file three original copies of a request to relinquish with 
BOEM on Form BOEM-0152, entitled, ``Relinquishment of Federal Oil and 
Gas Lease.'' No filing fee is required.
    (b) A relinquishment will be subject to the continued obligation of 
the record title owner and the surety to make all payments due, 
including any accrued rentals, royalties and deferred bonuses, and to 
abandon all wells and condition or remove all platforms and other 
facilities on the land to be relinquished to the satisfaction of the 
Director.
    (c) The effective date of the relinquishment is the date on which 
the relinquishment is filed with the proper BOEM regional office.



Sec.  556.1102  Under what circumstances will BOEM cancel my lease?

    (a) BOEM may cancel your non-producing lease if you fail to comply 
with any provision of OCSLA, the lease, or applicable regulations if the 
failure continues for 30 days after mailing of notice to your post 
office address of record by registered mail and you have not requested 
and been granted any additional time within which to correct the 
failure. Such cancellation is subject to judicial review under section 
23 of OCSLA (43 U.S.C. 1349).
    (b) Your producing lease may be cancelled if you fail to comply with 
any provision of OCSLA, the lease, or applicable regulations. The 
Secretary will cancel a producing lease after the judicial proceedings 
required under section 5(d) of OCSLA (43 U.S.C. 1334(d)).
    (c) BOEM may cancel your lease if it determines that the lease was 
obtained by fraud or misrepresentation. You will have notice and an 
opportunity to be heard before BOEM cancels your lease.
    (d) BOEM may cancel your lease at any time if it determines, after a 
hearing, that continued activity will probably cause serious harm or 
damage to life (including fish and other aquatic life), property, any 
mineral, national security or defense, or the marine, coastal, or human 
environment; that the threat of harm or damage will not disappear or 
decrease to an acceptable level within a reasonable period of time; and 
the advantages of cancellation outweigh the advantages of continuing the 
lease.
    (e) BOEM may cancel your lease at any time after operations under 
the lease have been suspended or temporarily prohibited by the 
Department continuously for a period of five years pursuant to paragraph 
(d) of this section, absent your request for a shorter period.
    (f) If, upon demand, you fail to provide a bond, or alternative type 
of security instrument acceptable to BOEM,

[[Page 509]]

the Regional Director may assess penalties or cancel your lease in 
accordance with part 550, subpart N of this chapter;
    (g) Title 30, part 550, subpart A of the CFR provides the procedures 
for lease cancellation and compensation, if applicable.



          Subpart L_Leases Maintained Under Section 6 of OCSLA



Sec.  556.1200  Effect of regulations on lease.

    (a) All regulations in this part, insofar as they are applicable, 
will supersede the provisions of any lease that is maintained under 
section 6(a) of the Act. However, the provisions of a lease relating to 
area, minerals, rentals, royalties (subject to sections 6(a)(8) and (9) 
of the Act), and term (subject to section 6(a)(10) of the Act and, as to 
sulfur, subject to section 6(b)(2) of the Act) will continue in effect, 
and, in the event of any conflict or inconsistency, will take precedence 
over these regulations.
    (b) A lease maintained under section 6(a) of the Act is also subject 
to all operating and conservation regulations applicable to the OCS. In 
addition, the regulations relating to geophysical and geological 
exploratory operations and to pipeline ROW(s) are applicable, to the 
extent that those regulations are not contrary to or inconsistent with 
the lease provisions relating to area, minerals, rentals, royalties and 
term. The lessee must comply with any provision of the lease as 
validated, the subject matter of which is not covered in the regulations 
in this part.



Sec.  556.1201  Section 6(a) leases and leases other than those
 for oil, gas, or sulfur.

    The existence of an oil and gas lease maintained under section 6(a) 
of the Act precludes only the issuance in the same area of an oil and 
gas lease under OCSLA, but does not preclude the issuance of other types 
of leases under OCSLA. However, no other lease may authorize or permit 
the lessee thereunder unreasonably to interfere with or endanger 
operations under the existing lease. The United States will not grant 
any sulfur leases on any area that is included in a lease covering 
sulfur under section 6(b) of the Act.



                     Subpart M_Environmental Studies



Sec.  556.1300  Environmental studies.

    (a) The Director will conduct a study or studies of any area or 
region included in any oil and gas lease sale or other lease in order to 
establish information needed for assessment and management of impacts on 
the human, marine and coastal environments which may be affected by OCS 
oil and gas or other mineral activities in such area or region. The 
purposes of such studies will include, to the extent practicable, 
analyses of the impacts of pollutants introduced into the environments 
and impacts of offshore activities on the seabed and affected coastal 
areas.
    (b) Studies will be planned and carried out in cooperation with the 
affected States and interested parties and, to the extent possible, will 
not duplicate studies done under other laws. Where appropriate, the 
Director will, to the maximum extent practicable, coordinate with the 
National Oceanic and Atmospheric Administration (NOAA) in executing its 
environmental studies responsibilities. The Director may also make 
agreements for the coordination with, or the use of the services or 
resources of, any other Federal, State or local government agency in the 
conduct of such studies.
    (c) Any study of an area or region required by paragraph (a) of this 
section for a lease sale will be commenced not later than six months 
prior to holding a lease sale for that area. The Director may use 
information collected in any prior study. The Director may initiate 
studies for an area or region not identified in the leasing program.
    (d) After the leasing and developing of any area or region, the 
Director will conduct such studies as are deemed necessary to establish 
additional information and will monitor the human, marine and coastal 
environments of such area or region in a manner designed to provide 
information, which can be compared with the results of studies conducted 
prior to OCS oil and gas development. This will be done to identify any 
significant changes in the

[[Page 510]]

quality and productivity of such environments, to establish trends in 
the area studies, and to design experiments identifying the causes of 
such changes. Findings from such studies will be used to recommend 
modifications in practices that are employed to mitigate the effects of 
OCS activities and to enhance the data/information base for predicting 
impacts which might result from a single lease sale or cumulative OCS 
activities.
    (e) Information available or collected by the studies program will, 
to the extent practicable, be provided in a form and in a timeframe that 
can be used in the decision-making process associated with a specific 
leasing action or with longer term OCS minerals management 
responsibilities.



PART 560_OUTER CONTINENTAL SHELF OIL AND GAS LEASING-
-Table of Contents



                      Subpart A_General Provisions

560.100 Authority
560.100 What is the purpose of this part?
560.102 What definitions apply to this part?
560.103 What is BOEM's authority to collect information?

                        Subpart B_Bidding Systems

                           General Provisions

560.200 What is the purpose of this subpart?
560.201 What definitions apply to this subpart?
560.202 What bidding systems may BOEM use?
560.203 What conditions apply to the bidding systems that BOEM uses?

                             Eligible Leases

560.210 How do royalty suspension volumes apply to eligible leases?
560.211 When does an eligible lease qualify for a royalty suspension 
          volume?
560.212 How does BOEM assign and monitor royalty suspension volumes for 
          eligible leases?
560.213 How long will a royalty suspension volume for an eligible lease 
          be effective?
550.214 How do I measure natural gas production on my eligible lease?

                     Royalty Suspensions (RS) Leases

560.220 How does royalty suspension apply to leases issued in a sale 
          held after November 2000?
560.221 When does a lease issued in a sale held after November 2000 get 
          a royalty suspension?
560.222 How long will a royalty suspension volume be effective for a 
          lease issued in a sale held after November 2000?
560.223 How do I measure natural gas production for a lease issued in a 
          sale held after November 2000?
560.224 How will royalty suspension apply if BOEM assigns a lease issued 
          in a sale held after November 2000 to a field that has a pre-
          Act lease?

                    Bidding System Selection Criteria

560.230 What criteria does BOEM use for selecting bidding systems and 
          bidding system components?

                     Subpart C_Operating Allowances

560.300 Operating allowances.

Subpart D [Reserved]

                      Subpart E_Electronic Filings

560.500 Electronic document and data transmissions.
560.501 How long will the confidentiality of electronic document and 
          data transmissions be maintained?
560.502 Are electronically filed document transmissions legally binding?

    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                      Subpart A_General Provisions



Sec.  560.100  Authority.

    (a) The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1334) 
(``Outer Continental Shelf Lands Act Amendments of 1978'').
    (b) The Federal Oil and Gas Royalty Management Act, as amended 
(FOGRMA) (30 U.S.C. 1711), including the Federal Oil and Gas Royalty 
Simplification and Fairness Act of 1996, (30 U.S.C. 1701 note).
    (c) The Independent Offices Appropriations Act of 1952 (31 U.S.C. 
9701).
    (d) Public Law 89-554, 1966 (5 U.S.C. 301).

[81 FR 18175, Mar. 30, 2016]

[[Page 511]]



Sec.  560.101  What is the purpose of this part?

    This part 560 implements the Outer Continental Shelf Lands Act 
(OCSLA), 43 U.S.C. 1331 et seq., as amended, by providing regulations to 
foster competition including, but not limited to:
    (a) Implementing alternative bidding systems;
    (b) Prohibiting joint bidding for development rights by certain 
types of joint ventures; and
    (c) Establishing diligence requirements for Federal OCS leases.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.102  What definitions apply to this part?  What definitions
 apply to this part?

    (a) Terms used in this part have the meaning given in the Act and as 
defined in this part.
    (b) The following definitions apply to this part:
    Area or region means the geographic area or region over which the 
BOEM authorized officer has jurisdiction, unless the context in which 
those words are used indicates that a different meaning is intended.
    BOEM means Bureau of Ocean Energy Management.
    Designated official means a representative of DOI subject to the 
direction and supervisory authority of the Directors, BOEM, and the 
appropriate Regional Manager of the BOEM authorized and empowered to 
supervise and direct all oil and gas operations and to perform other 
duties prescribed in this chapter.
    Director means Director, BOEM, DOI.
    DOI means the Department of the Interior, including the Secretary of 
the Interior, or his or her delegate.
    Federal lease means an agreement which, for consideration, 
including, but not limited to, bonuses, rents or royalties conferred, 
and covenants to be observed, authorizes a person to explore for, or 
develop, or produce (or to do any or all of these) oil and gas, coal, 
oil shale, tar sands, and geothermal resources on lands or interests in 
lands under Federal jurisdiction.
    Gas or Natural Gas means a mixture of hydrocarbons and varying 
quantities of non-hydrocarbons that exist in the gaseous phase.
    Oil means a mixture of hydrocarbons that exists in a liquid or 
gaseous phase in an underground reservoir and which remains or becomes 
liquid at atmospheric pressure after passing through surface separating 
facilities, including condensate recovered by means other than a 
manufacturing process.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (43 U.S.C. 1301-1315) and of which 
the subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    OCSLA means the Outer Continental Shelf Lands Act, as amended (Act 
of August 7, 1953, Ch. 345, 67 Stat. 462, 43 U.S.C. 1331-1356a, as 
amended by Pub. L. 95-372, 92 Stat. 629).
    Person means a natural person, where so designated, or an entity, 
such as a partnership, association, State, political subdivision of a 
State or territory, or a private, public, or municipal corporation.
    We means the Bureau of Ocean Energy Management (BOEM).
    You means the lessee or operating rights owner.

[81 FR 18175, Mar. 30, 2016]



Sec.  560.103  What is BOEM's authority to collect information?

    (a) The Paperwork Reduction Act of 1995 (PRA) requires us to inform 
you that we may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number. The information collection under 30 CFR part 
560 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers to 
requirements covered under 30 CFR parts 203 and 556.
    (b) You may send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015. 
Redesignated at 81 FR 18175, Mar. 30, 2016]

[[Page 512]]



                        Subpart B_Bidding Systems

                           General Provisions



Sec.  560.200  What is the purpose of this subpart?

    This subpart establishes the bidding systems that we may use to 
offer and sell Federal leases for the exploration, development, and 
production of oil and gas resources located on the OCS.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.201  What definitions apply to this subpart?

    Act means the Outer Continental Shelf Deep Water Royalty Relief Act, 
Pub. L. 104-58, 43 U.S.C. 1337(3).
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature and/or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata, or laterally by local geologic barriers, or by both.
    Highest responsible qualified bidder means a person who has met the 
appropriate requirements of 30 CFR part 556, subpart G, and has 
submitted a bid higher than any other bids by qualified bidders on the 
same tract.
    Highest royalty rate means the highest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    Lease period means the time from lease issuance until 
relinquishment, expiration, or termination.
    Lowest royalty rate means the lowest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    OCS lease sale means the Department of the Interior (DOI) proceeding 
by which leases for certain OCS tracts are offered for sale by 
competitive bidding and during which bids are received, announced, and 
recorded.
    Pre-Act lease means a lease that:
    (1) Is issued as part of an OCS lease sale held before November 28, 
1995;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper; and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude (see 
30 CFR part 203).
    Production period means the period during which the amount of oil 
and gas produced from a tract (or, if the tract is unitized, the amount 
of oil and gas as allocated under a unitization formula) will be 
measured for purposes of determining the amount of royalty payable to 
the United States.
    Qualified bidder means a person who has met the appropriate 
requirements of 30 CFR part 556, subpart G.
    Royalty rate means the percentage of the amount or value of the 
production saved, removed, or sold that is due and payable to the United 
States Government.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Tract means a designation assigned solely for administrative 
purposes to a block or combination of blocks that are identified by a 
leasing map or an official protraction diagram prepared by the DOI.
    Value of production means the value of all oil and gas production 
saved, removed, or sold from a tract (or, if the tract is unitized, the 
value of all oil and gas production saved, removed, or sold and credited 
to the tract under a unitization formula) during a period of production. 
The value of production is determined under 30 CFR part 1206.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

[[Page 513]]



Sec.  560.202  What bidding systems may BOEM use?

    We will apply a single bidding system selected from those listed in 
this section to each tract included in an OCS lease sale. The following 
table lists bidding systems, the bid variables, and characteristics.

------------------------------------------------------------------------
For the bidding system   The bid variable is    And the characteristics
         . . .                the . . .                are . . .
------------------------------------------------------------------------
(a) Cash bonus bid      Cash bonus,            The highest responsible
 with a fixed royalty                           qualified bidder will
 rate of not less than                          pay a royalty rate of
 12.5 percent,                                  not less than 12.5
                                                percent at the beginning
                                                of the lease period. We
                                                will specify the royalty
                                                rate for each tract
                                                offered in the Notice of
                                                OCS Lease Sale published
                                                in the Federal Register.
(b) Royalty rate bid    Royalty rate,          We will specify the fixed
 with fixed cash                                amount of cash bonus the
 bonus,                                         highest responsible
                                                qualified bidder must
                                                pay in the Notice of OCS
                                                Lease Sale published in
                                                the Federal Register.
(c) Cash bonus bid      Cash bonus,            (1) We will calculate the
 with a sliding                                 royalty rate the highest
 royalty rate of not                            responsible qualified
 less than 12.5                                 bidder must pay using
 percent at the                                 either:
 beginning of the                              (i) A sliding-scale
 lease period,                                  formula, which relates
                                                the royalty rate to the
                                                adjusted value or volume
                                                of production, or
                                               (ii) A schedule that
                                                establishes the royalty
                                                rate that we will apply
                                                to specified ranges of
                                                the adjusted value or
                                                volume of production.
                                               (2) We will determine the
                                                adjusted value of
                                                production by applying
                                                an inflation factor to
                                                the actual value of
                                                production.
                                               (3) If you are the
                                                successful high bidder,
                                                your lease will include
                                                the sliding-scale
                                                formula or schedule and
                                                will specify the lowest
                                                and highest royalty
                                                rates that will apply.
                                               (4) You will pay a
                                                royalty rate of not less
                                                than 12.5 percent at the
                                                beginning of the lease
                                                period.
                                               (5) We will include the
                                                sliding-scale royalty
                                                formula or schedule,
                                                inflation factor and
                                                procedures for making
                                                the inflation adjustment
                                                and determining the
                                                value or amount of
                                                production in the Notice
                                                of OCS Lease Sale
                                                published in the Federal
                                                Register.
(d) Cash bonus bid      Cash bonus,            (1) If we award you a
 with fixed share of                            lease as the highest
 the net profits of no                          responsible qualified
 less than 30 percent,                          bidder, you will
                                                determine the amount of
                                                the net profit share
                                                payment to the United
                                                States for each month by
                                                multiplying the net
                                                profit share base times
                                                the net profit share
                                                rate, according to 30
                                                CFR 1220.022. You will
                                                calculate the net profit
                                                share base according to
                                                30 CFR 1220.021.
                                               (2) You will pay a net
                                                profit share of not less
                                                than 30 percent.
                                               (3) We will specify the
                                                capital recovery factor,
                                                as described in 30 CFR
                                                1220.020, and the net
                                                profit share rate, both
                                                of which may vary from
                                                tract to tract, in the
                                                Notice of OCS Lease Sale
                                                published in the Federal
                                                Register.
(e) Cash bonus with     Cash bonus,            (1) We may suspend or
 variable royalty                               defer royalty for a
 rate(s) during one or                          period, volume, or value
 more periods of                                of production.
 production,                                    Notwithstanding
                                                suspensions or
                                                deferrals, we may impose
                                                a minimum royalty. The
                                                suspensions or deferrals
                                                may vary based on prices
                                                or price changes of oil
                                                and/or gas.
                                               (2) You may pay a royalty
                                                rate less than 12.5
                                                percent on production
                                                but not less than zero
                                                percent.
                                               (3) We will specify the
                                                applicable royalty
                                                rates(s) and suspension
                                                or deferral magnitudes,
                                                formulas, or
                                                relationships in the
                                                Notice of OCS Lease Sale
                                                published in the Federal
                                                Register.
(f) Cash bonus with     Cash bonus,            We will base the royalty
 royalty rate(s) based                          rate on formula(s) or
 on formula(s) or                               schedule(s) specified in
 schedule(s) during                             the Notice of OCS Lease
 one or more periods                            Sale published in the
 of production,                                 Federal Register.
(g) Cash bonus with a   Cash bonus,            Except for periods of
 fixed royalty rate of                          royalty suspension, you
 not less than 12.5                             will pay a fixed royalty
 percent, at the                                rate of not less than
 beginning of the                               12.5 percent. If we
 lease period,                                  award to you a lease
 suspension of                                  under this system, you
 royalties for a                                must calculate the
 period, volume, or                             royalty due during the
 value of production,                           designated period using
 or depending upon                              the rate, formula, or
 selected                                       schedule specified in
 characteristics of                             the lease. We will
 extraction, and with                           specify the royalty
 suspensions that may                           rate, formula, or
 vary based on the                              schedule in the Notice
 price of production,                           of OCS Lease Sale
                                                published in the Federal
                                                Register.
------------------------------------------------------------------------


[[Page 514]]


[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.203  What conditions apply to the bidding systems that BOEM uses?

    (a) For each of the bidding systems in Sec.  560.110, we will 
include an annual rental fee. Other fees and provisions may apply as 
well. The Notice of OCS Lease Sale published in the Federal Register 
will specify the annual rental and any other fees the highest 
responsible qualified bidder must pay and any other provisions.
    (b) If we use any deferment or schedule of payments for the cash 
bonus bid, we will specify and include it in the Notice of OCS Lease 
Sale published in the Federal Register.
    (c) For the bidding systems listed in this subpart, if the bid 
variable is a cash bonus bid, the highest bid by a qualified bidder 
determines the amount of cash bonus to be paid. We will include the 
minimum bid level(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (d) For the bidding systems listed in this subpart, if the bid 
variable is the royalty rate, the highest bid by a qualified bidder 
determines the royalty rate to be paid. We will include the minimum 
royalty rate(s) in the Notice of OCS Lease Sale published in the Federal 
Register.
    (e) We may, by rule, add to or modify the bidding systems listed in 
Sec.  560.110, according to the procedural requirements of the OCSLA, 43 
U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

                             Eligible Leases



Sec.  560.210  How do royalty suspension volumes apply to eligible leases?

    Royalty suspension volumes, as specified in section 304 of the Act, 
apply to eligible leases that meet the criteria in Sec.  560.113. For 
purposes of this section and Sec. Sec.  560.113 through 560.117:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count against 
royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.211  When does an eligible lease qualify for a royalty suspension volume?

    (a) Your eligible lease will receive a royalty suspension volume as 
specified in the Act. The bidding system in Sec.  560.110(g) applies.
    (b) Your eligible lease may receive a royalty suspension volume only 
if your entire lease is west of 87 degrees, 30 minutes West longitude.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.212  How does BOEM assign and monitor royalty suspension volumes for eligible leases?

    (a) We have specified the water depth category for each eligible 
lease in the final Notice of OCS Lease Sale Package. The Final Notice of 
Sale is published in the Federal Register and the complete Final Notice 
of OCS Lease Sale Package is available on the BOEM Web site. Our 
determination of water depth for each lease became final when we issued 
the lease.
    (b) We have specified in the Notice of OCS Lease Sale the royalty 
suspension volume applicable to each water depth. The following table 
shows the royalty suspension volumes for each eligible lease in million 
barrels of oil equivalent (MMBOE):

------------------------------------------------------------------------
             Water depth               Minimum royalty suspension volume
------------------------------------------------------------------------
(1) 200 to less than 400 meters......  17.5 MMBOE.
(2) 400 to less than 800 meters......  52.5 MMBOE.
(3) 800 meters or more...............  87.5 MMBOE.
------------------------------------------------------------------------


[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.213  How long will a royalty suspension volume for an
 eligible lease be effective?

    A royalty suspension volume for an eligible lease will continue 
through the end of the month in which cumulative production from the 
leases in a field

[[Page 515]]

entitled to share the royalty suspension volume reaches that volume or 
the lease period ends.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.214  How do I measure natural gas production on my eligible lease?

    You must measure natural gas production on your eligible lease 
subject to the royalty suspension volume as follows: 5.62 thousand cubic 
feet of natural gas, measured according to 30 CFR part 250, subpart L, 
equals one barrel of oil equivalent.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

                     Royalty Suspension (RS) Leases



Sec.  560.220  How does royalty suspension apply to leases issued
 in a sale held after November 2000?

    We may issue leases with suspension of royalties for a period, 
volume or value of production, as authorized in section 303 of the Act. 
For purposes of this section and Sec. Sec.  560.121 through 560.124:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count against 
royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.221  When does a lease issued in a sale held after 
November 2000 get a royalty suspension?

    (a) We will specify any royalty suspension for your RS lease in the 
Notice of OCS Lease Sale published in the Federal Register for the sale 
in which you acquire the RS lease and will repeat it in the lease 
document. In addition:
    (1) Your RS lease may produce royalty-free the royalty suspension we 
specify for your lease, even if the field to which we assign it is 
producing.
    (2) The royalty suspension we specify in the Notice of OCS Lease 
Sale for your lease does not apply to any other leases in the field to 
which we assign your RS lease.
    (b) You may apply for a supplemental royalty suspension for a 
project under 30 CFR part 203, if your lease is located:
    (1) In the Gulf of Mexico, in water 200 meters or deeper, and wholly 
west of 87 degrees, 30 minutes West longitude; or
    (2) Offshore of Alaska.
    (c) Your RS lease retains the royalty suspension with which we 
issued it even if we deny your application for more relief.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.222  How long will a royalty suspension volume be effective
 for a lease issued in a sale held after November 2000?

    (a) The royalty suspension volume for your RS lease will continue 
through the end of the month in which cumulative production from your 
lease reaches the applicable royalty suspension volume or the lease 
period ends.
    (b)(1) Notwithstanding any royalty suspension volume under this 
subpart, you must pay royalty at the lease stipulated rate on:
    (i) Any oil produced for any period stipulated in the lease during 
which the arithmetic average of the daily closing price on the New York 
Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the 
applicable threshold price of $36.39 per barrel, adjusted annually after 
calendar year 2007 for inflation unless the lease terms prescribe a 
different price threshold.
    (ii) Any natural gas produced for any period stipulated in the lease 
during which the arithmetic average of the daily closing price on the 
NYMEX for natural gas exceeds the applicable threshold price of $4.55 
per MMBtu, adjusted annually after calendar year 2007 for inflation 
unless the lease terms prescribe a different price threshold.
    (iii) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.
    (2) You must pay any royalty due under this paragraph, plus late 
payment interest under 30 CFR 1218.54, no

[[Page 516]]

later than 90 days after the end of the period for which royalty is 
owed.
    (3) Any production on which you must pay royalty under this 
paragraph will count toward the production volume determined under 
Sec. Sec.  560.120 through 560.124.
    (c) If you must pay royalty on any product (either oil or natural 
gas) for any period under paragraph (b) of this section, you must 
continue to pay royalty on that product during the next succeeding 
period of the same length until the arithmetic average of the daily 
closing NYMEX prices for that product for that period can be determined. 
If the arithmetic average of the daily closing prices for that product 
for that period is less than the threshold price stipulated in the 
lease, you are entitled to a credit or refund of royalties paid for that 
period with interest under applicable law.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.223  How do I measure natural gas production for a lease
 issued in a sale held after November 2000?

    You must measure natural gas production subject to the royalty 
suspension volume for your lease as follows: 5.62 thousand cubic feet of 
natural gas, measured according to 30 CFR part 250, subpart L, equals 
one barrel of oil equivalent.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]



Sec.  560.224  How will royalty suspension apply if BOEM assigns a
 lease issued in a sale held after November 2000 to a field that has
 a pre-Act lease?

    (a) We will assign your lease that has a qualifying well (under 30 
CFR part 250, subpart A) to an existing field or designate a new field 
and will notify you and other affected lessees and operating rights 
holders in the field of that assignment.
    (1) Within 15 days of the final notification, you or any of the 
other affected lessees or operating rights holders may file a written 
request with the Director for reconsideration, accompanied by a 
Statement of Reasons.
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal to 
the Interior Board of Land Appeals under 30 CFR part 590 and 43 CFR part 
4.
    (b) If we establish a royalty suspension volume for a field as a 
result of an approved application for royalty relief submitted for a 
pre-Act lease under 30 CFR part 203, then:
    (1) Royalty-free production from your RS lease shares from and 
counts as part of any royalty suspension volume under Sec.  560.114(d) 
for the field to which we assign your lease; and
    (2) Your RS lease may continue to produce royalty-free up to the 
royalty suspension we specified for your lease, even if the field to 
which we assign your RS lease has produced all of its royalty suspension 
volume.
    (c) Your lease may share in a suspension volume larger than the 
royalty suspension with which we issued it and to the extent we grant a 
larger volume in response to an application by a pre-Act lease submitted 
under 30 CFR part 203. To share in any larger royalty suspension volume, 
you must file an application described in 30 CFR part 203 (Sec. Sec.  
203.71 and 203.83). In no case will royalty-free production for your RS 
lease be less than the royalty suspension specified for your lease.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

                    Bidding System Selection Criteria



Sec.  560.230  What criteria does BOEM use for selecting bidding systems 
and bidding system components?

    In analyzing the application of one of the bidding systems listed in 
Sec.  560.110 to tracts selected for any OCS lease sale, we may, at our 
discretion, consider the following purposes and policies. We recognize 
that each of the purposes and policies may not be specifically 
applicable to the selection process for a particular bidding system or 
tract, or may present a conflict that we will have to resolve in the 
process of bidding system selection. The order of listing does not 
denote a ranking.
    (a) Providing fair return to the Federal Government;
    (b) Increasing competition;

[[Page 517]]

    (c) Ensuring competent and safe operations;
    (d) Avoiding undue speculation;
    (e) Avoiding unnecessary delays in exploration, development, and 
production;
    (f) Discovering and recovering oil and gas;
    (g) Developing new oil and gas resources in an efficient and timely 
manner;
    (h) Limiting the administrative burdens on Government and industry; 
and
    (i) Providing an opportunity to experiment with various bidding 
systems to enable us to identify those most appropriate for the 
satisfaction of the objectives of the United States in OCS lease sales.



                     Subpart C_Operating Allowances



Sec.  560.300  Operating allowances.

    Notwithstanding any other provision in the regulations in this part, 
BOEM may issue a lease containing an operating allowance when so 
specified in the final notice of sale and the lease. The allowance 
amount or formula will be specified in the final notice of sale and in 
the lease.

[81 FR 18175, Mar. 10, 2016]

Subpart D [Reserved]



                      Subpart E_Electronic Filings

    Source: 81 FR 18176, Mar. 30, 2016, unless otherwise noted.



Sec.  560.500  Electronic document and data transmissions.

    (a) BOEM may notify you that it will allow or request you to submit 
the following information electronically through BOEM's secure 
electronic filing system, through an alternate secure electronic filing 
system supported and maintained by the Department, or through some other 
electronic filing system that BOEM has approved for this purpose:
    (1) Any document(s) or information described in the Qualifications 
section of part 556 of this chapter, as specified in subpart E. Such 
information would include, but not be limited to, the official name of 
the qualifying person, its legal and business address or addresses, its 
legal form and status, and the names and contact information of a person 
or organization authorized to act on the person's behalf.
    (2) Any document(s) or information required to obtain BOEM's 
approval of an assignment or sublease, including any form or instrument 
that creates or transfers ownership of a lease interest.
    (3) Any document(s) or information required to obtain BOEM's 
approval of your relinquishment of all, or any aliquot part of your 
lease, as specified in Sec.  556.1101 of this chapter.
    (4) Any document(s) creating, transferring or assigning economic 
interests, as specified in Sec. Sec.  556.715 and 556.808 of this 
chapter.
    (5) Any document(s) related to a bond, U.S. Treasury note or other 
security provided to BOEM, which is required to guarantee your 
compliance with terms and conditions of a lease.
    (6) Any document(s) or information necessary to bid for an OCS 
lease.
    (7) Any forms, document(s) or information necessary to determine 
worst case oil-spill discharge volume(s), or to provide evidence 
demonstrating oil spill financial responsibility, or to guarantee such 
financial responsibility or to comply with any other requirements of the 
Oil Spill Financial Responsibility Program, as described in part 553 of 
this chapter.
    (b) BOEM reserves the right to require the electronic filing of any 
document(s) or information addressed in paragraph (a)(5) of this section 
upon a 90-day notice published in the Federal Register; if BOEM mandates 
that you transmit such document(s) or information electronically, the 
Federal Register notice will specify the filing details necessary to 
comply with this regulation.
    (c) In the event BOEM sends documents to you in a secure electronic 
format, you may either return the document(s) in an electronic format 
utilizing the same secure transmission mechanism or print the 
document(s) and return them.
    (d) BOEM may electronically acknowledge, approve, sign, or execute 
any document(s) referenced in this section.

[[Page 518]]



Sec.  560.501  How long will the confidentiality of electronic document
 and data transmissions be maintained?

    The confidentiality of any electronically submitted information will 
be maintained for the same proprietary term that would apply to the 
corresponding non-electronic confidential submission, pursuant to Sec.  
556.104(b) of this chapter.



Sec.  560.502  Are electronically filed document transmissions
 legally binding?

    Any document or information referenced in Sec.  560.500 which is 
submitted to BOEM through a secure electronic filing system that is 
approved by BOEM will be legally binding, without the need for a paper 
copy thereof.



PART 570_NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF-
-Table of Contents



Sec.
570.1 Purpose.
570.2 Application of this part.
570.3 Definitions.
570.4 Discrimination prohibited.
570.5 Complaint.
570.6 Process.
570.7 Remedies.

    Authority: 43 U.S.C. 1863.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



Sec.  570.1  Purpose.

    The purpose of this part is to implement the provisions of section 
604 of the OCSLA of 1978 which provides that ``no person shall, on the 
grounds of race, creed, color, national origin, or sex, be excluded from 
receiving or participating in any activity, sale, or employment, 
conducted pursuant to the provisions of * * * the Outer Continental 
Shelf Lands Act.''



Sec.  570.2  Application of this part.

    This part applies to any contract or subcontract entered into by a 
lessee or by a contractor or subcontractor of a lessee after the 
effective date of these regulations to provide goods, services, 
facilities, or property in an amount of $10,000 or more in connection 
with any activity related to the exploration for or development and 
production of oil, gas, or other minerals or materials in the OCS under 
the Act.



Sec.  570.3  Definitions.

    As used in this part, the following terms shall have the following 
meaning:
    Contract means any business agreement or arrangement (in which the 
parties do not stand in the relationship of employer and employee) 
between a lessee and any person which creates an obligation to provide 
goods, services, facilities, or property.
    Lessee means the party authorized by a lease, grant of right-of-way, 
or an approved assignment thereof to explore, develop, produce, or 
transport oil, gas, or other minerals or materials in the OCS pursuant 
to the Act and this part.
    Person means a person or company, including but not limited to, a 
corporation, partnership, association, joint stock venture, trust, 
mutual fund, or any receiver, trustee in bankruptcy, or other official 
acting in a similar capacity for such company.
    Subcontract means any business agreement or arrangement (in which 
the parties do not stand in the relationship of employer and employee) 
between a lessee's contractor and any person other than a lessee that is 
in any way related to the performance of any one or more contracts.



Sec.  570.4  Discrimination prohibited.

    No contract or subcontract to which this part applies shall be 
denied to or withheld from any person on the grounds of race, creed, 
color, national origin, or sex.



Sec.  570.5  Complaint.

    (a) Whenever any person believes that he or she has been denied a 
contract or subcontract to which this part applies on the grounds of 
race, creed, color, national origin, or sex, such person may complain of 
such denial or withholding to the Regional Director of the OCS Region in 
which such action is alleged to have occurred. Any complaint filed under 
this part must be submitted in writing to the appropriate Regional 
Director not later than 180 days after the date of the alleged unlawful 
denial of a contract or subcontract which is the basis of the complaint.

[[Page 519]]

    (b) The complaint referred to in paragraph (a) of this section shall 
be accompanied by such evidence as may be available to a person and 
which is relevant to the complaint including affidavits and other 
documents.
    (c) Whenever any person files a complaint under this part, the 
Regional Director with whom such complaint is filed shall give written 
notice of such filing to all persons cited in the complaint no later 
than 10 days after receipt of such complaint. Such notice shall include 
a statement describing the alleged incident of discrimination, including 
the date and the names of persons involved in it.



Sec.  570.6  Process.

    Whenever a Regional Director determines on the basis of any 
information, including that which may be obtained under Sec.  570.5 of 
this part, that a violation of or failure to comply with any provision 
of this subpart probably occurred, the Regional Director shall undertake 
to afford the complainant and the person(s) alleged to have violated the 
provisions of this part an opportunity to engage in informal 
consultations, meetings, or any other form of communications for the 
purpose of resolving the complaint. In the event such communications or 
consultations result in a mutually satisfactory resolution of the 
complaint, the complainant and all persons cited in the complaint shall 
notify the Regional Director in writing of their agreement to such 
resolution. If either the complainant or the person(s) alleged to have 
wrongfully discriminated fail to provide such written notice within a 
reasonable period of time, the Regional Director must proceed in 
accordance with the provisions of 30 CFR part 550, subpart N.



Sec.  570.7  Remedies.

    In addition to the penalties available under 30 CFR part 550, 
subpart N, the Director may invoke any other remedies available to him 
or her under the Act or regulations for the lessee's failure to comply 
with provisions of the Act, regulations, or lease.



PART 580_PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR
 ON THE OUTER CONTINENTAL SHELF--Table of Contents



                      Subpart A_General Information

Sec.
580.1 What definitions apply to this part?
580.2 What is the purpose of this part?
580.3 What requirements must I follow when I conduct prospecting or 
          research activities?
580.4 What activities are not covered by this part?

          Subpart B_How To Apply for a Permit or File a Notice

580.10 What must I do before I may conduct prospecting activities?
580.11 What must I do before I may conduct scientific research?
580.12 What must I include in my application or notification?
580.13 Where must I send my application or notification?

                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements

580.20 What must I not do in conducting Geological and Geophysical (G&G) 
          prospecting or scientific research?
580.21 What must I do in conducting G&G prospecting or scientific 
          research?
580.22 What must I do when seeking approval for modifications?
580.23 How must I cooperate with inspection activities?
580.24 What reports must I file?

                         Interrupted Activities

580.25 When may BOEM require me to stop activities under this part?
580.26 When may I resume activities?
580.27 When may BOEM cancel my permit?
580.28 May I relinquish my permit?

                          Environmental Issues

580.29 Will BOEM monitor the environmental effects of my activity?
580.30 What activities will not require environmental analysis?
580.31 Whom will BOEM notify about environmental issues?

                          Penalties and Appeals

580.32 What penalties may I be subject to?
580.33 How can I appeal a penalty?
580.34 How can I appeal an order or decision?

[[Page 520]]

                       Subpart D_Data Requirements

                     Geological Data and Information

580.40 When do I notify BOEM that geological data and information are 
          available for submission, inspection, and selection?
580.41 What types of geological data and information must I submit to 
          BOEM?
580.42 When geological data and information are obtained by a third 
          party, what must we both do?

                       ysical Data and Information

580.50 When do I notify BOEM that geophysical data and information are 
          available for submission, inspection, and selection?
580.51 What types of geophysical data and information must I submit to 
          BOEM?
580.52 When geophysical data and information are obtained by a third 
          party, what must we both do?

                              Reimbursement

580.60 Which of my costs will be reimbursed?
580.61 Which of my costs will not be reimbursed?

                               Protections

580.70 What data and information will be protected from public 
          disclosure?
580.71 What is the timetable for release of data and information?
580.72 What procedure will BOEM follow to disclose acquired data and 
          information to a contractor for reproduction, processing, and 
          interpretation?
580.73 Will BOEM share data and information with coastal States?

                    Subpart E_Information Collection

580.80 Paperwork Reduction Act statement--information collection.

    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                      Subpart A_General Information



Sec.  580.1  What definitions apply to this part?

    Definitions in this part have the following meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State(s):
    (1) That is used, or is scheduled to be used, as a support base for 
geological and geophysical (G&G) prospecting or scientific research 
activities; or
    (2) In which there is a reasonable probability of significant effect 
on land or water uses from such activity.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Some examples of analysis include, 
but are not limited to, identification of lithologic and fossil content, 
core analyses, laboratory analyses of physical and chemical properties, 
well logs or charts, results from formation fluid tests, and 
descriptions of mineral occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understandings of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and are of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) that are strongly influenced by each other and 
in proximity to the shorelands of the several coastal States. The 
coastal zone includes islands, transition and intertidal areas, salt 
marshes, wetlands, and beaches. The coastal zone extends seaward to the 
outer limit of the United States territorial sea and extends inland from 
the shorelines to the extent necessary to control shorelands, the uses 
of

[[Page 521]]

which have a direct and significant impact on the coastal waters, and 
the inward boundaries of which may be identified by the several coastal 
States, under the authority in section 305(b)(1) of the Coastal Zone 
Management Act of 1972.
    Coastal Zone Management Act means the Coastal Zone Management Act of 
1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the penetration 
into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Ocean Energy 
Management, U.S. Department of the Interior, or an official authorized 
to act on the Director's behalf.
    Geological and geophysical (G&G) prospecting activities mean the 
commercial search for mineral resources other than oil, gas, or sulphur. 
Activities classified as prospecting include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, or the 
gathering through coring or other geological samples are used to detect 
or imply the presence of hard minerals; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical (G&G) scientific research activities mean 
any investigations related to hard minerals that are conducted on the 
OCS for academic or scientific research. These investigations would 
involve gathering and analyzing geological, geochemical, or geophysical 
data and information that are made available to the public for 
inspection and reproduction at the earliest practical time. The term 
does not include commercial G&G exploration or commercial G&G 
prospecting activities.
    Geological data and information means data and information gathered 
through or derived from geological and geochemical techniques, e.g., 
coring and test drilling, well logging, bottom sampling, or other 
physical sampling or chemical testing process.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters acquired while conducting prospecting 
or scientific research activities.
    Geophysical data and information means any data or information 
gathered through or derived from geophysical measurement or sensing 
techniques (e.g., gravity, magnetic, or seismic).
    Governor means the Governor of a State or the person or entity 
lawfully designated by or under State law to exercise the powers granted 
to a Governor under the Act.
    Hard minerals mean any minerals found on or below the surface of the 
seabed except for oil, gas, or sulphur.
    Interpreted geological information means the knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of geological 
data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and maps, 
developed by determining the geological significance of geophysical data 
and processed geophysical information.
    Lease means, depending upon the requirements of the context, either:
    (1) An agreement issued under section 8 or maintained under section 
6 of the Act that authorizes mineral exploration, development and 
production; or
    (2) The area covered by an agreement specified in paragraph (1) of 
this definition.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which evidence is situated.
    Minerals mean all minerals authorized by an Act of Congress to be 
produced from ``public lands'' as defined in section 103 of the Federal 
Land Policy and Management Act of 1976 (43 U.S.C. 1702). The term 
includes oil, gas, sulphur, geopressured-geothermal and associated 
resources.
    Notice means a written statement of intent to conduct G&G scientific 
research that is:

[[Page 522]]

    (1) Related to hard minerals on the OCS; and
    (2) Not covered under a permit.
    Oil, gas, and sulphur means oil, gas, and sulphur, geopressured-
geothermal and associated resources, including gas hydrates.
    Outer Continental Shelf (OCS) means all submerged lands:
    (1) That lie seaward and outside of the area of lands beneath 
navigable waters as defined in section 2 of the Submerged Lands Act (43 
U.S.C. 1301); and
    (2) Whose subsoil and seabed belong to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
under this part. The permit gives a person the right, under appropriate 
statutes, regulations, and stipulations, to conduct on the OCS:
    (1) Geological prospecting for hard minerals;
    (2) Geophysical prospecting for hard minerals;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued under this 
part to conduct activities on the OCS.
    Person means:
    (1) A citizen or national of the United States;
    (2) An alien lawfully admitted for permanent residence in the United 
States as defined in section 8 U.S.C. 1101(a)(20);
    (3) A private, public, or municipal corporation organized under the 
laws of the United States or of any State or territory thereof, and 
association of such citizens, nationals, resident aliens or private, 
public, or municipal corporations, States, or political subdivisions of 
States; or
    (4) Anyone operating in a manner provided for by treaty or other 
applicable international agreements. The term does not include Federal 
agencies.
    Processed geological or geophysical information means data collected 
under a permit and later processed or reprocessed.
    (1) Processing involves changing the form of data as to facilitate 
interpretation. Some examples of processing operations may include, but 
are not limited to:
    (i) Applying corrections for known perturbing causes;
    (ii) Rearranging or filtering data; and
    (iii) Combining or transforming data elements.
    (2) Reprocessing is the additional processing other than ordinary 
processing used in the general course of evaluation. Reprocessing 
operations may include varying identified parameters for the detailed 
study of a specific problem area.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility of the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Third party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    You means a person who applies for and/or obtains a permit, or files 
a notice to conduct G&G prospecting or scientific research related to 
hard minerals on the OCS.



Sec.  580.2  What is the purpose of this part?

    The purpose of this part is to:
    (a) Allow you to conduct prospecting activities or scientific 
research activities on the OCS in Federal waters related to hard 
minerals on unleased lands or on lands under lease to a third party.
    (b) Ensure that you carry out prospecting activities or scientific 
research activities in a safe and environmentally sound manner so as to 
prevent harm or damage to, or waste of, any natural resources (including 
any hard minerals in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the

[[Page 523]]

marine, coastal, or human environment.
    (c) Inform you and third parties of your legal and contractual 
obligations.
    (d) Inform you and third parties of:
    (1) The U.S. Government's rights to access G&G data and information 
collected under permit on the OCS;
    (2) Reimbursement we will make for data and information that are 
submitted; and
    (3) The proprietary terms of data and information that we retain.



Sec.  580.3  What requirements must I follow when I conduct prospecting
 or research activities?

    You must conduct G&G prospecting activities or scientific research 
activities under this part according to:
    (a) The Act;
    (b) The regulations in this part;
    (c) Orders of the Director/Regional Director (RD); and
    (d) Other applicable statutes, regulations, and amendments.



Sec.  580.4  What activities are not covered by this part?

    This part does not apply to:
    (a) G&G prospecting activities conducted by, or on behalf of, the 
lessee on a lease on the OCS;
    (b) Federal agencies;
    (c) Postlease activities for mineral resources other than oil, gas, 
and sulphur, which are covered by regulations at 30 CFR parts 582 and 
282; and
    (d) G&G exploration or G&G scientific research activities related to 
oil, gas, and sulphur, including gas hydrates, which are covered by 
regulations at 30 CFR parts 551 and 251.



          Subpart B_How To Apply for a Permit or File a Notice



Sec.  580.10  What must I do before I may conduct prospecting activities?

    You must have a BOEM-approved permit to conduct G&G prospecting 
activities, including deep stratigraphic tests, for hard minerals. If 
you conduct both G&G prospecting activities, you must have a separate 
permit for each.



Sec.  580.11  What must I do before I may conduct scientific research?

    You may conduct G&G scientific research activities related to hard 
minerals on the OCS only after you obtain a BOEM-approved permit or file 
a notice.
    (a) Permit. You must obtain a permit if the research activities you 
want to conduct involve:
    (1) Using solid or liquid explosives;
    (2) Drilling a deep stratigraphic test; or
    (3) Developing data and information for proprietary use or sale.
    (b) Notice. If you conduct research activities (including federally 
funded research) not covered by paragraph (a) of this section, you must 
file a notice with the regional director at least 30 days before you 
begin. If you cannot file a 30-day notice, you must provide oral 
notification before you begin and follow up in writing. You must also 
inform BOEM in writing when you conclude your work.



Sec.  580.12  What must I include in my application or notification?

    (a) Permits. You must submit to the Regional Director a signed 
original and three copies of the permit application form (Form BOEM-
0134) at least 30 days before the startup date for activities in the 
permit area. If unusual circumstances prevent you from meeting this 
deadline, you must immediately contact the Regional Director to arrange 
an acceptable deadline. The form includes names of persons; the type, 
location, purpose, and dates of activity; and environmental and other 
information. A nonrefundable service fee of $2,012 must be paid 
electronically through Pay.gov at: https://www.pay.gov/paygov/ and you 
must include a copy of the Pay.gov confirmation receipt page with your 
application.
    (b) Disapproval of permit application. If we disapprove your 
application for a permit, the RD will explain the reasons for the 
disapproval and what you must do to obtain approval.
    (c) Notices. You must sign and date a notice that includes:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;

[[Page 524]]

    (2) The name(s) of any other person(s) participating in the proposed 
research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) A map, plat, or chart, that shows the location where you will 
conduct research;
    (5) The proposed projected starting and ending dates for your 
research activity;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practical time you expect to make the data and 
information resulting from your research activity available to the 
public;
    (8) Your plan of how you will make the data and information you 
collect available to the public;
    (9) A statement that you and others involved will not sell or 
withhold the data and information resulting from your research; and
    (10) At your option, the nonexclusive use agreement for scientific 
research attachment to Form BOEM-0134. (If you submit this agreement, 
you do not have to submit the material required in paragraphs (c)(7), 
(c)(8), and (c)(9) of this section.)



Sec.  580.13  Where must I send my application or notification?

    You must apply for a permit or file a notice at one of the following 
locations:

------------------------------------------------------------------------
  For the OCS off the . . .                  Apply to . . .
------------------------------------------------------------------------
(a) State of Alaska..........  Regional Supervisor for Resource
                                Evaluation, Bureau of Ocean Energy
                                Management, Alaska OCS Region, 3801
                                Centerpoint Drive, Suite 500, Anchorage,
                                AK 99503.
(b) Atlantic Coast, Gulf of    Regional Supervisor for Resource
 Mexico, Puerto Rico, or U.S.   Evaluation, Bureau of Ocean Energy
 territories in the Caribbean   Management, Gulf of Mexico OCS Region,
 Sea.                           1201 Elmwood Park Boulevard, New
                                Orleans, LA 70123-2394.
(c) States of California,      Regional Supervisor for Resource
 Oregon, Washington, Hawaii,    Evaluation, Bureau of Ocean Energy
 or U.S. territories in the     Management, Pacific OCS Region, 760
 Pacific Ocean.                 Paseo Camarillo, Suite 102 (CM 102),
                                Camarillo, CA 93010.
------------------------------------------------------------------------


[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]



                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements



Sec.  580.20  What must I not do in conducting Geological and 
Geophysical (G&G) prospecting or scientific research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must not:
    (a) Interfere with or endanger operations under any lease, right-of-
way, easement, right-of-use, notice, or permit issued or maintained 
under the Act;
    (b) Cause harm or damage to life (including fish and other aquatic 
life), property, or the marine, coastal, or human environment;
    (c) Cause harm or damage to any mineral resources (in areas leased 
or not leased);
    (d) Cause pollution;
    (e) Disturb archaeological resources;
    (f) Create hazardous or unsafe conditions;
    (g) Unreasonably interfere with or cause harm to other uses of the 
area; or
    (h) Claim any oil, gas, sulphur, or other minerals you discover 
while conducting operations under a permit or notice.



Sec.  580.21  What must I do in conducting G&G prospecting or
 scientific research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must:
    (a) Immediately report to the Regional Director if you:
    (1) Detect hydrocarbon or any other mineral occurrences;
    (2) Detect environmental hazards that imminently threaten life and 
property; or
    (3) Adversely affect the environment, aquatic life, archaeological 
resources, or other uses of the area where you are

[[Page 525]]

prospecting or conducting scientific research activities.
    (b) Consult and coordinate your G&G activities with other users of 
the area for navigation and safety purposes.
    (c) If you conduct shallow test drilling or deep stratigraphic test 
drilling activities, you must use the best available and safest 
technologies that the Regional Director considers economically feasible.



Sec.  580.22  What must I do when seeking approval for modifications?

    Before you begin modified operations, you must submit a written 
request describing the modifications and receive the Regional Director's 
oral or written approval. If circumstances preclude a written request, 
you must make an oral request and follow up in writing.



Sec.  580.23  How must I cooperate with inspection activities?

    (a) You must allow our representatives to inspect your G&G 
prospecting or any scientific research activities that are being 
conducted under a permit. They will determine whether operations are 
adversely affecting the environment, aquatic life, archaeological 
resources, or other uses of the area.
    (b) BOEM will reimburse you for food, quarters, and transportation 
that you provide for our representatives if you send in your 
reimbursement request to the region that issued the permit within 90 
days of the inspection.



Sec.  580.24  What reports must I file?

    (a) You must submit status reports on a schedule specified in the 
permit and include a daily log of operations.
    (b) You must submit a final report of G&G prospecting or scientific 
research activities under a permit within 30 days after you complete 
acquisition activities under the permit. You may combine the final 
report with the last status report and must include each of the 
following:
    (1) A description of the work performed.
    (2) Charts, maps, plats and digital navigation data in a format 
specified by the Regional Director, showing the areas and blocks in 
which any G&G prospecting or permitted scientific research activities 
were conducted. Identify the lines of geophysical traverses and their 
locations including a reference sufficient to identify the data produced 
during each activity.
    (3) The dates on which you conducted the actual prospecting or 
scientific research activities.
    (4) A summary of any:
    (i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
    (ii) Environmental hazards; and
    (iii) Adverse effects of the G&G prospecting or scientific research 
activities on the environment, aquatic life, archaeological resources, 
or other uses of the area in which the activities were conducted.
    (5) Other descriptions of the activities conducted as specified by 
the Regional Director.

                         Interrupted Activities



Sec.  580.25  When may BOEM require me to stop activities under 
this part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, and any minerals (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order 
or provision of the permit. This would include our required submission 
of reports, well records or logs, and G&G data and information within 
the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.
    (b) The Regional Director will advise you either orally or in 
writing of the procedures to temporarily stop activities. We will 
confirm an oral notification in writing and deliver all written 
notifications by courier or certified/registered mail. You must stop all 
activities under a permit as soon as you receive an oral or written 
notification.

[[Page 526]]



Sec.  580.26  When may I resume activities?

    The Regional Director will advise you when you may start
 your permit 
activities again.



Sec.  580.27  When may BOEM cancel my permit?

    The Regional Director may cancel a permit at any time.
    (a) If we cancel your permit, the Regional Director will advise you 
by certified or registered mail 30 days before the cancellation date and 
will state the reason.
    (b) After we cancel your permit, you are still responsible for 
proper abandonment of any drill site according to the requirements of 30 
CFR 251.7(b)(8). You must comply with all other obligations specified in 
this part or in the permit.



Sec.  580.28  May I relinquish my permit?

    (a) You may relinquish your permit at any time by advising the 
Regional Director by certified or registered mail 30 days in advance.
    (b) After you relinquish your permit, you are still responsible for 
proper abandonment of any drill sites according to the requirements of 
30 CFR 251.7(b)(8). You must also comply with all other obligations 
specified in this part or in the permit.

                          Environmental Issues



Sec.  580.29  Will BOEM monitor the environmental effects of my activity?

    We will evaluate the potential of proposed prospecting or scientific 
research activities for adverse impact on the environment to determine 
the need for mitigation measures.



Sec.  580.30  What activities will not require environmental analysis?

    We anticipate that activities of the type listed below typically 
will not cause significant environmental impact and will normally be 
categorically excluded from additional environmental analysis. The types 
of activities include:
    (a) Gravity and magnetometric observations and measurements;
    (b) Bottom and subbottom acoustic profiling or imaging without the 
use of explosives;
    (c) Hard minerals sampling of a limited nature such as shallow test 
drilling;
    (d) Water and biotic sampling, if the sampling does not adversely 
affect shellfish beds, marine mammals, or an endangered species or if 
permitted by the National Marine Fisheries Service or another Federal 
agency;
    (e) Meteorological observations and measurements, including the 
setting of instruments;
    (f) Hydrographic and oceanographic observations and measurements, 
including the setting of instruments;
    (g) Sampling by box core or grab sampler to determine seabed 
geological or geotechnical properties;
    (h) Television and still photographic observation and measurements;
    (i) Shipboard hard mineral assaying and analysis; and
    (j) Placement of positioning systems, including bottom transponders 
and surface and subsurface buoys reported in Notices to Mariners.



Sec.  580.31  Whom will BOEM notify about environmental issues?

    (a) In cases where Coastal Zone Management Act consistency review is 
required, the Director will notify the Governor of each adjacent State 
with a copy of the application for a permit immediately upon the 
submission for approval.
    (b) In cases where an environmental assessment is to be prepared, 
the Director will invite the Governor of each adjacent State to review 
and provide comments regarding the proposed activities. The Director's 
invitation to provide comments will allow the Governor a specified 
period of time to comment.
    (c) When a permit is issued, the Director will notify affected 
parties including each affected coastal State, Federal agency, local 
government, and special interest organization that has expressed an 
interest.

                          Penalties and Appeals



Sec.  580.32  What penalties may I be subject to?

    (a) Penalties for noncompliance under a permit. You are subject to 
the penalty provisions of section 24 of the Act (43

[[Page 527]]

U.S.C. 1350) and the procedures contained in 30 CFR part 550, subpart N 
for noncompliance with:
    (1) Any provision of the Act;
    (2) Any provisions of a G&G or drilling permit; or
    (3) Any regulation or order issued under the Act.
    (b) Penalties under other laws and regulations. The penalties 
prescribed in this section are in addition to any other penalty imposed 
by any other law or regulation.



Sec.  580.33  How can I appeal a penalty?

    See 30 CFR part 550.1409 and 30 CFR part 590, subpart A, for 
instructions on how to appeal any decision assessing a civil penalty 
under 43 U.S.C. 1350 and 30 CFR part 550, subpart A.



Sec.  580.34  How can I appeal an order or decision?

    See 30 CFR part 590, subpart A, for instructions on how to appeal an 
order or decision.



                       Subpart D_Data Requirements

                     Geological Data and Information



Sec.  580.40  When do I notify BOEM that geological data and
 information are available for submission, inspection, and
 selection?

    (a) You must notify the Regional Director, in writing, when you 
complete the initial analysis, processing, or interpretation of any 
geological data and information. Initial analysis and processing are the 
stages of analysis or processing where the data and information first 
become available for in-house interpretation by the permittee or become 
available commercially to third parties via sale, trade, license 
agreement, or other means.
    (b) The Regional Director may ask if you have further analyzed, 
processed, or interpreted any geological data and information. When 
asked, you must respond to us in writing within 30 days.
    (c) The Regional Director may ask you or a third party to submit the 
analyzed, processed, or interpreted geologic data and information for us 
to inspect or permanently retain. You must submit the data and 
information within 30 days after such a request.



Sec.  580.41  What types of geological data and information must
 I submit to BOEM?

    Unless the Regional Director specifies otherwise, you must submit 
geological data and information that include:
    (a) An accurate and complete record of all geological (including 
geochemical) data and information describing each operation of analysis, 
processing, and interpretation;
    (b) Paleontological reports identifying by depth any microscopic 
fossils collected, including the reference datum to which 
paleontological sample depths are related and, if the Regional Director 
requests, washed samples, that you maintain for paleontological 
determinations;
    (c) Copies of well logs or charts in a digital format, if available;
    (d) Results and data obtained from formation fluid tests;
    (e) Analyses of core or bottom samples and/or a representative cut 
or split of the core or bottom sample;
    (f) Detailed descriptions of any hydrocarbons or other minerals or 
hazardous conditions encountered during operations, including near 
losses of well control, abnormal geopressures, and losses of 
circulation; and
    (g) Other geological data and information that the RD may specify.



Sec.  580.42  When geological data and information are obtained by 
a third party, what must we both do?

    A third party may obtain geological data and information from a 
permittee, or from another third party, by sale, trade, license 
agreement, or other means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec.  580.40(a) and is subject to the penalty provisions of Sec.  
580.32(a)(1) and 30 CFR part 550, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and

[[Page 528]]

    (c) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director in writing within 30 days of the 
sale, trade, or other agreement, including the identity of the recipient 
of the data and information; or
    (d) For license agreements, a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the Regional Director, advise the Regional Director, in writing, of 
the license agreement, including the identity of the recipient of the 
data and information.

                    Geophysical Data and Information



Sec.  580.50  When do I notify BOEM that geophysical data and
 information are available for submission, inspection, and selection?

    (a) You must notify the Regional Director in writing when you 
complete the initial processing and interpretation of any geophysical 
data and information. Initial processing is the stage of processing 
where the data and information become available for in-house 
interpretation by the permittee, or become available commercially to 
third parties via sale, trade, license agreement, or other means.
    (b) The Regional Director may ask whether you have further processed 
or interpreted any geophysical data and information. When asked, you 
must respond to us in writing within 30 days.
    (c) The Regional Director may request that the permittee or third 
party submit geophysical data and information before making a final 
selection for retention. Our representatives may inspect and select the 
data and information on your premises, or the Regional Director can 
request delivery of the data and information to the appropriate regional 
office for review.
    (d) You must submit the geophysical data and information within 30 
days of receiving the request, unless the Regional Director extends the 
delivery time.
    (e) At any time before final selection, the Regional Director may 
review and return any or all geophysical data and information. We will 
notify you in writing of any data the RD decides to retain.



Sec.  580.51  What types of geophysical data and information must 
I submit to BOEM?

    Unless the Regional Director specifies otherwise, you must include:
    (a) An accurate and complete record of each geophysical survey 
conducted under the permit, including digital navigational data and 
final location maps;
    (b) All seismic data collected under a permit presented in a format 
and of a quality suitable for processing;
    (c) Processed geophysical information derived from seismic data with 
extraneous signals and interference removed, presented in a quality 
format suitable for interpretive evaluation, reflecting state-of-the-art 
processing techniques; and
    (d) Other geophysical data, processed geophysical information, and 
interpreted geophysical information including, but not limited to, 
shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity 
and magnetic surveys, and special studies such as refraction and 
velocity surveys.



Sec.  580.52  When geophysical data and information are obtained by
 a third party, what must we both do?

    A third party may obtain geophysical data, processed geophysical 
information, or interpreted geophysical information from a permittee, or 
from another third party, by sale, trade, license agreement, or other 
means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec.  580.50(a) and is subject to the penalty provisions of Sec.  
580.32(a)(1) and 30 CFR 550, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise the 
recipient, in writing, that accepting these obligations is a condition 
precedent of the sale, trade, license, or other agreement; and
    (c) Except for license agreements, a permittee or third party that 
sells,

[[Page 529]]

trades, or otherwise provides data and information to a third party must 
advise the Regional Director, in writing within 30 days of the sale, 
trade, or other agreements, including the identity of the recipient of 
the data and information; or
    (d) For license agreements, a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the Regional Director, advise the Regional Director, in writing, of 
the license agreement, including the identity of the recipient of the 
data and information.

                              Reimbursement



Sec.  580.60  Which of my costs will be reimbursed?

    (a) We will reimburse you or a third party for reasonable costs of 
reproducing data and information that the Regional Director requests if:
    (1) You deliver G&G data and information to us for the Regional 
Director to inspect or select and retain (according to Sec. Sec.  580.40 
and 580.50);
    (2) We receive your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate (or a third party's) or at the 
lowest commercial rate established in the area, whichever is less.
    (b) We will reimburse you or the third party for the reasonable 
costs of processing geophysical information (which does not include cost 
of data acquisition) if, at the request of the Regional Director, you 
processed the geophysical data or information in a form or manner other 
than that used in the normal conduct of business.



Sec.  580.61  Which of my costs will not be reimbursed?

    (a) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (b) We will not reimburse you or a third party for data acquisition 
costs or for the costs of analyzing or processing geological information 
or interpreting geological or geophysical information.

                               Protections



Sec.  580.70  What data and information will be protected from public
 disclosure?

    In making data and information available to the public, the Regional 
Director will follow the applicable requirements of:
    (a) The Freedom of Information Act (5 U.S.C. 552);
    (b) The implementing regulations at 43 CFR part 2;
    (c) The Act; and
    (d) The regulations at 30 CFR parts 550 and 552.
    (1) If the RD determines that any data or information is exempt from 
disclosure under the Freedom of Information Act, we will not disclose 
the data and information unless either:
    (i) You and all third parties agree to the disclosure; or
    (ii) A provision of 30 CFR parts 550 and 552 allows us to make the 
disclosure.
    (2) We will keep confidential the identity of third-party recipients 
of data and information collected under a permit. We will not release 
the identity unless you and the third parties agree to the disclosure.
    (3) When you detect any significant hydrocarbon occurrences or 
environmental hazards on unleased lands during drilling operations, the 
Regional Director will immediately issue a public announcement. The 
announcement must further the National interest without unduly damaging 
your competitive position.



Sec.  580.71  What is the timetable for release of data and information?

    We will release data and information that you or a third party 
submits and we retain according to paragraphs (a) and (b) of this 
section.
    (a) If the data and information are not related to a deep 
stratigraphic test, we will release them to the public according to 
items (1), (2), and (3) in the following table:

[[Page 530]]



------------------------------------------------------------------------
                                             The Regional Director will
  If you or a third party submits and we     disclose them to the public
               retain . . .                             . . .
------------------------------------------------------------------------
(1) Geological data and information,        10 years after issuing the
                                             permit.
(2) Geophysical data,                       50 years after you or a
                                             third party submit the
                                             data.
(3) Geophysical information,                25 years after you or a
                                             third party submit the
                                             information.
(4) Data and information related to a deep  25 years after you complete
 stratigraphic test,                         the test, unless the
                                             provisions of paragraph (b)
                                             of this section apply.
------------------------------------------------------------------------

    (b) This paragraph applies if you are covered by paragraph (a)(4) of 
this section and a lease sale is held or a noncompetitive agreement is 
negotiated after you complete a test well. We will release the data and 
information related to the deep stratigraphic test at the earlier of the 
following times:
    (1) Twenty-five years after you complete the test; or
    (2) Sixty calendar days after we issue a lease, located partly or 
totally within 50 geographic miles (92.7 kilometers) of the test.



Sec.  580.72  What procedure will BOEM follow to disclose acquired 
data and information to a contractor for reproduction, processing,
 and interpretation?

    (a) When practical, the Regional Director will advise the person who 
submitted data and information under Sec.  580.40 or Sec.  580.50 of the 
intent to provide the data or information to an independent contractor 
or agent for reproduction, processing, and interpretation.
    (b) The person notified will have at least five working days to 
comment on the action.
    (c) When the Regional Director advises the person who submitted the 
data and information, all other owners of the data or information will 
be considered to have been notified.
    (d) The independent contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the Regional Director's consent.



Sec.  580.73  Will BOEM share data and information with coastal States?

    (a) We can disclose proprietary data, information, and samples 
submitted to us by permittees or third parties that we receive under 
this part to the Governor of any adjacent State that requests it 
according to paragraphs (b), (c), and (d) of this section. The permittee 
or third parties who submitted proprietary data, information, and 
samples will be notified about the disclosure and will have at least 
five working days to comment on the action.
    (b) We will make a disclosure under this section only after the 
Governor and the Secretary have entered into an agreement containing all 
of the following provisions:
    (1) The confidentiality of the information will be maintained.
    (2) In any action taken for failure to protect the confidentiality 
of proprietary information, neither the Federal Government nor the State 
may raise as a defense:
    (i) Any claim of sovereign immunity; or
    (ii) Any claim that the employee who revealed the proprietary 
information was acting outside the scope of his/her employment in 
revealing the information.
    (3) The State agrees to hold the Federal Government harmless for any 
violation by the State or its employees or contractors of the agreement 
to protect the confidentiality of proprietary data and information and 
samples.
    (4) The materials containing the proprietary data, information, and 
samples will remain the property of the Federal Government.
    (c) The data, information, and samples available for reproduction to 
the State(s) under an agreement must be related to leased lands. Data 
and information on unleased lands may be viewed but not copied or 
reproduced.
    (d) The State must return to us the materials containing the 
proprietary data, information, and samples when we ask for them or when 
the State no longer needs them.
    (e) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to confidentiality 
requirements of:
    (1) The Act; and

[[Page 531]]

    (2) The regulations at 30 CFR parts 580, 581, and 582.



                    Subpart E_Information Collection



Sec.  580.80  Paperwork Reduction Act statement--information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq. and assigned OMB control number 1010-0072. The title of this 
information collection is ``30 CFR part 580, Prospecting for Minerals 
other than Oil, Gas, and Sulphur on the Outer Continental Shelf.''
    (b) We may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number.
    (c) We use the information collected under this part to:
    (1) Evaluate permit applications and monitor scientific research 
activities for environmental and safety reasons.
    (2) Determine that prospecting does not harm resources, result in 
pollution, create hazardous or unsafe conditions, or interfere with 
other users in the area.
    (3) Approve reimbursement of certain expenses.
    (4) Monitor the progress and activities carried out under an OCS 
prospecting permit.
    (5) Inspect and select G&G data and information collected under an 
OCS prospecting permit.
    (d) Respondents are Federal OCS permittees and notice filers. 
Responses are mandatory or are required to obtain or retain a benefit. 
We will protect information considered proprietary under applicable law 
and under regulations at Sec.  580.70 and 30 CFR part 581.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



PART 581_LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN 
THE OUTER CONTINENTAL SHELF--Table of Contents



                            Subpart A_General

Sec.
581.0 Authority for information collection.
581.1 Purpose and applicability.
581.2 Authority.
581.3 Definitions.
581.4 Qualifications of lessees.
581.5 False statements.
581.6 Appeals.
581.7 Disclosure of information to the public.
581.8 Rights to minerals.
581.9 Jurisdictional controversies.

                      Subpart B_Leasing Procedures

581.11 Unsolicited request for a lease sale.
581.12 Request for OCS mineral information and interest.
581.13 Joint State/Federal coordination.
581.14 OCS mining area identification.
581.15 Tract size.
581.16 Proposed leasing notice.
581.17 Leasing notice.
581.18 Bidding system.
581.19 Lease term.
581.20 Submission of bids.
581.21 Award of leases.
581.22 Lease form.
581.23 Effective date of leases.

                   Subpart C_Financial Considerations

581.26 Payments.
581.27 Annual rental.
581.28 Royalty.
581.29 Royalty valuation.
581.30 Minimum royalty.
581.31 Overriding royalties.
581.32 Waiver, suspension, or reduction of rental, minimum royalty, or 
          production royalty.
581.33 Bonds and bonding requirements.

               Subpart D_Assignments and Lease Extensions

581.40 Assignment of leases or interests therein.
581.41 Requirements for filing for transfers.
581.42 Effect of assignment on particular lease.
581.43 Effect of suspensions on lease term.

                     Subpart E_Termination of Leases

581.46 Relinquishment of leases or parts of leases.
581.47 Cancellation of leases.


[[Page 532]]


    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General



Sec.  581.0  Authority for information collection.

    The information collection requirements contained in part 581 have 
been approved by the Office of Management and Budget under 44 U.S.C. 
3507 and assigned clearance number 1010-0082. The information is being 
collected to determine if the applicant for a lease on the Outer 
Continental Shelf (OCS) is qualified to hold such a lease or to 
determine if a requested action is warranted. The information will be 
used to make those determinations. An applicant must respond to obtain 
or retain a benefit.



Sec.  581.1  Purpose and applicability.

    The purpose of these regulations is to establish procedures under 
which the Secretary of the Interior (Secretary) will exercise the 
authority granted to administer a leasing program for minerals other 
than oil, gas, and sulphur in the OCS. The rules in this part apply 
exclusively to leasing activities for minerals other than oil, gas, and 
sulphur in the OCS pursuant to the Act.



Sec.  581.2  Authority.

    The Act authorizes the Secretary to grant leases for any mineral 
other than oil, gas, and sulphur in any area of the OCS to the qualified 
persons offering the highest cash bonuses on the basis of competitive 
bidding upon such royalty, rental, and other terms and conditions as the 
Secretary may prescribe at the time of offering the area for lease (43 
U.S.C. 1337(k)). The Secretary is to administer the leasing provisions 
of the Act and prescribe the rules and regulations necessary to carry 
out those provisions (43 U.S.C. 1334(a)).



Sec.  581.3  Definitions.

    When used in this part, the following terms shall have the following 
meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State--
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipping OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, and mining activities; or
    (3) In which there is a reasonable probability of significant effect 
on land or water uses from such activity.
    Director means the Director of the Bureau of Ocean Energy Management 
(BOEM) of the U.S. Department of the Interior or an official authorized 
to act on the Director's behalf.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to such Governor pursuant to the Act.
    Lease means any form of authorization which is issued under section 
8 of the Act and which authorizes exploration for, and development and 
production of, minerals, or the area covered by that authorization, 
whichever is required by the context.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all persons holding that authority by or through the lessee.
    OCS mineral means a mineral deposit or accretion found on or below 
the surface of the seabed but does not include oil, gas, sulphur; salt 
or sand and gravel intended for use in association with the development 
of oil, gas, or sulphur; or source materials essential to production of 
fissionable materials which are reserved to the United States pursuant 
to section 12(e) of the Act.

[[Page 533]]

    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Overriding royalty means a royalty created out of the lessee's 
interest which is over and above the royalty reserved to the lessor in 
the original lease.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. The 
term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.



Sec.  581.4  Qualifications of lessees.

    (a) In accordance with section 8(k) of the Act, leases shall be 
awarded only to qualified persons offering the highest cash bonus bid.
    (b) Mineral leases issued pursuant to section 8 of the Act may be 
held only by:
    (1) Citizens and nationals of the United States;
    (2) Aliens lawfully admitted for permanent residence in the United 
States as defined in 8 U.S.C. 1101(a)(20);
    (3) Private, public, or municipal corporations organized under the 
laws of the United States or of any State or of the District of Columbia 
or territory thereof; or
    (4) Associations of such citizens, nationals, resident aliens, or 
private, public, or municipal corporations, States, or political 
subdivisions of States.



Sec.  581.5  False statements.

    Under the provisions of 18 U.S.C. 1001, it is a crime punishable by 
up to 5 years imprisonment or a fine of $10,000, or both, for anyone 
knowingly and willfully to submit or cause to be submitted to any Agency 
of the United States any false or fraudulent statement(s) to any matters 
within the Agency's jurisdiction.



Sec.  581.6  Appeals.

    Any party adversely affected by a decision of a BOEM official made 
pursuant to the provisions of this part shall have the right of appeal 
pursuant to 30 CFR part 590, except as provided otherwise in Sec.  
581.21 of this part.



Sec.  581.7  Disclosure of information to the public.

    The Secretary shall make data and information available to the 
public in accordance with the requirements and subject to the 
limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), 
and the implementing regulations (30 CFR parts 580, 582, and 43 CFR part 
2).



Sec.  581.8  Rights to minerals.

    (a) Unless otherwise specified in the leasing notice, a lease for 
OCS minerals shall include rights to all minerals within the leased area 
except the following;
    (1) Minerals subject to rights granted by existing leases;
    (2) Oil;
    (3) Gas;
    (4) Sulphur;
    (5) Minerals produced in direct association with oil, gas, or 
sulphur;
    (6) Salt deposits which are identified in the leasing notice as 
being reserved;
    (7) Sand and gravel deposits which are identified in the leasing 
notice as being reserved; and
    (8) Source materials essential to production of fissionable 
materials which are reserved pursuant to section 12(a) of the Act.
    (b) When an OCS mineral lease issued under this part limits the 
minerals to which rights are granted, such lease shall include rights to 
minerals produced in direct association with the OCS mineral specified 
in the lease but

[[Page 534]]

not the rights to minerals specifically reserved.
    (c) The existence of an OCS mineral, oil and gas, or sulphur lease 
shall not preclude the issuance of a lease(s) for other OCS minerals in 
the same area. However, no OCS mineral lease shall authorize or permit 
the lessee thereunder to unreasonably interfere with or endanger 
operations under an existing OCS mineral, oil and gas, or sulphur lease.



Sec.  581.9  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State jurisdiction 
(43 U.S.C. 1336), either the Governor or the Secretary may initiate 
negotiations in an attempt to settle the jurisdictional controversy. 
With the concurrence of the Attorney General, the Secretary may enter 
into an agreement with a State with respect to OCS mineral activities 
under the Act or under State authority and to payment and impounding of 
rents, royalties, and other sums and with respect to the offering of 
lands for lease pending settlement of the controversy.



                      Subpart B_Leasing Procedures



Sec.  581.11  Unsolicited request for a lease sale.

    (a) Any person may at any time request that OCS minerals be offered 
for lease. A request that OCS minerals be offered for lease shall be 
submitted to the Director and shall contain the following information:
    (1) The area to be offered for lease.
    (2) The OCS minerals of primary interest.
    (3) The available OCS mineral resource and environmental information 
pertaining to the area of interest to be offered for lease which 
supports the request.
    (b) Within 45 days after receipt of a request submitted under 
paragraph (a) of this section, the Director shall either initiate steps 
leading to the offer of OCS minerals for lease and notify the applicant 
of the action taken or inform the applicant of the reasons for not 
initiating steps leading to the offer of OCS minerals for lease.
    (c) Any interested party may at any time submit information to the 
Director concerning the scheduling of proposed lease sales of OCS 
minerals in any area of the OCS. Such information may include but not be 
limited to any of the following:
    (1) Benefits of conducting a lease sale in an area.
    (2) Costs of conducting a lease sale in an area.
    (3) Geohazards which could be encountered in an area.
    (4) Geological information about an area and mineral resource 
potential.
    (5) Environmental information about an area.
    (6) Information about known archaeological resources in an area.



Sec.  581.12  Request for OCS mineral information and interest.

    (a) When considering whether to offer OCS minerals for lease, the 
Secretary, upon the Department of the Interior's own initiative or as a 
result of a submission under Sec.  581.11, may request indications of 
interest in the leasing of a specific OCS mineral, a group of OCS 
minerals, or all OCS minerals in the area being considered for lease. 
Requests for information and interest shall be published in the Federal 
Register and may be published elsewhere.
    (b) States and local governments, industry, other Federal Agencies, 
and all interested parties (including the public) may respond to a 
request for information and interest. All information provided to the 
Secretary will be considered in the decision whether to proceed with 
additional steps leading to the offering of OCS minerals for lease.
    (c) The Secretary may request specific information concerning the 
offering of a specific OCS mineral, a group of OCS minerals, or all OCS 
minerals in a broad area for lease or the offering of one or more 
discrete tracts which represent a minable orebody. The Secretary's 
request may ask for comments on OCS areas which have been determined to 
warrant special consideration and analysis. Requests may be for comments 
concerning geological conditions or archaeological resources on the 
seabed; multiple uses of the area proposed for leasing, including 
navigation,

[[Page 535]]

recreation and fisheries; and other socioeconomic, biological, and 
environmental information relating to the area proposed for leasing.



Sec.  581.13  Joint State/Federal coordination.

    (a) The Secretary may invite the adjacent State Governor(s) to join 
in, or the adjacent State Governor(s) may request that the Secretary 
join in, the establishment of a State/Federal task force or some other 
joint planning or coordination arrangement when industry interest exists 
for OCS mineral leasing or geological information appears to support the 
leasing of OCS minerals in specific areas. Participation in joint State/
Federal task forces or other arrangements will afford the adjacent State 
Governor(s) opportunity for access to available data and information 
about the area; knowledge of progress made in the leasing process and of 
the results of subsequent exploration and development activities; 
facilitate the resolution of issues of mutual interest; and provide a 
mechanism for planning, coordination, consultation, and other activities 
which the Secretary and the Governor(s) may identify as contributing to 
the leasing process.
    (b) State/Federal task forces or other such arrangements are to be 
constituted pursuant to such terms and conditions (consistent with 
Federal law and these regulations) as the Secretary and the adjacent 
State Governor(s) may agree.
    (c) State/Federal task forces or other such arrangements will 
provide a forum which the Secretary and adjacent State Governor(s) may 
use for planning, consultation, and coordination on concerns associated 
with the offering of OCS minerals other than oil, gas, or sulphur for 
lease.
    (d) With respect to the activities authorized under these 
regulations each State/Federal task force may make recommendations to 
the Secretary and adjacent State Governor(s) concerning:
    (1) The identification of areas in which OCS minerals might be 
offered for lease;
    (2) The potential for conflicts between the exploration and 
development of OCS mineral resources, other users and uses of the area, 
and means for resolution or mitigation of these conflicts;
    (3) The economic feasibility of developing OCS mineral resources in 
the area proposed for leasing;
    (4) Potential environmental problems and measures that might be 
taken to mitigate these problems;
    (5) Development of guidelines and procedures for safe, 
environmentally responsible exploration and development practices; and
    (6) Other issues of concern to the Secretary and adjacent State 
Governor(s).
    (e) State/Federal task forces or other such arrangements might also 
be used to conduct or oversee research, studies, or reports (e.g., 
Environmental Impact Statements).



Sec.  581.14  OCS mining area identification.

    The Secretary, after considering the available OCS mineral resources 
and environmental data and information, the recommendation of any joint 
State/Federal task force established pursuant to Sec.  581.13 of this 
part, and the comments received from interested parties, shall select 
the tracts to be considered for offering for lease. The selected tracts 
will be considered in the environmental analysis conducted for the 
proposed lease offering.



Sec.  581.15  Tract size.

    The size of the tracts to be offered for lease shall be as 
determined by the Secretary and specified in the leasing notice. It is 
intended that tracts offered for lease be sufficiently large to include 
potentially minable OCS mineral orebodies. When the presence of any 
minable orebody is unknown and additional prospecting is needed to 
discover and delineate OCS minerals, the size of tracts specified in the 
leasing notice may be relatively large.



Sec.  581.16  Proposed leasing notice.

    (a) Prior to offering OCS minerals in an area for lease, the 
Director shall assess the available information including 
recommendations of any joint State/Federal task force established

[[Page 536]]

pursuant to Sec.  581.13 of this part to determine lease sale procedures 
to be prescribed and to develop a proposed leasing notice which sets out 
the proposed primary term of the OCS mineral leases to be offered; lease 
stipulations including measures to mitigate potentially adverse impacts 
on the environment; and such rental, royalty, and other terms and 
conditions as the Secretary may prescribe in the leasing notice.
    (b) The proposed leasing notice shall be sent to the Governor(s) of 
any adjacent State(s), and a Notice of its availability shall be 
published in the Federal Register at least 60 days prior to the 
publication of the leasing notice.
    (c) Written comments of the adjacent State Governor(s) submitted 
within 60 days after publication of the Notice of Availability of the 
proposed leasing notice shall be considered by the Secretary.
    (d) Prior to publication of the leasing notice, the Secretary shall 
respond in writing to the comments of the adjacent State Governor(s) 
stating the reasons for accepting or rejecting the Governor's 
recommendations, or for implementing any alternative mutually acceptable 
approach identified in consultation with the Governor(s) as a means to 
provide a reasonable balance between the National interest and the well 
being of the citizens of the adjacent State.



Sec.  581.17  Leasing notice.

    (a) The Director shall publish the leasing notice in the Federal 
Register at least 30 days prior to the date that OCS minerals will be 
offered for lease. The leasing notice shall state whether oral or sealed 
bids or a combination thereof will be used; the place, date, and time at 
which sealed bids shall be filed; and the place, date, and time at which 
sealed bids shall be opened and/or oral bids received. The leasing 
notice shall contain or reference a description of the tract(s) to be 
offered for lease; specify the mineral(s) to be offered for lease (if 
less than all OCS minerals are being offered); specify the period of 
time the primary term of the lease shall cover; and any stipulation(s), 
term(s), and condition(s) of the offer to lease (43 U.S.C. 1337(k)).
    (b) The leasing notice shall contain a reference to the OCS minerals 
lease form which shall be issued to successful bidders.
    (c) The leasing notice shall specify the terms and conditions 
governing the payment of the winning bid.



Sec.  581.18  Bidding system.

    (a) The OCS minerals shall be offered by competitive, cash bonus 
bidding under terms and conditions specified in the leasing notice and 
in accordance with all applicable laws and regulations.
    (b)(1) When the leasing notice specifies the use of sealed bids, 
such bids received in response to the leasing notice shall be opened at 
the place, date, and time specified in the leasing notice. The sole 
purpose of opening bids is to publicly announce and record the bids 
received, and no bids shall be accepted or rejected at that time.
    (2) The Secretary reserves the right to reject any and all sealed 
bids received for any tract, regardless of the amount offered.
    (3) In the event the highest bids are tie bids when using sealed 
bidding procedures, the tied bidders may be permitted to submit oral 
bids to determine the highest cash bonus bidder.
    (c)(1) When the leasing notice specifies the use of oral bids, oral 
bids shall be received at the place, time, and date and in accordance 
with the procedures specified in the leasing notice.
    (2) The Secretary reserves the right to reject all oral bids 
received for any tract, regardless of the amount offered.
    (d) When the leasing notice specifies the use of deferred cash bonus 
bidding, bids shall be received in accordance with paragraph (b) or (c) 
of this section, as appropriate. The high bid will be determined based 
upon the net present value of each total bid. The appropriate discount 
rate will be specified in the leasing notice. High bidders using the 
deferred bonus option shall pay a minimum of 20 percent of the cash 
bonus bid prior to lease issuance. At least a total of 60 percent of the 
cash bonus bid shall be due on or before the 5th anniversary of the 
lease, and payment of the remainder of the cash

[[Page 537]]

bonus bid shall be due on the 10th anniversary of the lease. The lessee 
shall submit a bond guaranteeing payment of the deferred portion of the 
bonus, in accordance with Sec.  581.33.



Sec.  581.19  Lease term.

    An OCS mineral lease for OCS minerals other than sand and gravel 
shall be for a primary term of not less than 20 years as stipulated in 
the leasing notice. The primary lease term for each OCS mineral shall be 
determined based on exploration and development requirements for the OCS 
minerals being offered by the Secretary. An OCS mineral lease for sand 
and gravel shall be for a primary term of 10 years unless otherwise 
stipulated in the leasing notice. A lease will continue beyond the 
specified primary term for so long thereafter as leased OCS minerals are 
being produced in accordance with an approved mining operation or the 
lessee is otherwise in compliance with provisions of the lease and the 
regulations in this chapter under which a lessee can earn continuance of 
the OCS mineral lease in effect.



Sec.  581.20  Submission of bids.

    (a) If the bidder is an individual, a statement of citizenship shall 
accompany the bid.
    (b) If the bidder is an association (including a partnership), the 
bid shall be accompanied by a certified statement indicating the State 
in which it is registered and that the association is authorized to hold 
mineral leases on the OCS, or appropriate reference to statements or 
records previously submitted to a BOEM OCS office (including material 
submitted in compliance with prior regulations).
    (c) If the bidder is a corporation, the bid shall be accompanied by 
the following information:
    (1) Either a statement certified by the corporate Secretary or 
Assistant Secretary over the corporate seal showing the State in which 
it was incorporated and that it is authorized to hold mineral leases on 
the OCS or appropriate reference to statements or record previously 
submitted to a BOEM OCS office (including material submitted in 
compliance with prior regulations).
    (2) Evidence of authority of persons signing to bind the 
corporation. Such evidence may be in the form of a certified copy of 
either the minutes of the board of directors or of the bylaws indicating 
that the person signing has authority to do so, or a certificate to that 
effect signed by the Secretary or Assistant Secretary of the corporation 
over the corporate seal, or appropriate reference to statements or 
records previously submitted to a BOEM OCS office (including material 
submitted in compliance with prior regulations). Bidders are advised to 
keep their filings current.
    (3) The bid shall be executed in conformance with corporate 
requirements.
    (d) Bidders should be aware of the provisions of 18 U.S.C. 1860, 
which prohibits unlawful combination or intimidation of bidders.
    (e) When sealed bidding is specified in the leasing notice, a 
separate sealed bid shall be submitted for each bid unit that is bid 
upon as described in the leasing notice. A bid may not be submitted for 
less than a bidding unit identified in the leasing notice.
    (f) When oral bidding is specified in the leasing notice, 
information which must accompany a bid pursuant to paragraph (a), (b), 
or (c) of this section, shall be presented to BOEM at the lease sale 
prior to the offering of an oral bid.



Sec.  581.21  Award of leases.

    (a)(1) The decision of the Director on bids shall be the final 
action of the Department, subject only to reconsideration by the 
Secretary, pursuant to a written request in accordance with paragraph 
(a)(2) of this section. The delegation of review authority to the Office 
of Hearings and Appeals shall not be applicable to decisions on high 
bids for leases in the OCS.
    (2) Any bidder whose bid is rejected by the Director may file a 
written request for reconsideration with the Secretary within 15 days of 
notice of rejection, accompanied by a statement of reasons with a copy 
to the Director. The Secretary shall respond in writing either affirming 
or reversing the decision.
    (b) Written notice of the Director's action in accepting or 
rejecting bids

[[Page 538]]

shall be transmitted promptly to those bidders whose deposits have been 
held. If a bid is accepted, such notice shall transmit three copies of 
the lease form to the successful bidder. As provided in Sec.  581.26 of 
this part, the bidder shall, not later than the 10th business day after 
receipt of the lease, execute the lease, pay the first year's rental, 
and unless payment of a portion of the bid is deferred, pay the balance 
of the bonus bid. When payment of a portion of the bid is deferred, the 
successful bidder shall also file a bond to guarantee payment of the 
deferred portion as required in Sec.  581.33. Deposits shall be refunded 
on high bids subsequently rejected. When three copies of the lease have 
been executed by the successful bidder and returned to the Director, the 
lease shall be executed on behalf of the United States; and one fully 
executed copy shall be transmitted to the successful bidder.
    (c) If the successful bidder fails to execute the lease within the 
prescribed time or to otherwise comply with the applicable regulations, 
the successful bidder's deposit shall be forfeited and disposed of in 
the same manner as other receipts under the Act.
    (d) If, before the lease is executed on behalf of the United States, 
the land which would be subject to the lease is withdrawn or restricted 
from leasing, the deposit shall be refunded.
    (e) If the awarded lease is executed by an agent acting on behalf of 
the bidder, the bidder shall submit with the executed lease, evidence 
that the agent is authorized to act on behalf of the bidder.



Sec.  581.22  Lease form.

    The OCS mineral leases shall be issued on the lease form prescribed 
by the Secretary in the leasing notice.



Sec.  581.23  Effective date of leases.

    Leases issued under the regulations in this part shall be dated and 
become effective as of the first day of the month following the date 
leases are signed on behalf of the lessor except that, upon written 
request, a lease may be dated and become effective as of the first day 
of the month within which it is signed on behalf of the lessor.



                   Subpart C_Financial Considerations



Sec.  581.26  Payments.

    (a) For sealed bids, a bonus bid deposit of a specified percentage 
of the total amount bid is required to be submitted with the bid. The 
percentage of bonus bid required to be deposited will be specified in 
the leasing notice. The remittance may be made in cash or by Federal 
Reserve check, commercial check, bank draft, money order, certified 
check, or cashier's check made payable to ``Department of the Interior--
BOEM.'' Payment of this portion of the bonus bid may not be made by 
Electronic Funds Transfer.
    (b) For oral bids, a bonus bid deposit of a specified percentage of 
the total amount bid must be submitted to the official designated in the 
leasing notice following the completion of the oral bidding. The 
percentage of bonus bid required to be deposited will be specified in 
the leasing notice. Payment of this portion of the bonus bid must be 
made by Electronic Fund Transfer within the timeframe specified in the 
leasing notice.
    (c) The deposit received from high bidders will be placed in a 
Treasury account pending acceptance or rejection of the bid. Other bids 
submitted under paragraph (a) of this section will be returned to the 
bidders. If the high bid is subsequently rejected, an amount equal to 
that deposited with the high bid will be returned according to 
applicable regulations.
    (d) The balance of the winning bonus bid and all rentals and 
royalties must be paid in accordance with the terms and conditions of 
this part, the Leasing Notice, and subchapter A of this chapter.
    (e) For each lease issued pursuant to this subpart, there shall be 
one person identified who shall be solely responsible for all payments 
due and payable under the provisions of the lease. The single 
responsible person shall be designated as the payor for the lease and 
shall be so identified on the Solid Minerals Production and Royalty 
Report (P&R) (Form ONRR-4430) in accordance with 30 CFR 1210.201 of this 
title. The designated person shall be responsible

[[Page 539]]

for all bonus, rental, and royalty payments.
    (f) Royalty shall be computed at the rate specified in the leasing 
notice, and paid in value unless the Secretary elects to have the 
royalty delivered in kind.
    (g) For leases which provide for minimum royalty payments, each 
lessee shall pay the minimum royalty specified in the lease at the end 
of each lease year beginning with the lease year in which production 
royalty is paid (whether the full amount specified in the lease or \1/2\ 
the amount specified in the lease pursuant to Sec.  581.28(b) on this 
part) of OCS minerals produced (sold, transferred, used, or otherwise 
disposed of) from the leasehold.
    (h)(1) Unless stated otherwise in the lease, product valuation will 
be in accordance with the regulations in part 1206 of chapter XII. The 
value used in the computation of royalty shall be determined by the 
Director of the Office of Natural Resources Revenue. The value, for 
royalty purposes, shall be the gross proceeds received by the lessee for 
produced substances at the point the product is produced and placed in 
its first marketable condition, consistent with prevailing practices in 
the industry. In establishing the value, the Director shall consider, in 
this order:
    (i) The price received by the lessee;
    (ii) Commodity and spot market transactions;
    (iii) Any other valuation method proposed by the lessee and approved 
by the Director; and
    (iv) Value or cost netback.
    (2) For non-arm's length transactions, the first benchmark will only 
be accepted if it is not less than the second benchmark.
    (i) All payors must submit payments and payment forms and maintain 
auditable records in accordance with 30 CFR chapter XII, Subchapter A--
Natural Resources Revenue.



Sec.  581.27  Annual rental.

    (a) The annual lease rental shall be due and payable in accordance 
with the provisions of this section. No rental shall be due or payable 
under a lease commencing with the first lease anniversary date following 
the commencement of royalty payments on leasehold production computed on 
the basis of the royalty rate specified in the lease except that annual 
rental shall be due for any year in which production from the leasehold 
is not subject to royalty pursuant to Sec.  581.28.
    (b) Unless otherwise specified in the leasing notice and 
subsequently issued lease, no annual rental payment shall be due during 
the first 5 years in the life of a lease.
    (c) The leasee shall pay an annual rental in the amount specified in 
the leasing notice and subsequently issued lease not later than the last 
day prior to the commencement of the rental year.
    (d) A rental adjustment schedule and amount may be specified in a 
leasing notice and subsequently issued lease when a variance is 
warranted by geologic, geographic, technical, or economic conditions.



Sec.  581.28  Royalty.

    (a) The royalty due the lessor on OCS minerals produced (i.e., sold, 
transferred, used, or otherwise disposed of) from a lease shall be set 
out in a separate schedule attached to and made a part of each lease and 
shall be as specified in the leasing notice. The royalty due on 
production shall be based on a percentage of the value or amount of the 
OCS mineral(s) produced, a sum assessed per unit of product, or other 
such method as the Secretary may prescribe in the leasing notice. When 
the royalty specified is a sum assessed per unit of product, the amount 
of the royalty shall be subject to an annual adjustment based on changes 
in the appropriate price index, when specified in the leasing notice. 
When the royalty is specified as a percentage of the value or amount of 
the OCS minerals produced, the Secretary will notify the lessee when and 
where royalty is to be delivered in kind. Unless stated otherwise in the 
lease, product valuation will be in accordance with the regulations in 
part 1206 of chapter XII. The value used in the computation of royalty 
shall be determined by the Director of the Office of Natural Resources 
Revenue.

[[Page 540]]

    (b) When prescribed in the leasing notice and subsequently issued 
lease, royalty due on OCS minerals produced from a leasehold will be 
reduced for up to any 5 consecutive years, as specified by the lessee 
prior to the commencement of production, during the 1st through 15th 
year in the life of the lease. No royalty shall be due in any year of 
the specified 5-year period that occurs during the 1st through 10th 
years in the life of the lease, and a royalty of one-half the amount 
specified in the lease shall be due in any year of the specified 5-year 
period that occurs in the 11th through 15th year in the life of the 
lease. The lessee shall pay the amount specified in the lease rental for 
any royalty free year. The minimum royalty specified in the lease shall 
apply during any year of reduced royalty.



Sec.  581.29  Royalty valuation.

    Unless stated otherwise in the leasing notice and subsequently 
issued lease, product valuation will be in accordance with the 
regulations in part 1206 of chapter XII. The value used in the 
computation of royalty shall be determined by the Director of the Office 
of Natural Resources Revenue.



Sec.  581.30  Minimum royalty.

    Unless otherwise specified in the leasing notice, each lease issued 
pursuant to the regulations in this part shall require the payment of a 
specified minimum annual royalty beginning with the year in which OCS 
minerals are produced (sold, transferred, used, or otherwise disposed 
of) from the leasehold except that the annual rentals shall apply during 
any year that royalty free production is in effect pursuant to Sec.  
581.28(b). Minimum royalty payments shall be offset by royalty paid on 
production during the lease year. Minimum royalty payments are due at 
the beginning of the lease year and payable by the end of the month 
following the end of the lease year for which they are due.



Sec.  581.31  Overriding royalties.

    (a) Subject to the approval of the Secretary, an overriding royalty 
interest may be created by an assignment pursuant to section 8(e) of the 
Act. The Secretary may deny approval of an assignment which creates an 
overriding royalty on a lease whenever that denial is determined to be 
in the interest of conservation, necessary to prevent premature 
abandonment of a producing mine, or to make possible the mining of 
economically marginal or low-grade ore deposits. In any case, the total 
of applicable overriding royalties may not exceed 2.5 percent or one-
half the base royalty due the Federal Government, whichever is less.
    (b) No transfer or agreement may be made which creates an overriding 
royalty interest unless the owner of that interest files an agreement in 
writing that such interest is subject to the limitations provided in 
Sec.  581.30 of this part, paragraph (a) of this section, and Sec.  
581.32 of this part.



Sec.  581.32  Waiver, suspension, or reduction of rental, minimum
 royalty, or production royalty.

    (a) The Secretary may waive, suspend, or reduce the rental, minimum 
royalty, and/or production royalty prescribed in a lease for a specified 
time period when the Secretary determines that it is in the National 
interest, it will result in the conservation of natural resources of the 
OCS, it will promote development, or the mine cannot be successfully 
operated under existing conditions.
    (b) An application for waiver, suspension, or reduction of rental, 
minimum royalty, or production royalty under paragraph (a) of this 
section shall be filed in duplicate with the Director. The application 
shall contain the serial number(s) of the lease(s), the name of the 
lessee(s) of record, and the operator(s) if applicable. The application 
shall either:
    (1)(i) Show the location and extent of all mining operations and a 
tabulated statement of the minerals mined and subject to royalty for 
each of the last 12 months immediately prior to filing the application:
    (ii) Contain a detailed statement of expenses and costs of operating 
the lease, the income from the sale of any lease products, and the 
amount of all overriding royalties and payments out of production paid 
to others than the United States; and

[[Page 541]]

    (iii) All facts showing whether or not the mine(s) can be 
successfully operated under the royalty fixed in the lease; or
    (2) If no production has occurred from the lease, show that the 
lease cannot be successfully operated under the rental, royalty, and 
other conditions specified in the lease.
    (c) The applicant for a waiver, suspension, or reduction under this 
section shall file documentation that the lessee and the royalty holders 
agree to a reduction of all other royalties from the lease so that the 
aggregate of all other royalties does not exceed one-half the amount of 
the reduced royalties that would be paid to the United States.



Sec.  581.33  Bonds and bonding requirements.

    (a) When the leasing notice specifies that payment of a portion of 
the bonus bid can be deferred, the lessee shall be required to submit a 
surety or personal bond to guarantee payment of a deferred portion of 
the bid. Upon the payment of the full amount of the cash bonus bid, the 
lessee's bond will be released.
    (b) All bonds to guarantee payment of the deferred portion of the 
high cash bonus bid furnished by the lessee must be in a form or on a 
form approved by the Deputy Director. A single copy of the required form 
is to be executed by the principal or, in the case of surety bonds, by 
both the principal and an acceptable surety.
    (1) Only those surety bonds issued by qualified surety companies 
approved by the Department of the Treasury shall be accepted (see 
Department of the Treasury Circular No. 570 and any supplemental or 
replacement circulars).
    (2) Personal bonds shall be accompanied by a cashier's check, 
certified check, or negotiable U.S. Treasury bonds of an equal value to 
the amount specified in the bond. Negotiable Treasury bonds shall be 
accompanied by a proper conveyance of full authority to the Director to 
sell such securities in case of default in the performance of the terms 
and conditions of the lease.
    (c) Prior to the commencement of any activity on a lease(s), the 
lessee shall submit a surety or personal bond as described in Sec.  
582.40 of this title. Prior to the approval of a Delineation, Testing, 
or Mining Plan, the bond amount shall be adjusted, if appropriate, to 
cover the operations and activities described in the proposed plan.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



               Subpart D_Assignments and Lease Extensions



Sec.  581.40  Assignment of leases or interests therein.

    (a) Subject to the approval of the Secretary, a lease may be 
assigned, in whole or in part, pursuant to section 8(e) of the Act to 
anyone qualified to hold a lease.
    (b) Any approved assignment shall be deemed to be effective on the 
first day of the lease month following the date that it is submitted to 
the Director for approval unless by written request the parties request 
that the effective date be the first of the month in which the Director 
approves the assignment.
    (c) The assignor shall be liable for all obligations under the lease 
occurring prior to the effective date of an assignment.
    (d) The assignee shall be liable for all obligations under the lease 
occurring on or after the effective date of an assignment and shall 
comply with all terms and conditions of the lease and applicable 
regulations issued under the Act.



Sec.  581.41  Requirements for filing for transfers.

    (a)(1) All instruments of transfer of a lease or of an interest 
therein including subleases and assignments of record interest shall be 
filed in triplicate for approval within 90 days from the date of final 
execution. They shall include a statement over the transferee's own 
signature with respect to citizenship and qualifications similar to that 
required of a lessee and shall contain all of the terms and conditions 
agreed upon by the parties thereto.
    (2) An application for approval of any instrument required to be 
filed will not be accepted unless a nonrefundable fee of $50 is paid 
electronically through Pay.gov at: https://www.pay.gov/paygov/ and a 
copy of the Pay.gov confirmation

[[Page 542]]

receipt page is included with your application. For any document you are 
not required to file by these regulations but which you submit for 
record purposes, you must also pay electronically through Pay.gov a 
nonrefundable fee of $50 per lease affected, and you must include a copy 
of the Pay.gov confirmation receipt page with your document. Such 
documents may be rejected at the discretion of the authorized officer.
    (b) An attorney in fact signing on behalf of the holder of a lease 
or sublease, shall furnish evidence of authority to execute the 
assignment or application for approval and the statement required by 
Sec.  581.20 of this part.
    (c) Where an assignment creates separate leases, a bond shall be 
furnished for each of the resulting leases in the amount prescribed in 
Sec.  582.40 of this title. Where an assignment does not create separate 
leases, the assignee, if the assignment so provides and the surety 
consents, may become a joint principal on the bond with the assignor.
    (d) An heir or devisee of a deceased holder of a lease or any 
interest therein shall be recognized as the lawful successor to such 
lease or interest if evidence of status as an heir or devisee is 
furnished in the form of:
    (1) A certified copy of an appropriate order or decree of the court 
having jurisdiction over the distribution of the estate, or
    (2) If no court action is necessary, the statement of two 
disinterested persons having knowledge of the fact or a certified copy 
of the will.
    (e) The heirs or devisee shall file statements that they are the 
persons named as successors to the estate with evidence of their 
qualifications to hold such lease or interest therein.
    (f) In the event an heir or devisee is unable to qualify to hold the 
lease or interest, the heir or devisee shall be recognized as the lawful 
successor of the deceased and be entitled to hold the lease for a period 
not to exceed 2 years from the date of death of the predecessor in 
interest.
    (g) Each obligation under any lease and under the regulations in 
this part shall inure to the heirs, executors, administrators, 
successors, or assignees of the lease.



Sec.  581.42  Effect of assignment on particular lease.

    (a) When an assignment is made of all the record title to a portion 
of the acreage in a lease, the assigned and retained portions of the 
lease area become segregated into separate and distinct leases. In such 
a case, the assignee becomes a lessee of the Government as to the 
segregated tract that is the subject of the assignment and is bound by 
the terms of the lease as though the lease had been obtained from the 
United States in the assignee's own name, and the assignment, after its 
approval, shall be the basis of a new record. Royalty, minimum royalty, 
and annual rental provisions of the lease shall apply separately to each 
segregated portion.
    (b) Each lease of an OCS mineral created by the segregation of a 
lease under paragraph (a) of this section shall continue in full force 
and effect for the remainder of the primary term of the original lease 
and so long thereafter as minerals are produced from the portion of the 
lease created by segregation in accordance with operations approved by 
the Director or the lessee is otherwise in compliance with provisions of 
the lease or regulations for earning the continuation of the lease in 
effect.



Sec.  581.43  Effect of suspensions on lease term.

    (a) If the BSEE Director orders the suspension of either operations 
or production, or both, with respect to any lease in its primary term, 
the primary term of the lease shall be extended by a period of time 
equivalent to the period of the directed suspension.
    (b) If the BSEE Director orders or approves the suspension of either 
operations or production, or both, with respect to any lease that is in 
force beyond its primary term, the term of the lease shall not be deemed 
to expire so long as the suspension remains in effect.

[[Page 543]]



                     Subpart E_Termination of Leases



Sec.  581.46  Relinquishment of leases or parts of leases.

    (a) A lease or any part thereof may be surrendered by the record 
title holder by filing a written relinquishment with the Director. A 
relinquishment shall take effect on the date it is filed subject to the 
continued obligation of the lessee and the surety to:
    (1) Make all payments due, including any accrued rentals and 
royalties; and
    (2) Abandon all operations, remove all facilities, and clear the 
land to be relinquished to the satisfaction of the Director.
    (b) Upon relinquishment of a lease, the data and information 
submitted under the lease will no longer be held confidential and will 
be available to the public.



Sec.  581.47  Cancellation of leases.

    (a) Whenever the owner of a nonproducing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, and the default continues for a period of 30 days after 
mailing of notice by registered or certified letter to the lease owner 
at the owner's record post office address, the Secretary may cancel the 
lease pursuant to section 5(c) of the Act, and the lessee shall not be 
entitled to compensation. Any such cancellation is subject to judicial 
review as provided by section 23(b) of the Act.
    (b) Whenever the owner of any producing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, the Secretary may cancel the lease only after judicial 
proceedings pursuant to section 5(d) of the Act, and the lessee shall 
not be entitled to compensation.
    (c) Any lease issued under the Act, whether producing or not, may be 
canceled by the Secretary upon proof that it was obtained by fraud or 
misrepresentation and after notice and opportunity to be heard has been 
afforded to the lessee.
    (d) The Secretary may cancel a lease in accordance with the 
following:
    (1) Cancellation may occur at any time if the Secretary determines 
after a hearing that:
    (i) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life (including fish and other aquatic life), 
to property, to any mineral (in areas leased or not leased), to the 
National security or defense, or to the marine, coastal, or human 
environment;
    (ii) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing such lease in force;
    (2) Cancellation shall not occur unless and until operations under 
such lease shall have been under suspension or temporary prohibition by 
the Secretary, with due extension of any lease term continuously for a 
period of 5 years, or for a lesser period upon request of the lessee; 
and
    (3) Cancellation shall entitle the lessee to receive such 
compensation as is shown to the Secretary as being equal to the lesser 
of:
    (i) The fair value of the canceled rights as of the date of 
cancellation, taking into account both anticipated revenues from the 
lease and anticipated costs, including costs of compliance with all 
applicable regulations and operating orders, liability for cleanup costs 
or damages, or both, and all other costs reasonably anticipated on the 
lease, or
    (ii) The excess, if any, over the lessee's revenues from the lease 
(plus interest thereon from the date of receipt to date of 
reimbursement) of all consideration paid for the lease and all direct 
expenditures made by the lessee after the date of issuance of such lease 
and in connection with exploration or development, or both, pursuant to 
the lease (plus interest on such consideration and such expenditures 
from date of payment to date of reimbursement), except that in the case 
of joint leases which are canceled due to the failure of one or more 
partners to exercise due diligence, the innocent parties shall have the 
right to seek damages for such loss from the responsible party or 
parties and the right to acquire the interests of the negligent party or 
parties and be issued the lease in question.

[[Page 544]]

    (iii) The lessee shall not be entitled to compensation where one of 
the following circumstances exists when a lease is canceled:
    (A) A producing lease is forfeited or is canceled pursuant to 
section (5)(d) of the Act;
    (B) A Testing Plan or Mining Plan is disapproved because of the 
lessee's failure to demonstrate compliance with the requirements of 
applicable Federal Law; or
    (C) The lessee(s) of a nonproducing lease fails to comply with a 
provision of the Act, the lease, or regulations issued under the Act, 
and the noncompliance continues for a period of 30 days or more after 
the mailing of a notice of noncompliance by registered or certified 
letter to the lessee(s).



PART 582_OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS
 OTHER THAN OIL, GAS, AND SULPHUR--Table of Contents



                            Subpart A_General

Sec.
582.0 Authority for information collection.
582.1 Purpose and authority.
582.2 Scope.
582.3 Definitions.
582.4 Opportunities for review and comment.
582.5 Disclosure of data and information to the public.
582.6 Disclosure of data and information to an adjacent State.
582.7 Jurisdictional controversies.

         Subpart B_Jurisdiction and Responsibilities of Director

582.10 Jurisdiction and responsibilities of Director.
582.11 Director's authority.
582.12 Director's responsibilities.
582.13 [Reserved]
582.14 Noncompliance, remedies, and penalties.
582.15 Cancellation of leases.

          Subpart C_Obligations and Responsibilities of Lessees

582.20 Obligations and responsibilities of lessees.
582.21 Plans, general.
582.22 Delineation Plan.
582.23 Testing Plan.
582.24 Mining Plan.
582.25 Plan modification.
582.26 Contingency Plan.
582.27 Conduct of operations.
582.28 Environmental protection measures.
582.29 Reports and records.
582.30 Right of use and easement.
582.31 [Reserved]

                           Subpart D_Payments

582.40 Bonds.
582.41 Method of royalty calculation.
582.42 Payments.

                            Subpart E_Appeals

582.50 Appeals.

    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                            Subpart A_General



Sec.  582.0  Authority for information collection.

    The information collection requirements in this part have been 
approved by the Office of Management and Budget under 44 U.S.C. 3507 and 
assigned clearance number 1010-0081. The information is being collected 
to inform the Bureau of Ocean Energy Management (BOEM) of general mining 
operations in the Outer Continental Shelf (OCS). The information will be 
used to ensure that operations are conducted in a safe and 
environmentally responsible manner in compliance with governing laws and 
regulations. The requirement to respond is mandatory.



Sec.  582.1  Purpose and authority.

    (a) The Act authorizes the Secretary to prescribe such rules and 
regulations as may be necessary to carry out the provisions of the Act 
(43 U.S.C. 1334). The Secretary is authorized to prescribe and amend 
regulations that the Secretary determines to be necessary and proper in 
order to provide for the prevention of waste, conservation of the 
natural resources of the OCS, and the protection of correlative rights 
therein. In the enforcement of safety, environmental, and conservation 
laws and regulations, the Secretary is authorized to cooperate with 
adjacent

[[Page 545]]

States and other Departments and Agencies of the Federal Government.
    (b) Subject to the supervisory authority of the Secretary, and 
unless otherwise specified, the regulations in this part shall be 
administered by the Director of BOEM.



Sec.  582.2  Scope.

    The rules and regulations in this part apply as of their effective 
date to all operations conducted under a mineral lease for OCS minerals 
other than oil, gas, or sulphur issued under the provisions of section 
8(k) of the Act.



Sec.  582.3  Definitions.

    When used in this part, the following terms shall have the meaning 
given below:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State:
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipment OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, or mining activities; or
    (3) In which there is a reasonable probability of significant effect 
on land or water uses from such activity.
    Contingency Plan means a plan for action to be taken in emergency 
situations.
    Data means geological and geophysical (G&G) facts and statistics or 
samples which have not been analyzed, processed, or interpreted.
    Development means those activities which take place following the 
discovery of minerals in paying quantities including geophysical 
activities, drilling, construction of offshore facilities, and operation 
of all onshore support facilities, which are for the purpose of 
ultimately producing the minerals discovered.
    Director means the Director of BOEM of the U.S. Department of the 
Interior or an official authorized to act on the Director's behalf.
    Exploration means the process of searching for minerals on a lease 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of minerals;
    (2) Any drilling including the drilling of a borehole in which the 
discovery of a mineral other than oil, gas, or sulphur is made and the 
drilling of any additional boreholes needed to delineate any mineral 
deposits; and
    (3) The taking of sample portions of a mineral deposit to enable the 
lessee to determine whether to proceed with development and production.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters (when obtained for geochemical 
analysis) acquired while conducting postlease mining activities.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the power granted 
to a Governor.
    Information means G&G data that have been analyzed, processed, or 
interpreted.
    Lease means one of the following, whichever is required by the 
context: Any form of authorization which is issued under section 8 or 
maintained under section 6 of the Acts and which authorizes exploration 
for, and development and production of, specific minerals; or the area 
covered by that authorization.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all parties holding that authority by or through the lessee.
    Major Federal action means any action or proposal by the Secretary 
which is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act (NEPA) (i.e., an action which will have a 
significant impact on the quality of the human environment requiring 
preparation of an Environmental Impact Statement (EIS) pursuant to 
section 102(2)(C) of NEPA).

[[Page 546]]

    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors which interactively determine the 
productivity, state, condition, and quality of the marine ecosystem, 
including the waters of the high seas, the contiguous zone, transitional 
and intertidal areas, salt marshes, and wetlands within the coastal zone 
and on the OCS.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from ``public lands'' as defined in 
section 103 of the Federal Land Policy and Management Act of 1976.
    OCS mineral means any mineral deposit or accretion found on or below 
the surface of the seabed but does not include oil, gas, or sulphur; 
salt or sand and gravel intended for use in association with the 
development of oil, gas, or sulphur; or source materials essential to 
production of fissionable materials which are reserved to the United 
States pursuant to section 12(e) of the Act.
    Operator means the individual, partnership, firm, or corporation 
having control or management of operations on the lease or a portion 
thereof. The operator may be a lessee, designated agent of the lessee, 
or holder of rights under an approved operating agreement.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. The 
term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Testing means removing bulk samples for processing tests and 
feasibility studies and/or the testing of mining equipment to obtain 
information needed to develop a detailed Mining Plan.



Sec.  582.4  Opportunities for review and comment.

    (a) In carrying out BOEM's responsibilities under the Act and 
regulations in this part, the Director shall provide opportunities for 
Governors of adjacent States, State/Federal task forces, lessees and 
operators, other Federal Agencies, and other interested parties to 
review proposed activities described in a Delineation, Testing, or 
Mining Plan together with an analysis of potential impacts on the 
environment and to provide comments and recommendations for the 
disposition of the proposed plan.
    (b)(1) For Delineation Plans, the adjacent State Governor(s) shall 
be notified by the Director within 15 days following the submission of a 
request for approval of a Delineation Plan. Notification shall include a 
copy of the proposed Delineation Plan and the accompanying environmental 
information. The adjacent State Governor(s) who wishes to comment on a 
proposed Delineation Plan may do so within 30 days of the receipt of the 
proposed plan and the accompanying information.
    (2) In cases where an Environmental Assessment is to be prepared, 
the Director's invitation to provide comments may allow the adjacent 
State Governor(s) more than 30 days following receipt of the proposed 
plan to provide comments.
    (3) The Director shall notify Federal Agencies, as appropriate, with 
a copy of the proposed Delineation Plan and the accompanying 
environmental information within 15 days following the submission of the 
request. Agencies that wish to comment on a proposed Delineation Plan 
shall do so within 30 days following receipt of the plan and the 
accompanying information.
    (c)(1) For Testing Plans, the adjacent State Governor(s) shall be 
notified by

[[Page 547]]

the Director within 20 days following submission of a request for 
approval of a proposed Testing Plan. Notification shall include a copy 
of the proposed Testing Plan and the accompanying environmental 
information. The adjacent State Governor(s) who wishes to comment on a 
proposed Testing Plan may do so within 60 days of the receipt of a plan 
and the accompanying information.
    (2) In cases where an EIS is to be prepared, the Director's 
invitation to provide comments may allow the adjacent State Governor(s) 
more than 60 days following receipt of the proposed plan to provide 
comments.
    (3) The Director shall notify Federal Agencies, as appropriate, with 
a copy of the proposed Testing Plan and the accompanying environmental 
information within 20 days following the submission of the request. 
Agencies that wish to comment on a proposed Testing Plan shall do so 
within 60 days following receipt of the plan and the accompanying 
information.
    (d)(1) For Mining Plans, the adjacent State Governor(s) shall be 
notified by the Director within 20 days following the submission of a 
request for approval of a proposed Mining Plan. Notification shall 
include a copy of the proposed Mining Plan and the accompanying 
environmental information. The adjacent State Governor(s) who wishes to 
comment on a proposed Mining Plan may do so within 60 days of the 
receipt of a plan and the accompanying information.
    (2) In cases where an EIS is to be prepared, the Director's 
invitation to provide comments may allow the adjacent State Governor(s) 
more than 60 days following receipt of the proposed plan to provide 
comments.
    (3) The Director shall notify Federal Agencies, as appropriate, with 
a copy of the proposed Mining Plan and the accompanying environmental 
information within 20 days following the submission of the request. 
Agencies that wish to comment on a proposed Mining Plan shall do so 
within 60 days following receipt of the plan and the accompanying 
information.
    (e) When an adjacent State Governor(s) has provided comments 
pursuant to paragraphs (b), (c), and (d) of this section, the 
Governor(s) shall be given, in writing, a list of recommendations which 
are adopted and the reasons for rejecting any of the recommendations of 
the Governor(s) or for implementing any alternative means identified 
during consultations with the Governor(s).



Sec.  582.5  Disclosure of data and information to the public.

    (a) The Director shall make data, information, and samples available 
in accordance with the requirements and subject to the limitations of 
the Act, the Freedom of Information Act (5 U.S.C. 552), and the 
implementing regulations (43 CFR part 2).
    (b) Geophysical data, processed G&G information, interpreted G&G 
information, and other data and information submitted pursuant to the 
requirements of this part shall not be available for public inspection 
without the consent of the lessee so long as the lease remains in 
effect, unless the Director determines that earlier limited release of 
such information is necessary for the unitization of operations on two 
or more leases, to ensure proper Mining Plans for a common orebody, or 
to promote operational safety. When the Director determines that early 
limited release of data and information is necessary, the data and 
information shall be shown only to persons with a direct interest in the 
affected lease(s), unitization agreement, or joint Mining Plan.
    (c) Geophysical data, processed geophysical information, and 
interpreted geophysical information collected on a lease with high 
resolution systems (including, but not limited to, bathymetry, side-scan 
sonar, subbottom profiler, and magnetometer) in compliance with 
stipulations or orders concerning protection of environmental aspects of 
the lease may be made available to the public 60 days after submittal to 
the Director, unless the lessee can demonstrate to the satisfaction of 
the Director that release of the information or data would unduly damage 
the lessee's competitive position.

[[Page 548]]



Sec.  582.6  Disclosure of data and information to an adjacent State.

    (a) Proprietary data, information, and samples submitted to BOEM 
pursuant to the requirements of this part shall be made available for 
inspection by representatives of adjacent State(s) upon request by the 
Governor(s) in accordance with paragraphs (b), (c), and (d) of this 
section.
    (b) Disclosure shall occur only after the Governor has entered into 
an agreement with the Secretary providing that:
    (1) The confidentiality of the information shall be maintained;
    (2) In any action commenced against the Federal Government or the 
State for failure to protect the confidentiality of proprietary 
information, the Federal Government or the State, as the case may be, 
may not raise as a defense any claim of sovereign immunity or any claim 
that the employee who revealed the proprietary information, which is the 
basis of the suit, was acting outside the scope of the person's 
employment in revealing the information;
    (3) The State agrees to hold the United States harmless for any 
violation by the State or its employees or contractors of the agreement 
to protect the confidentiality of proprietary data, information, and 
samples; and
    (c) The data, information, and samples available for inspection by 
representatives of adjacent State(s) pursuant to an agreement shall be 
related to leased lands.



Sec.  582.7  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State 
jurisdiction, either the Governor of the State or the Secretary may 
initiate negotiations in an attempt to settle the jurisdictional 
controversy. With the concurrence of the Attorney General, the Secretary 
may enter into an agreement with a State with respect to OCS mineral 
activities and to payment and impounding of rents, royalties, and other 
sums and with respect to the issuance or nonissuance of new leases 
pending settlement of the controversy.



         Subpart B_Jurisdiction and Responsibilities of Director



Sec.  582.10  Jurisdiction and responsibilities of Director.

    Subject to the authority of the Secretary, the following activities 
are subject to the regulations in this part and are under the 
jurisdiction of the Director: Exploration, testing, and mining 
operations together with the associated environmental protection 
measures needed to permit those activities to be conducted in an 
environmentally responsible manner; handling, measurement, and 
transportation of OCS minerals; and other operations and activities 
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant 
to a right of use and easement granted under this part, by or on behalf 
of a lessee or the holder of a right of use and easement.



Sec.  582.11  Director's authority.

    (a) In the exercise of jurisdiction under Sec.  582.10, the Director 
is authorized and directed to act upon the requests, applications, and 
notices submitted under the regulations in this part; to issue either 
written or oral orders to govern lease operations; and to require 
compliance with applicable laws, regulations, and lease terms so that 
all operations conform to sound conservation practices and are conducted 
in a manner which is consistent with the following:
    (1) Make such OCS minerals available to meet the nation's needs in a 
timely manner;
    (2) Balance OCS mineral resource development with protection of the 
human, marine, and coastal environments;
    (3) Ensure the public a fair and equitable return on OCS minerals 
leased on the OCS; and
    (4) Foster and encourage private enterprise.
    (b)(1) The Director is to be provided ready access to all OCS 
mineral resource data and all environmental data acquired by the lessee 
or holder of a right of use and easement in the course of operations on 
a lease or right of use and easement and may require a lessee or holder 
to obtain additional environmental data when deemed necessary to

[[Page 549]]

assure adequate protection of the human, marine, and coastal 
environments.
    (2) The Director is to be provided an opportunity to inspect, cut, 
and remove representative portions of all samples acquired by a lessee 
in the course of operations on the lease.
    (c) In addition to the rights and privileges granted to a lessee 
under any lease issued or maintained under the Act, on request, the 
Director may grant a lessee, subject to such conditions as the Director 
may prescribe, a right of use and easement to construct and maintain 
platforms, artificial islands, and/or other installations and devices 
which are permanently or temporarily attached to the seabed and which 
are needed for the conduct of leasehold exploration, testing, 
development, production, and processing activities or other leasehold 
related operations whether on or off the lease.
    (d)(1) The Director may approve the consolidation of two or more OCS 
mineral leases or portions of two or more OCS mineral leases into a 
single mining unit requested by lessees, or the Director may require 
such consolidation when the operation of those leases or portions of 
leases as a single mining unit is in the interest of conservation of the 
natural resources of the OCS or the prevention of waste. A mining unit 
may also include all or portions of one or more OCS mineral leases with 
all or portions of one or more adjacent State leases for minerals in a 
common orebody. A single unit operator shall be responsible for 
submission of required Delineation, Testing, and Mining Plans covering 
OCS mineral operations for an approved mining unit.
    (2) Operations such as exploration, testing, and mining activities 
conducted in accordance with an approved plan on any lease or portion of 
a lease which is subject to an approved mining unit shall be considered 
operations on each of the leases that is made subject to the approved 
mining unit.
    (3) Minimum royalty paid pursuant to a Federal lease, which is 
subject to an approved mining unit, is creditable against the production 
royalties allocated to that Federal lease during the lease year for 
which the minimum royalty is paid.
    (4) Any OCS minerals produced from State and Federal leases which 
are subject to an approved mining unit shall be accounted for separately 
unless a method of allocating production between State and Federal 
leases has been approved by the Director and the appropriate State 
official.



Sec.  582.12  Director's responsibilities.

    (a) The Director is responsible for the regulation of activities to 
assure that all operations conducted under a lease or right of use and 
easement are conducted in a manner that protects the environment and 
promotes orderly development of OCS mineral resources. Those activities 
are to be designed to prevent serious harm or damage to, or waste of, 
any natural resource (including OCS mineral deposits and oil, gas, and 
sulphur resources in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the marine, coastal, or human 
environment.
    (b)(1) In the evaluation of a Delineation Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law; and
    (v) Requirements for the protection of the environment, health, and 
safety.
    (2) Within 30 days following the completion of an environmental 
assessment or other NEPA document prepared pursuant to the regulations 
implementing NEPA or within 30 days following the comment period 
provided in Sec.  582.4(b) of this part, the Director shall:
    (i) Approve any Delineation Plan which is consistent with the 
criteria in paragraph (b)(1) of this section;
    (ii) Require the lessee to modify any Delineation Plan that is 
inconsistent with the criteria in paragraph (b)(1) of this section; or
    (iii) Disapprove a Delineation Plan when it is determined that an 
activity proposed in the plan would probably cause serious harm or 
damage to life (including fish and other aquatic life); to property; to 
natural resources of the OCS including mineral deposits (in areas leased 
or not leased); or to the

[[Page 550]]

marine, coastal, or human environment, and the proposed activity cannot 
be modified to avoid the conditions.
    (3) The Director shall notify the lessee in writing of the reasons 
for disapproving a Delineation Plan or for requiring modification of a 
plan and the conditions that must be met for plan approval.
    (c)(1) In the evaluation of a Testing Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law;
    (v) Environmental, safety, and health requirements; and
    (vi) The statutory requirement to protect property, natural 
resources of the OCS, including mineral deposits (in areas leased or not 
leased), and the National security or defense.
    (2) Within 60 days following the release of a final EIS prepared 
pursuant to NEPA or within 60 days following the comment period provided 
in Sec.  582.4(c) of this part, the Director shall:
    (i) Approve any Testing Plan which is consistent with the criteria 
in paragraph (c)(1) of this section;
    (ii) Require the lessee to modify any Testing Plan which is 
inconsistent with the criteria in paragraph (c)(1) of this section; or
    (iii) Disapprove any Testing Plan when the Director determines the 
existence of exceptional geological conditions in the lease area, 
exceptional resource values in the marine or coastal environment, or 
other exceptional circumstances and that (A) implementation of the 
activities described in the plan would probably cause serious harm and 
damage to life (including fish and other aquatic life), to property, to 
any mineral deposit (in areas leased or not leased), to the National 
security or defense, or to the marine, coastal, or human environments; 
(B) that the threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and (C) the 
advantages of disapproving the Testing Plan outweigh the advantages of 
development and production of the OCS mineral resources.
    (3) The Director shall notify the lessee in writing of the reason(s) 
for disapproving a Testing Plan or for requiring modification of a 
Testing Plan and the conditions that must be met for approval of the 
plan.
    (d)(1) In the evaluation of a Mining Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law;
    (v) Environmental, safety, and health requirements; and
    (vi) The statutory requirements to protect property, natural 
resources of the OCS, including mineral deposits (in areas leased or not 
leased), and the National security or defense.
    (2) Within 60 days following the release of a final EIS prepared 
pursuant to NEPA or within 60 days following the comment period provided 
in Sec.  582.4(d) of this part, the Director shall:
    (i) Approve any Mining Plan which is consistent with the criteria in 
paragraph (d)(1) of this section;
    (ii) Require the lessee to modify any Mining Plan which is 
inconsistent with the criteria in paragraph (d)(1) of this section; or
    (iii) Disapprove any Mining Plan when the Director determines the 
existence of exceptional geological conditions in the lease area, 
exceptional resource values in the marine or coastal environment, or 
other exceptional circumstances, and that:
    (A) Implementation of the activities described in the plan would 
probably cause serious harm and damage to life (including fish and other 
aquatic life), to property, to any mineral deposit (in areas leased or 
not leased), to the National security or defense, or to the marine, 
coastal, or human environments;
    (B) That the threat of harm or damage will not disappear or decrease 
to an acceptable extent within a reasonable period of time; and

[[Page 551]]

    (C) The advantages of disapproving the Mining Plan outweigh the 
advantages of development and production of the OCS mineral resources.
    (3) The Director shall notify the lessee in writing of the reason(s) 
for disapproving a Mining Plan or for requiring modification of a Mining 
Plan and the conditions that must be met for approval of the plan.
    (e)-(f) [Reserved]
    (g) The Director shall establish practices and procedures to govern 
the collection of all rents, royalties, and other payments due the 
Federal Government in accordance with terms of the leasing notice, the 
lease, and the applicable Royalty Management regulations listed in Sec.  
581.26(i) of this chapter.
    (h) [Reserved]



Sec.  582.13  [Reserved]



Sec.  582.14  Noncompliance, remedies, and penalties.

    (a)(1) If the Director determines that a lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the approved Delineation, Testing, or 
Mining Plan; or the Director's orders or instructions, and the Director 
determines that such noncompliance poses a threat of immediate, serious, 
or irreparable damage to the environment, the mine or the deposit being 
mined, or other valuable mineral deposits or other resources, the 
Director shall order the lessee to take immediate and appropriate 
remedial action to alleviate the threat. Any oral orders shall be 
followed up by service of a notice of noncompliance upon the lessee by 
delivery in person to the lessee or agent, or by certified or registered 
mail addressed to the lessee at the last known address.
    (2) If the Director determines that the lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the requirements of an approved 
Delineation, Testing, or Mining Plan; or the Director's orders or 
instructions, and such noncompliance does not pose a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall serve a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent or by certified or 
registered mail addressed to the lessee at the last known address.
    (b) A notice of noncompliance shall specify in what respect(s) the 
lessee has failed to comply with the provisions of applicable law; 
regulations; the lease; the requirements of an approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
shall specify the action(s) which must be taken to correct the 
noncompliance and the time limits within which such action must be 
taken.
    (c) Failure of a lessee to take the actions specified in the notice 
of noncompliance within the time limit specified shall be grounds for a 
suspension of operations and other appropriate actions, including but 
not limited to the assessment of a civil penalty of up to $10,000 per 
day for each violation that is not corrected within the time period 
specified (43 U.S.C. 1350(b)).
    (d) Whenever the Director determines that a violation of or failure 
to comply with any provision of the Act; or any provision of a lease, 
license, or permit issued pursuant to the Act; or any provision of any 
regulation promulgated under the Act probably occurred and that such 
apparent violation continued beyond notice of the violation and the 
expiration of the reasonable time period allowed for corrective action, 
the Director shall follow the procedures concerning remedies and 
penalties in subpart N, Remedies and Penalties, of 30 CFR part 550 to 
determine and assess an appropriate penalty.
    (e) The remedies and penalties prescribed in this section shall be 
concurrent and cumulative, and the exercise of one shall not preclude 
the exercise of the other. Further, the remedies and penalties 
prescribed in this section shall be in addition to any other remedies 
and penalties afforded by any other law or regulation (43 U.S.C. 
1350(e)).



Sec.  582.15  Cancellation of leases.

    (a) Whenever the owner of a nonproducing lease fails to comply with 
any

[[Page 552]]

of the provisions of the Act, the lease, or the regulations issued under 
the Act, and the default continues for a period of 30 days after mailing 
of notice by registered or certified letter to the lease owner at the 
owner's record post office address, the Secretary may cancel the lease 
pursuant to section 5(c) of the Act, and the lessee shall not be 
entitled to compensation. Any such cancellation is subject to judicial 
review as provided by section 23(b) of the Act.
    (b) Whenever the owner of any producing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, the Secretary may cancel the lease only after judicial 
proceedings pursuant to section 5(d) of the Act, and the lessee shall 
not be entitled to compensation.
    (c) Any lease issued under the Act, whether producing or not, may be 
canceled by the Secretary upon proof that it was obtained by fraud or 
misrepresentation and after notice and opportunity to be heard has been 
afforded to the lessee.
    (d) The Secretary may cancel a lease in accordance with the 
following:
    (1) Cancellation may occur at any time if the Secretary determines 
after a hearing that:
    (i) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life (including fish and other aquatic life), 
to property, to any mineral (in areas leased or not leased), to the 
National security or defense, or to the marine, coastal, or human 
environment;
    (ii) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing such lease in force.
    (2) Cancellation shall not occur unless and until operations under 
such lease shall have been under suspension or temporary prohibition by 
the Secretary, with due extension of any lease term continuously for a 
period of 5 years or for a lesser period upon request of the lessee;
    (3) Cancellation shall entitle the lessee to receive such 
compensation as is shown to the Secretary as being equal to the lesser 
of:
    (i) The fair value of the canceled rights as of the date of 
cancellation, taking account of both anticipated revenues from the lease 
and anticipated costs, including costs of compliance with all applicable 
regulations and operating orders, liability for cleanup costs or 
damages, or both, and all other costs reasonably anticipated on the 
lease, or
    (ii) The excess, if any, over the lessee's revenue from the lease 
(plus interest thereon from the date of receipt to date of 
reimbursement) of all consideration paid for the lease and all direct 
expenditures made by the lessee after the date of issuance of such lease 
and in connection with exploration or development, or both, pursuant to 
the lease (plus interest on such consideration and such expenditures 
from date of payment to date of reimbursement), except that in the case 
of joint leases which are canceled due to the failure of one or more 
partners to exercise due diligence, the innocent parties shall have the 
right to seek damages for such loss from the responsible party or 
parties and the right to acquire the interests of the negligent party or 
parties and be issued the lease in question.
    (iii) The lessee shall not be entitled to compensation where one of 
the following circumstances exists when a lease is canceled:
    (A) A producing lease is forfeited or is canceled pursuant to 
section (5)(d) of the Act;
    (B) A Testing Plan or Mining Plan is disapproved because the 
lessee's failure to demonstrate compliance with the requirements of 
applicable Federal law; or
    (C) The lessee of a nonproducing lease fails to comply with a 
provision of the Act, the lease, or regulations issued under the Act, 
and the noncompliance continues for a period of 30 days or more after 
the mailing of a notice of noncompliance by registered or certified 
letter to the lessee.

[[Page 553]]



          Subpart C_Obligations and Responsibilities of Lessees



Sec.  582.20  Obligations and responsibilities of lessees.

    (a) The lessee shall comply with the provisions of applicable laws; 
regulations; the lease; the requirements of the approved Delineation, 
Testing, or Mining Plans; and other written or oral orders or 
instructions issued by the Director when performing exploration, 
testing, development, and production activities pursuant to a lease 
issued under 30 CFR part 581. The lessee shall take all necessary 
precautions to prevent waste and damage to oil, gas, sulphur, and other 
OCS mineral-bearing formations and shall conduct operations in such 
manner that does not cause or threaten to cause harm or damage to life 
(including fish and other aquatic life); to property; to the National 
security or defense; or to the marine, coastal, or human environment 
(including onshore air quality). The lessee shall make all mineral 
resource data and information and all environmental data and information 
acquired by the lessee in the course of exploration, testing, 
development, and production operations on the lease available to the 
Director for examination and copying at the lease site or an onshore 
location convenient to the Director.
    (b) In all cases where there is more than one lease owner of record, 
one person shall be designated payor for the lease. The payor shall be 
responsible for making all rental, minimum royalty, and royalty 
payments.
    (c) In all cases where lease operations are not conducted by the 
sole lessee, a ``designation of operator'' shall be submitted to and 
accepted by the Director prior to the commencement of leasehold 
operations. This designation when accepted will be recognized as 
authority for the designee to act on behalf of the lessees and to 
fulfill the lessees' obligations under the Act, the lease, and the 
regulations of this part. All changes of address and any termination of 
a designation of operator shall be reported immediately, in writing, to 
the Director. In the case of a termination of a designation of operator 
or in the event of a controversy between the lessee and the designated 
operator, both the lessee and the designated operator will be 
responsible for the protection of the interests of the lessor.
    (d) When required by the Director or at the option of the lessee, 
the lessee shall submit to the Director the designation of a local 
representative empowered to receive notices, provide access to OCS 
mineral and environmental data and information, and comply with orders 
issued pursuant to the regulations of this part. If there is a change in 
the designated representative, the Director shall be notified 
immediately.
    (e) Before beginning operations, the lessee shall inform the 
Director in writing of any designation of a local representative under 
paragraph (d) of this section and the address of the mine office 
responsible for the exploration, testing, development, or production 
activities; the lessee's temporary and permanent addresses; or the name 
and address of the designated operator who will be responsible for the 
operations, and who will act as the local representative of the lessee. 
The Director shall also be informed of each change thereafter in the 
address of the mine office or in the name or address of the local 
representative.
    (f) The holder of a right-of-use and easement shall exercise its 
rights under the right of use and easement in accordance with the 
regulations of this part.
    (g) A lessee shall submit reports and maintain records in accordance 
with Sec.  582.29 of this part.
    (h) When an oral approval is given by BOEM in response to an oral 
request under these regulations, the oral request shall be confirmed in 
writing by the lessee or holder of a right of use and easement within 72 
hours.
    (i) The lessee is responsible for obtaining all permits and 
approvals from BOEM, BSEE or other Agencies needed to carry out 
exploration, testing, development, and production activities under a 
lease issued under 30 CFR part 581 of this title.



Sec.  582.21  Plans, general.

    (a) No exploration, testing, development, or production activities, 
except

[[Page 554]]

preliminary activities, shall be commenced or conducted on any lease 
except in accordance with a plan submitted by the lessee and approved by 
the Director. Plans will not be approved before completion of 
comprehensive technical and environmental evaluations to assure that the 
activities described will be carried out in a safe and environmentally 
responsible manner. Prior to the approval of a plan, the Director will 
assure that the lessee is prepared to take adequate measures to prevent 
waste; conserve natural resources of the OCS; and protect the 
environment, human life, and correlative rights. The lessee shall 
demonstrate to the satisfaction of the Director that the lease is in 
good standing, the lessee is authorized and capable of conducting the 
activities described in the plan, and that an acceptable bond has been 
provided.
    (b) Plans shall be submitted to the Director for approval. The 
lessee shall submit the number of copies prescribed by the Director. 
Such plans shall describe in detail the activities that are to be 
conducted and shall demonstrate that the proposed exploration, testing, 
development, and production activities will be conducted in an 
operationally safe and environmentally responsible manner that is 
consistent with the provisions of the lease, applicable laws, and 
regulations. The Governor of an affected State and other Federal 
Agencies shall be provided an opportunity to review and provide comments 
on proposed Delineation, Testing, and Mining Plans and any proposal for 
a significant modification to an approved plan. Following review, 
including the technical and environmental evaluations, the Director 
shall either approve, disapprove, or require the lessee to modify its 
proposed plan.
    (c) Lessees are not required to submit a Delineation or Testing Plan 
prior to submittal of a proposed Testing or Mining Plan if the lessee 
has sufficient data and information on which to base a Testing or Mining 
Plan without carrying out postlease exploration and/or testing 
activities. A Mining Plan may include proposed exploration or testing 
activities where those activities are needed to obtain additional data 
and information on which to base plans for future mining activities. A 
Testing Plan may include exploration activities when those activities 
are needed to obtain additional data or information on which to base 
plans for future testing or mining activities.
    (d) Preliminary activities are bathymetric, geological, geophysical, 
mapping, and other surveys necessary to develop a comprehensive 
Delineation, Testing, or Mining Plan. Such activities are those which 
have no significant adverse impact on the natural resources of the OCS. 
The lessee shall give notice to the Director at least 30 days prior to 
initiating the proposed preliminary activities on the lease. The notice 
shall describe in detail those activities that are to be conducted and 
the time schedule for conducting those activities.
    (e) Leasehold activities shall be carried out with due regard to 
conservation of resources, paying particular attention to the wise 
management of OCS mineral resources, minimizing waste of the leased 
resource(s) in mining and processing, and preventing damage to unmined 
parts of the mineral deposit and other resources of the OCS.



Sec.  582.22  Delineation Plan.

    All exploration activities shall be conducted in accordance with a 
Delineation Plan submitted by the lessee and approved by the Director. 
The Delineation Plan shall describe the proposed activities necessary to 
locate leased OCS minerals, characterize the quantity and quality of the 
minerals, and generate other information needed for the development of a 
comprehensive Testing or Mining Plan. A Delineation Plan at a minimum 
shall include the following:
    (a) The OCS mineral(s) or primary interest.
    (b) A brief narrative description of the activities to be conducted 
and how the activities will lead to the discovery and evaluation of a 
commercially minable deposit on the lease.
    (c) The name, registration, and type of equipment to be used, 
including vessel types as well as their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.

[[Page 555]]

    (d) Information showing that the equipment to be used (including the 
vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (e) Maps showing the proposed locations of test drill holes, the 
anticipated depth of penetration of test drill holes, the locations 
where surficial samples were taken, and the location of proposed 
geophysical survey lines for each surveying method being employed.
    (f) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife species and their habitats; any unique or special features 
in the lease area; aquifers; other natural resources of the OCS; and 
hazards to public health, safety, and navigation.
    (g) A schedule indicating the starting and completion dates for each 
proposed exploration activity.
    (h) A list of any known archaeological resources on the lease and 
measures to assure that the proposed exploration activities do not 
damage those resources.
    (i) A description of any potential conflicts with other uses and 
users of the area.
    (j) A description of measures to be taken to monitor the effects of 
the proposed exploration activities on the environment in accordance 
with Sec.  582.28(c) of this part.
    (k) A detailed description of practices and procedures to effect the 
abandonment of exploration activities, e.g., plugging of test drill 
holes. The proposed procedures shall indicate the steps to be taken to 
assure that test drill holes and other testing procedures which 
penetrate the seafloor to a significant depth are properly sealed and 
that the seafloor is left free of obstructions or structures that may 
present a hazard to other uses or users of the OCS such as navigation or 
commercial fishing.
    (l) A detailed description of the cycle of all materials, the method 
for discharge and disposal of waste and refuse, and the chemical and 
physical characteristics of waste and refuse.
    (m) A description of the potential environmental impacts of the 
proposed exploration activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and affected environment (e.g., maps, land 
use, and layout);
    (2) A description of the nature and degree of environmental impacts 
and the domestic socioeconomic effects of construction and operation of 
the associated facilities, including waste characteristics and toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternative sites and technologies considered by the lessee and 
the reasons why they were not chosen.
    (n) Any other information needed for technical evaluation of the 
planned activity, such as sample analyses to be conducted at sea, and 
the evaluation of potential environmental impacts.



Sec.  582.23  Testing Plan.

    All testing activities shall be conducted in accordance with a 
Testing Plan submitted by the lessee and approved by the Director. Where 
a lessee needs more information to develop a detailed Mining Plan than 
is obtainable under an approved Delineation Plan, to prepare feasibility 
studies, to carry out a pilot program to evaluate processing techniques 
or technology or mining equipment, or to determine environmental effects 
by a pilot test mining operation, the lessee shall submit a 
comprehensive Testing Plan for the Director's approval. Any OCS minerals 
acquired during activities conducted under an approved Testing Plan will 
be subject to the payment of royalty pursuant to the governing lease 
terms. A Testing Plan at a minimum shall include the following:
    (a) The nature and purpose of the proposed testing program.
    (b) A comprehensive description of the activities to be performed 
including descriptions of the proposed methods for analysis of samples 
taken.
    (c) A narrative description and maps showing water depths and the 
locations

[[Page 556]]

of the proposed pilot mining or other testing activities.
    (d) A comprehensive description of the method and manner in which 
testing activities will be conducted and the results the lessee expects 
to obtain as a result of those activities.
    (e) The name, registration, and type of equipment to be used, 
including vessel types together with their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.
    (f) Information showing that the equipment to be used (including the 
vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (g) A schedule specifying the starting and completion dates for each 
of the testing activities.
    (h) A list of known archaeological resources on the lease and 
measures to be used to assure that the proposed testing activities do 
not damage those resources.
    (i) A description of any potential conflicts with other uses and 
users of the area.
    (j) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife species and their habitat; any unique or special features 
in the lease area, other natural resources of the OCS; and hazards to 
public health, safety, and navigation.
    (k) A description of the measures to be taken to monitor the impacts 
of the proposed testing activities in accordance with Sec.  582.28(c) of 
this part.
    (l) A detailed description of the cycle of all materials including 
samples and wastes, the method for discharge and disposal of waste and 
refuse, and the chemical and physical characteristics of such waste and 
refuse.
    (m) A detailed description of practices and procedures to effect the 
abandonment of testing activities, e.g., abandonment of a pilot mining 
facility. The proposed procedures shall indicate the steps to be taken 
to assure that mined areas do not pose a threat to the environment and 
that the seafloor is left free of obstructions and structures that may 
present a hazard to other uses or users of the OCS such as navigation or 
commercial fishing.
    (n) A description of potential environmental impacts of testing 
activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and affected environment (e.g., maps, land 
use, and layout);
    (2) A description of the nature and degree of potential 
environmental impacts of the proposed testing activities and the 
domestic socioeconomic effects of construction and operation of the 
proposed testing facilities, including waste characteristics and 
toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternate sites and technologies considered by the lessee and 
the reasons why they were not selected.
    (o) Any other information needed for technical evaluation of the 
planned activities and for evaluation of the impact of those activities 
on the human, marine, and coastal environments.



Sec.  582.24  Mining Plan.

    All OCS mineral development and production activities shall be 
conducted in accordance with a Mining Plan submitted by the lessee and 
approved by the Director. A Mining Plan shall include comprehensive 
detailed descriptions, illustrations, and explanations of the proposed 
OCS mineral development, production, and processing activities and 
accurately present the lessee's proposed plan of operation. A Mining 
Plan at a minimum shall include the following:
    (a) A narrative description of the mining activities including:
    (1) The OCS mineral(s) or material(s) to be recovered;
    (2) Estimates of the number of tons and grade(s) of ore to be 
recovered;
    (3) Anticipated annual production;
    (4) Volume of ocean bottom expected to be disturbed (area and depth 
of disruption) each year; and
    (5) All activities of the mining cycle from extraction through 
processing and waste disposal.

[[Page 557]]

    (b) Maps of the lease showing water depths, the outline of the 
mineral deposit(s) to be mined with cross sections showing thickness, 
and the area(s) anticipated to be mined each year.
    (c) The name, registration, and type of equipment to be used, 
including vessel types as well as their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.
    (d) Information showing that the equipment to be used (including the 
vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (e) A description of equipment to be used in mining, processing, and 
transporting of the ore.
    (f) A schedule indicating the anticipated starting and completion 
dates for each activity described in the plan.
    (g) For onshore processing, a description of how OCS minerals are to 
be processed and how the produced OCS minerals will be weighed, assayed, 
and royalty determinations made.
    (h) For at-sea processing, additional information including type and 
size of installation or structures and the method of tailings disposal.
    (i) A list of known archaeological resources on the lease and the 
measures to be taken to assure that the proposed mining activities do 
not damage those resources.
    (j) Description of any potential conflicts with other uses and users 
of the area.
    (k) A detailed description of the nature and occurrence of the OCS 
mineral deposit(s) in the leased area with adequate maps and sections.
    (l) A detailed description of development and mining methods to be 
used, the proposed sequence of mining or development, the expected 
production rate, the method and location of the proposed processing 
operation, and the method of measuring production.
    (m) A detailed description of the method of transporting the 
produced OCS minerals from the lease to shore and adequate maps showing 
the locations of pipelines, conveyors, and other transportation 
facilities and corridors.
    (n) A detailed description of the cycle of all materials including 
samples and wastes, the method of discharge and disposal of waste and 
refuse, and the chemical and physical characteristics of the waste and 
refuse.
    (o) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife species and their habitats; any unique or special features 
in the lease area, aquifers, or other natural resources of the OCS; and 
hazards to public health, safety, and navigation.
    (p) A detailed description of measures to be taken to monitor the 
impacts of the proposed mining and processing activities on the 
environment in accordance with Sec.  582.28(c) of this part.
    (q) A detailed description of practices and procedures to effect the 
abandonment of mining and processing activities. The proposed procedures 
shall indicate the steps to be taken to assure that mined areas on 
tailing deposits do not pose a threat to the environment and that the 
seafloor is left free of obstructions and structures that present a 
hazard to other users or uses of the OCS such as navigation or 
commercial fishing.
    (r) A description of potential environmental impacts of mining 
activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and the affected environment (e.g., maps, land 
use, and layout);
    (2) A description of the nature and degree of potential 
environmental impacts of the proposed mining activities and the domestic 
socioeconomic effects of construction and operation of the associated 
facilities, including waste characteristics and toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternative sites and technologies considered by the lessee and 
the reasons why they were not chosen.
    (s) Any other information needed for technical evaluation of the 
proposed activities and for the evaluation of potential impacts on the 
environment.

[[Page 558]]



Sec.  582.25  Plan modification.

    Approved Delineation, Testing, and Mining Plans may be modified upon 
the Director's approval of the changes proposed. When circumstances 
warrant, the Director may direct the lessee to modify an approved plan 
to adjust to changed conditions. If the lessee requests the change, the 
lessee shall submit a detailed, written statement of the proposed 
modifications, potential impacts, and the justification for the proposed 
changes. Revision of an approved plan whether initiated by the lessee or 
ordered by the Director shall be submitted to the Director for approval. 
When the Director determines that a proposed revision could result in 
significant change in the impacts previously identified and evaluated or 
requires additional permits, the proposed plan revision shall be subject 
to the applicable review and approval procedures of Sec. Sec.  582.21, 
582.22, 582.23, and 582.24 of this part.



Sec.  582.26  Contingency Plan.

    (a) When required by the Director, a lessee shall include a 
Contingency Plan as part of its request for approval of a Delineation, 
Testing, or Mining Plan. The Contingency Plan shall comply with the 
requirements of Sec.  582.28(e) of this part.
    (b) The Director may order or the lessee may request the Director's 
approval of a modification of the Contingency Plan when such a change is 
necessary to reflect any new information concerning the nature, 
magnitude, and significance of potential equipment or procedural 
failures or the effectiveness of the corrective actions described in the 
Contingency Plan.



Sec.  582.27  Conduct of operations.

    (a)-(h) [Reserved]
    (i) Any bulk sampling or testing that is necessary to be conducted 
prior to submission of a Mining Plan shall be in accordance with an 
approved Testing Plan. The sale of any OCS minerals acquired under an 
approved Testing Plan shall be subject to the payment of the royalty 
specified in the lease to the United States.
    (j)-(m) [Reserved]



Sec.  582.28  Environmental protection measures.

    (a) Exploration, testing, development, production, and processing 
activities proposed to be conducted under a lease will only be approved 
by the Director upon the determination that the adverse impacts of the 
proposed activities can be avoided, minimized, or otherwise mitigated. 
The Director shall take into account the information contained in the 
sale-specific environmental evaluation prepared in association with the 
lease offering as well as the site- and operational-specific 
environmental evaluations prepared in association with the review and 
evaluation of the approved Delineation, Testing, or Mining Plan. The 
Director's review of the air quality consequences of proposed OCS 
activities will follow the practices and procedures specified in 30 CFR 
250.194, Sec. Sec.  550.194, 550.218, 550.249, and 550.303.
    (b) If the baseline data available are judged by the Director to be 
inadequate to support an environmental evaluation of a proposed 
Delineation, Testing, or Mining Plan, the Director may require the 
lessee to collect additional environmental baseline data prior to the 
approval of the activities proposed.
    (c)(1) [Reserved]
    (2) Monitoring of environmental effects shall include determination 
of the spatial and temporal environmental changes induced by the 
exploration, testing, development, production, and processing activities 
on the flora and fauna of the sea surface, the water column, and/or the 
seafloor.
    (3)-(4) [Reserved]
    (5) When prototype test mining is proposed, the lessee shall include 
a monitoring strategy for assessing the impacts of the testing 
activities and for developing a strategy for monitoring commercial-scale 
recovery and mitigating the impacts of commercial-scale recovery more 
effectively. At a minimum, the proposed monitoring activities shall 
address specific concerns expressed in the lease-sale environmental 
analysis.
    (6) When required, the monitoring plan shall specify:

[[Page 559]]

    (i) The sampling techniques and procedures to be used to acquire the 
needed data and information;
    (ii) The format to be used in analysis and presentation of the data 
and information;
    (iii) The equipment, techniques, and procedures to be used in 
carrying out the monitoring program; and
    (iv) The name and qualifications of person(s) designated to be 
responsible for carrying out the environmental monitoring.
    (d) [Reserved]
    (e) In the event that equipment or procedural failure might result 
in significant additional damage to the environment, the lessee shall 
submit a Contingency Plan which specifies the procedures to be followed 
to institute corrective actions in response to such a failure and to 
minimize adverse impacts on the environment. Such procedures shall be 
designed for the site and mining activities described in the approved 
Delineation, Testing, or Mining Plan.



Sec.  582.29  Reports and records.

    (a) A report of the amount and value of each OCS mineral produced 
from each lease shall be made by the payor for the lease for each 
calendar month, beginning with the month in which approved testing, 
development, or production activities are initiated and shall be filed 
in duplicate with the Director on or before the 20th day of the 
succeeding month, unless an extension of time for the filing of such 
report is granted by the Director. The report shall disclose accurately 
and in detail all operations conducted during each month and present a 
general summary of the status of leasehold activities. The report shall 
be submitted each month until the lease is terminated or relinquished 
unless the Director authorizes omission of the report during an approved 
suspension of production. The report shall show for each calendar month 
the location of each mining and processing activity; the number of days 
operations were conducted; the identity, quantity, quality, and value of 
each OCS mineral produced, sold, transferred, used or otherwise disposed 
of; identity, quantity, and quality of an inventory maintained prior to 
the point of royalty determination; and other information as may be 
required by the Director.
    (b) The lessee shall submit a status report on exploration and/or 
testing activities under an approved Delineation or Testing Plan to the 
Director within 30 days of the close of each calendar quarter which 
shall include:
    (1) A summary of activities conducted;
    (2) A listing of all geophysical and geochemical data acquired and 
developed such as acoustic or seismic profiling records;
    (3) A map showing location of holes drilled and where bottom samples 
were taken; and
    (4) Identification of samples analyzed.
    (c) Each lessee shall submit to the Director a report of exploration 
and/or testing activities within 3 months after the completion of 
operations. The final report of exploration and/or testing activities 
conducted on the lease shall include:
    (1) A description of work performed;
    (2) Charts, maps, or plats depicting the area and leases in which 
activities were conducted specifically identifying the lines of 
geophysical traverses and/or the locations where geological activity was 
conducted and/or the locations of other exploration and testing 
activities;
    (3) The dates on which the actual operations were performed;
    (4) A narrative summary of any mineral occurrences; environmental 
hazards; and effects of the activities on the environment, aquatic life, 
archaeological resources, or other uses and users of the area in which 
the activities were conducted;
    (5) Such other descriptions of the activities conducted as may be 
specified by the Director; and
    (6) Records of all samples from core drilling or other tests made on 
the lease. The records shall be in such form that the location and 
direction of the samples can be accurately located on a map. The records 
shall include logs of all strata penetrated and conditions encountered, 
such as minerals, water, gas, or unusual conditions, and copies of 
analyses of all samples analyzed.

[[Page 560]]

    (d) The lessee shall report the results of environmental monitoring 
activities required in Sec.  582.28 of this part and shall submit such 
other environmental data as the Director may require to conform with the 
requirements of these regulations.
    (e)(1) All maps shall be appropriately marked with reference to 
official lease boundaries and elevations marked with reference to sea 
level. When required by the Director, vertical projections and cross 
sections shall accompany plan views. The maps shall be kept current and 
submitted to the Director annually, or more often when required by the 
Director. The accuracy of maps furnished shall be certified by a 
professional engineer or land surveyor.
    (2) The lessee shall prepare such maps of the leased lands as are 
necessary to show the geological conditions as determined from G&G 
surveys, bottom sampling, drill holes, trenching, dredging, or mining. 
All excavations shall be shown in such manner that the volume of OCS 
minerals produced during a royalty period can be accurately ascertained.
    (f) Any lessee who acquires rock, mineral, and core samples under a 
lease shall keep a representative split of each geological sample and a 
quarter longitudinal segment of each core for 5 years during which time 
the samples shall be available for inspection at the convenience of the 
Director who may take cuts of such cores, cuttings, and samples.
    (g)(1) The lessee shall keep all original data and information 
available for inspection or duplication, by the Director at the expense 
of the lessor, as long as the lease continues in force. Should the 
lessee choose to dispose of original data and information once the lease 
has expired, said data and information shall be offered to the lessor 
free of costs and shall, if accepted, become the property of the lessor.
    (2) Navigation tapes showing the location(s) where samples were 
taken and test drilling conducted shall be retained for as long as the 
lease continues in force.
    (h) Lessees shall maintain records in which will be kept an accurate 
account of all ore and rock mined; all ore put through a mill; all 
mineral products produced; all ore and mineral products sold, 
transferred, used, or otherwise disposed of and to whom sold or 
transferred, and the inventory weight, assay value, moisture content, 
base sales price, dates, penalties, and price received. The percentage 
of each of the mineral products recovered and the percentages lost shall 
be shown. The records associated with activities on a lease shall be 
available to the Director for auditing.
    (i) When special forms or reports other than those referred to in 
the regulations in this part may be necessary, instructions for the 
filing of such forms or reports will be given by the Director.



Sec.  582.30  Right of use and easement.

    (a) A right of use and easement that includes any area subject to a 
lease issued or maintained under the Act shall be granted only after the 
lessee has been notified by the requestor and afforded the opportunity 
to comment on the request. A holder of a right under a right of use and 
easement shall exercise that right in accordance with the requirements 
of the regulations in this part. A right of use and easement shall be 
exercised only in a manner which does not interfere unreasonably with 
operations of any lessee on its lease.
    (b) Once a right of use and easement has been exercised, the right 
shall continue, beyond the termination of any lease on which it may be 
situated, as long as it is demonstrated to the Director that the right 
of use and easement is being exercised by the holder of the right and 
that the right of use and easement continues to serve the purpose 
specified in the grant. If the right of use and easement extends beyond 
the termination of any lease on which the right may be situated or if it 
is situated on an unleased portion of the OCS, the rights of all 
subsequent lessees shall be subject to such right. Upon termination of a 
right of use and easement, the holder of the right shall abandon the 
premises in the same manner that a lessee abandons activities on a lease 
to the satisfaction of the Director.

[[Page 561]]



Sec.  582.31  [Reserved]



                           Subpart D_Payments



Sec.  582.40  Bonds.

    (a) Pursuant to the requirements for a bond in Sec.  581.33 of this 
title, prior to the commencement of any activity on a lease, the lessee 
shall submit a surety or personal bond to cover the lessee's royalty and 
other obligations under the lease as specified in this section.
    (b) All bonds furnished by a lessee or operator must be in a form 
approved by the Deputy Director. A single copy of the required form is 
to be executed by the principal or, in the case of surety bonds, by both 
the principal and an acceptable surety.
    (c) Only those surety bonds issued by qualified surety companies 
approved by the Department of the Treasury shall be accepted (see 
Department of Treasury Circular No. 570 and any supplemental or 
replacement circulars).
    (d) Personal bonds shall be accompanied by a cashier's check, 
certified check, or negotiable U.S. Treasury bonds of an equal value to 
the amount specified in the bond. Negotiable Treasury bonds shall be 
accompanied by a proper conveyance of full authority to the Director to 
sell such securities in case of default in the performance of the terms 
and conditions of the lease.
    (e) A bond in the minimum amount of $50,000 to cover the lessee's 
obligations under the lease shall be submitted prior to the commencement 
of any activity on a leasehold. A $50,000 bond shall not be required on 
a lease if the lessee already maintains or furnishes a $300,000 bond 
conditioned on compliance with the terms of leases for OCS minerals 
other than oil, gas, and sulphur held by the lessee on the OCS for the 
area in which the lease is located. A bond submitted pursuant to Sec.  
556.58(a) of this chapter may be amended to include the aforementioned 
condition for compliance. Prior to approval of a Delineation, Testing, 
or Mining Plan, the bond amount shall be adjusted, if appropriate, to 
cover the operations and activities described in the proposed plan.
    (f) For the purposes of this section there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Ocean;
    (2) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the coast of Alaska.
    (g) A separate bond shall be required for each area. An operator's 
bond may be submitted for a specific lease(s) in the same amount as the 
lessee's bond(s) applicable to the lease(s) involved.
    (h) Where, upon a default, the surety makes a payment to the United 
States of an obligation incurred under a lease, the face amount of the 
surety bond and the surety's liability thereunder shall be reduced by 
the amount of such payment.
    (i) After default, the principal shall, within 6 months after notice 
or within such shorter period as may be fixed by the Director, either 
post a new bond or increase the existing bond to the amount previously 
held. In lieu thereof, the principal may, within that time, file 
separate or substitute bonds for each lease. Failure to meet these 
requirements may result in a suspension of operations including 
production on leases covered by such bonds.
    (j) The Director shall not consent to termination of the period of 
liability of any bond unless an acceptable alternative bond has been 
filed or until all the terms and conditions of the lease covered by the 
bond have been met.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



Sec.  582.41  Method of royalty calculation.

    In the event that the provisions of royalty management regulations 
in part 1206 of chapter XII do not apply to the specific commodities 
produced under regulations in this part, the lessee shall comply with 
procedures specified in the leasing notice.



Sec.  582.42  Payments.

    Rentals, royalties, and other payments due the Federal Government on 
leases for OCS minerals shall be paid and reports submitted by the payor 
for a lease in accordance with Sec.  581.26.

[[Page 562]]



                            Subpart E_Appeals



Sec.  582.50  Appeals.

    See 30 CFR part 590 for instructions on how to appeal any order or 
decision that we issue under this part.



PART 583_NEGOTIATED NONCOMPETITIVE AGREEMENTS FOR THE USE OF OUTER
 CONTINENTAL SHELF SAND, GRAVEL, AND/OR SHELL RESOURCES-
-Table of Contents



                            Subpart A_General

Sec.
583.100 What is BOEM's authority for information collection (IC)?
583.105 What is the purpose of this part and to whom does it apply?
583.110 What is BOEM's authority for this part?
583.115 What definitions do I need to know?
583.120 Who is qualified for a project?
583.125 What are my rights to seek reconsideration of an unfavorable 
          decision by BOEM?
583.130 What are the minimum contents of an agreement to use OCS sand, 
          gravel, and/or shell resources?

Subpart B--[Reserved]

 Subpart C_Outer Continental Shelf Sand, Gravel, and/or Shell Resources 
                          Negotiated Agreements

Sec.
583.300 How do I submit a request for an agreement?
583.305 How will BOEM determine if a project qualifies?
583.310 What process does BOEM use to technically and environmentally 
          evaluate a qualified project?
583.315 What is the process for negotiating and executing an agreement?
583.320 What kinds of information must be included in an agreement?
583.325 What is the effective date of an agreement?
583.330 How will BOEM enforce the agreement?
583.335 What is the term of the agreement?
583.340 What debarment or suspension obligations apply to transactions 
          and contracts related to a project?
583.345 What is the process for extending or modifying an agreement?
583.350 When can an agreement be terminated?

    Authority: 43 U.S.C. 1334.

    Source: 82 FR 45973, Oct. 3, 2017, unless otherwise noted.



                            Subpart A_General



Sec.  583.100  What is BOEM's authority for information collection (IC)?

    The IC requirements contained in part 583 have been approved by OMB 
under 44 U.S.C. 3501 and assigned control number 1010-0191. The 
information is being collected to determine if the applicant for a 
negotiated noncompetitive agreement (agreement) for the use of sand, 
gravel, and/or shell resources on the Outer Continental Shelf (OCS) is 
qualified to enter into such an agreement and to determine if the 
requested action is warranted. Applicants and parties to an agreement 
are required to respond to requests related to IC activities.



Sec.  583.105  What is the purpose of this part and to whom does it apply?

    The regulations in this part provide procedures for entering into 
negotiated noncompetitive agreements for the use of OCS sand, gravel, 
and/or shell resources. The rules of this part apply exclusively to 
negotiated noncompetitive use of OCS sand, gravel, and/or shell 
resources and do not apply to competitive leasing of minerals, including 
oil, gas, sulphur, geopressured-geothermal and associated resources, and 
all other minerals that are authorized by an Act of Congress to be 
produced from ``public lands'' as defined in section 103 of the Federal 
Land Policy and Management Act of 1976, as amended (43 U.S.C. 1701 et 
seq.).



Sec.  583.110  What is BOEM's authority for this part?

    (a) Pursuant to authority granted by section 8(k) of the Outer 
Continental Shelf Lands Act (OSCLA), as amended (43 U.S.C. 1337(k)), the 
Secretary has authority to negotiate a noncompetitive agreement for the 
use of OCS sand, gravel, and/or shell resources:
    (1) In a program of, or project for, shore protection, beach 
restoration, or coastal wetlands restoration undertaken by a Federal, 
State, or local government agency; or
    (2) In a construction project, other than a project described in 
paragraph

[[Page 563]]

(a)(1) of this section, that is funded in whole or in part by or 
authorized by the Federal Government.
    (b) The Secretary has delegated authority to BOEM to administer the 
negotiated noncompetitive agreement provisions of OCSLA and prescribe 
the rules and regulations necessary to carry out those provisions.



Sec.  583.115  What definitions do I need to know?

    The definitions at 30 CFR 550.105 apply to this part. In addition, 
when used in this part, the following terms will have the meaning given 
below:
    Agreement means a negotiated noncompetitive agreement that 
authorizes a person to use OCS sand, gravel, and/or shell resources in a 
program of, or project for, shore protection, beach restoration or 
coastal wetlands restoration undertaken by one or more Federal, state or 
local government agencies, or in a construction project authorized by, 
or funded in whole or in part by, the Federal government. The form of 
the agreement will be a Memorandum of Agreement (if one or more of the 
parties to the agreement, other than BOEM, is a Federal agency) or a 
lease (if all of the parties to the agreement other than BOEM are non-
Federal agencies or persons).
    Amendment means a modification to the agreement between BOEM and the 
parties to the agreement that extends or modifies the terms of the 
agreement.
    Applicant means any person proposing to use OCS sand, gravel, and/or 
shell resources for a shore protection, beach restoration or coastal 
wetlands restoration project undertaken by a Federal, state or local 
government agency, or a construction project authorized by, or funded in 
whole or in part by, the Federal Government. If multiple persons or 
Federal, state, or local governments, other than BOEM, partner on a 
project they will be considered joint applicants.
    BOEM means the Bureau of Ocean Energy Management of the U.S. 
Department of the Interior (DOI).
    Borrow area means the offshore geographic area(s) or region(s) where 
OCS sand, gravel, and/or shell resources have been identified for 
potential use in a specific project.
    Federal agency means any department, agency, or instrumentality of 
the United States.
    Local government means the governing authority at the county or city 
level with jurisdiction to administer a particular project(s).
    Modification means the process whereby parties to an agreement and 
BOEM mutually agree to change, alter or amend an existing agreement.
    Placement area means the geographic area in which OCS sand, gravel, 
and/or shell resources, used by agreement, will be placed pursuant to 
that agreement.
    Program means a group of related projects that may be the subject of 
a negotiated noncompetitive agreement for the use of OCS sand, gravel, 
and/or shell resources.
    Project means an undertaking that may be the subject of a negotiated 
noncompetitive agreement for the use of OCS sand, gravel, and/or shell 
resources.
    Secretary means the Secretary of the Interior.



Sec.  583.120  Who is qualified for a project?

    (a) BOEM may enter into an agreement with any person proposing to 
use OCS sand, gravel, and/or shell resources for a program of, or 
project for, shore protection, beach restoration, or coastal wetlands 
restoration undertaken by a Federal, state, or local government agency 
or in a construction project that is funded in whole or in part by or 
authorized by the Federal Government.
    (b) To request an agreement under this part, the applicant must be:
    (1) A Federal, state, or local government agency;
    (2) A citizen or national of the United States;
    (3) An alien lawfully admitted for permanent residence in the United 
States, as defined in the Immigration and Nationality Act, as amended (8 
U.S.C. 1101(a)(20));
    (4) A private or public corporation organized under the laws of the 
United States, or of any State or territory thereof; or

[[Page 564]]

    (5) An association of such citizens, nationals, resident aliens, or 
private or public corporations.
    (c) When entering into an agreement under this part, all applicants 
are subject to the requirements of 2 CFR part 180 and 2 CFR part 1400.



Sec.  583.125  What are my rights to seek reconsideration of an
 unfavorable decision by BOEM?

    (a) After being notified of disqualification or disapproval of an 
agreement or modification, an unsuccessful applicant, or adversely 
affected party to an agreement, may apply for reconsideration by the 
Director.
    (1) All applications for reconsideration must be submitted to the 
Director within 15 days of being notified of disqualification or 
disapproval of an agreement or modification, and must be accompanied by 
a statement of reasons for the requested reconsideration, with one copy 
also submitted to the program office whose decision is the subject of 
the request for reconsideration.
    (2) The Director will respond in writing within 30 days.
    (b) No appeal rights are available under 30 CFR part 590 and 43 CFR 
part 4, subpart E.



Sec.  583.130  What are the minimum contents of an agreement to use
 OCS sand, gravel, and/or shell resources?

    Any use of OCS sand, gravel, and/or shell resources in an agreement 
will be negotiated on a case-by-case basis. The agreement will specify, 
at a minimum, who may use the OCS sand, gravel, and/or shell resources; 
the nature of the rights granted, including any terms and conditions and 
environmental stipulations; and the location, type, and volume of OCS 
sand, gravel, and/or shell resources. An authorization to use OCS sand, 
gravel, and/or shell resources identified in an agreement is not 
exclusive; BOEM may allow other entities to use OCS sand, gravel, and/or 
shell resources from the same borrow area if these uses are determined 
by BOEM to be non-conflicting and do not exceed the availability of the 
OCS resource.

Subpart B--[Reserved]



 Subpart C_Outer Continental Shelf Sand, Gravel, and/or Shell Resources 
                          Negotiated Agreements



Sec.  583.300  How do I submit a request for an agreement?

    Any person may submit a written request to BOEM to obtain an 
agreement for the use of OCS sand, gravel, and/or shell resources for 
use in a program of, or project for, shore protection, beach 
restoration, or coastal wetlands restoration undertaken by a Federal, 
state, or local government agency, or in a construction project that is 
funded in whole or in part by or authorized by the Federal Government.
    (a) The written request must include:
    (1) A detailed description of the proposed project for which the OCS 
sand, gravel, and/or shell resources will be used and how it qualifies 
as a program or project eligible under OCSLA to use OCS sand, gravel, or 
shell resources;
    (2) A description of the proposed borrow area(s) and placement 
area(s), along with maps with geographic coordinates depicting the 
location of the desired borrow area(s), the OCS block number(s), OCS 
Planning Area(s), OCS Protraction Diagram Designation(s), and the 
placement area(s). These should include:
    (i) A detailed set of digital (e.g., portable document format or 
pdf) maps with coordinates and navigation features of the desired OCS 
project area (including borrow area and other project features); and
    (ii) Digital geo-referenced spatial and tabular data depicting the 
borrow area with features, such as geological sampling locations and any 
hard or live-bottom benthic habitat present;
    (3) Any available geological and geophysical data used to select, 
design, and delineate the borrow area(s) and potential borrow areas 
considered but not selected for final design in digital format, geo-
referenced where relevant. These may include:
    (i) Sediment sampling (sediment cores and grab samples) data such as 
physical description sheets, photographs, core locations, and grain size 
analysis; and
    (ii) Geophysical data such as subbottom profiler, marine 
magnetometer,

[[Page 565]]

and side-scan sonar data, and bathymetry including geo-referenced 
navigation survey tracklines, shotpoints, and/or timestamps;
    (4) Any other uses of the OCS or infrastructure in the borrow area 
that are known to the applicant at the time of application submittal;
    (5) A description of the environmental evaluations and corresponding 
documents that have been completed or are being prepared that cover all 
offshore and onshore components of the project, as applicable;
    (6) A target date or date range when the OCS sand, gravel, and/or 
shell resources will be needed;
    (7) A description of the person or government entities undertaking 
the project;
    (8) A list of any permits, licenses or authorizations required for 
the project and their current status;
    (9) A description of any potential inconsistencies with state 
coastal zone management plans and/or any other applicable state and 
local statutes, regulations or ordinances;
    (10) The name, title, telephone number, mailing address and email 
address of any points of contact for any Federal agencies, state, or 
local governments, and contractor(s) with whom the applicant has 
contracted or intends to contract;
    (11) A statement explaining who authorized the project and how the 
project is to be funded, indicating whether the project is federally 
funded, in whole or in part, and whether the project is authorized by 
the Federal Government; and
    (12) For any other Federal, state, or local government agency 
identified in the application, the name, title, mailing address, 
telephone number, and email address of both a primary and a secondary 
point of contact for the agency.
    (b) [Reserved]



Sec.  583.305  How will BOEM determine if a project qualifies?

    BOEM will make a determination as to whether the project, as 
described in Sec.  583.300, qualifies for a negotiated noncompetitive 
agreement for the use of OCS sand, gravel, and/or shell resources. 
Within 15 business days of receipt of the application, BOEM will 
determine if the application is complete or will request additional 
information. After it has determined the application is complete, BOEM 
will review the application and notify the applicant in writing whether 
the project qualifies for an agreement. In determining whether a project 
qualifies for an agreement, BOEM will consider, among other criteria, 
the following:
    (a) The project purpose;
    (b) Other uses of OCS sand, gravel, and/or shell resources from the 
same borrow area that are currently or were previously authorized by 
BOEM for other projects or programs, including the location, type and 
volume of such resources;
    (c) The project funding source(s) and amounts;
    (d) The proposed design and feasibility of the project;
    (e) Any potential environmental and safety risks associated with the 
project;
    (f) Other federal interests located near or within the specified 
borrow area;
    (g) Comments received from potentially affected state or local 
governments, if any;
    (h) The applicant's background and experience working on similar 
projects or activities;
    (i) Whether the project operations can be conducted in a manner that 
protects the environment and promotes orderly development of OCS mineral 
resources;
    (j) Whether activities can be conducted in a manner that does not 
pose a threat of serious harm or damage to, or waste of, any natural 
resource, any life (including fish and other aquatic life), property, or 
the marine, coastal, or human environment; and
    (k) Whether the project is consistent with the requirements of 
applicable statutes and their implementing regulations, which may 
include, but are not limited to, the Endangered Species Act (ESA) (16 
U.S.C. 1531 et seq.), the Marine Mammal Protection Act (MMPA) (16 U.S.C. 
1361 et seq.), the Marine Debris Research, Prevention, and Reduction Act 
(MDRPRA) (33 U.S.C. 1951 et seq.), the Marine Plastic Pollution Research 
and Control Act (MPPRCA) (33

[[Page 566]]

U.S.C. 1901 et seq.), the Federal Water Pollution Control Act (FWPCA) 
(33 U.S.C. 1381 et seq.), and the International Convention for the 
Prevention of Pollution from Ships (MARPOL), MARPOL-Annex V Treaty.



Sec.  583.310  What process does BOEM use to technically and 
environmentally evaluate a qualified project?

    (a) Once BOEM has determined a project qualifies for an agreement, 
BOEM will begin the project evaluation process to decide whether to 
enter into a negotiated noncompetitive agreement.
    (b) BOEM will coordinate with relevant Federal agencies, State, and 
local governments and any potentially affected federally recognized 
Indian tribes or Alaska Native Corporations in the project evaluation.
    (c) BOEM will evaluate the project and additional information 
provided pursuant to Sec. Sec.  583.300 and 583.305, to determine if the 
information is sufficient to conduct necessary technical and 
environmental reviews to comply with the requirements of applicable 
statutes and regulations, which may include, but are not limited to: 
OCSLA (43 U.S.C. 1331 et seq.), the National Environmental Policy Act 
(NEPA) (42 U.S.C. 4321 et seq.), the ESA (16 U.S.C. 1531 et seq.), the 
MMPA (16 U.S.C. 1361 et seq.), the Magnuson-Stevens Fishery Conservation 
and Management Act (MSFCMA) (16 U.S.C. 1801 et seq.), the National 
Historic Preservation Act (NHPA) (54 U.S.C. 300101 et seq.), and the 
Coastal Zone Management Act (CZMA) (16 U.S.C. 1451 et seq.).
    (d) BOEM will not enter into a negotiated noncompetitive agreement 
with the applicant until the information requested for the evaluation 
has been provided and BOEM has evaluated it.



Sec.  583.315  What is the process for negotiating and executing
 an agreement?

    (a) Upon completion of the technical, environmental and other 
evaluations established in Sec. Sec.  583.305 and 583.310, BOEM will 
decide whether to enter into a negotiated noncompetitive agreement with 
the applicant for use of OCS sand, gravel, or shell resources for its 
proposed project.
    (b) If BOEM decides not to enter into such an agreement, BOEM will 
inform the applicant of its reasons for not doing so. An applicant may 
ask the BOEM Director for reconsideration of this decision, in 
accordance with Sec.  583.125(a).
    (c) If BOEM has decided to enter into a negotiated noncompetitive 
agreement with the applicant, BOEM will negotiate the terms and 
conditions of the agreement with the applicant and prepare a draft 
agreement for the applicant's review.
    (d) After considering comments and suggestions from the applicant, 
BOEM, at its discretion, may finalize the agreement and distribute it to 
the applicant for signature.
    (e) Upon receipt of the agreement with the applicant's signature, 
BOEM will execute the agreement. A copy of the executed agreement will 
be mailed to the parties.



Sec.  583.320  What kinds of information must be included in an
 agreement?

    Every agreement is negotiated on a case-by-case basis, but at a 
minimum, must include:
    (a) An agreement number, as assigned by BOEM;
    (b) The purpose of, and authorities for, the agreement;
    (c) Designated and delineated borrow area(s);
    (d) A project description, including the timeframe within which the 
project is to be started and completed;
    (e) The terms and conditions of the agreement, including any 
reporting requirements, environmental mitigations, and operating 
parameters;
    (f) All obligations of the parties; and
    (g) The signatures of appropriate individuals authorized to bind the 
applicant and BOEM.



Sec.  583.325  What is the effective date of an agreement?

    The agreement will become effective on the date when all parties to 
the agreement have signed it.



Sec.  583.330  How will BOEM enforce the agreement?

    (a) Failure to comply with any applicable law or any provision, 
term, or condition of the agreement may result

[[Page 567]]

in the termination of the agreement, a referral to an appropriate 
Federal or State agency for enforcement, or both. Termination of the 
agreement for noncompliance will be in the sole discretion of the 
Director.
    (b) The failure to comply in a timely and satisfactory manner with 
any provision, term or condition of the agreement may delay or prevent 
BOEM's approval of future requests for use of OCS sand, gravel, and/or 
shell resources on the part of the parties to the agreement.



Sec.  583.335  What is the term of the agreement?

    (a) An agreement will terminate upon one of the following, whichever 
occurs first:
    (1) The agreement expires by its own terms, unless the term is 
extended prior to expiration under Sec.  583.345;
    (2) The project is terminated, as set forth in Sec.  583.350; or
    (3) A party to the agreement notifies BOEM, in writing, that 
sufficient OCS sand, gravel, and/or shell resources, up to the amount 
authorized in the agreement, have been obtained to complete the project.
    (b) Absent extraordinary circumstances, no agreement will be for a 
term longer than five years from its effective date.



Sec.  583.340  What debarment or suspension obligations apply to
 transactions and contracts related to a project?

    The parties to an agreement must ensure that all contracts and 
transactions related to an agreement issued under this part comply with 
the suspension and debarment regulations in 2 CFR part 180 and 2 CFR 
part 1400.



Sec.  583.345  What is the process for extending or modifying an
 agreement?

    (a) Unless otherwise provided for in the agreement, the parties to 
the agreement may submit to BOEM a written request to extend or modify 
an agreement. BOEM is under no obligation to extend or modify an 
agreement and cannot be held liable for the consequences of the 
expiration of an agreement. With the exception of paragraph (b) of this 
section, any such requests must be made at least 180 days before the 
term of the agreement expires. BOEM will respond to the request for 
modification within 30 days of receipt and request any necessary 
information and evaluations to comply with Sec.  583.305. BOEM may 
approve the request, disapprove it, or approve it with modifications 
subject to the requirements of Sec.  583.305.
    (1) If BOEM approves a request to extend or modify an agreement, 
BOEM will draft an agreement modification for review by the parties to 
the agreement in the form of an amendment to the original agreement. The 
amendment will include:
    (i) The agreement number, as assigned by BOEM;
    (ii) The modification(s) agreed to;
    (iii) Any additional mitigation required; and
    (iv) The signatures of the parties to the agreement and BOEM.
    (2) If BOEM disapproves a request to extend or modify an agreement, 
BOEM will inform the parties to the agreement of the reasons in writing. 
Parties to the agreement may ask the BOEM Director for reconsideration 
in accordance with Sec.  583.125.
    (b) By written request, for strictly minor modifications that do not 
change the substance of the project or the analyzed environmental 
effects of the project, including but not limited to, the change of a 
business address, the substitution of a different Federal, State or 
local government agency contact, or an extension of less than 30 days, 
parties to the agreement may memorialize the minor modification in a 
letter from BOEM to the parties indicating the request has been granted.



Sec.  583.350  When can an agreement be terminated?

    (a) The Director will terminate any agreement issued under this part 
upon proof that it was obtained by fraud or misrepresentation, after 
notice and an opportunity to be heard has been afforded to the parties 
of the agreement.
    (b) The Director may immediately suspend and subsequently terminate 
any agreement issued under this part when:
    (1) There is noncompliance with the agreement, pursuant to Sec.  
583.330 (a); or

[[Page 568]]

    (2) It is necessary for reasons of national security or defense; or
    (3) The Director determines that:
    (i) Continued activity under the agreement would cause serious harm 
or damage to natural resources; life (including human and wildlife); 
property; the marine, coastal, or human environment; or sites, 
structures, or objects of historical or archaeological significance;
    (ii) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (iii) The advantages of termination outweigh the advantages of 
continuing the agreement.
    (c) The Director will immediately notify the parties to the 
agreement of the suspension or termination. The Director will also mail 
a letter to the parties to the agreement at their record post office 
address with notice of any suspension or termination and the cause for 
such action.
    (d) In the event that BOEM terminates an agreement under this 
section, none of the parties to the agreement will be entitled to 
compensation as a result of expenses or lost revenues that may result 
from the termination.



PART 585_RENEWABLE ENERGY AND ALTERNATE USES OF EXISTING FACILITIES
 ON THE OUTER CONTINENTAL SHELF--Table of Contents



                      Subpart A_General Provisions

Sec.
585.100 Authority.
585.101 What is the purpose of this part?
585.102 What are BOEM's responsibilities under this part?
585.103 When may BOEM prescribe or approve departures from these 
          regulations?
585.104 Do I need a BOEM lease or other authorization to produce or 
          support the production of electricity or other energy product 
          from a renewable energy resource on the OCS?
585.105 What are my responsibilities under this part?
585.106 Who can hold a lease or grant under this part?
585.107 How do I show that I am qualified to be a lessee or grant 
          holder?
585.108 When must I notify BOEM if an action has been filed alleging 
          that I am insolvent or bankrupt?
585.109 When must I notify BOEM of mergers, name changes, or changes of 
          business form?
585.110 How do I submit plans, applications, reports, or notices 
          required by this part?
585.111 When and how does BOEM charge me processing fees on a case-by-
          case basis?
585.112 Definitions.
585.113 How will data and information obtained by BOEM under this part 
          be disclosed to the public?
585.114 Paperwork Reduction Act statements--information collection.
585.115 Documents incorporated by reference.
585.116 Requests for information on the state of the offshore renewable 
          energy industry.
585.117 [Reserved]
585.118 What are my appeal rights?

            Subpart B_Issuance of OCS Renewable Energy Leases

                        General Lease Information

585.200 What rights are granted with a lease issued under this part?
585.201 How will BOEM issue leases?
585.202 What types of leases will BOEM issue?
585.203 With whom will BOEM consult before issuance of a lease?
585.204 What areas are available for leasing consideration?
585.205 How will leases be mapped?
585.206 What is the lease size?
585.207-585.209 [Reserved]

                        Competitive Lease Process

585.210 How does BOEM initiate the competitive leasing process?
585.211 What is the process for competitive issuance of leases?
585.212 What is the process BOEM will follow if there is reason to 
          believe that competitors have withdrawn before the Final Sale 
          Notice is issued?
585.213 What must I submit in response to a Request for Interest or a 
          Call for Information and Nominations?
585.214 What will BOEM do with information from the Requests for 
          Information or Calls for Information and Nominations?
585.215 What areas will BOEM offer in a lease sale?
585.216 What information will BOEM publish in the Proposed Sale Notice 
          and Final Sale Notice?
585.217-585.219 [Reserved]

                     Competitive Lease Award Process

585.220 What auction format may BOEM use in a lease sale?

[[Page 569]]

585.221 What bidding systems may BOEM use for commercial leases and 
          limited leases?
585.222 What does BOEM do with my bid?
585.223 What does BOEM do if there is a tie for the highest bid?
585.224 What happens if BOEM accepts my bid?
585.225 What happens if my bid is rejected, and what are my appeal 
          rights?
585.226-585.229 [Reserved]

                   Noncompetitive Lease Award Process

585.230 May I request a lease if there is no Call?
585.231 How will BOEM process my unsolicited request for a 
          noncompetitive lease?
585.232 May I acquire a lease noncompetitively after responding to a 
          Request for Interest or Call for Information and Nominations?
585.233-585.234 [Reserved]

                   Commercial and Limited Lease Terms

585.235 If I have a commercial lease, how long will my lease remain in 
          effect?
585.236 If I have a limited lease, how long will my lease remain in 
          effect?
585.237 What is the effective date of a lease?
585.238 Are there any other renewable energy research activities that 
          will be allowed on the OCS?

Subpart C_Rights-of-Way Grants and Rights-of-Use and Easement Grants for 
                       Renewable Energy Activities

                        ROW Grants and RUE Grants

585.300 What types of activities are authorized by ROW grants and RUE 
          grants issued under this part?
585.301 What do ROW grants and RUE grants include?
585.302 What are the general requirements for ROW grant and RUE grant 
          holders?
585.303 How long will my ROW grant or RUE grant remain in effect?
585.304 [Reserved]

                   Obtaining ROW Grants and RUE Grants

585.305 How do I request an ROW grant or RUE grant?
585.306 What action will BOEM take on my request?
585.307 How will BOEM determine whether competitive interest exists for 
          ROW grants and RUE grants?
585.308 How will BOEM conduct an auction for ROW grants and RUE grants?
585.309 When will BOEM issue a noncompetitive ROW grant or RUE grant?
585.310 What is the effective date of an ROW grant or RUE grant?
585.311-585.314 [Reserved]

          Financial Requirements for ROW Grants and RUE Grants

585.315 What deposits are required for a competitive ROW grant or RUE 
          grant?
585.316 What payments are required for ROW grants or RUE grants?

                Subpart D_Lease and Grant Administration

                   Noncompliance and Cessation Orders

585.400 What happens if I fail to comply with this part?
585.401 When may BOEM issue a cessation order?
585.402 What is the effect of a cessation order?
585.403-585.404 [Reserved]

                         Designation of Operator

585.405 How do I designate an operator?
585.406 Who is responsible for fulfilling lease and grant obligations?
585.407 [Reserved]

                        Lease or Grant Assignment

585.408 May I assign my lease or grant interest?
585.409 How do I request approval of a lease or grant assignment?
585.410 How does an assignment affect the assignor's liability?
585.411 How does an assignment affect the assignee's liability?
585.412-585.414 [Reserved]

                        Lease or Grant Suspension

585.415 What is a lease or grant suspension?
585.416 How do I request a lease or grant suspension?
585.417 When may BOEM order a suspension?
585.418 How will BOEM issue a suspension?
585.419 What are my immediate responsibilities if I receive a suspension 
          order?
585.420 What effect does a suspension order have on my payments?
585.421 How long will a suspension be in effect?
585.422-585.424 [Reserved]

                         Lease or Grant Renewal

585.425 May I obtain a renewal of my lease or grant before it 
          terminates?
585.426 When must I submit my request for renewal?
585.427 How long is a renewal?
585.428 What effect does applying for a renewal have on my activities 
          and payments?
585.429 What criteria will BOEM consider in deciding whether to renew a 
          lease or grant?
585.430-585.431 [Reserved]

[[Page 570]]

                       Lease or Grant Termination

585.432 When does my lease or grant terminate?
585.433 What must I do after my lease or grant terminates?
585.434 [Reserved]

                      Lease or Grant Relinquishment

585.435 How can I relinquish a lease or a grant or parts of a lease or 
          grant?

                       Lease or Grant Contraction

585.436 Can BOEM require lease or grant contraction?

                       Lease or Grant Cancellation

585.437 When can my lease or grant be canceled?

         Subpart E_Payments and Financial Assurance Requirements

                                Payments

585.500 How do I make payments under this part?
585.501 What deposits must I submit for a competitively issued lease, 
          ROW grant, or RUE grant?
585.502 What initial payment requirements must I meet to obtain a 
          noncompetitive lease, ROW grant, or RUE grant?
585.503 What are the rent and operating fee requirements for a 
          commercial lease?
585.504 How are my payments affected if I develop my lease in phases?
585.505 What are the rent and operating fee requirements for a limited 
          lease?
585.506 What operating fees must I pay on a commercial lease?
585.507 What rent payments must I pay on a project easement?
585.508 What rent payments must I pay on ROW grants or RUE grants 
          associated with renewable energy projects?
585.509 Who is responsible for submitting lease or grant payments to 
          BOEM?
585.510 May BOEM reduce or waive my lease or grant payments?
585.511-585.514 [Reserved]

         Financial Assurance Requirements for Commercial Leases

585.515 What financial assurance must I provide when I obtain my 
          commercial lease?
585.516 What are the financial assurance requirements for each stage of 
          my commercial lease?
585.517 How will BOEM determine the amounts of the supplemental and 
          decommissioning financial assurance requirements associated 
          with commercial leases?
585.518-585.519 [Reserved]

   Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

585.520 What financial assurance must I provide when I obtain my limited 
          lease, ROW grant, or RUE grant?
585.521 Do my financial assurance requirements change as activities 
          progress on my limited lease or grant?
585.522-585.524 [Reserved]

            Requirements for Financial Assurance Instruments

585.525 What general requirements must a financial assurance instrument 
          meet?
585.526 What instruments other than a surety bond may I use to meet the 
          financial assurance requirement?
585.527 May I demonstrate financial strength and reliability to meet the 
          financial assurance requirement for lease or grant activities?
585.528 May I use a third-party guaranty to meet the financial assurance 
          requirement for lease or grant activities?
585.529 Can I use a lease- or grant-specific decommissioning account to 
          meet the financial assurance requirements related to 
          decommissioning?

                     Changes in Financial Assurance

585.530 What must I do if my financial assurance lapses?
585.531 What happens if the value of my financial assurance is reduced?
585.532 What happens if my surety wants to terminate the period of 
          liability of my bond?
585.533 How does my surety obtain cancellation of my bond?
585.534 When may BOEM cancel my bond?
585.535 Why might BOEM call for forfeiture of my bond?
585.536 How will I be notified of a call for forfeiture?
585.537 How will BOEM proceed once my bond or other security is 
          forfeited?
585.538-585.539 [Reserved]

                       Revenue Sharing with States

585.540 How will BOEM equitably distribute revenues to States?
585.541 What is a qualified project for revenue sharing purposes?
585.542 What makes a State eligible for payment of revenues?
585.543 Example of how the inverse distance formula works.

              Subpart F_Plans and Information Requirements

585.600 What plans and information must I submit to BOEM before I 
          conduct activities on my lease or grant?
585.601 When am I required to submit my plans to BOEM?

[[Page 571]]

585.602 What records must I maintain?
585.603-585.604 [Reserved]

 Site Assessment Plan and Information Requirements for Commercial Leases

585.605 What is a Site Assessment Plan (SAP)?
585.606 What must I demonstrate in my SAP?
585.607 How do I submit my SAP?
585.608-585.609 [Reserved]

                  Contents of the Site Assessment Plan

585.610 What must I include in my SAP?
585.611 What information and certifications must I submit with my SAP to 
          assist BOEM in complying with NEPA and other relevant laws?
585.612 How will my SAP be processed for Federal consistency under the 
          Coastal Zone Management Act?
585.613 How will BOEM process my SAP?

                    Activities Under an Approved SAP

585.614 When may I begin conducting activities under my approved SAP?
585.615 What other reports or notices must I submit to BOEM under my 
          approved SAP?
585.616 [Reserved]
585.617 What activities require a revision to my SAP, and when will BOEM 
          approve the revision?
585.618 What must I do upon completion of approved site assessment 
          activities?
585.619 [Reserved]

         Construction and Operations Plan for Commercial Leases

585.620 What is a Construction and Operations Plan (COP)?
585.621 What must I demonstrate in my COP?
585.622 How do I submit my COP?
585.623-585.625 [Reserved]

            Contents of the Construction and Operations Plan

585.626 What must I include in my COP?
585.627 What information and certifications must I submit with my COP to 
          assist the BOEM in complying with NEPA and other relevant 
          laws?
585.628 How will BOEM process my COP?
585.629 May I develop my lease in phases?
585.630 [Reserved]

                    Activities Under an Approved COP

585.631 When must I initiate activities under an approved COP?
585.632 What documents must I submit before I may construct and install 
          facilities under my approved COP?
585.633 How do I comply with my COP?
585.634 What activities require a revision to my COP, and when will BOEM 
          approve the revision?
585.635 What must I do if I cease activities approved in my COP before 
          the end of my commercial lease?
585.636 What notices must I provide BOEM following approval of my COP?
585.637 When may I commence commercial operations on my commercial 
          lease?
585.638 What must I do upon completion of my commercial operations as 
          approved in my COP or FERC license?
585.639 [Reserved]

General Activities Plan Requirements for Limited Leases, ROW Grants, and 
                               RUE Grants

585.640 What is a General Activities Plan (GAP)?
585.641 What must I demonstrate in my GAP?
585.642 How do I submit my GAP?
585.643-585.644 [Reserved]

                 Contents of the General Activities Plan

585.645 What must I include in my GAP?
585.646 What information and certifications must I submit with my GAP to 
          assist BOEM in complying with NEPA and other relevant laws?
585.647 How will my GAP be processed for Federal consistency under the 
          Coastal Zone Management Act?
585.648 How will BOEM process my GAP?
585.649 [Reserved]

                    Activities Under an Approved GAP

585.650 When may I begin conducting activities under my GAP?
585.651 When may I construct complex or significant OCS facilities on my 
          limited lease or any facilities on my project easement 
          proposed under my GAP?
585.652 How long do I have to conduct activities under an approved GAP?
585.653 What other reports or notices must I submit to BOEM under my 
          approved GAP?
585.654 [Reserved]
585.655 What activities require a revision to my GAP, and when will BOEM 
          approve the revision?
585.656 What must I do if I cease activities approved in my GAP before 
          the end of my term?
585.657 What must I do upon completion of approved activities under my 
          GAP?

                      Cable and Pipeline Deviations

585.658 Can my cable or pipeline construction deviate from my approved 
          COP or GAP?
585.659 What requirements must I include in my SAP, COP, or GAP 
          regarding air quality?

[[Page 572]]

        Subpart G_Facility Design, Fabrication, and Installation

                                 Reports

585.700 What reports must I submit to BOEM before installing facilities 
          described in my approved SAP, COP, or GAP?
585.701 What must I include in my Facility Design Report?
585.702 What must I include in my Fabrication and Installation Report?
585.703 What reports must I submit for project modifications and 
          repairs?
585.704 [Reserved]

                      Certified Verification Agent

585.705 When must I use a Certified Verification Agent (CVA)?
585.706 How do I nominate a CVA for BOEM approval?
585.707 What are the CVA's primary duties for facility design review?
585.708 What are the CVA's or project engineer's primary duties for 
          fabrication and installation review?
585.709 When conducting onsite fabrication inspections, what must the 
          CVA or project engineer verify?
585.710 When conducting onsite installation inspections, what must the 
          CVA or project engineer do?
585.711 [Reserved]
585.712 What are the CVA's or project engineer's reporting requirements?
585.713 What must I do after the CVA or project engineer confirms 
          conformance with the Fabrication and Installation Report on my 
          commercial lease?
585.714 What records relating to SAPs, COPs, and GAPs must I keep?

Subpart H_Environmental and Safety Management, Inspections, and Facility 
     Assessments for Activities Conducted Under SAPs, COPs and GAPs

585.800 How must I conduct my activities to comply with safety and 
          environmental requirements?
585.801 How must I conduct my approved activities to protect marine 
          mammals, threatened and endangered species, and designated 
          critical habitat?
585.802 What must I do if I discover a potential archaeological resource 
          while conducting my approved activities?
585.803 How must I conduct my approved activities to protect essential 
          fish habitats identified and described under the Magnuson-
          Stevens Fishery Conservation and Management Act?
585.804-585.809 [Reserved]

                        Safety Management Systems

585.810 What must I include in my Safety Management System?
585.811 When must I follow my Safety Management System?
585.812 [Reserved]

                        Maintenance and Shutdowns

585.813 When do I have to report removing equipment from service?
585.814 [Reserved]

           Equipment Failure and Adverse Environmental Effects

585.815 What must I do if I have facility damage or an equipment 
          failure?
585.816 What must I do if environmental or other conditions adversely 
          affect a cable, pipeline, or facility?
585.817-585.819 [Reserved]

                       Inspections and Assessments

585.820 Will BOEM conduct inspections?
585.821 Will BOEM conduct scheduled and unscheduled inspections?
585.822 What must I do when BOEM conducts an inspection?
585.823 Will BOEM reimburse me for my expenses related to inspections?
585.824 How must I conduct self-inspections?
585.825 When must I assess my facilities?
585.826-585.829 [Reserved]

                  Incident Reporting and Investigation

585.830 What are my incident reporting requirements?
585.831 What incidents must I report, and when must I report them?
585.832 How do I report incidents requiring immediate notification?
585.833 What are the reporting requirements for incidents requiring 
          written notification?

                        Subpart I_Decommissioning

              Decommissioning Obligations and Requirements

585.900 Who must meet the decommissioning obligations in this subpart?
585.901 When do I accrue decommissioning obligations?
585.902 What are the general requirements for decommissioning for 
          facilities authorized under my SAP, COP, or GAP?
585.903 What are the requirements for decommissioning FERC-licensed 
          hydrokinetic facilities?
585.904 Can I request a departure from the decommissioning requirements?

                      Decommissioning Applications

585.905 When must I submit my decommissioning application?

[[Page 573]]

585.906 What must my decommissioning application include?
585.907 How will BOEM process my decommissioning application?
585.908 What must I include in my decommissioning notice?

                            Facility Removal

585.909 When may BOEM authorize facilities to remain in place following 
          termination of a lease or grant?
585.910 What must I do when I remove my facility?
585.911 [Reserved]

                         Decommissioning Report

585.912 After I remove a facility, cable, or pipeline, what information 
          must I submit?

         Compliance with an Approved Decommissioning Application

585.913 What happens if I fail to comply with my approved 
          decommissioning application?

  Subpart J_Rights of Use and Easement for Energy- and Marine-Related 
                Activities Using Existing OCS Facilities

                          Regulated Activities

585.1000 What activities does this subpart regulate?
585.1001-585.1003 [Reserved]

                     Requesting an Alternate Use RUE

585.1004 What must I do before I request an Alternate Use RUE?
585.1005 How do I request an Alternate Use RUE?
585.1006 How will BOEM decide whether to issue an Alternate Use RUE?
585.1007 What process will BOEM use for competitively offering an 
          Alternate Use RUE?
585.1008-585.1009 [Reserved]

                    Alternate Use RUE Administration

585.1010 How long may I conduct activities under an Alternate Use RUE?
585.1011 What payments are required for an Alternate Use RUE?
585.1012 What financial assurance is required for an Alternate Use RUE?
585.1013 Is an Alternate Use RUE assignable?
585.1014 When will BOEM suspend an Alternate Use RUE?
585.1015 How do I relinquish an Alternate Use RUE?
585.1016 When will an Alternate Use RUE be cancelled?
585.1017 [Reserved]

                  Decommissioning an Alternate Use RUE

585.1018 Who is responsible for decommissioning an OCS facility subject 
          to an Alternate Use RUE?
585.1019 What are the decommissioning requirements for an Alternate Use 
          RUE?

    Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C. 
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777, 
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



                      Subpart A_General Provisions



Sec.  585.100  Authority.

    The authority for this part derives from amendments to subsection 8 
of the Outer Continental Shelf Lands Act (OCS Lands Act) (43 U.S.C. 
1337), as set forth in section 388(a) of the Energy Policy Act of 2005 
(EPAct) (Pub. L. 109-58). The Secretary of the Interior delegated to the 
Bureau of Ocean Energy Management (BOEM) the authority to regulate 
activities under section 388(a) of the EPAct. These regulations 
specifically apply to activities that:
    (a) Produce or support production, transportation, or transmission 
of energy from sources other than oil and gas; or
    (b) Use, for energy-related purposes or for other authorized marine-
related purposes, facilities currently or previously used for activities 
authorized under the OCS Lands Act.



Sec.  585.101  What is the purpose of this part?

    The purpose of this part is to:
    (a) Establish procedures for issuance and administration of leases, 
right-of-way (ROW) grants, and right-of-use and easement (RUE) grants 
for renewable energy production on the Outer Continental Shelf (OCS) and 
RUEs for the alternate use of OCS facilities for energy or marine-
related purposes;
    (b) Inform you and third parties of your obligations when you 
undertake activities authorized in this part; and

[[Page 574]]

    (c) Ensure that renewable energy activities on the OCS and 
activities involving the alternate use of OCS facilities for energy or 
marine-related purposes are conducted in a safe and environmentally 
sound manner, in conformance with the requirements of subsection 8(p) of 
the OCS Lands Act, other applicable laws and regulations, and the terms 
of your lease, ROW grant, RUE grant, or Alternate Use RUE grant.
    (d) This part will not convey access rights for oil, gas, or other 
minerals.



Sec.  585.102  What are BOEM's responsibilities under this part?

    (a) BOEM will ensure that any activities authorized in this part are 
carried out in a manner that provides for:
    (1) Safety;
    (2) Protection of the environment;
    (3) Prevention of waste;
    (4) Conservation of the natural resources of the OCS;
    (5) Coordination with relevant Federal agencies (including, in 
particular, those agencies involved in planning activities that are 
undertaken to avoid conflicts among users and maximize the economic and 
ecological benefits of the OCS, including multifaceted spatial planning 
efforts);
    (6) Protection of National security interests of the United States;
    (7) Protection of the rights of other authorized users of the OCS;
    (8) A fair return to the United States;
    (9) Prevention of interference with reasonable uses (as determined 
by the Secretary or Director) of the exclusive economic zone, the high 
seas, and the territorial seas;
    (10) Consideration of the location of and any schedule relating to a 
lease or grant under this part for an area of the OCS, and any other use 
of the sea or seabed;
    (11) Public notice and comment on any proposal submitted for a lease 
or grant under this part; and
    (12) Oversight, inspection, research, monitoring, and enforcement of 
activities authorized by a lease or grant under this part.
    (b) BOEM will require compliance with all applicable laws, 
regulations, other requirements, and the terms of your lease or grant 
under this part and approved plans. BOEM will approve, disapprove, or 
approve with conditions any plans, applications, or other documents 
submitted to BOEM for approval under the provisions of this part.
    (c) Unless otherwise provided in this part, BOEM may give oral 
directives or decisions whenever prior BOEM approval is required under 
this part. BOEM will document in writing any such oral directives within 
10 business days.
    (d) BOEM will establish practices and procedures to govern the 
collection of all payments due to the Federal Government, including any 
cost recovery fees, rents, operating fees, and other fees or payments. 
BOEM will do this in accordance with the terms of this part, the leasing 
notice, the lease or grant under this part, and applicable Office of 
Natural Resources Revenue regulations or guidance.
    (e) BOEM will provide for coordination and consultation with the 
Governor of any State, the executive of any local government, and the 
executive of any Indian Tribe that may be affected by a lease, easement, 
or ROW under this subsection. BOEM may invite any affected State 
Governor, representative of an affected Indian Tribe, and affected local 
government executive to join in establishing a task force or other joint 
planning or coordination agreement in carrying out our responsibilities 
under this part.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]



Sec.  585.103  When may BOEM prescribe or approve departures from
 these regulations?

    (a) BOEM may prescribe or approve departures from these regulations 
when departures are necessary to:
    (1) Facilitate the appropriate activities on a lease or grant under 
this part;
    (2) Conserve natural resources;
    (3) Protect life (including human and wildlife), property, or the 
marine, coastal, or human environment; or
    (4) Protect sites, structures, or objects of historical or 
archaeological significance.
    (b) Any departure approved under this section and its rationale 
must:
    (1) Be consistent with subsection 8(p) of the OCS Lands Act;

[[Page 575]]

    (2) Protect the environment and the public health and safety to the 
same degree as if there was no approved departure from the regulations;
    (3) Not impair the rights of third parties; and
    (4) Be documented in writing.



Sec.  585.104  Do I need a BOEM lease or other authorization to
 produce or support the production of electricity or other energy
 product from a renewable energy resource on the OCS?

    Except as otherwise authorized by law, it will be unlawful for any 
person to construct, operate, or maintain any facility to produce, 
transport, or support generation of electricity or other energy product 
derived from a renewable energy resource on any part of the OCS, except 
under and in accordance with the terms of a lease, easement, or ROW 
issued pursuant to the OCS Lands Act.



Sec.  585.105  What are my responsibilities under this part?

    As a lessee, applicant, operator, or holder of a ROW grant, RUE 
grant, or Alternate Use RUE grant, you must:
    (a) Design your projects and conduct all activities in a manner that 
ensures safety and will not cause undue harm or damage to natural 
resources, including their physical, atmospheric, and biological 
components to the extent practicable; and take measures to prevent 
unauthorized discharge of pollutants including marine trash and debris 
into the offshore environment.
    (b) Submit requests, applications, plans, notices, modifications, 
and supplemental information to BOEM as required by this part;
    (c) Follow up, in writing, any oral request or notification you 
made, within 3 business days;
    (d) Comply with the terms, conditions, and provisions of all reports 
and notices submitted to BOEM, and of all plans, revisions, and other 
BOEM approvals, as provided in this part;
    (e) Make all applicable payments on time;
    (f) Comply with the DOI's nonprocurement debarment regulations at 2 
CFR part 1400;
    (g) Include the requirement to comply with 2 CFR part 1400 in all 
contracts and transactions related to a lease or grant under this part;
    (h) Conduct all activities authorized by the lease or grant in a 
manner consistent with the provisions of subsection 8(p) of the OCS 
Lands Act;
    (i) Compile, retain, and make available to BOEM representatives, 
within the time specified by BOEM, any data and information related to 
the site assessment, design, and operations of your project; and
    (j) Respond to requests from the Director in a timely manner.



Sec.  585.106  Who can hold a lease or grant under this part?

    (a) You may hold a lease or grant under this part if you can 
demonstrate that you have the technical and financial capabilities to 
conduct the activities authorized by the lease or grant and you are 
a(n):
    (1) Citizen or national of the United States;
    (2) Alien lawfully admitted for permanent residence in the United 
States as defined in 8 U.S.C. 1101(a)(20);
    (3) Private, public, or municipal corporations organized under the 
laws of any State of the United States, the District of Columbia, or any 
territory or insular possession subject to U.S. jurisdiction;
    (4) Association of such citizens, nationals, resident aliens, or 
corporations;
    (5) Executive Agency of the United States as defined in section 105 
of Title 5 of the U.S. Code;
    (6) State of the United States; and
    (7) Political subdivision of States of the United States.
    (b) You may not hold a lease or grant under this part or acquire an 
interest in a lease or grant under this part if:
    (1) You or your principals are excluded or disqualified from 
participating in transactions covered by the Federal nonprocurement 
debarment and suspension system (2 CFR part 1400), unless BOEM 
explicitly has approved an exception for this transaction;
    (2) BOEM determines or has previously determined after notice and 
opportunity for a hearing that you or your principals have failed to 
meet or

[[Page 576]]

exercise due diligence under any OCS lease or grant; or
    (3) BOEM determines or has previously determined after notice and 
opportunity for a hearing that you:
    (i) Remained in violation of the terms and conditions of any lease 
or grant issued under the OCS Lands Act for a period extending longer 
than 30 days (or such other period BOEM allowed for compliance) after 
BOEM directed you to comply; and
    (ii) You took no action to correct the noncompliance within that 
time period.



Sec.  585.107  How do I show that I am qualified to be a lessee or 
grant holder?

    (a) You must demonstrate your technical and financial capability to 
construct, operate, maintain, and terminate/decommission projects for 
which you are requesting authorization. Documentation can include:
    (1) Descriptions of international or domestic experience with 
renewable energy projects or other types of electric-energy-related 
projects; and
    (2) Information establishing access to sufficient capital to carry 
out development.
    (b) An individual must submit a written statement of citizenship 
status attesting to U.S. citizenship. It does not need to be notarized 
nor give the age of individual. A resident alien may submit a photocopy 
of the Immigration and Naturalization Service form evidencing legal 
status of the resident alien.
    (c) A corporation or association must submit evidence, as specified 
in the table in paragraph (d) of this section, acceptable to BOEM that:
    (1) It is qualified to hold leases or grants under this part;
    (2) It is authorized to conduct business under the laws of its 
State;
    (3) It is authorized to hold leases or grants on the OCS under the 
operating rules of its business; and
    (4) The persons holding the titles listed are authorized to bind the 
corporation or association when conducting business with BOEM.
    (d) Acceptable evidence under paragraph (c) of this section 
includes, but is not limited to the following:

----------------------------------------------------------------------------------------------------------------
 Requirements to qualify to hold leases or
            grants on the OCS:                  Corp.     Ltd. Prtnsp.  Gen. Prtnsp.       LLC          Trust
----------------------------------------------------------------------------------------------------------------
(1) Original certificate or certified copy           XX   ............  ............  ............
 from the State of incorporation stating
 the name of the corporation exactly as it
 must appear on all legal documents.
(2) Certified statement by Secretary/                XX   ............  ............  ............
 Assistant Secretary over corporate seal,
 certifying that the corporation is
 authorized to hold OCS leases.
(3) Evidence of authority of titled                  XX   ............  ............  ............
 positions to bind corporation, certified
 by Secretary/Assistant Secretary over
 corporate seal, including the following:
    (i) Certified copy of resolution of
     the board of directors with titles of
     officers authorized to bind
     corporation.
    (ii) Certified copy of resolutions
     granting corporate officer authority
     to issue a power of attorney.
    (iii) Certified copy of power of
     attorney or certified copy of
     resolution granting power of
     attorney.
(4) Original certificate or certified copy  ............           XX            XX            XX
 of partnership or organization paperwork
 registering with the appropriate State
 official.
(5) Copy of articles of partnership or      ............           XX            XX            XX
 organization evidencing filing with
 appropriate Secretary of State, certified
 by Secretary/Assistant Secretary of
 partnership or member or manager of LLC.
(6) Original certificate or certified copy  ............           XX            XX            XX
 evidencing State where partnership or LLC
 is registered. Statement of authority to
 hold OCS leases, certified by Secretary/
 Assistant Secretary, OR original
 paperwork registering with the
 appropriate State official.
(7) Statements from each partner or LLC     ............           XX            XX            XX
 member indicating the following:

[[Page 577]]

 
    (i) If a corporation or partnership,
     statement of State of organization
     and authorization to hold OCS leases,
     certified by Secretary/Assistant
     Secretary over corporate seal, if a
     corporation.
    (ii) If an individual, a statement of
     citizenship.
(8) Statement from general partner,         ............           XX   ............  ............
 certified by Secretary/Assistant
 Secretary that:
    (i) Each individual limited partner is
     a U.S. citizen and;
    (ii) Each corporate limited partner or
     other entity is incorporated or
     formed and organized under the laws
     of a U.S. State or territory.
(9) Evidence of authority to bind           ............           XX            XX            XX
 partnership or LLC, if not specified in
 partnership agreement, articles of
 organization, or LLC regulations, i.e.,
 certificates of authority from Secretary/
 Assistant Secretary reflecting authority
 of officers.
(10) Listing of members of LLC certified    ............  ............  ............           XX
 by Secretary/Assistant Secretary or any
 member or manager of LLC.
(11) Copy of trust agreement or document    ............  ............  ............  ............           XX
 establishing the trust and all
 amendments, properly certified by the
 trustee with reference to where the
 original documents are filed.
(12) Statement indicating the law under     ............  ............  ............  ............           XX
 which the trust is established and that
 the trust is authorized to hold OCS
 leases or grants.
----------------------------------------------------------------------------------------------------------------

    (e) A local, State, or Federal executive entity must submit a 
written statement that:
    (1) It is qualified to hold leases or grants under this part; and
    (2) The person(s) acting on behalf of the entity is authorized to 
bind the entity when conducting business with us.
    (f) BOEM may require you to submit additional information at any 
time considering your bid or request for a noncompetitive lease.



Sec.  585.108  When must I notify BOEM if an action has been filed alleging that I am insolvent or bankrupt?

    You must notify BOEM within 3 business days after you learn of any 
action filed alleging that you are insolvent or bankrupt.



Sec.  585.109  When must I notify BOEM of mergers, name changes,
 or changes of business form?

    You must notify BOEM in writing of any merger, name change, or 
change of business form. You must notify BOEM as soon as practicable 
following the merger, name change, or change in business form, but no 
later than 120 days after the earliest of either the effective date, or 
the date of filing the change or action with the Secretary of the State 
or other authorized official in the State of original registry.



Sec.  585.110  How do I submit plans, applications, reports, or
 notices required by this part?

    (a) You must submit all plans, applications, reports, or notices 
required by this part to BOEM at the following address: Deputy Director, 
Bureau of Ocean Energy Management, 45600 Woodland Road, Sterling, VA 
20166.
    (b) Unless otherwise stated, you must submit one paper copy and one 
electronic copy of all plans, applications, reports, or notices required 
by this part.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



Sec.  585.111  When and how does BOEM charge me processing fees on
 a case-by-case basis?

    (a) BOEM will charge a processing fee on a case-by-case basis under 
the procedures in this section with regard to any application or request 
under this part if we decide at any time that the preparation of a 
particular document

[[Page 578]]

or study is necessary for the application or request and it will have a 
unique processing cost, such as the preparation of an Environmental 
Assessment (EA) or Environmental Impact Statement (EIS).
    (1) Processing costs will include contract oversight and efforts to 
review and approve documents prepared by contractors, whether the 
contractor is paid directly by the applicant or through BOEM.
    (2) We may apply a standard overhead rate to direct processing 
costs.
    (b) We will assess the ongoing processing fee for each individual 
application or request according to the following procedures:
    (1) Before we process your application or request, we will give you 
a written estimate of the proposed fee based on reasonable processing 
costs.
    (2) You may comment on the proposed fee.
    (3) You may:
    (i) Ask for our approval to perform, or to directly pay a contractor 
to perform, all or part of any document, study, or other activity 
according to standards we specify, thereby reducing our costs for 
processing your application or request; or
    (ii) Ask to pay us to perform, or contract for, all or part of any 
document, study, or other activity.
    (4) We will then give you the final estimate of the processing fee 
amount with payment terms and instructions after considering your 
comments and any BOEM-approved work you will do.
    (i) If we encounter higher or lower processing costs than 
anticipated, we will re-estimate our reasonable processing costs 
following the procedures in paragraphs (b)(1) through (4) of this 
section, but we will not stop ongoing processing unless you do not pay 
in accordance with paragraph (b)(5) of this section.
    (ii) Once processing is complete, we will refund to you the amount 
of money that we did not spend on processing costs.
    (5)(i) Consistent with the payment and billing terms provided in the 
final estimate, we will periodically estimate what our reasonable 
processing costs will be for a specific period and will bill you for 
that period. Payment is due to us 30 days after you receive your bill. 
We will stop processing your document if you do not pay the bill by the 
date payment is due.
    (ii) If a periodic payment turns out to be more or less than our 
reasonable processing costs for the period, we will adjust the next 
billing accordingly or make a refund. Do not deduct any amount from a 
payment without our prior written approval.
    (6) You must pay the entire fee before we will issue the final 
document or take final action on your application or request.
    (7) You may appeal our estimated processing costs in accordance with 
the regulations in 43 CFR part 4. We will not process the document 
further until the appeal is resolved, unless you pay the fee under 
protest while the appeal is pending. If the appeal results in a decision 
changing the proposed fee, we will adjust the fee in accordance with 
paragraph (b)(5)(ii) of this section. If we adjust the fee downward, we 
will not pay interest.



Sec.  585.112  Definitions.

    Terms used in this part have the meanings as defined in this 
section:
    Affected local government means with respect to any activities 
proposed, conducted, or approved under this part, any locality--
    (1) That is, or is proposed to be, the site of gathering, 
transmitting, or distributing electricity or other energy product, or is 
otherwise receiving, processing, refining, or transshipping product, or 
services derived from activities approved under this part;
    (2) That is used, or is proposed to be used, as a support base for 
activities approved under this part; or
    (3) In which there is a reasonable probability of significant effect 
on land or water uses from activities approved under this part.
    Affected State means with respect to any activities proposed, 
conducted, or approved under this part, any coastal State--
    (1) That is, or is proposed to be, the site of gathering, 
transmitting, or distributing energy or is otherwise receiving, 
processing, refining, or transshipping products, or services derived

[[Page 579]]

from activities approved under this part;
    (2) That is used, or is scheduled to be used, as a support base for 
activities approved under this part; or
    (3) In which there is a reasonable probability of significant effect 
on land or water uses from activities approved under this part.
    Alternate Use refers to the energy- or marine-related use of an 
existing OCS facility for activities not otherwise authorized by this 
subchapter or other applicable law.
    Alternate Use RUE means a right-of-use and easement issued for 
activities authorized under subpart J of this part.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest (i.e., which are capable of providing scientific 
or humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation).
    Best available and safest technology means the best available and 
safest technologies that BOEM determines to be economically feasible 
wherever failure of equipment would have a significant effect on safety, 
health, or the environment.
    Best management practices mean practices recognized within their 
respective industry, or by Government, as one of the best for achieving 
the desired output while reducing undesirable outcomes.
    BOEM means Bureau of Ocean Energy Management of the Department of 
the Interior.
    Certified Verification Agent (CVA) means an individual or 
organization, experienced in the design, fabrication, and installation 
of offshore marine facilities or structures, who will conduct specified 
third-party reviews, inspections, and verifications in accordance with 
this part.
    Coastline means the same as the term ``coast line'' in section 2 of 
the Submerged Lands Act (43 U.S.C. 1301(c)).
    Commercial activities mean, for renewable energy leases and grants, 
all activities associated with the generation, storage, or transmission 
of electricity or other energy product from a renewable energy project 
on the OCS, and for which such electricity or other energy product is 
intended for distribution, sale, or other commercial use, except for 
electricity or other energy product distributed or sold pursuant to 
technology-testing activities on a limited lease. This term also 
includes activities associated with all stages of development, including 
initial site characterization and assessment, facility construction, and 
project decommissioning.
    Commercial lease means a lease issued under this part that specifies 
the terms and conditions under which a person can conduct commercial 
activities.
    Commercial operations mean the generation of electricity or other 
energy product for commercial use, sale, or distribution on a commercial 
lease.
    Decommissioning means removing BOEM-approved facilities and 
returning the site of the lease or grant to a condition that meets the 
requirements under subpart I of this part.
    Director means the Director of the Bureau of Ocean Energy Management 
(BOEM), of the U.S. Department of the Interior, or an official 
authorized to act on the Director's behalf.
    Distance means the minimum great circle distance.
    Eligible State means a coastal State having a coastline (measured 
from the nearest point) no more than 15 miles from the geographic center 
of a qualified project area.
    Facility means an installation that is permanently or temporarily 
attached to the seabed of the OCS. Facilities include any structures; 
devices; appurtenances; gathering, transmission, and distribution 
cables; pipelines; and permanently moored vessels. Any group of OCS 
installations interconnected with walkways, or any group of 
installations that includes a central or primary installation with one 
or more satellite or secondary installations, is a single facility. BOEM 
may decide that the complexity of the installations justifies their 
classification as separate facilities.
    Geographic center of a project means the centroid (geometric center 
point)

[[Page 580]]

of a qualified project area. The centroid represents the point that is 
the weighted average of coordinates of the same dimension within the 
mapping system, with the weights determined by the density function of 
the system. For example, in the case of a project area shaped as a 
rectangle or other parallelogram, the geographic center would be that 
point where lines between opposing corners intersect. The geographic 
center of a project could be outside the project area itself if that 
area is irregularly shaped.
    Governor means the Governor of a State or the person or entity 
lawfully designated by or under State law to exercise the powers granted 
to a Governor.
    Grant means a right-of-way, right-of-use and easement, or alternate 
use right-of-use and easement issued under the provisions of this part.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Income, unless clearly specified to the contrary, refers to the 
money received by the project owner or holder of the lease or grant 
issued under this part. The term does not mean that project receipts 
exceed project expenses.
    Lease means an agreement authorizing the use of a designated portion 
of the OCS for activities allowed under this part. The term also means 
the area covered by that agreement, when the context requires.
    Lessee means the holder of a lease, a BOEM-approved assignee, and, 
when describing the conduct required of parties engaged in activities on 
the lease, it also refers to the operator and all persons authorized by 
the holder of the lease or operator to conduct activities on the lease.
    Limited lease means a lease issued under this part that specifies 
the terms and conditions under which a person may conduct activities on 
the OCS that support the production of energy, but do not result in the 
production of electricity or other energy product for sale, 
distribution, or other commercial use exceeding a limit specified in the 
lease.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within the 
coastal zone and on the OCS.
    Miles mean nautical miles, as opposed to statute miles.
    Natural resources include, without limiting the generality thereof, 
renewable energy, oil, gas, and all other minerals (as defined in 
section 2(q) of the OCS Lands Act), and marine animal and marine plant 
life.
    Operator means the individual, corporation, or association having 
control or management of activities on the lease or grant under this 
part. The operator may be a lessee, grant holder, or a contractor 
designated by the lessee or holder of a grant under this part.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters, as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means, in addition to a natural person, an association 
(including partnerships and joint ventures); a Federal agency; a State; 
a political subdivision of a State; a Native American Tribal government; 
or a private, public, or municipal corporation.
    Project, for the purposes of defining the source of revenues to be 
shared, means a lease ROW, RUE, or Alternate Use RUE on which the 
activities authorized under this part are conducted on the OCS. The term 
``project'' may be used elsewhere in this rule to refer to these same 
authorized activities, the facilities used to conduct these activities, 
or to the geographic area of the project, i.e., the project area.
    Project area means the geographic surface leased, or granted, for 
the purpose of a specific project. If OCS acreage is granted for a 
project under some form of agreement other than a lease (i.e., a ROW, 
RUE, or Alternate Use

[[Page 581]]

RUE issued under this part), the Federal acreage granted would be 
considered the project area. To avoid distortions in the calculation of 
the geometric center of the project area, project easements issued under 
this part are not considered part of the qualified project's area.
    Project easement means an easement to which, upon approval of your 
Construction and Operations Plan (COP) or General Activities Plan (GAP), 
you are entitled as part of the lease for the purpose of installing, 
gathering, transmission, and distribution cables, pipelines, and 
appurtenances on the OCS as necessary for the full enjoyment of the 
lease.
    Renewable Energy means energy resources other than oil and gas and 
minerals as defined in 30 CFR part 580. Such resources include, but are 
not limited to, wind, solar, and ocean waves, tides, and current.
    Revenues mean bonuses, rents, operating fees, and similar payments 
made in connection with a project or project area. It does not include 
administrative fees such as those assessed for cost recovery, civil 
penalties, and forfeiture of financial assurance.
    Right-of-use and easement (RUE) grant means an easement issued by 
BOEM under this part that authorizes use of a designated portion of the 
OCS to support activities on a lease or other use authorization for 
renewable energy activities. The term also means the area covered by the 
authorization.
    Right-of-way (ROW) grant means an authorization issued by BOEM under 
this part to use a portion of the OCS for the construction and use of a 
cable or pipeline for the purpose of gathering, transmitting, 
distributing, or otherwise transporting electricity or other energy 
product generated or produced from renewable energy, but does not 
constitute a project easement under this part. The term also means the 
area covered by the authorization.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Significant archaeological resource means an archaeological resource 
that meets the criteria of significance for eligibility for listing in 
the National Register of Historic Places, as defined in 36 CFR 60.4 or 
its successor.
    Site assessment activities mean those initial activities conducted 
to characterize a site on the OCS, such as resource assessment surveys 
(e.g., meteorological and oceanographic) or technology testing, 
involving the installation of bottom-founded facilities.
    You and your means an applicant, lessee, the operator, or designated 
operator, ROW grant holder, RUE grant holder, or Alternate Use RUE grant 
holder under this part, or the designated agent of any of these, or the 
possessive of each, depending on the context. The terms You and your 
also include contractors and subcontractors of the entities specified in 
the preceding sentence.
    We, us, and our refer to the Bureau of Ocean Energy Management of 
the Department of the Interior, or its possessive, depending on the 
context.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]



Sec.  585.113  How will data and information obtained by BOEM under
 this part be disclosed to the public?

    (a) BOEM will make data and information available in accordance with 
the requirements and subject to the limitations of the Freedom of 
Information Act (FOIA) (5 U.S.C. 552), the regulations contained in 43 
CFR part 2 (Records and Testimony).
    (b) BOEM will not release such data and information that we have 
determined is exempt from disclosure under exemption 4 of FOIA. We will 
review such data and information and objections of the submitter by the 
following schedule to determine whether release at that time will result 
in substantial competitive harm or disclosure of trade secrets.

------------------------------------------------------------------------
                                          Then BOEM will review data and
          If you have a . . .                information for possible
                                                     release:
------------------------------------------------------------------------
(1) Commercial lease...................  At the earlier of:
                                            (i) 3 years after the
                                             initiation of commercial
                                             generation or
                                            (ii) 3 years after the lease
                                             terminates.

[[Page 582]]

 
(2) Limited lease......................  At 3 years after the lease
                                          terminates.
(3) ROW or RUE grant...................  At the earliest of:
                                            (i) 10 years after the
                                             approval of the grant;
                                            (ii) Grant termination; or
                                            (iii) 3 years after the
                                             completion of construction
                                             activities.
------------------------------------------------------------------------

    (c) After considering any objections from the submitter, if we 
determine that release of such data and information will result in:
    (1) No substantial competitive harm or disclosure of trade secrets, 
then the data and information will be released.
    (2) Substantial competitive harm or disclosure of trade secrets, 
then the data and information will not be released at that time but will 
be subject to further review every 3 years thereafter.



Sec.  585.114  Paperwork Reduction Act statements--information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in 30 CFR part 585 under 44 U.S.C. 
3501, et seq., and assigned OMB Control Number 1010-0176. The table in 
paragraph (e) of this section lists the subpart in the rule requiring 
the information and its title, summarizes the reasons for collecting the 
information, and summarizes how BOEM uses the information.
    (b) Respondents are primarily renewable energy applicants, lessees, 
ROW grant holders, RUE grant holders, Alternate Use RUE grant holders, 
and operators. The requirement to respond to the information collection 
in this part is mandated under subsection 8(p) of the OCS Lands Act. 
Some responses are also required to obtain or retain a benefit, or may 
be voluntary.
    (c) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) 
requires us to inform the public that an agency may not conduct or 
sponsor, and you are not required to respond to, a collection of 
information unless it displays a currently valid OMB control number.
    (d) Comments regarding any aspect of the collections of information 
under this part, including suggestions for reducing the burden, should 
be sent to the Information Collection Clearance Officer, Bureau of Ocean 
Energy Management, 45600 Woodland Road, Sterling, VA 20166.
    (e) BOEM is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR 585 subpart, title, and/or BOEM       Reasons for collecting
         Form (OMB Control No.)              information and how used
------------------------------------------------------------------------
(1) Subpart A--General Provisions......  To inform BOEM of actions taken
                                          to comply with general
                                          operational requirements on
                                          the OCS. To ensure that
                                          operations on the OCS meet
                                          statutory and regulatory
                                          requirements, are safe and
                                          protect the environment, and
                                          result in diligent development
                                          on OCS leases.
(2) Subpart B--Issuance of OCS           To provide BOEM with
 Renewable Energy Leases.                 information needed to
                                          determine when to use a
                                          competitive process for
                                          issuing a renewable energy
                                          lease, to identify auction
                                          formats and bidding systems
                                          and variables that we may use
                                          when that determination is
                                          affirmative, and to determine
                                          the terms under which we will
                                          issue renewable energy leases.
(3) Subpart C--ROW Grants and RUE        To issue ROW grants and RUE
 Grants for Renewable Energy Activities.  grants for OCS renewable
                                          energy activities that are not
                                          associated with a BOEM-issued
                                          renewable energy lease.
(4) Subpart D--Lease and Grant           To ensure compliance with
 Administration.                          regulations pertaining to a
                                          lease or grant; assignment and
                                          designation of operator; and
                                          suspension, renewal,
                                          termination, relinquishment,
                                          and cancellation of leases and
                                          grants.
(5) Subpart E--Payments and Financial    To ensure that payments and
 Assurance Requirements.                  financial assurance payments
                                          for renewable energy leases
                                          comply with subpart E.
(6) Subpart F--Plans and Information     To enable BOEM to comply with
 Requirements.                            the National Environmental
                                          Policy Act (NEPA), the Coastal
                                          Zone Management Act (CZMA),
                                          and other Federal laws and to
                                          ensure the safety of the
                                          environment on the OCS.

[[Page 583]]

 
(7) Subpart G--Facility Design,          To enable BOEM to review the
 Fabrication, and Installation.           final design, fabrication, and
                                          installation of facilities on
                                          a lease or grant to ensure
                                          that these facilities are
                                          designed, fabricated, and
                                          installed according to
                                          appropriate standards in
                                          compliance with BOEM
                                          regulations, and where
                                          applicable, the approved plan.
(8) Subpart H--Environmental and Safety  To ensure that lease and grant
 Management, Inspections, and Facility    operations are conducted in a
 Assessments.                             manner that is safe and
                                          protects the environment. To
                                          ensure compliance with other
                                          Federal laws, these
                                          regulations, the lease or
                                          grant, and approved plans.
(9) Subpart I--Decommissioning.........  To determine that
                                          decommissioning activities
                                          comply with regulatory
                                          requirements and approvals. To
                                          ensure that site clearance and
                                          platform or pipeline removal
                                          are properly performed to
                                          protect marine life and the
                                          environment and do not
                                          conflict with other users of
                                          the OCS.
(10) Subpart J--RUEs for Energy and      To enable BOEM to review
 Marine-Related Activities Using          information regarding the
 Existing OCS Facilities.                 design, installation, and
                                          operation of RUEs on the OCS,
                                          to ensure that RUE operations
                                          are safe and protect the
                                          human, marine, and coastal
                                          environment. To ensure
                                          compliance with other Federal
                                          laws, these regulations, the
                                          RUE grant, and, where
                                          applicable, the approved plan.
------------------------------------------------------------------------


[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



Sec.  585.115  Documents incorporated by reference.

    (a) BOEM is incorporating by reference the documents listed in the 
table in paragraph (e) of this section. The Director of the Federal 
Register has approved this incorporation by reference according to 5 
U.S.C. 552(a) and 1 CFR part 51.
    (1) BOEM will publish, as a rule, any changes in the documents 
incorporated by reference in the Federal Register.
    (2) BOEM may amend by rule the list of industry standards 
incorporated by reference of the document effective without prior 
opportunity for public comment when BOEM determines that the revisions 
to a document result in safety improvements or represent new industry 
standard technology and do not impose undue costs on the affected 
parties; and
    (3) BOEM may make a rule, effective immediately, amending the list 
of industry standards incorporated by reference if it determines good 
cause exists for doing so under 5 U.S.C. 553.
    (b) BOEM is incorporating each document or specific portion by 
reference in the sections noted. The entire document is incorporated by 
reference, unless the text of the corresponding sections in this part 
calls for compliance with specific portions of the listed documents. In 
each instance, the applicable document is the specific edition, or 
specific edition and supplement, or specific addition and addendum cited 
in this section.
    (c) You may comply with a later edition of a specific document 
incorporated by reference, only if:
    (1) You show that complying with the later edition provides a degree 
of protection, safety, or performance equal to or better than what would 
be achieved by compliance with the listed edition; and
    (2) You obtain the prior written approval for alternative compliance 
from the authorized BOEM official.
    (d) You may inspect these documents at the Bureau of Ocean Energy 
Management, 45600 Woodland Road, Sterling, VA 20166, 703-787-1605; or at 
the National Archives and Records Administration (NARA). For information 
on the availability of this material at NARA, call 202-741-6030, or go 
to: http://www.archives.gov/federal_register/
code_of_federal_regulations/ibr_locations.html. You may obtain the 
documents from the publishing organizations at the addresses given in 
the following table:

------------------------------------------------------------------------
               For . . .                          Write to . . .
------------------------------------------------------------------------
API Recommended Practices..............  American Petroleum Institute,
                                          1220 L Street, NW.,
                                          Washington, DC 20005-4070.
                                          http://www.api.org/
                                          publications/
------------------------------------------------------------------------


[[Page 584]]

    (e) This paragraph lists documents incorporated by reference. To 
easily reference text of the corresponding sections with the list of 
documents incorporated by reference, the list is in alphanumerical order 
by organization and document.

----------------------------------------------------------------------------------------------------------------
                 Title of documents                               Incorporated by reference at . . .
----------------------------------------------------------------------------------------------------------------
API RP 2A-WSD, Recommended Practice for Planning,     30 CFR 585.825
 Designing and Constructing Fixed Offshore
 Platforms--Working Stress Design; Twenty-first
 Edition, December 2000; Errata and Supplement 1,
 December 2002; Errata and Supplement 2, September
 2005; Errata and Supplement 3, October 2007;
 Product No. G2AWSD.
----------------------------------------------------------------------------------------------------------------


[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]



Sec.  585.116  Requests for information on the state of the offshore
 renewable energy industry.

    (a) The Director may, from time to time, and at his discretion, 
solicit information from industry and other relevant stakeholders 
(including State and local agencies), as necessary, to evaluate the 
state of the offshore renewable energy industry, including the 
identification of potential challenges or obstacles to its continued 
development. Such requests for information may relate to the 
identification of environmental, technical, regulatory, or economic 
matters that promote or detract from continued development of renewable 
energy technologies on the OCS. From the information received, the 
Director may evaluate potential refinements to the OCS Alternative 
Energy Program that promote development of the industry in a safe and 
environmentally responsible manner, and that ensure fair value for use 
of the Nation's OCS.
    (b) BOEM may make such requests for information on a regional basis, 
and may tailor the requests to specific types of renewable energy 
technologies.
    (c) BOEM will publish such requests for information by the Director 
in the Federal Register.



Sec.  585.117  [Reserved]



Sec.  585.118  What are my appeal rights?

    (a) Any party adversely affected by a BOEM official's final decision 
or order issued under the regulations of this part may appeal that 
decision or order to the Interior Board of Land Appeals. The appeal must 
conform with the procedures found in 30 CFR part 590 and 43 CFR part 4, 
subpart E. Appeal of a final decision for bid acceptance is covered 
under paragraph (c) of this section.
    (b) A decision will remain in full force and effect during the 
period in which an appeal may be filed and during an appeal, unless a 
stay is granted pursuant to 43 CFR part 4.
    (c) Our decision on a bid is the final action of the Department, 
except that an unsuccessful bidder may apply for reconsideration by the 
Director.
    (1) A bidder whose bid we reject may file a written request for 
reconsideration with the Director within 15 days of the date of the 
receipt of the notice of rejection, accompanied by a statement of 
reasons, with one copy to us. The Director will respond in writing 
either affirming or reversing the decision.
    (2) The delegation of review authority given to the Office of 
Hearings and Appeals does not apply to decisions on high bids for leases 
or grants under this part.



            Subpart B_Issuance of OCS Renewable Energy Leases

                        General Lease Information



Sec.  585.200  What rights are granted with a lease issued under
 this part?

    (a) A lease issued under this part grants the lessee the right, 
subject to obtaining the necessary approvals, including but not limited 
to those required under the FERC hydrokinetic licensing process, and 
complying with all provisions of this part, to occupy, and install and 
operate facilities on, a designated portion of the OCS for the purpose 
of conducting:
    (1) Commercial activities; or

[[Page 585]]

    (2) Other limited activities that support, result from, or relate to 
the production of energy from a renewable energy source.
    (b) A lease issued under this part confers on the lessee the right 
to one or more project easements without further competition for the 
purpose of installing gathering, transmission, and distribution cables; 
pipelines; and appurtenances on the OCS as necessary for the full 
enjoyment of the lease.
    (1) You must apply for the project easement as part of your COP or 
GAP, as provided under subpart F of this part; and
    (2) BOEM will incorporate your approved project easement in your 
lease as an addendum.
    (c) A commercial lease issued under this part may be developed in 
phases, with BOEM approval as provided in Sec.  585.629.



Sec.  585.201  How will BOEM issue leases?

    BOEM will issue leases on a competitive basis, as provided under 
Sec. Sec.  585.210 through 585.225. However, if we determine after 
public notice of a proposed lease that there is no competitive interest, 
we will issue leases noncompetitively, as provided under Sec. Sec.  
585.230 and 585.232. We will issue leases on forms approved by BOEM and 
will include terms, conditions, and stipulations identified and 
developed through the process set forth in Sec. Sec.  585.211 and 
585.231.



Sec.  585.202  What types of leases will BOEM issue?

    BOEM may issue leases on the OCS for the assessment and production 
of renewable energy and may authorize a combination of specific 
activities. We may issue commercial leases or limited leases.



Sec.  585.203  With whom will BOEM consult before issuance of a lease?

    For leases issued under this part, through either the competitive or 
noncompetitive process, BOEM, prior to issuing the lease, will 
coordinate and consult with relevant Federal agencies (including, in 
particular, those agencies involved in planning activities that are 
undertaken to avoid or minimize conflicts among users and maximize the 
economic and ecological benefits of the OCS, including multifaceted 
spatial planning efforts), the Governor of any affected State, the 
executive of any affected local government, and any affected Indian 
Tribe, as directed by subsections 8(p)(4) and (7) of the OCS Lands Act 
or other relevant Federal laws. Federal statutes that require BOEM to 
consult with interested parties or Federal agencies or to respond to 
findings of those agencies, including the Endangered Species Act (ESA) 
and the Magnuson-Stevens Fishery Conservation and Management Act (MSA). 
BOEM also engages in consultation with state and tribal historic 
preservation officers pursuant to the National Historic Preservation Act 
(NHPA).

[79 FR 21621, Apr. 17, 2014]



Sec.  585.204  What areas are available for leasing consideration?

    BOEM may offer any appropriately platted area of the OCS, as 
provided in Sec.  585.205, for a renewable energy lease, except any area 
within the exterior boundaries of any unit of the National Park System, 
National Wildlife Refuge System, National Marine Sanctuary System, or 
any National Monument.



Sec.  585.205  How will leases be mapped?

    BOEM will prepare leasing maps and official protraction diagrams of 
areas of the OCS. The areas included in each lease will be in accordance 
with the appropriate leasing map or official protraction diagram.



Sec.  585.206  What is the lease size?

    (a) BOEM will determine the size for each lease based on the area 
required to accommodate the anticipated activities. The processes 
leading to both competitive and noncompetitive issuance of leases will 
provide public notice of the lease size adopted. We will delineate 
leases by using mapped OCS blocks or portions, or aggregations of 
blocks.
    (b) The lease size includes the minimum area that will allow the 
lessee sufficient space to develop the project and manage activities in 
a manner that is consistent with the provisions of this part. The lease 
may include whole lease blocks or portions of a lease block.

[[Page 586]]



Sec. Sec.  585.207-585.209  [Reserved]

                        Competitive Lease Process



Sec.  585.210  How does BOEM initiate the competitive leasing process?

    BOEM may publish in the Federal Register a public notice of Request 
for Interest to assess interest in leasing all or part of the OCS for 
activities authorized in this part. BOEM will consider information 
received in response to a Request for Interest to determine whether 
there is competitive interest for scheduling sales and issuing leases. 
We may prepare and issue a national, regional, or more specific schedule 
of lease sales pertaining to one or more types of renewable energy.



Sec.  585.211  What is the process for competitive issuance of leases?

    BOEM will use auctions to award leases on a competitive basis. We 
will publish details of the process to be employed for each lease sale 
auction in the Federal Register. For each lease sale, we will publish a 
Proposed Sale Notice and a Final Sale Notice. Individual lease sales 
will include steps such as:
    (a) Call for Information and Nominations (Call). BOEM will publish 
in the Federal Register Calls for Information and Nominations for 
leasing in specified areas. The comment period following issuance of a 
Call will be 45 days. In this document, we may:
    (1) Request comments on areas which should receive special 
consideration and analysis;
    (2) Request comments concerning geological conditions (including 
bottom hazards); archaeological sites on the seabed or nearshore; 
multiple uses of the proposed leasing area (including navigation, 
recreation, and fisheries); and other socioeconomic, biological, and 
environmental information; and
    (3) Suggest areas to be considered by the respondents for leasing.
    (b) Area Identification. BOEM will identify areas for environmental 
analysis and consideration for leasing. We will do this in consultation 
with appropriate Federal agencies, States, local governments, affected 
Indian Tribes, and other interested parties.
    (1) We may consider for lease those areas nominated in response to 
the Call for Information and Nominations, together with other areas that 
BOEM determines are appropriate for leasing.
    (2) We will evaluate the potential effect of leasing on the human, 
marine, and coastal environments, and develop measures to mitigate 
adverse impacts, including lease stipulations.
    (3) We will consult to develop measures, including lease 
stipulations and conditions, to mitigate adverse impacts on the 
environment; and
    (4) We may hold public hearings on the environmental analysis after 
appropriate notice.
    (c) Proposed Sale Notice. BOEM will publish the Proposed Sale Notice 
in the Federal Register and send it to the Governor of any affected 
State, any Indian Tribe that might be affected, and the executive of any 
local government that might be affected. The comment period following 
issuance of a Proposed Sale Notice will be 60 days.
    (d) Final Sale Notice. BOEM will publish the Final Sale Notice in 
the Federal Register at least 30 days before the date of the sale.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]



Sec.  585.212  What is the process BOEM will follow if there is reason
 to believe that competitors have withdrawn before the Final Sale
 Notice is issued?

    BOEM may decide to end the competitive process before the Final Sale 
Notice if we have reason to believe that competitors have withdrawn and 
competition no longer exists. We will issue a second public notice of 
Request for Interest and consider comments received to confirm that 
there is no competitive interest.
    (a) If, after reviewing comments in response to the notice of 
Request for Interest, BOEM determines that there is no competitive 
interest in the lease area, and one party wishes to acquire a lease, we 
will discontinue the competitive process and will proceed with the 
noncompetitive process set forth in Sec.  585.231(d) through (i) 
following receipt of the acquisition fee specified in Sec.  585.502(a).

[[Page 587]]

    (b) If, after reviewing comments in response to the notice of 
Request for Interest, BOEM determines that competitive interest in the 
lease area continues to exist, we will continue with the competitive 
process set forth in Sec. Sec.  585.211 through 585.225.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]



Sec.  585.213  What must I submit in response to a Request for
 Interest or a Call for Information and Nominations?

    If you are a potential lessee, when you respond to a Request for 
Interest or a Call, your response must include the following items:
    (a) The area of interest for a possible lease.
    (b) A general description of your objectives and the facilities that 
you would use to achieve those objectives.
    (c) A general schedule of proposed activities, including those 
leading to commercial operations.
    (d) Available and pertinent data and information concerning 
renewable energy and environmental conditions in the area of interest, 
including energy and resource data and information used to evaluate the 
area of interest. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and as provided in Sec.  
585.113.
    (e) Documentation showing that you are qualified to hold a lease, as 
specified in Sec.  585.107.
    (f) Any other information requested by BOEM in the Federal Register 
notice.



Sec.  585.214  What will BOEM do with information from the Requests
 for Information or Calls for Information and Nominations?

    BOEM will use the information received in response to the Requests 
or Calls to:
    (a) Identify the lease area;
    (b) Develop options for the environmental analysis and leasing 
provisions (stipulations, payments, terms, and conditions); and
    (c) Prepare appropriate documentation to satisfy applicable Federal 
requirements, such as NEPA, CZMA, the ESA, and the MMPA.



Sec.  585.215  What areas will BOEM offer in a lease sale?

    BOEM will offer the areas for leasing determined through the process 
set forth in Sec.  585.211 of this part. We will not accept nominations 
after the Call for Information and Nominations closes.



Sec.  585.216  What information will BOEM publish in the Proposed Sale
 Notice and Final Sale Notice?

    For each competitive lease sale, BOEM will publish a Proposed Sale 
Notice and a Final Sale Notice in the Federal Register. In the Proposed 
Sale Notice, we will request public comment on the items listed in this 
section. We will consider all public comments received in developing the 
final lease sale terms and conditions. We will publish the final terms 
and conditions in the Final Sale Notice. The Proposed Sale Notice and 
Final Sale Notice will include, or describe the availability of, 
information pertaining to:
    (a) The area available for leasing.
    (b) Proposed and final lease provisions and conditions, including, 
but not limited to:
    (1) Lease size;
    (2) Lease term;
    (3) Payment requirements;
    (4) Performance requirements; and
    (5) Site-specific lease stipulations.
    (c) Auction details, including:
    (1) Bidding procedures and systems;
    (2) Minimum bid;
    (3) Deposit amount;
    (4) The place and time for filing bids and the place, date, and hour 
for opening bids;
    (5) Lease award method; and
    (6) Bidding or application instructions.
    (d) The official BOEM lease form to be used or a reference to that 
form.
    (e) Criteria BOEM will use to evaluate competing bids or 
applications and how the criteria will be used in decision-making for 
awarding a lease.
    (f) Award procedures, including how and when BOEM will award leases 
and how BOEM will handle unsuccessful bids or applications.

[[Page 588]]

    (g) Procedures for appealing the lease issuance decision.
    (h) Execution of the lease instrument.



Sec. Sec.  585.217-585.219  [Reserved]

                     Competitive Lease Award Process



Sec.  585.220  What auction format may BOEM use in a lease sale?

    (a) Except as provided in Sec.  585.231, we will hold competitive 
auctions to award renewable energy leases and will use one of the 
following auction formats, as determined through the lease sale process 
and specified in the Proposed Sale Notice and in the Final Sale Notice:

------------------------------------------------------------------------
       Type of auction            Bid variable         Bidding process
------------------------------------------------------------------------
(1) Sealed bidding..........  A cash bonus or an    One sealed bid per
                               operating fee rate.   company per lease
                                                     or packaged bidding
                                                     unit.
(2) Ascending bidding.......  A cash bonus or an    Continuous bidding
                               operating fee rate.   per lease.
(3) Two-stage bidding         An operating fee      Ascending or sealed
 (combination of ascending     rate in one, both,    bidding until:
 and sealed bidding).          or neither stage        (i) Only two
                               and a cash bonus in      bidders remain,
                               one, both, or            or
                               neither stage.          (ii) More than
                                                        one bidder
                                                        offers to pay
                                                        the maximum bid
                                                        amount.
                                                    Stage-two sealed or
                                                     ascending bidding
                                                     commences at some
                                                     predetermined time
                                                     after the end of
                                                     stage-one bidding.
(4) Multiple-factor bidding.  Factors may include,  One proposal per
                               but are not limited   company per lease
                               to: technical         or packaged bidding
                               merit, timeliness,    unit.
                               financing and
                               economics,
                               environmental
                               considerations,
                               public benefits,
                               compatibility with
                               State and local
                               needs, cash bonus,
                               rental rate, and an
                               operating fee rate.
------------------------------------------------------------------------

    (b) You must submit your bid and a deposit as specified in 
Sec. Sec.  585.500 and 585.501 to cover the bid for each lease area, 
according to the terms specified in the Final Sale Notice.



Sec.  585.221  What bidding systems may BOEM use for commercial leases
 and limited leases?

    (a) For commercial leases, we will specify minimum bids in the Final 
Sale Notice and use one of the following bidding systems, as specified 
in the Proposed Sale Notice and in the Final Sale Notice:

------------------------------------------------------------------------
               Bid system                          Bid variable
------------------------------------------------------------------------
(1) Cash bonus with a constant fee rate  Cash bonus.
 (decimal).
(2) Constant operating fee rate with     A fee rate used in the formula
 fixed cash bonus.                        found in Sec.   585.506 to set
                                          the operating fee per year
                                          during the operations term of
                                          your lease.
(3) Sliding operating fee rate with a    A fee rate used in the formula
 fixed cash bonus.                        in Sec.   585.506 to set the
                                          operating fee for the first
                                          year of the operations term of
                                          your lease. The fee rate for
                                          subsequent years changes by a
                                          mathematical function we
                                          specify in the Final Sale
                                          Notice.
(4) Cash bonus and constant operating    Cash bonus and operating fee
 fee rate.                                rate as stated in paragraph
                                          (2) of this section (two-stage
                                          auction format only).
(5) Cash bonus and sliding operating     Cash bonus and operating fee
 fee rate.                                rate as stated in paragraph
                                          (3) of this section (two-stage
                                          auction format only).
(6) Multiple-factor combination of       BOEM will identify bidding
 nonmonetary and monetary factors.        variables in the Final Sale
                                          Notice.
                                         Variables may include:
                                            (i) Nonmonetary (e.g.,
                                             technical merit) factors
                                             and
                                            (ii) Monetary (e.g., cash
                                             bonus, rental rate, fee
                                             rate) factors.
------------------------------------------------------------------------


[[Page 589]]

    (b) For limited leases, the bid variable will be a cash bonus, with 
a minimum bid as we specify in the Final Sale Notice.



Sec.  585.222  What does BOEM do with my bid?

    (a) If sealed bidding is used:
    (1) We open the sealed bids at the place, date, and hour specified 
in the Final Sale Notice for the sole purpose of publicly announcing and 
recording the bids. We do not accept or reject any bids at that time.
    (2) We reserve the right to reject any and all high bids, including 
a bid for any proposal submitted under the multiple-factor bidding 
format, regardless of the amount offered or bidding system used. The 
reasons for the rejection of a winning bid may include, but are not 
necessarily limited to, insufficiency, illegality, anti-competitive 
behavior, administrative error, and the presence of unusual bidding 
patterns. We intend to accept or reject all high bids within 90 days, 
but we may extend that time if necessary.
    (b) If we use ascending bidding, we may, in the Final Sale Notice, 
reserve the right to accept the winning bid solely based on its being 
the highest bid submitted by a qualified bidder (qualified to be an OCS 
lessee under Sec.  585.107).
    (c) If we use two-stage bidding and the auction concludes with
    (i) An ascending bidding stage, the winning bid will be determined 
as stated in paragraph (b) of this section; or
    (ii) A sealed bidding stage, the winning bid will be determined as 
stated in paragraph (a) of this section.
    (d) If we use multiple-factor bidding, determination of the winning 
bid for any proposal submitted will be made by a panel composed of 
members selected by BOEM. The details of the process will be described 
in the Final Sale Notice.
    (e) We will send a written notice of our decision to accept or 
reject bids to all bidders whose deposits we hold.



Sec.  585.223  What does BOEM do if there is a tie for the highest bid?

    (a) Unless otherwise specified in the Final Sale Notice, except in 
the first stage of a two-stage bidding auction, if more than one bidder 
on a lease submits the same high bid amount, the winning bidder will be 
determined by a further round or stage of bidding as described in the 
Final Sale Notice.
    (b) The winning bidder will be subject to final confirmation 
following determination of bid adequacy.



Sec.  585.224  What happens if BOEM accepts my bid?

    If we accept your bid, we will send you a notice with three copies 
of the lease form.
    (a) Within 10 business days after you receive the lease copies, you 
must:
    (1) Execute the lease;
    (2) File financial assurance as required under Sec. Sec.  585.515 
through 585.537; and
    (3) Pay the balance of the bonus bid as specified in the lease sale 
notice.
    (b) Within 45 days after you receive the lease copies, you must pay 
the first 12-months' rent as required in Sec.  585.503.
    (c) When you execute three copies of the lease and return the copies 
to us, we will execute the lease on behalf of the United States and send 
you one fully executed copy.
    (d) You will forfeit your deposit if you do not execute and return 
the lease within 10 business days of receipt, or otherwise fail to 
comply with applicable regulations or terms of the Final Sale Notice.
    (e) We may extend the 10 business day time period for executing and 
returning the lease if we determine the delay to be caused by events 
beyond your control.
    (f) We reserve the right to withdraw an OCS area in which we have 
held a lease sale before you and BOEM execute the lease in that area. If 
we exercise this right, we will refund your bid deposit, without 
interest.
    (g) If the awarded lease is executed by an agent acting on behalf of 
the bidder, the bidder must submit, along with the executed lease, 
written evidence that the agent is authorized to act on behalf of the 
bidder.
    (h) BOEM will consider the highest submitted qualified bid to be the 
winning bid when bidding occurs under the systems described in Sec.  
585.221(a)(1) through (5). We will determine the winning bid for 
proposals submitted under

[[Page 590]]

the multiple-factor bidding format on the basis of selection by the 
panel as specified in Sec.  585.222(d) when the bidding system under 
Sec.  585.221(a)(6) is used. We will refund the deposit on all other 
bids.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]



Sec.  585.225  What happens if my bid is rejected, and what are my
 appeal rights?

    (a) If we reject your bid, we will provide a written statement of 
the reasons and refund any money deposited with your bid, without 
interest.
    (b) You may ask the BOEM Director for reconsideration, in writing, 
within 15 business days of bid rejection, under Sec.  585.118(c)(1). We 
will send you a written response either affirming or reversing the 
rejection.



Sec. Sec.  585.226-585.229  [Reserved]

                   Noncompetitive Lease Award Process



Sec.  585.230  May I request a lease if there is no Call?

    You may submit an unsolicited request for a commercial lease or a 
limited lease under this part. Your unsolicited request must contain the 
following information:
    (a) The area you are requesting for lease.
    (b) A general description of your objectives and the facilities that 
you would use to achieve those objectives.
    (c) A general schedule of proposed activities including those 
leading to commercial operations.
    (d) Available and pertinent data and information concerning 
renewable energy and environmental conditions in the area of interest, 
including energy and resource data and information used to evaluate the 
area of interest. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and as provided in Sec.  
585.113.
    (e) If available from the appropriate State or local government 
authority, a statement that the proposed activity conforms with State 
and local energy planning requirements, initiatives, or guidance.
    (f) Documentation showing that you meet the qualifications to become 
a lessee, as specified in Sec.  585.107.
    (g) An acquisition fee, as specified in Sec.  585.502(a).



Sec.  585.231  How will BOEM process my unsolicited request for a 
noncompetitive lease?

    (a) BOEM will consider unsolicited requests for a lease on a case-
by-case basis and may issue a lease noncompetitively in accordance with 
this part. We will not consider an unsolicited request for a lease under 
this part that is proposed in an area of the OCS that is scheduled for a 
lease sale under this part.
    (b) BOEM will issue a public notice of a request for interest 
relating to your proposal and consider comments received to determine if 
competitive interest exists.
    (c) If BOEM determines that competitive interest exists in the lease 
area:
    (1) BOEM will proceed with the competitive process set forth in 
Sec. Sec.  585.210 through 585.225;
    (2) If you submit a bid for the lease area in a competitive lease 
sale, your acquisition fee will be applied to the deposit for your bonus 
bid; and
    (3) If you do not submit a bid for the lease area in a competitive 
lease sale, BOEM will not refund your acquisition fee.
    (d) If BOEM determines that there is no competitive interest in a 
lease, we will publish in the Federal Register a notice of Determination 
of No Competitive Interest. After BOEM publishes this notice, you will 
be responsible for submitting any required consistency certification and 
necessary data and information pursuant to 15 CFR part 930, subpart D to 
the applicable State CZMA agency or agencies and BOEM.
    (e) BOEM will coordinate and consult with affected Federal agencies, 
State, and local governments, and affected Indian tribes in the review 
of noncompetitive lease requests.
    (f) After completing the review of your lease request, BOEM may 
offer you a noncompetitive lease.
    (g) If you accept the terms and conditions of the lease, then we 
will issue

[[Page 591]]

the lease, and you must comply with all terms and conditions of your 
lease and all applicable provisions of this part. If we issue you a 
lease, we will send you a notice with 3 copies of the lease form.
    (1) Within 10 business days after you receive the lease copies you 
must:
    (i) Execute the lease;
    (ii) File financial assurance as required under Sec. Sec.  585.515 
through 585.537; and
    (2) Within 45 days after you receive the lease copies, you must pay 
the first 12-months' rent, as required in Sec.  585.503.
    (h) BOEM will publish in the Federal Register a notice announcing 
the issuance of your lease.
    (i) If you do not accept the terms and conditions, BOEM will not 
issue a lease, and we will not refund your acquisition fee.

[76 FR 64623, Oct. 18, 2011, as amended at 77 FR 1019, Jan. 9, 2012; 79 
FR 21622, Apr. 17, 2014]



Sec.  585.232  May I acquire a lease noncompetitively after responding
 to a Request for Interest or Call for Information and Nominations?

    (a) If you submit an area of interest for a possible lease and BOEM 
receives no competing submissions in response to the RFI or Call, we may 
inform you that there does not appear to be competitive interest, and 
ask if you wish to proceed with acquiring a lease.
    (b) If you wish to proceed with acquiring a lease, you must submit 
your acquisition fee as specified in Sec.  585.502(a).
    (c) After receiving the acquisition fee, BOEM will follow the 
process outlined in Sec.  585.231(d) through (i).

[76 FR 64623, Oct. 18, 2011, as amended at 77 FR 1019, Jan. 9, 2012]



Sec. Sec.  585.233-585.234  [Reserved]

                   Commercial and Limited Lease Terms



Sec.  585.235  If I have a commercial lease, how long will my lease
 remain in effect?

    (a) For commercial leases, the lease terms and applicable automatic 
extensions are as shown in the following table:

------------------------------------------------------------------------
         Lease term           Automatic extensions      Requirements
------------------------------------------------------------------------
(1) Each commercial lease     If BOEM receives a    The SAP must meet
 will have a preliminary       SAP that satisfies    the requirements of
 term of 12 months, within     the requirements of   Sec.  Sec.
 which the lessee must         Sec.  Sec.            585.605 through
 submit: (i) a SAP; or (ii)    585.605 through       585.613. The SAP/
 a combined SAP and            585.613 or a SAP/     COP must meet the
 Construction and Operations   COP that satisfies    requirements of
 Plan (COP). The preliminary   the requirements of   Sec.  Sec.
 term begins on the            Sec.  Sec.            585.605 through
 effective date of the lease.  585.605 through       585.613 and Sec.
                               585.613 and Sec.      Sec.   585.620
                               Sec.   585.620        through 585.629.
                               through 585.629,
                               the preliminary
                               term will be
                               extended for the
                               time necessary for
                               us to conduct
                               technical and
                               environmental
                               reviews of the SAP
                               or SAP/COP.
(2) A commercial lease will   If we receive a COP   The COP must meet
 have a site assessment term   that satisfies the    the requirements of
 of five years to conduct      requirements of       Sec.  Sec.
 site assessment activities    Sec.  Sec.            585.620 through
 and to submit a COP, if a     585.620 through       585.629 of this
 SAP/COP has not been          585.629, the site     part.
 submitted. Your site          assessment term
 assessment term begins when   will be
 BOEM approves your SAP or     automatically
 SAP/COP.                      extended for the
                               period of time
                               necessary for us to
                               conduct technical
                               and environmental
                               reviews of the COP.
(3) A commercial lease will   ....................  The lease renewal
 have an operations term of                          request must meet
 25 years, unless a longer                           the requirements in
 term is negotiated by the                           Sec.  Sec.
 parties. A request for                              585.425 through
 lease renewal must be                               585.429.
 submitted two years before
 the end of the operations
 term. If you submit a COP,
 your operations term begins
 on the date that BOEM
 approves the COP. If you
 submit a SAP/COP, your
 operations term begins on
 the earliest of the
 following dates: five years
 after BOEM approves the SAP/
 COP; when fabrication
 begins; or, when
 installation commences.

[[Page 592]]

 
(4) A commercial lease may    ....................  NOTE: BOEM may also
 have additional time added                          order or grant a
 to the operations term                              suspension of the
 through a lease renewal.                            operations term, as
 The term of the lease                               provided in Sec.
 renewal will not exceed the                         Sec.   585.415
 original term of the lease,                         through 585.421
 unless a longer term is                             thereby effectively
 negotiated by the parties.                          extending the term
 The lease renewal term                              of the lease.
 begins upon expiration of
 the original operations
 term.
------------------------------------------------------------------------

    (b) If you do not timely submit a SAP, COP, or SAP/COP, as 
appropriate, you may request additional time to extend the preliminary 
or site assessment term of your commercial lease that includes a revised 
schedule for submission of the plan, as appropriate.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21622, Apr. 17, 2014]



Sec.  585.236  If I have a limited lease, how long will my lease
 remain in effect?

    (a) For limited leases, the lease terms are as shown in the 
following table:

------------------------------------------------------------------------
                                  Extension or
         Lease term                suspension           Requirements
------------------------------------------------------------------------
(1) Each limited lease has a  If we receive a GAP   The GAP must meet
 preliminary term of 12        that satisfies the    the requirements of
 months to submit a GAP. The   requirements of       Sec.  Sec.
 preliminary term begins on    Sec.  Sec.            585.640 through
 the effective date of the     585.640 through       585.648.
 lease.                        585.648 of this
                               part, the
                               preliminary term
                               will be
                               automatically
                               extended for the
                               period of time
                               necessary for us to
                               conduct a technical
                               and environmental
                               review of the plans.
(2) Each limited lease has    We may order or
 an operations term of five    grant a suspension
 years for conducting site     of the operations
 assessment, technology        term as provided in
 testing, or other             Sec.  Sec.
 activities. The operations    585.415 through
 term begins on the date       585.421.
 that we approve your GAP.
------------------------------------------------------------------------

    (b) If you do not timely submit a GAP, you may request additional 
time to extend the preliminary term of your limited lease that includes 
a revised schedule for submission of a GAP.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21622, Apr. 17, 2014]



Sec.  585.237  What is the effective date of a lease?

    (a) A lease issued under this part must be dated and becomes 
effective as of the first day of the month following the date a lease is 
signed by the lessor.
    (b) If the lessee submits a written request and BOEM approves, a 
lease may be dated and become effective the first day of the month in 
which it is signed by the lessor.



Sec.  585.238  Are there any other renewable energy research activities
 that will be allowed on the OCS?

    (a) The Director may issue OCS leases, ROW grants, and RUE grants to 
a Federal agency or a State for renewable energy research activities 
that support the future production, transportation, or transmission of 
renewable energy.
    (b) In issuing leases, ROW grants, and RUE grants to a Federal 
agency or a State on the OCS for renewable energy research activities 
under this provision, BOEM will coordinate and consult with other 
relevant Federal agencies, any other affected State(s), affected local 
government executives, and affected Indian Tribes.
    (c) BOEM may issue leases, RUEs, and ROWs for research activities 
managed by a Federal agency or a State only in areas for which the 
Director

[[Page 593]]

has determined, after public notice and opportunity to comment, that no 
competitive interest exists.
    (d) The Director and the head of the Federal agency or the Governor 
of a requesting State, or their authorized representatives, will 
negotiate the terms and conditions of such renewable energy leases, 
RUEs, or ROWs under this provision on a case-by-case basis. The 
framework for such negotiations, and standard terms and conditions of 
such leases, RUEs, or ROWs may be set forth in a memorandum of agreement 
(MOA) or other agreement between BOEM and a Federal agency or a State. 
The MOA must include the agreement of the head of the Federal agency or 
the Governor to assure that all subcontractors comply with these 
regulations, other applicable laws, and terms and conditions of such 
leases or grants.
    (e) Any lease, RUE, or ROW that BOEM issues to a Federal agency or 
to a State that authorizes access to an area of the OCS for research 
activities managed by a Federal agency or a State must include:
    (1) Requirements to comply with all applicable Federal laws; and
    (2) Requirements to comply with these regulations, except as 
otherwise provided in the lease or grant.
    (f) BOEM will issue a public notice of any lease, RUE, ROW issued to 
a Federal agency or to a State, or an approved MOA for such research 
activities.
    (g) BOEM will not charge any fees for the purpose of ensuring a fair 
return for the use of such research areas on the OCS.



Subpart C_Rights-of-Way Grants and Rights-of-Use and Easement Grants for 
                       Renewable Energy Activities

                        ROW Grants and RUE Grants



Sec.  585.300  What types of activities are authorized by ROW grants
 and RUE grants issued under this part?

    (a) An ROW grant authorizes the holder to install on the OCS cables, 
pipelines, and associated facilities that involve the transportation or 
transmission of electricity or other energy product from renewable 
energy projects.
    (b) An RUE grant authorizes the holder to construct and maintain 
facilities or other installations on the OCS that support the 
production, transportation, or transmission of electricity or other 
energy product from any renewable energy resource.
    (c) You do not need an ROW grant or RUE grant for a project easement 
authorized under Sec.  585.200(b) to serve your lease.



Sec.  585.301  What do ROW grants and RUE grants include?

    (a) An ROW grant:
    (1) Includes the full length of the corridor on which a cable, 
pipeline, or associated facility is located;
    (2) Is 200 feet (61 meters) in width, centered on the cable or 
pipeline, unless safety and environmental factors during construction 
and maintenance of the associated cable or pipeline require a greater 
width; and
    (3) For the associated facility, is limited to the area reasonably 
necessary for a power or pumping station or other accessory facility.
    (b) An RUE grant includes the site on which a facility or other 
structure is located and the areal extent of anchors, chains, and other 
equipment associated with a facility or other structure. The specific 
boundaries of an RUE will be determined by BOEM on a case-by-case basis 
and set forth in each RUE grant.



Sec.  585.302  What are the general requirements for ROW grant and
 RUE grant holders?

    (a) To acquire an ROW grant or RUE grant you must provide evidence 
that you meet the qualifications as required in Sec.  585.107.
    (b) An ROW grant or RUE grant is subject to the following 
conditions:
    (1) The rights granted will not prevent the granting of other rights 
by the United States, either before or after the granting of the ROW or 
RUE, provided that any subsequent authorization issued by BOEM in the 
area of a previously issued ROW grant or RUE grant may not unreasonably 
interfere

[[Page 594]]

with activities approved or impede existing operations under such a 
grant; and
    (2) The holder agrees that the United States, its lessees, or other 
ROW grant or RUE grant holders may use or occupy any part of the ROW 
grant or RUE grant not actually occupied or necessarily incident to its 
use for any necessary activities.



Sec.  585.303  How long will my ROW grant or RUE grant remain in effect?

    (a) Each ROW or RUE grant will have a preliminary term of 12 months 
from the date of issuance of the ROW or RUE grant within which to submit 
a GAP. The preliminary term begins on the effective date of the grant. 
You must submit a GAP no later than the end of the preliminary term for 
your grant to remain in effect. However, you may submit a GAP prior to 
the issuance of your ROW or RUE grant.
    (b) Except as described in paragraph (a) of this section, your ROW 
grant or RUE grant will remain in effect for as long as the associated 
activities are properly maintained and used for the purpose for which 
the grant was made, unless otherwise expressly stated in the grant.

[79 FR 21623, Apr. 17, 2014]



Sec.  585.304  [Reserved]

                   Obtaining ROW Grants and RUE Grants



Sec.  585.305  How do I request an ROW grant or RUE grant?

    You must submit to BOEM one paper copy and one electronic copy of a 
request for a new or modified ROW grant or RUE grant. You must submit a 
separate request for each ROW grant or RUE grant you are requesting. The 
request must contain the following information:
    (a) The area you are requesting for a ROW grant or RUE grant.
    (b) A general description of your objectives and the facilities that 
you would use to achieve those objectives.
    (c) A general schedule of proposed activities.
    (d) Pertinent information concerning environmental conditions in the 
area of interest.



Sec.  585.306  What action will BOEM take on my request?

    BOEM will consider requests for ROW grants and RUE grants on a case-
by-case basis and may issue a grant competitively, as provided in Sec.  
585.308, or noncompetitively if we determine after public notice that 
there is no competitive interest. BOEM will coordinate and consult with 
relevant Federal agencies, with the Governor of any affected State, and 
the executive of any affected local government.
    (a) In response to an unsolicited request for a ROW grant or RUE 
grant, the BOEM will first determine if there is competitive interest, 
as provided in Sec.  585.307.
    (b) If BOEM determines that there is no competitive interest in a 
ROW grant or RUE grant, we will publish a notice in the Federal Register 
of such determination. After BOEM publishes this notice, you will be 
responsible for submitting any required consistency certification and 
necessary data and information pursuant to 15 CFR part 930, subpart D to 
the applicable State CZMA agency or agencies and BOEM. We will establish 
terms and conditions for the grant in consultation with you.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.307  How will BOEM determine whether competitive interest
 exists for ROW grants and RUE grants?

    To determine whether or not there is competitive interest:
    (a) We will publish a public notice, describing the parameters of 
the project, to give affected and interested parties an opportunity to 
comment on the proposed ROW grant or RUE grant area.
    (b) We will evaluate any comments received on the notice and make a 
determination of the level of competitive interest.



Sec.  585.308  How will BOEM conduct an auction for ROW grants and
 RUE grants?

    (a) If BOEM determines that there is competitive interest, we will:
    (1) Publish a notice of each grant auction in the Federal Register 
describing auction procedures, allowing

[[Page 595]]

interested persons 30 days to comment; and
    (2) Conduct a competitive auction for issuing the ROW grant or RUE 
grant. The auction process for ROW grants and RUE grants will be 
conducted following the same process for leases set forth in Sec. Sec.  
585.211 through 585.225.
    (b) If you are the successful bidder in an auction, you must pay the 
first year's rent, as provided in Sec.  585.316.



Sec.  585.309  When will BOEM issue a noncompetitive ROW grant or
 RUE grant?

    After completing the review of your grant request, BOEM may offer 
you a noncompetitive grant.
    (a) If you accept the terms and conditions of the grant, then we 
will issue the grant, and you must comply with all terms and conditions 
of your grant and all applicable provisions of this part.
    (b) If you do not accept the terms and conditions, BOEM will not 
issue a grant.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.310  What is the effective date of an ROW grant or
 RUE grant?

    Your ROW grant or RUE grant becomes effective on the date 
established by BOEM on the ROW grant or RUE grant instrument.



Sec. Sec.  585.311-585.314  [Reserved]

          Financial Requirements for ROW Grants and RUE Grants



Sec.  585.315  What deposits are required for a competitive
 ROW grant or RUE grant?

    (a) You must make a deposit, as required in Sec.  585.501(a), 
regardless of whether the auction is a sealed-bid, oral, electronic, or 
other auction format. BOEM will specify in the sale notice the official 
to whom you must submit the payment, the time by which the official must 
receive the payment, and the forms of acceptable payment.
    (b) If your high bid is rejected, we will provide a written 
statement of reasons.
    (c) For all rejected bids, we will refund, without interest, any 
money deposited with your bid.



Sec.  585.316  What payments are required for ROW grants or RUE grants?

    Before we issue the ROW grant or RUE grant, you must pay:
    (a) Any balance on accepted high bids to BOEM, as provided in the 
sale notice.
    (b) An annual rent for the first year of the grant, as specified in 
Sec.  585.508.



                Subpart D_Lease and Grant Administration

                   Noncompliance and Cessation Orders



Sec.  585.400  What happens if I fail to comply with this part?

    (a) BOEM may take appropriate corrective action under this part if 
you fail to comply with applicable provisions of Federal law, the 
regulations in this part, other applicable regulations, any order of the 
Director, the provisions of a lease or grant issued under this part, or 
the requirements of an approved plan or other approval under this part.
    (b) BOEM may issue to you a notice of noncompliance if we determine 
that there has been a violation of the regulations in this part, any 
order of the Director, or any provision of your lease, grant or other 
approval issued under this part. When issuing a notice of noncompliance, 
BOEM will serve you at your last known address.
    (c) A notice of noncompliance will tell you how you failed to comply 
with this part, any order of the Director, and/or the provisions of your 
lease, grant or other approval, and will specify what you must do to 
correct the noncompliance and the time limits within which you must act.
    (d) Failure of a lessee, operator, or grant holder under this part 
to take the actions specified in a notice of noncompliance within the 
time limit specified provides the basis for BOEM to issue a cessation 
order as provided in Sec.  585.401, and/or a cancellation of the lease 
or grant as provided in Sec.  585.437.
    (e) If BOEM determines that any incident of noncompliance poses an 
imminent threat of serious or irreparable damage to natural resources; 
life (including human and wildlife); property; the marine, coastal, or 
human environment; or sites, structures, or objects of

[[Page 596]]

historical or archaeological significance, BOEM may include with its 
notice of noncompliance an order directing you to take immediate 
remedial action to alleviate threats and to abate the violation and, 
when appropriate, a cessation order.
    (f) The BOEM may assess civil penalties, as authorized by section 24 
of the OCS Lands Act, if you fail to comply with any provision of this 
part or any term of a lease, grant, or order issued under the authority 
of this part, after notice of such failure and expiration of any 
reasonable period allowed for corrective action. Civil penalties will be 
determined and assessed in accordance with the procedures set forth in 
30 CFR part 550, subpart N.
    (g) You may be subject to criminal penalties as authorized by 
section 24 of the OCS Lands Act.



Sec.  585.401  When may BOEM issue a cessation order?

    (a) BOEM may issue a cessation order during the term of your lease 
or grant when you fail to comply with an applicable law; regulation; 
order; or provision of a lease, grant, plan, or other BOEM approval 
under this part. Except as provided in Sec.  585.400(e), BOEM will allow 
you a period of time to correct any noncompliance before issuing an 
order to cease activities.
    (b) A cessation order will set forth what measures you are required 
to take, including reports you are required to prepare and submit to 
BOEM, to receive approval to resume activities on your lease or grant.



Sec.  585.402  What is the effect of a cessation order?

    (a) Upon receiving a cessation order, you must cease all activities 
on your lease or grant, as specified in the order. BOEM may authorize 
certain activities during the period of the cessation order.
    (b) A cessation order will last for the period specified in the 
order or as otherwise specified by BOEM. If BOEM determines that the 
circumstances giving rise to the cessation order cannot be resolved 
within a reasonable time period, the Secretary may initiate cancellation 
of your lease or grant, as provided in Sec.  585.437.
    (c) A cessation order does not extend the term of your lease or 
grant for the period you are prohibited from conducting activities.
    (d) You must continue to make all required payments on your lease or 
grant during the period a cessation order is in effect.



Sec. Sec.  585.403-585.404  [Reserved]

                         Designation of Operator



Sec.  585.405  How do I designate an operator?

    (a) If you intend to designate an operator who is not the lessee or 
grant holder, you must identify the proposed operator in your SAP (under 
Sec.  585.610(a)(3)), COP (under Sec.  585.626(b)(2)), or GAP (under 
Sec.  585.645(b)(3)), as applicable. If no operator is designated in a 
SAP, COP, or GAP, BOEM will deem the lessee or grant holder to be the 
operator.
    (b) An operator must be designated in any SAP, COP, or GAP if there 
is more than one lessee or grant holder for any individual lease or 
grant.
    (c) Once approved in your plan, the designated operator is 
authorized to act on your behalf and required to perform activities 
necessary to comply with the OCS Lands Act, the lease or grant, and the 
regulations in this part.
    (d) You, or your designated operator, must immediately provide BOEM 
with a written notification of change of address of the lessee or 
operator.
    (e) If there is a change in the designated operator, you must 
provide written notice to BOEM and identify the new designated operator 
within 72 hours on a form approved by BOEM. The lessee(s) or grantee(s) 
is the operator and responsible for compliance until BOEM approves 
designation of the new operator.
    (f) Designation of an operator under any lease or grant issued under 
this part does not relieve the lessee or grant holder of its obligations 
under this part or its lease or grant.
    (g) A designated operator performing activities on the lease must 
comply with all regulations governing those activities and may be held 
liable or penalized for any noncompliance during the time it was 
operator, notwithstanding its subsequent resignation.

[[Page 597]]



Sec.  585.406  Who is responsible for fulfilling lease and grant
 obligations?

    (a) When you are not the sole lessee or grantee, you and your co-
lessee(s) or co-grantee(s) are jointly and severally responsible for 
fulfilling your obligations under the lease or grant and the provisions 
of this part, unless otherwise provided in these regulations.
    (b) If your designated operator fails to fulfill any of your 
obligations under the lease or grant and this part, BOEM may require you 
or any or all of your co-lessees or co-grantees to fulfill those 
obligations or other operational obligations under the OCS Lands Act, 
the lease, grant, or the regulations.
    (c) Whenever the regulations in this part require the lessee or 
grantee to conduct an activity in a prescribed manner, the lessee or 
grantee and operator (if one has been designated) are jointly and 
severally responsible for complying with the regulations.



Sec.  585.407  [Reserved]

                        Lease or Grant Assignment



Sec.  585.408  May I assign my lease or grant interest?

    (a) You may assign all or part of your lease or grant interest, 
including record title, subject to BOEM approval under this subpart. 
Each instrument that creates or transfers an interest must describe the 
entire tract or describe by officially designated subdivisions the 
interest you propose to create or transfer.
    (b) You may assign a lease or grant interest by submitting one paper 
copy and one electronic copy of an assignment application to BOEM. The 
assignment application must include:
    (1) BOEM-assigned lease or grant number;
    (2) A description of the geographic area or undivided interest you 
are assigning;
    (3) The names of both the assignor and the assignee, if applicable;
    (4) The names and telephone numbers of the contacts for both the 
assignor and the assignee;
    (5) The names, titles, and signatures of the authorizing officials 
for both the assignor and the assignee;
    (6) A statement that the assignee agrees to comply with and to be 
bound by the terms and conditions of the lease or grant;
    (7) The qualifications of the assignee to hold a lease or grant 
under Sec.  585.107; and
    (8) A statement on how the assignee will comply with the financial 
assurance requirements of Sec. Sec.  585.515 through 585.537. No 
assignment will be approved until the assignee provides the required 
financial assurance.
    (c) If you submit an application to assign a lease or grant, you 
will continue to be responsible for payments that are or become due on 
the lease or grant until the date BOEM approves the assignment.
    (d) The assignment takes effect on the date BOEM approves your 
application.
    (e) You do not need to request an assignment for mergers, name 
changes, or changes of business form. You must notify BOEM of these 
events under Sec.  585.109.



Sec.  585.409  How do I request approval of a lease or grant assignment?

    (a) You must request approval of each assignment on a form approved 
by BOEM, and submit originals of each instrument that creates or 
transfers ownership of record title or certified copies thereof within 
90 days after the last party executes the transfer agreement.
    (b) Any assignee will be subject to all the terms and conditions of 
your original lease or grant, including the requirement to furnish 
financial assurance in the amount required in Sec. Sec.  585.515 through 
585.537.
    (c) The assignee must submit proof of eligibility and other 
qualifications specified in Sec.  585.107.
    (d) Persons executing on behalf of the assignor and assignee must 
furnish evidence of authority to execute the assignment.



Sec.  585.410  How does an assignment affect the assignor's liability?

    As assignor, you are liable for all obligations, monetary and 
nonmonetary, that accrued under your lease or grant before BOEM approves 
your assignment. Our approval of the assignment

[[Page 598]]

does not relieve you of these accrued obligations. BOEM may require you 
to bring the lease or grant into compliance to the extent the obligation 
accrued before the effective date of your assignment if your assignee or 
subsequent assignees fail to perform any obligation under the lease or 
grant.



Sec.  585.411  How does an assignment affect the assignee's liability?

    (a) As assignee, you are liable for all lease or grant obligations 
that accrue after BOEM approves the assignment. As assignee, you must 
comply with all the terms and conditions of the lease or grant and all 
applicable regulations, remedy all existing environmental and 
operational problems on the lease or grant, and comply with all 
decommissioning requirements under subpart I of this part.
    (b) Assignees are bound to comply with each term or condition of the 
lease or grant and the regulations in this subchapter. You are jointly 
and severally liable for the performance of all obligations under the 
lease or grant and under the regulations in this part with each prior 
and subsequent lessee who held an interest from the time the obligation 
accrued until it is satisfied, unless this part provides otherwise.



Sec. Sec.  585.412-585.414  [Reserved]

                        Lease or Grant Suspension



Sec.  585.415  What is a lease or grant suspension?

    (a) A suspension is an interruption of the term of your lease or 
grant that may occur:
    (1) As approved by BOEM at your request, as provided in Sec.  
585.416; or
    (2) As ordered by BOEM, as provided in Sec.  585.417.
    (b) A suspension extends the term of your lease or grant for the 
length of time the suspension is in effect.
    (c) Activities may not be conducted on your lease or grant during 
the period of a suspension except as expressly authorized by BOEM under 
the terms of the suspension.



Sec.  585.416  How do I request a lease or grant suspension?

    You must submit a written request to BOEM that includes the 
following information no later than 90 days prior to the expiration of 
your appropriate lease or grant term:
    (a) The reasons you are requesting suspension of your lease or grant 
term, and the length of additional time requested.
    (b) An explanation of why the suspension is necessary in order to 
ensure full enjoyment of your lease or grant and why it is in the 
lessor's or grantor's interest to approve the suspension.
    (c) If you do not timely submit a SAP, COP, or GAP, as required, you 
may request a suspension to extend the preliminary or site assessment 
term of your lease or grant that includes a revised schedule for 
submission of a SAP, COP, or GAP, as appropriate.
    (d) Any other information BOEM may require.



Sec.  585.417  When may BOEM order a suspension?

    (a) BOEM may order a suspension under the following circumstances:
    (1) When necessary to comply with judicial decrees prohibiting some 
or all activities under your lease;
    (2) When continued activities pose an imminent threat of serious or 
irreparable harm or damage to natural resources; life (including human 
and wildlife); property; the marine, coastal, or human environment; or 
sites, structures, or objects of historical or archaeological 
significance; or
    (3) When the suspension is necessary for reasons of National 
security or defense.
    (b) If BOEM orders a suspension under paragraph (a)(2) of this 
section, and if you wish to resume activities, we may require you to 
conduct a site-specific study that evaluates the cause of the harm, the 
potential damage, and the available mitigation measures. Other 
requirements and actions may occur:
    (1) You may be required to pay for the study;
    (2) You must furnish one paper copy and one electronic copy of the 
study and results to us;
    (3) We will make the results available to other interested parties 
and to the public; and

[[Page 599]]

    (4) We will use the results of the study and any other information 
that become available:
    (i) To decide if the suspension order can be lifted; and
    (ii) To determine any actions that you must take to mitigate or 
avoid any damage to natural resources; life (including human and 
wildlife); property; the marine, coastal, or human environment; or 
sites, structures, or objects of historical or archaeological 
significance.



Sec.  585.418  How will BOEM issue a suspension?

    (a) BOEM will issue a suspension order orally or in writing.
    (b) BOEM will send you a written suspension order as soon as 
practicable after issuing an oral suspension order.
    (c) The written order will explain the reasons for its issuance and 
describe the effect of the suspension order on your lease or grant and 
any associated activities. BOEM may authorize certain activities during 
the period of the suspension, as set forth in the suspension order.



Sec.  585.419  What are my immediate responsibilities if I receive
 a suspension order?

    You must comply with the terms of a suspension order upon receipt 
and take any action prescribed within the time set forth therein.



Sec.  585.420  What effect does a suspension order have on my payments?

    (a) While BOEM evaluates your request for a suspension under Sec.  
585.416, you must continue to fulfill your payment obligation until the 
end of the original term of your lease or grant. If our evaluation goes 
beyond the end of the original term of your lease or grant, the term of 
your lease or grant will be extended for the period of time necessary 
for BOEM to complete its evaluation of your request, but you will not be 
required to make payments during the time of the extension.
    (b) If BOEM approves your request for a suspension, as provided in 
Sec.  585.416, we may suspend your payment obligation, as appropriate 
for the term that is suspended, depending on the reasons for the 
requested suspension.
    (c) If BOEM orders a suspension, as provided in Sec.  585.417, your 
payments, as appropriate for the term that is suspended, will be waived 
during the suspension period.



Sec.  585.421  How long will a suspension be in effect?

    A suspension will be in effect for the period specified by BOEM.
    (a) BOEM will not approve a suspension request pursuant to Sec.  
585.416 for a period longer than 2 years.
    (b) If BOEM determines that the circumstances giving rise to a 
suspension ordered under Sec.  585.417 cannot be resolved within 5 
years, the Secretary may initiate cancellation of the lease or grant, as 
provided in Sec.  585.437.



Sec. Sec.  585.422-585.424  [Reserved]

                         Lease or Grant Renewal



Sec.  585.425  May I obtain a renewal of my lease or grant before
 it terminates?

    You may request renewal of the operations term of your lease or the 
original authorized term of your grant. BOEM, at its discretion, may 
approve a renewal request to conduct substantially similar activities as 
were originally authorized under the lease or grant. BOEM will not 
approve a renewal request that involves development of a type of 
renewable energy not originally authorized in the lease or grant. BOEM 
may revise or adjust payment terms of the original lease, as a condition 
of lease renewal.



Sec.  585.426  When must I submit my request for renewal?

    (a) You must request a renewal from BOEM:
    (1) No later than 180 days before the termination date of your 
limited lease or grant.
    (2) No later than 2 years before the termination date of the 
operations term of your commercial lease.
    (b) You must submit to BOEM all information we request pertaining to 
your lease or grant and your renewal request.



Sec.  585.427  How long is a renewal?

    BOEM will set the term of a renewal at the time of renewal on a 
case-by-case basis.

[[Page 600]]

    (a) For commercial leases, a renewal term will not exceed the 
original operations term unless a longer term is negotiated by the 
applicable parties.
    (b) For limited leases, a renewal term will not exceed the original 
operations term.
    (c) For RUE and ROW grants, a renewal will continue for as long as 
the associated activities are conducted and facilities properly 
maintained and used for the purpose for which the grant was made, unless 
otherwise expressly stated.



Sec.  585.428  What effect does applying for a renewal have on my
 activities and payments?

    If you timely request a renewal:
    (a) You may continue to conduct activities approved under your lease 
or grant under the original terms and conditions for as long as your 
request is pending decision by BOEM.
    (b) You may request a suspension of your lease or grant, as provided 
in Sec.  585.416, while we consider your request.
    (c) For the period BOEM considers your request for renewal, you must 
continue to make all payments in accordance with the original terms and 
conditions of your lease or grant.



Sec.  585.429  What criteria will BOEM consider in deciding whether
 to renew a lease or grant?

    BOEM will consider the following criteria in deciding whether to 
renew a lease or grant:
    (a) Design life of existing technology.
    (b) Availability and feasibility of new technology.
    (c) Environmental and safety record of the lessee or grantee.
    (d) Operational and financial compliance record of the lessee or 
grantee.
    (e) Competitive interest and fair return considerations.
    (f) Effects of the lease or grant on generation capacity and 
reliability within the regional electrical distribution and transmission 
system.



Sec. Sec.  585.430-585.431  [Reserved]

                       Lease or Grant Termination



Sec.  585.432  When does my lease or grant terminate?

    Your lease or grant terminates on whichever of the following dates 
occurs first:
    (a) The expiration of the applicable term of your lease or grant, 
unless your term is automatically extended under Sec.  585.235 or Sec.  
585.236, a request for renewal of your lease or grant is pending a 
decision by BOEM, or your lease or grant is suspended or renewed as 
provided in this subpart;
    (b) A cancellation, as set forth in Sec.  585.437; or
    (c) Relinquishment, as set forth in Sec.  585.435.



Sec.  585.433  What must I do after my lease or grant terminates?

    (a) After your lease or grant terminates, you must:
    (1) Make all payments due, including any accrued rentals and 
deferred bonuses; and
    (2) Perform any other outstanding obligations under the lease or 
grant within 6 months.
    (b) Within 2 years following termination of a lease or grant, you 
must remove or dispose of all facilities, installations, and other 
devices permanently or temporarily attached to the seabed on the OCS in 
accordance with a plan or application approved by BOEM under subpart I 
of this part.
    (c) If you fail to comply with your approved decommissioning plan or 
application:
    (1) BOEM may call for the forfeiture of your financial assurance; 
and
    (2) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure.



Sec.  585.434  [Reserved]

                      Lease or Grant Relinquishment



Sec.  585.435  How can I relinquish a lease or a grant or parts of 
a lease or grant?

    (a) You may surrender the lease or grant, or an officially 
designated subdivision thereof, by filing one paper

[[Page 601]]

copy and one electronic copy of a relinquishment application with BOEM. 
A relinquishment takes effect on the date we approve your application, 
subject to the continued obligation of the lessee and the surety to:
    (1) Make all payments due on the lease or grant, including any 
accrued rent and deferred bonuses;
    (2) Decommission all facilities on the lease or grant to be 
relinquished to the satisfaction of BOEM; and
    (3) Perform any other outstanding obligations under the lease or 
grant.
    (b) Your relinquishment application must include:
    (1) Name;
    (2) Contact name;
    (3) Telephone number;
    (4) Fax number;
    (5) E-mail address;
    (6) BOEM-assigned lease or grant number, and, if applicable, the 
name of any facility;
    (7) A description of the geographic area you are relinquishing;
    (8) The name, title, and signature of your authorizing official (the 
name, title, and signature must match exactly the name, title, and 
signature in BOEM qualification records); and
    (9) A statement that you will adhere to the requirements of subpart 
I of this part.
    (c) If you have submitted an application to relinquish a lease or 
grant, you will be billed for any outstanding payments that are due 
before the relinquishment takes effect, as provided in paragraph (a) of 
this section.

                       Lease or Grant Contraction



Sec.  585.436  Can BOEM require lease or grant contraction?

    At an interval no more frequent than every 5 years, the BOEM may 
review your lease or grant area to determine whether the lease or grant 
area is larger than needed to develop the project and manage activities 
in a manner that is consistent with the provisions of this part. BOEM 
will notify you of our proposal to contract the lease or grant area.
    (a) BOEM will give you the opportunity to present orally or in 
writing information demonstrating that you need the area in question to 
manage lease or grant activities consistent with these regulations.
    (b) Prior to taking action to contract the lease or grant area, BOEM 
will issue a decision addressing your contentions that the area is 
needed.
    (c) You may appeal this decision under Sec.  585.118 of this part.

                       Lease or Grant Cancellation



Sec.  585.437  When can my lease or grant be canceled?

    (a) The Secretary will cancel any lease or grant issued under this 
part upon proof that it was obtained by fraud or misrepresentation, and 
after notice and opportunity to be heard has been afforded to the lessee 
or grant holder.
    (b) The Secretary may cancel any lease or grant issued under this 
part when:
    (1) The Secretary determines after notice and opportunity for a 
hearing that, with respect to the lease or grant that would be canceled, 
the lessee or grantee has failed to comply with any applicable provision 
of the OCS Lands Act or these regulations; any order of the Director; or 
any term, condition or stipulation contained in the lease or grant, and 
that the failure to comply continued 30 days (or other period BOEM 
specifies) after you receive notice from BOEM. The Secretary will mail a 
notice by registered or certified letter to the lessee or grantee at its 
record post office address;
    (2) The Secretary determines after notice and opportunity for a 
hearing that you have terminated commercial operations under your COP, 
as provided in Sec.  585.635, or other approved activities under your 
GAP, as provided in Sec.  585.656;
    (3) Required by National security or defense; or
    (4) The Secretary determines after notice and opportunity for a 
hearing that continued activity under the lease or grant:
    (i) Would cause serious harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance; and

[[Page 602]]

    (ii) That the threat of harm or damage would not disappear or 
decrease to an acceptable extent within a reasonable period of time; and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing the lease or grant in force.



         Subpart E_Payments and Financial Assurance Requirements

                                Payments



Sec.  585.500  How do I make payments under this part?

    (a) For acquisition fees or the initial 12-months' rent paid for the 
preliminary term of your lease, you must make your electronic payments 
through the Fees for Services page on the BOEM Web site at http://
www.boem.gov, and you must include one copy of the Pay.gov confirmation 
receipt page with your unsolicited request.
    (b) For all other required rent payments and for operating fee 
payments, you must make your payments as required in 30 CFR 1218.51.
    (c) This table summarizes payments you must make for leases and 
grants, unless otherwise specified in the Final Sale Notice:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Payment                 Amount                 Due date          Payment mechanism      Section reference
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Initial payments for leases
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) If your lease is issued          Bid Deposit...........  As set in Final Sale    With bid.............  Pay.Gov..............  Sec.   585.501.
 competitively,                                               Notice/depends on bid.
                                     Bonus Balance.........  ......................  Lease issuance.......  30 CFR 1218.51.......
(2) If your lease is issued non-     Acquisition Fee.......  $0.25 per acre, unless  With application.....  Pay.gov..............  Sec.   585.502.
 competitively.                                               otherwise set by the
                                                              Director.
(3) All leases.....................  Initial Rent..........  $3 per acre per year..  45 days after lease    Pay.gov..............  Sec.   585.503.
                                                                                      issuance.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  Subsequent payments for leases and project easements
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) All leases.....................  Subsequent Rent.......  $3 per acre per year..  Annually.............  30 CFR 1218.51.......  Sec.  Sec.   585.503
                                                                                                                                    and 585.504.
(5) If you have a project easement.  Rent..................  Greater of $5 per acre  When operations term   30 CFR 1218.51.......  Sec.   585.507.
                                                              per year or $450 per    for associated lease
                                                              year.                   starts, then
                                                                                      annually.
(7) If your commercial lease is      Operating Fee.........  Determined by the       Annually.............  30 CFR 1218.51.......  Sec.   585.506.
 producing,                                                   formula in Sec.
                                                              585.506.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         Payments for ROW grants and RUE grants*
--------------------------------------------------------------------------------------------------------------------------------------------------------
(8) All ROW grants and RUE grants..  Initial Rent..........  $70 per statute mile,   Grant Issuance.......  Pay.gov..............  Sec.   585.508.
                                                              and the greater of $5
                                                              per acre per year or
                                                              $450 per year.
                                     Subsequent Rent.......  ......................  Annually or in 5-year  30 CFR 1218.51.......
                                                                                      batches.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* There is no acquisition fee for ROW grants or RUE grants.


[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.501  What deposits must I submit for a competitively issued
 lease, ROW grant, or RUE grant?

    (a) For a competitive lease or grant that we offer through sealed 
bidding, you must submit a deposit of 20 percent of the total bid 
amount, unless some other amount is specified in the Final Sale Notice.
    (b) For a competitive lease that we offer through ascending bidding, 
you must submit a deposit as established in the Final Sale Notice.

[[Page 603]]

    (c) You must pay any balances on accepted high bids in accordance 
with the Final Sale Notice, this part, and your lease or grant 
instrument.
    (d) The deposit will be forfeited for any successful bidder who 
fails to execute the lease within the prescribed time, or otherwise does 
not comply with the regulations concerning acquisition of a lease or 
grant or stipulations in the Final Sale Notice.



Sec.  585.502  What initial payment requirements must I meet to obtain
 a noncompetitive lease, ROW grant, or RUE grant?

    When requesting a noncompetitive lease, you must meet the initial 
payment (acquisition fee) requirements of this section, unless specified 
otherwise in your lease instrument. No initial payment is required when 
requesting noncompetitive ROW grants and RUE grants.
    (a) If you request a noncompetitive lease, you must submit an 
acquisition fee of $0.25 per acre, unless otherwise set by the Director, 
as provided in Sec.  585.500.
    (b) If BOEM determines there is no competitive interest, we will 
then:
    (1) Retain your acquisition fee if we issue you a lease; or
    (2) Refund your acquisition fee, without interest, if we do not 
issue your requested lease.
    (c) If we determine that there is a competitive interest in an area 
you requested, then we will proceed with a competitive lease sale 
process provided for in subpart B of this part, and we will:
    (1) Apply your acquisition fee to the required deposit for your bid 
amount if you submit a bid;
    (2) Apply your acquisition fee to your bonus bid if you acquire the 
lease; or
    (3) Retain your acquisition fee if you do not bid for or acquire the 
lease.



Sec.  585.503  What are the rent and operating fee requirements for
 a commercial lease?

    (a) The rent for a commercial lease is $3 per acre per year, unless 
otherwise established in the Final Sale Notice or lease.
    (1) You must pay ONRR the initial 12-months' rent 45 days after you 
receive the lease copies from BOEM in accordance with the requirements 
provided in Sec.  585.500(a).
    (2) You must pay ONRR, under the regulations at 30 CFR part 1218, 
rent at the beginning of each subsequent 1-year period in accordance 
with the regulations at 30 CFR 1218.51 for the entire lease area until 
the facility begins to generate commercially, as specified in Sec.  
585.506 or as otherwise specified in the Final Sale Notice or lease 
instrument:
    (i) For leases issued competitively, the BOEM will specify in the 
Final Sale Notice and lease any adjustment to the rent fee to take 
effect during the operations term and prior to the commercial 
generation.
    (ii) For leases issued noncompetitively, the BOEM will specify in 
the lease any adjustment to the rent fee to take effect during the 
operations term and prior to the commercial generation.
    (3) You must pay ONRR, under the regulations at 30 CFR part 1218, 
the rent for a project easement in addition to the lease rent, as 
provided in Sec.  585.507. You must commence rent payments for your 
project easement upon our approval of your COP or GAP.
    (b) After your lease begins commercial generation of electricity or 
on the date specified by BOEM, you must pay operating fees in the amount 
specified in Sec.  585.506:
    (1) For leases issued competitively, BOEM will specify in the Final 
Sale Notice and lease the date when operating fees commence; and
    (2) For leases issued noncompetitively, BOEM will specify in the 
lease the date when operating fee commences.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.504  How are my payments affected if I develop my lease
 in phases?

    If you develop your commercial lease in phases, as approved by us in 
your COP under Sec.  585.629, you must pay ONRR, under the regulations 
at 30 CFR part 1218:
    (a) Rent on the portion of the lease that is not authorized for 
commercial operations.

[[Page 604]]

    (b) Operating fees on the portion of the lease that is authorized 
for commercial operations, in the amount specified in Sec.  585.506 and 
as described in Sec.  585.503(b).
    (c) Rent for a project easement in addition to lease rent, as 
provided in Sec.  585.507. You must commence rent payments for your 
project easement upon our approval of your COP.



Sec.  585.505  What are the rent and operating fee requirements
 for a limited lease?

    (a) The rent for a limited lease is $3 per acre per year, unless 
otherwise established in the Final Sale Notice and your lease 
instrument.
    (b) You must pay ONRR the initial 12-months' rent 45 days after you 
receive the lease copies from BOEM in accordance with the requirements 
provided in Sec.  585.500(a).
    (c) You must pay ONRR, under the regulations at 30 CFR part 1218, 
rent at the beginning of each subsequent 1-year period on the entire 
lease area for the duration of your operations term in accordance with 
the regulations at 30 CFR 1218.51.
    (d) BOEM will not charge an operating fee for the authorized sale of 
power from a limited lease.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.506  What operating fees must I pay on a commercial
 lease?

    If you are generating electricity, you must pay ONRR, under the 
regulations at 30 CFR part 1218, operating fees on your commercial lease 
when you begin commercial generation, as described in Sec.  585.503.
    (a) BOEM will determine the annual operating fee for activities 
relating to the generation of electricity on your lease based on the 
following formula,

F = M * H * c * P * r,

Where:

(1) F is the dollar amount of the annual operating fee;
(2) M is the nameplate capacity expressed in megawatts;
(3) H is the number of hours in a year, equal to 8,760, used to 
          calculate an annual payment;
(4) c is the ``capacity factor'' representing the anticipated efficiency 
          of the facility's operation expressed as a decimal between 
          zero and one;
(5) P is a measure of the annual average wholesale electric power price 
          expressed in dollars per megawatt hour, as provided in 
          paragraph (c)(2) of this section; and
(6) r is the operating fee rate expressed as a decimal between zero and 
          one.

    (b) The annual operating fee formula relating to the value of annual 
electricity generation is restated as:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         M (nameplate             H (hours per            c (capacity                                   r (operating fee
    F (annual operating fee)      =        capacity)       *         year)         *        factor)        *    P (power price)    *         rate)
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) BOEM will specify operating fee parameters in the Final Sale 
Notice for commercial leases issued competitively and in the lease for 
those issued noncompetitively.
    (1) Unless BOEM specifies otherwise, in the operating fee rate, 
``r'' is 0.02 for each year the operating fee applies when you begin 
commercial generation of electricity. We may apply a different fee rate 
for new projects (i.e., a new generation based on new technology) after 
considering factors such as program objectives, state of the industry, 
project type, and project potential. Also, we may agree to reduce or 
waive the fee rate under Sec.  585.510.
    (2) The power price ``P,'' for each year when the operating fee 
applies, will be determined annually. The process by which the power 
price will be determined will be specified in the Final Sale Notice and/
or in the lease. BOEM:
    (i) Will use the most recent annual average wholesale power price in 
the State in which a project's transmission cables make landfall, as 
published by the DOE, Energy Information Administration (EIA), or other 
publicly available wholesale power price indices; and
    (ii) May adjust the published average wholesale power price to 
reflect documented variations by State or within a region and recent 
market conditions.

[[Page 605]]

    (3) BOEM will select the capacity factor ``c'' based upon applicable 
analogs drawn from present and future domestic and foreign projects that 
operate in comparable conditions and on comparable scales.
    (i) Upon the completion of the first year of commercial operations 
on the lease, BOEM may adjust the capacity factor as necessary (to 
accurately represent a comparison of actual production over a given 
period of time with the amount of power a facility would have produced 
if it had run at full capacity) in a subsequent year.
    (ii) After the first adjustment, BOEM may adjust the capacity factor 
(to accurately represent a comparison of actual generation over a given 
period of time with the amount of power a facility would have generated 
if it had run at full capacity) no earlier than in 5-year intervals from 
the most recent year that BOEM adjusts the capacity factor.
    (iii) The process by which BOEM will adjust the capacity factor, 
including any calculations (incorporating an average capacity factor 
reflecting actual operating experience), will be specified in the lease. 
The operator or lessee may request review and adjustment of the capacity 
factor under Sec.  585.510.
    (4) Ten days after the anniversary date of when you began to 
commercially generate electricity, you must submit to BOEM documentation 
of the gross annual generation of electricity produced by the generating 
facility on the lease. You must use the same information collection form 
as authorized by the EIA for this information.
    (5) For the nameplate capacity ``M,'' BOEM will use the total 
installed capacity of the equipment you install, as specified in your 
approved COP.
    (d) You must submit all operating fee payments to BOEM in accordance 
with the provisions under 30 CFR 1218.51.
    (e) BOEM will establish the operating fee in the Final Sale Notice 
or in the lease on a case-by-case basis for:
    (1) Activities that do not relate to the generation of electricity 
(e.g., hydrogen production), and
    (2) Leases issued for hydrokinetic activities requiring a FERC 
license.



Sec.  585.507  What rent payments must I pay on a project easement?

    (a) You must pay ONRR, under the regulations at 30 CFR part 1218, a 
rent fee for your project easement of $5 per acre, subject to a minimum 
of $450 per year, unless specified otherwise in the Final Sale Notice or 
lease:
    (1) The size of the project easement area for a cable or a pipeline 
is the full length of the corridor and a width of 200 feet (61 meters), 
centered on the cable or pipeline; and
    (2) The size of a project easement area for an accessory platform is 
limited to the aerial extent of anchor chains and other facilities and 
devices associated with the accessory.
    (b) You must commence rent payments for your project easement upon 
our approval of your COP or GAP:
    (1) You must make the first rent payment when the operations term 
begins, as provided in Sec.  585.500;
    (2) You must submit all subsequent rent payments in accordance with 
the regulations at 30 CFR 1218.51; and
    (3) You must continue to pay annual rent for your project easement 
until your lease is terminated.



Sec.  585.508  What rent payments must I pay on ROW grants or RUE
 grants associated with renewable energy projects?

    (a) For each ROW grant BOEM approves under subpart C of this part, 
you must pay ONRR, under the regulations at 30 CFR part 1218, an annual 
rent as follows, unless specified otherwise in the Final Sale Notice:
    (1) A fee of $70 for each nautical mile or part of a nautical mile 
of the OCS that your ROW crosses; and
    (2) An additional $5 per acre, subject to a minimum of $450 for use 
of the entire affected area, if you hold a ROW grant that includes a 
site outside the corridor of a 200-foot width (61 meters), centered on 
the cable or pipeline. The affected area includes the areal extent of 
anchor chains, risers, and other devices associated with a site outside 
the corridor.
    (b) For each RUE grant BOEM approves under subpart C of this part, 
you must pay ONRR, under the regulations at 30 CFR part 1218, a rent of:
    (1) $5 per acre per year; or

[[Page 606]]

    (2) A minimum of $450 per year.
    (c) You must make the rent payments required by paragraphs (a) and 
(b) of this section on:
    (1) An annual basis;
    (2) For a 5-year period; or
    (3) For multiples of 5 years.
    (d) You must make the first annual rent payment upon approval of 
your ROW grant or RUE grant request, as provided in Sec.  585.500, and 
all subsequent rent payments to ONRR in accordance with the regulations 
at 30 CFR 1218.51.



Sec.  585.509  Who is responsible for submitting lease or grant
 payments to BOEM?

    (a) For each lease, ROW grant, or RUE grant issued under this part, 
you must identify one person who is responsible for all payments due and 
payable under the provisions of the lease or grant. The responsible 
person identified is designated as the payor, and you must document 
acceptance of such responsibilities, as provided in 30 CFR 1218.52.
    (b) All payors must submit payments and maintain auditable records 
in accordance with guidance we issue or any applicable regulations in 
subchapter A of this chapter. In addition, the lessee or grant holder 
must also maintain such auditable records.



Sec.  585.510  May BOEM reduce or waive my lease or grant payments?

    (a) BOEM Director may reduce or waive the rent or operating fee or 
components of the operating fee, such as the fee rate or capacity 
factor, when the Director determines that it is necessary to encourage 
continued or additional activities.
    (b) When requesting a reduction or waiver, you must submit an 
application to us that includes all of the following:
    (1) The number of the lease, ROW grant, or RUE grant involved;
    (2) Name of each lessee or grant holder of record;
    (3) Name of each operator;
    (4) A demonstration that:
    (i) Continued activities would be uneconomic without the requested 
reduction or waiver, or
    (ii) A reduction or waiver is necessary to encourage additional 
activities; and
    (5) Any other information required by the Director.
    (c) No more than 6 years of your operations term will be subject to 
a full waiver of the operating fee.



Sec. Sec.  585.511-585.514  [Reserved]

         Financial Assurance Requirements for Commercial Leases



Sec.  585.515  What financial assurance must I provide when I obtain
 my commercial lease?

    (a) Before BOEM will issue your commercial lease or approve an 
assignment of an existing commercial lease, you (or, for an assignment, 
the proposed assignee) must guarantee compliance with all terms and 
conditions of the lease by providing either:
    (1) A $100,000 minimum, lease-specific bond; or
    (2) Another approved financial assurance instrument guaranteeing 
performance up to $100,000, as specified in Sec. Sec.  585.526 through 
585.529.
    (b) You meet the financial assurance requirements under this subpart 
if your designated lease operator provides a $100,000 minimum, lease-
specific bond or other approved financial assurance that guarantees 
compliance with all terms and conditions of the lease.
    (1) The dollar amount of the minimum, lease-specific financial 
assurance in paragraphs (a)(1) and (b) of this section will be adjusted 
to reflect changes in the Consumer Price Index-All Urban Consumers (CPI-
U) or a substantially equivalent index if the CPI-U is discontinued; and
    (2) The first CPI-U-based adjustment can be made no earlier than the 
5-year anniversary of the adoption of this rule. Subsequent CPI-U-based 
adjustments may be made every 5 years thereafter.



Sec.  585.516  What are the financial assurance requirements for each
 stage of my commercial lease?

    (a) The basic financial assurance requirements for each stage of 
your commercial lease are as follows:

[[Page 607]]



------------------------------------------------------------------------
         Before BOEM will . . .               You must provide . . .
------------------------------------------------------------------------
(1) Issue a commercial lease or approve  A $100,000 minimum, lease-
 an assignment of an existing             specific financial assurance.
 commercial lease.
(2) Approve your SAP...................  A supplemental bond or other
                                          financial assurance, in an
                                          amount determined by BOEM, if
                                          upon reviewing your SAP, BOEM
                                          determines that a supplemental
                                          bond is required in addition
                                          to your minimum lease-specific
                                          bond, due to the complexity,
                                          number, and location of any
                                          facilities involved in your
                                          site assessment activities.
(3) Approve your COP...................  A supplemental bond or other
                                          financial assurance, in an
                                          amount determined by BOEM
                                          based on the complexity,
                                          number, and location of all
                                          facilities involved in your
                                          planned activities and
                                          commercial operation. The
                                          supplemental financial
                                          assurance requirement is in
                                          addition to your lease-
                                          specific bond and, if
                                          applicable, the previous
                                          supplement associated with SAP
                                          approval.
(4) Allow you to install facilities      A decommissioning bond or other
 approved in your COP.                    financial assurance, in an
                                          amount determined by BOEM
                                          based on anticipated
                                          decommissioning costs. BOEM
                                          will allow you to provide your
                                          financial assurance for
                                          decommissioning in accordance
                                          with the number of facilities
                                          installed or being installed.
                                          BOEM must approve the schedule
                                          for providing the appropriate
                                          financial assurance coverage.
------------------------------------------------------------------------

    (b) Each bond or other financial assurance must guarantee compliance 
with all terms and conditions of the lease. You may provide a new bond 
or increase the amount of your existing bond, to satisfy any additional 
financial assurance requirements.
    (c) For hydrokinetic commercial leases, supplemental financial 
assurance may be required in an amount determined by BOEM before FERC 
issues a license.



Sec.  585.517  How will BOEM determine the amounts of the supplemental
 and decommissioning financial assurance requirements associated with
 commercial leases?

    (a) BOEM will base the determination for the amounts of the SAP, 
COP, and decommissioning financial assurance requirements on estimates 
of the cost to meet all accrued lease obligations.
    (b) We determine the amount of the supplemental and decommissioning 
financial assurance requirements on a case-by-case basis. The amount of 
the financial assurance must be no less than the amount required to meet 
all lease obligations, including:
    (1) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (2) Any past due rent and other payments;
    (3) Other monetary obligations; and
    (4) The estimated cost of facility decommissioning, as required by 
subpart I of this part.
    (c) If your cumulative potential obligations and liabilities 
increase or decrease, we may adjust the amount of supplemental or the 
decommissioning financial assurance.
    (1) If we propose adjusting your financial assurance amount, we will 
notify you of the proposed adjustment and give you an opportunity to 
comment; and
    (2) We may approve a reduced financial assurance amount if you 
request it and if the reduced amount that you request continues to be 
greater than the sum of:
    (i) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (ii) Any past due rent and other payments;
    (iii) Other monetary obligations; and
    (iv) The estimated cost of facility decommissioning.

[[Page 608]]



Sec. Sec.  585.518-585.519  [Reserved]

   Financial Assurance for Limited Leases, ROW Grants, and RUE Grants



Sec.  585.520  What financial assurance must I provide when I obtain
 my limited lease, ROW grant, or RUE grant?

    (a) Before BOEM will issue your limited lease, ROW grant, or RUE 
grant, you or a proposed assignee must guarantee compliance with all 
terms and conditions of the lease or grant by providing either:
    (1) A $300,000 minimum, lease- or grant-specific bond; or
    (2) Another approved financial assurance instrument of such minimum 
level as specified in Sec. Sec.  585.526 through 585.529.
    (b) You meet the financial assurance requirements under this subpart 
if your designated lease or grant operator provides a minimum limited 
lease-specific or grant-specific bond in an amount sufficient to 
guarantee compliance with all terms and conditions of the limited lease 
or grant.
    (1) The dollar amount of the minimum, lease- or grant-specific 
financial assurance in paragraph (a)(1) of this section will be adjusted 
to reflect changes in the CPI-U or a substantially equivalent index if 
the CPI-U is discontinued; and
    (2) The first CPI-U-based adjustment can be made no earlier than the 
5-year anniversary of the adoption of this rule. Subsequent CPI-U-based 
adjustments may be made every 5 years thereafter.



Sec.  585.521  Do my financial assurance requirements change as activities
 progress on my limited lease or grant?

    (a) BOEM may require you to increase the level of your financial 
assurance as activities progress on your limited lease or grant. We will 
base the determination for the amount of financial assurance 
requirements on our estimate of the cost to meet all accrued lease or 
grant obligations, including:
    (1) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (2) Any past due rent and other payments;
    (3) Other monetary obligations; and
    (4) The estimated cost of facility decommissioning.
    (b) You may satisfy the requirement for increased financial 
assurance levels for the limited lease or grant by increasing the amount 
of your existing bond or replacing your existing bond.
    (c) BOEM will authorize you to establish a separate decommissioning 
bond or other financial assurance for your limited lease or grant.
    (1) The separate decommissioning bond or other financial assurance 
instrument must meet the requirements specified in Sec. Sec.  585.525 
through 585.529.
    (2) BOEM will allow you to provide your financial assurance for 
decommissioning in accordance with the number of facilities installed or 
being installed. BOEM must approve the schedule for providing the 
appropriate financial assurance coverage.



Sec. Sec.  585.522-585.524  [Reserved]

            Requirements for Financial Assurance Instruments



Sec.  585.525  What general requirements must a financial assurance
 instrument meet?

    (a) Any bond or other acceptable financial assurance instrument that 
you provide must:
    (1) Be payable to BOEM upon demand; and
    (2) Guarantee compliance of all lessees, grant holders, operators, 
and payors with all terms and conditions of the lease or grant, any 
subsequent approvals and authorizations, and all applicable regulations.
    (b) All bonds and other forms of financial assurance must be on or 
in a form approved by BOEM. You may submit this on an approved form that 
you have reproduced or generated by use of a computer. If the document 
you submit omits any terms and conditions that are included on the BOEM-
approved form, your bond is deemed to contain the omitted terms and 
conditions.
    (c) Surety bonds must be issued by an approved surety listed in the 
current Treasury Circular 570, as required by 31 CFR 223.16. You may 
obtain a copy of

[[Page 609]]

Circular 570 from the Treasury Web site at http://www.fms.treas.gov/
c570/.
    (d) Your surety bond cannot exceed the underwriting limit listed in 
the current Treasury Circular 570, except as permitted therein.
    (e) You and a qualified surety must execute your bond. When the 
surety is a corporation, an authorized corporate officer must sign the 
bond and attest to it over the corporate seal.
    (f) You may not terminate the period of liability of your bond or 
cancel your bond, except as provided in this subpart. Bonds must 
continue in full force and effect even though an event has occurred that 
could diminish or terminate a surety's obligation under State law.
    (g) Your surety must notify you and BOEM within 5 business days 
after:
    (1) It initiates any judicial or administrative proceeding alleging 
its insolvency or bankruptcy; or
    (2) The Treasury decertifies the surety.



Sec.  585.526  What instruments other than a surety bond may I use to
 meet the financial assurance requirement?

    (a) You may use other types of security instruments, if BOEM 
determines that such security protects BOEM to the same extent as the 
surety bond. BOEM will consider pledges of the following:
    (1) U.S. Department of Treasury securities identified in 31 CFR part 
225;
    (2) Cash in an amount equal to the required dollar amount of the 
financial assurance, to be deposited and maintained in a Federal 
depository account of the U.S. Treasury by BOEM;
    (3) Certificates of deposit or savings accounts in a bank or 
financial institution organized or authorized to transact business in 
the United States with:
    (i) Minimum net assets of $500,000,000; and
    (ii) Minimum Bankrate.com Safe & Sound rating of 3 Stars, and 
Capitalization, Assets, Equity and Liquidity (CAEL) rating of 3 or less;
    (4) Negotiable U.S. Government, State, and municipal securities or 
bonds having a market value of not less than the required dollar amount 
of the financial assurance and maintained in a Securities Investors 
Protection Corporation insured trust account by a licensed securities 
brokerage firm for the benefit of the BOEM;
    (5) Investment-grade rated securities having a Standard and Poor's 
rating of AAA or an equivalent rating from a nationally recognized 
securities rating service having a market value of not less than the 
required dollar amount of the financial assurance and maintained in a 
Securities Investors Protection Corporation insured trust account by a 
licensed securities brokerage firm for the benefit of BOEM; and
    (6) Insurance, if its form and function is such that the funding or 
enforceable pledges of funding are used to guarantee performance of 
regulatory obligations in the event of default on such obligations by 
the lessee. Insurance must have an A.M. Best rating of ``superior'' or 
an equivalent rating from a nationally recognized insurance rating 
service.
    (b) If you use a Treasury security:
    (1) You must post 115 percent of your financial assurance amount;
    (2) You must monitor the collateral value of your security. If the 
collateral value of your security as determined in accordance with the 
31 CFR part 203 Collateral Margins Table (which can be found at http://
www.treasurydirect.gov) falls below the required level of coverage, you 
must pledge additional security to provide 115 percent of the required 
amount; and
    (3) You must include with your pledge authority for us to sell the 
security and use the proceeds if we determine that you have failed to 
comply with any of the terms and conditions of your lease or grant, any 
subsequent approval or authorization, or applicable regulations.
    (c) If you use the instruments described in paragraphs (a)(4) or 
(a)(5) of this section, you must provide BOEM by the end of each 
calendar year a certified statement describing the nature and market 
value of the instruments maintained in that account, and including any 
current statements or reports furnished by the brokerage firm to the 
lessee concerning the asset value of the account.

[[Page 610]]



Sec.  585.527  May I demonstrate financial strength and reliability
 to meet the financial assurance requirement for lease or grant 
activities?

    BOEM may allow you to use your financial strength and reliability to 
meet financial assurance requirements. We will make this determination 
based on audited financial statements, business stability, reliability, 
and compliance with regulations.
    (a) You must provide the following information if you want to 
demonstrate financial strength and reliability to meet your financial 
assurance requirements:
    (1) Audited financial statements (including auditor's certificate, 
balance sheet, and profit and loss sheet) that show you have financial 
capacity substantially in excess of existing and anticipated lease and 
other obligations;
    (2) Evidence that shows business stability based on 5 years of 
continuous operation and generation of renewable energy on the OCS or 
onshore;
    (3) Evidence that shows reliability in meeting obligations based on 
credit ratings or trade references, including names and addresses of 
other lessees, contractors, and suppliers with whom you have dealt; and
    (4) Evidence that shows a record of compliance with laws, 
regulations, and lease, ROW, or RUE terms.
    (b) If we approve your request to use your financial strength and 
reliability to meet your financial assurance requirements, you must 
submit annual updates to the information required by paragraph (a) of 
this section. You must submit this information no later than March 31 of 
each year.
    (c) If the annual updates to the information required by paragraph 
(a) of this section do not continue to demonstrate financial strength 
and reliability or BOEM has reason to believe that you are unable to 
meet the financial assurance requirements of this section, after notice 
and opportunity for a hearing, BOEM will terminate your ability to use 
financial strength and reliability for financial assurance and require 
you to provide another type of financial assurance. You must provide 
this new financial assurance instrument within 90 days after we 
terminate your use of financial strength and reliability.



Sec.  585.528  May I use a third-party guaranty to meet the financial
 assurance requirement for lease or grant activities?

    (a) You may use a third-party guaranty if the guarantor meets the 
criteria prescribed in paragraph (b) of this section and submits an 
agreement meeting the criteria prescribed in paragraph (c) of this 
section. The agreement must guarantee compliance with the obligations of 
all lessees and operators and grant holders.
    (b) BOEM will consider the following factors in deciding whether to 
accept an agreement:
    (1) The length of time that your guarantor has been in continuous 
operation as a business entity. You may exclude periods of interruption 
that are beyond the guarantor's control by demonstrating, to the 
satisfaction of the Director, that the interruptions do not affect the 
likelihood of your guarantor remaining in business during the SAP, COP, 
and decommissioning stages of activities covered by the indemnity 
agreement.
    (2) Financial information available in the public record or 
submitted by your guarantor in sufficient detail to show us that your 
guarantor meets the criterion stated in paragraph (b)(4) of this 
section. Such detail includes:
    (i) The current rating for your guarantor's most recent bond 
issuance by a generally recognized bond rating service such as Moody's 
Investor Service or Standard and Poor's Corporation;
    (ii) Your guarantor's net worth, taking into account liabilities for 
compliance with all terms and conditions of your lease, regulations, and 
other guarantees;
    (iii) Your guarantor's ratio of current assets to current 
liabilities, taking into account liabilities for compliance with all 
terms and conditions of your lease, regulations, and other guarantees; 
and
    (iv) Your guarantor's unencumbered domestic fixed assets.
    (3) If the information in paragraph (b)(2) of this section is not 
publicly available, your guarantor must submit the information in the 
following table,

[[Page 611]]

to be updated annually within 90 days of the end of the fiscal year (FY) 
or as otherwise prescribed.

------------------------------------------------------------------------
    Your guarantor must submit . . .                That . . .
------------------------------------------------------------------------
(i) Financial statements for the most    Include a report by an
 recently completed FY.                   independent certified public
                                          accountant containing the
                                          accountant's audit or review
                                          opinion of the statements. The
                                          report must be prepared in
                                          conformance with generally
                                          accepted accounting principles
                                          and contain no adverse
                                          opinion.
(ii) Financial statement for completed   Your guarantor's financial
 quarter in the current FY.               officer certifies to be
                                          correct.
(iii) Additional information related to  Your guarantor's financial
 bonds, if requested by the Director.     officer certifies to be
                                          correct.
------------------------------------------------------------------------

    (4) Your guarantor's total outstanding and proposed guarantees must 
not exceed 25 percent of its unencumbered domestic net worth.
    (c) Your guarantor must submit an agreement executed by the 
guarantor and all parties bound by the agreement. All parties are bound 
jointly and severally and must meet the qualifications set forth in 
Sec.  585.107.
    (1) When any party is a corporation, two corporate officers 
authorized to execute the guaranty agreement on behalf of the 
corporation must sign the agreement.
    (2) When any party is a partnership, joint venture, or syndicate, 
the guaranty agreement must bind each party who has a beneficial 
interest in your guarantor and provide that, upon BOEM demand under your 
guaranty, each party is jointly and severally liable for compliance with 
all terms and conditions of your lease(s) or grant(s) covered by the 
agreement.
    (3) When forfeiture of the guaranty is called for, the agreement 
must provide that your guarantor will either bring your lease(s) or 
grant(s) into compliance or provide, within 7 days, sufficient funds to 
permit BOEM to complete corrective action.
    (4) The guaranty agreement must contain a confession of judgment, 
providing that, if we determine that you are, or your operator or 
operating rights owner is, in default, the guarantor must not challenge 
the determination and must remedy the default.
    (5) If you fail, or your operator or operating rights owner fails, 
to comply with any law, term, or regulation, your guarantor must either 
take corrective action or provide, within 7 days or other agreed upon 
time period, sufficient funds for BOEM to complete corrective action. 
Such compliance must not reduce your guarantor's liability.
    (6) If your guarantor wants to terminate the period of liability, 
your guarantor must notify you and us at least 90 days before the 
proposed termination date, obtain our approval for termination of all or 
a specified portion of the guarantee for liabilities arising after that 
date, and remain liable for all your work performed during the period 
the agreement is in effect.
    (7) Each guaranty submitted pursuant to this section is deemed to 
contain all the above terms, even if they are not actually in the 
agreement.
    (d) Before the termination of your guaranty, you must provide an 
acceptable replacement in the form of a bond or other security.



Sec.  585.529  Can I use a lease- or grant-specific decommissioning 
account to meet the financial assurance requirements related to 
decommissioning?

    (a) In lieu of a surety bond, BOEM may authorize you to establish a 
lease-, ROW grant-, or RUE grant-specific decommissioning account in a 
federally-insured institution. The funds may not be withdrawn from the 
account without our written approval.
    (1) The funds must be payable to BOEM and pledged to meet your lease 
or grant decommissioning and site clearance obligations; and
    (2) You must fully fund the account within the time BOEM prescribes 
to cover all costs of decommissioning including site clearance. BOEM 
will estimate the cost of decommissioning, including site clearance.
    (b) Any interest paid on the account will be treated as account 
funds unless

[[Page 612]]

we authorize in writing that any interest be paid to the depositor.
    (c) We may allow you to pledge Treasury securities, payable to BOEM 
on demand, to satisfy your obligation to make payments into the account. 
Acceptable Treasury securities and their collateral value are determined 
in accordance with 31 CFR part 203, Collateral Margins Table (which can 
be found at http://www.treasurydirect.gov).
    (d) We may require you to commit a specified stream of revenues as 
payment into the account so that the account will be fully funded, as 
prescribed in paragraph (a)(2) of this section. The commitment may 
include revenue from other operations.

                     Changes in Financial Assurance



Sec.  585.530  What must I do if my financial assurance lapses?

    (a) If your surety is decertified by the Treasury, becomes bankrupt 
or insolvent, or if your surety's charter or license is suspended or 
revoked, or if any other approved financial assurance expires for any 
reason, you must:
    (1) Inform BOEM within 3 business days about the financial assurance 
lapse; and
    (2) Provide new financial assurance in the amount set by BOEM, as 
provided in this subpart.
    (b) You must notify BOEM within 3 business days after you learn of 
any action filed alleging that you, your surety, or third-party 
guarantor, is insolvent or bankrupt.



Sec.  585.531  What happens if the value of my financial assurance
 is reduced?

    If the value of your financial assurance is reduced below the 
required financial assurance amount because of a default or any other 
reason, you must provide additional financial assurance sufficient to 
meet the requirements of this subpart within 45 days or within a 
different period as specified by BOEM.



Sec.  585.532  What happens if my surety wants to terminate the
 period of liability of my bond?

    (a) Terminating the period of liability of a bond ends the period 
during which surety liability continues to accrue. The surety continues 
to be responsible for obligations and liabilities that accrued during 
the period of liability and before the date on which BOEM terminates the 
period of liability under paragraph (b) of this section. The liabilities 
that accrue during a period of liability include:
    (1) Obligations that started to accrue before the beginning of the 
period of liability and have not been met; and
    (2) Obligations that began accruing during the period of liability.
    (b) Your surety must submit to BOEM its request to terminate the 
period of liability under its bond and notify you of that request. If 
you intend to continue activities, or have not met all obligations of 
your lease or grant, you must provide a replacement bond or alternative 
form of financial assurance of equivalent or greater value. BOEM will 
terminate that period of liability within 90 days after BOEM receives 
the request.



Sec.  585.533  How does my surety obtain cancellation of my bond?

    (a) BOEM will release a bond or allow a surety to cancel a bond, and 
will relieve the surety from accrued obligations only if:
    (1) BOEM determines that there are no outstanding obligations 
covered by the bond; or
    (2) The following occurs:
    (i) BOEM accepts a replacement bond or an alternative form of 
financial assurance in an amount equal to or greater than the bond to be 
cancelled to cover the terminated period of liability;
    (ii) The surety issuing the new bond has expressly agreed to assume 
all outstanding liabilities under the original bond that accrued during 
the period of liability that was terminated; and
    (iii) The surety issuing the new bond has agreed to assume that 
portion of the outstanding liabilities that accrued during the 
terminated period of liability that exceeds the coverage of the bond 
prescribed under Sec. Sec.  585.515, 585.516, 585.520, or 585.521, and 
of which you were notified.
    (b) When your lease or grant ends, your surety(ies) remain(s) 
responsible, and BOEM will retain any financial assurance as follows:
    (1) The period of liability ends when you cease all operations and 
activities

[[Page 613]]

under the lease or grant, including decommissioning and site clearance;
    (2) Your surety or collateral financial assurance will not be 
released until 7 years after the lease ends, or a longer period as 
necessary to complete any appeals or judicial litigation related to your 
bonded obligation, or for BOEM to determine that all of your obligations 
under the lease or grant have been satisfied; and
    (3) BOEM will reduce the amount of your bond or return a portion of 
your financial assurance if we determine that we need less than the full 
amount of the bond or financial assurance to meet any possible future 
obligations.



Sec.  585.534  When may BOEM cancel my bond?

    When your lease or grant ends, your surety(ies) remain(s) 
responsible, and BOEM will retain any pledged security as shown in the 
following table:

------------------------------------------------------------------------
                                                     Your bond will not
            Bond                  The period of      be released until .
                              liability ends . . .           . .
------------------------------------------------------------------------
(a) Bonds for commercial      When BOEM determines  Seven years after
 leases submitted under Sec.   that you have met     the lease ends, or
   585.515.                    all of your           a longer period as
                               obligations under     necessary to
                               the lease.            complete any
                                                     appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations.
(b) Supplemental or           When BOEM determines  (1) Seven years
 decommissioning bonds         that you have met     after the lease
 submitted under Sec.          all your              ends, or a longer
 585.516.                      decommissioning,      period as necessary
                               site clearance, and   to complete any
                               other obligations.    appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations; and
                                                    (2) BOEM determines
                                                     that the potential
                                                     liability resulting
                                                     from any undetected
                                                     noncompliance is
                                                     not greater than
                                                     the amount of the
                                                     lease base bond.
(c) Bonds submitted under     When BOEM determines  Seven years after
 Sec.  Sec.   585.520 and      that you have met     the limited lease,
 585.521 for limited leases,   all of your           ROW, or RUE grant
 ROW grants, or RUE grants.    obligations under     or a longer period
                               the limited lease     as necessary to
                               or grant.             complete any
                                                     appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations.
------------------------------------------------------------------------



Sec.  585.535  Why might BOEM call for forfeiture of my bond?

    (a) BOEM may call for forfeiture of all or part of the bond, pledged 
security, or other form of guaranty if:
    (1) After notice and demand for performance by BOEM, you refuse or 
fail, within the timeframe we prescribe, to comply with any term or 
condition of your lease or grant, other authorization or approval, or 
applicable regulations; or
    (2) You default on one of the conditions under which we accepted 
your bond.
    (b) We may pursue forfeiture without first making demands for 
performance against any co-lessee or holder of an interest in your ROW 
or RUE, or other person approved to perform obligations under your lease 
or grant.



Sec.  585.536  How will I be notified of a call for forfeiture?

    (a) BOEM will notify you and your surety, including any provider of 
financial assurance, in writing of the call for forfeiture and provide 
the reasons for the forfeiture and the amount to be forfeited. We will 
base the amount

[[Page 614]]

upon an estimate of the total cost of corrective action to bring your 
lease or grant into compliance.
    (b) We will advise you and your surety that you may avoid forfeiture 
if, within 10 business days:
    (1) You agree to and demonstrate in writing to BOEM that you will 
bring your lease or grant into compliance within the timeframe we 
prescribe, and you do so; or
    (2) Your surety agrees to and demonstrates that it will bring your 
lease or grant into compliance within the timeframe we prescribe, even 
if the cost of compliance exceeds the face amount of the bond.



Sec.  585.537  How will BOEM proceed once my bond or other security 
is forfeited?

    (a) If BOEM determines that your bond or other security is 
forfeited, we will collect the forfeited amount and use the funds to 
bring your lease or grant(s) into compliance and correct any default.
    (b) If the amount collected under your bond or other security is 
insufficient to pay the full cost of corrective action, BOEM may take or 
direct action to obtain full compliance and recover all costs in excess 
of the forfeited bond from you or any co-lessee or co-grantee.
    (c) If the amount collected under your bond or other security 
exceeds the full cost of corrective action to bring your lease or 
grant(s) into compliance, we will return the excess funds to the party 
from whom the excess was collected.



Sec. Sec.  585.538-585.539  [Reserved]

                       Revenue Sharing With States



Sec.  585.540  How will BOEM equitably distribute revenues to States?

    (a) BOEM will distribute among the eligible coastal States 27 
percent of the following revenues derived from qualified projects, where 
a qualified project and qualified project area is determined in Sec.  
585.541 and an eligible State is determined in Sec.  585.542, with each 
term defined in Sec.  585.112. Revenues subject to distribution to 
eligible States include all bonuses, acquisition fees, rentals, and 
operating fees derived from the entire qualified project area and 
associated project easements not limited to revenues attributable to the 
portion of the project area within 3 miles of the seaward boundary of a 
coastal State. The revenues to be shared do not include administrative 
fees such as service fees and those assessed for civil penalties and 
forfeiture of bond or other surety obligations.
    (b) The project area is the area included within a single lease or 
grant. For each qualified project, BOEM will determine and announce the 
project area and its geographic center at the time it grants or issues a 
lease, easement, or right-of-way on the OCS. If a qualified project 
lease or grant's boundaries change significantly due to actions pursuant 
to Sec. Sec.  585.435 or 585.436, BOEM will re-evaluate the project area 
to determine whether the geographic center has changed. If it has, BOEM 
will re-determine State eligibility and shares accordingly.
    (c) To determine each eligible State's share of the 27 percent of 
the revenues for a qualified project, BOEM will use the inverse distance 
formula, which apportions shares according to the relative proximity of 
the nearest point on the coastline of each eligible State to the 
geographic center of the qualified project area. If Si is 
equal to the nearest distance from the geographic center of the project 
area to the i = 1, 2, * * * nth eligible State's coastline, then 
eligible State i would be entitled to the fraction Fi of the 
27-percent aggregate revenue share due to all the eligible States 
according to the formula:

Fi= (1/Si) / ([Sigma]i=1* * 
*n(1/Si)).



Sec.  585.541  What is a qualified project for revenue sharing purposes?

    A qualified project for the purpose of revenue sharing with eligible 
coastal States is one authorized under subsection 8(p) of the OCS Lands 
Act, which includes acreage within the area extending 3 nautical miles 
seaward of State submerged lands. A qualified project is subject to 
revenue sharing with those States that are eligible for revenue sharing 
under Sec.  585.542. The entire area within a lease or grant for the 
qualified project, excluding project easements, is considered the 
qualified project area.

[[Page 615]]



Sec.  585.542  What makes a State eligible for payment of revenues?

    A State is eligible for payment of revenues if any part of the 
State's coastline is located within 15 miles of the announced geographic 
center of the project area of a qualified project. A State is not 
eligible for revenue sharing if all parts of that State's coastline are 
more than 15 miles from the announced geographic center of the qualified 
project area. This is the case even if the qualified project area is 
located wholly or partially within an area extending 3 nautical miles 
seaward of the submerged lands of that State or if there are no States 
with a coastline less than 15 miles from the announced geographic center 
of the qualified project area.



Sec.  585.543  Example of how the inverse distance formula works.

    (a) Assume that the geographic center of the project area lies 12 
miles from the closest coastline point of State A and 4 miles from the 
closest coastline point of State B. BOEM will round dollar shares to the 
nearest whole dollar. The proportional share due each State would be 
calculated as follows:
    (1) State A's share = [(\1/12\) / (\1/12\ + \1/4\)] = \1/4\.
    (2) State B's share = [(\1/4\) / (\1/12\ + \1/4\)] = \3/4\.
    (b) Therefore, State B would receive a share of revenues that is 
three times as large as that awarded to State A, based on the finding 
that State B's nearest coastline is one-third the distance to the 
geographic center of the qualified project area as compared to State A's 
nearest coastline. Eligible States share the 27 percent of the total 
revenues from the qualified project as mandated under the OCS Lands Act. 
Hence, if the qualified project generates $1,000,000 of Federal revenues 
in a given year, the Federal Government would distribute the States' 27-
percent share as follows:
    (1) State A's share = $270,000 x \1/4\ = $67,500.
    (2) State B's share = $270,000 x \3/4\ = $202,500.



              Subpart F_Plans and Information Requirements



Sec.  585.600  What plans and information must I submit to BOEM before
 I conduct activities on my lease or grant?

    You must submit a SAP, COP, or GAP and receive BOEM approval as set 
forth in the following table:

------------------------------------------------------------------------
                Before you:                           you must:
------------------------------------------------------------------------
(a) conduct any site assessment activities  submit and obtain approval
 on your commercial lease,                   for your SAP according to
                                             Sec.  Sec.   585.605
                                             through 585.613.
(b) conduct any activities pertaining to    submit and obtain approval
 construction of facilities for commercial   for your COP, according to
 operations on your commercial lease,        Sec.  Sec.   585.620
                                             through 585.629.
(c) conduct any activities on your limited  submit and obtain approval
 lease, ROW grant, or RUE grant in any OCS   for your GAP according to
 area,                                       Sec.  Sec.   585.640
                                             through 585.648.
------------------------------------------------------------------------



Sec.  585.601  When am I required to submit my plans to BOEM?

    You must submit your plans as follows:
    (a) You may submit your SAP or GAP prior to lease or grant issuance, 
but must submit your SAP or your GAP no later than 12 months from the 
date of lease or grant issuance.
    (b) If you intend to continue your commercial lease with an 
operations term, you must submit a COP, or a FERC license application, 
at least 6 months before the end of your site assessment term.
    (c) You may submit your COP or FERC license application with your 
SAP.
    (1) You must provide sufficient data and information with your COP 
for BOEM to complete the needed reviews and NEPA analysis; and
    (2) BOEM may need to conduct additional reviews, including NEPA 
analysis, if significant new information becomes available after you 
complete your site assessment activities or you

[[Page 616]]

revise your COP. As a result of the additional reviews, we may require 
modification of your COP.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]



Sec.  585.602  What records must I maintain?

    Until BOEM releases your financial assurance under Sec.  585.534, 
you must maintain and provide to BOEM, upon request, all data and 
information related to compliance with required terms and conditions of 
your SAP, COP, or GAP.



Sec. Sec.  585.603-585.604  [Reserved]

 Site Assessment Plan and Information Requirements for Commercial Leases



Sec.  585.605  What is a Site Assessment Plan (SAP)?

    (a) A SAP describes the activities (e.g., installation of 
meteorological towers, meteorological buoys) you plan to perform for the 
characterization of your commercial lease, including your project 
easement, or to test technology devices.
    (1) Your SAP must describe how you will conduct your resource 
assessment (e.g., meteorological and oceanographic data collection) or 
technology testing activities; and
    (2) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and as provided in Sec.  585.113.
    (b) Your SAP must include data from:
    (1) Physical characterization surveys (e.g., geological and 
geophysical surveys or hazards surveys); and
    (2) Baseline environmental surveys (e.g., biological or 
archaeological surveys).
    (c) You must receive BOEM approval of your SAP before you can begin 
any of the approved activities on your lease, as provided in Sec.  
585.613.
    (d) If you propose to construct a facility or combination of 
facilities deemed by BOEM to be complex or significant, as provided in 
Sec.  585.613(a)(1), you must also comply with the requirements of 
subpart G of this part and submit your Safety Management System as 
required by Sec.  585.810.



Sec.  585.606  What must I demonstrate in my SAP?

    (a) Your SAP must demonstrate that you have planned and are prepared 
to conduct the proposed site assessment activities in a manner that 
conforms to your responsibilities listed in Sec.  585.105(a) and:
    (1) Conforms to all applicable laws, regulations, and lease 
provisions of your commercial lease;
    (2) Is safe;
    (3) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (4) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (5) Uses best available and safest technology;
    (6) Uses best management practices; and
    (7) Uses properly trained personnel.
    (b) You must also demonstrate that your site assessment activities 
will collect the necessary information and data required for your COP, 
as provided in Sec.  585.626(a).



Sec.  585.607  How do I submit my SAP?

    You must submit one paper copy and one electronic version of your 
SAP to BOEM at the address listed in Sec.  585.110(a).



Sec. Sec.  585.608-585.609  [Reserved]

                  Contents of the Site Assessment Plan



Sec.  585.610  What must I include in my SAP?

    Your SAP must include the following information, as applicable.
    (a) For all activities you propose to conduct under your SAP, you 
must provide the following information:

[[Page 617]]



------------------------------------------------------------------------
          Project information                       Including
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) The site assessment or technology    A discussion of the objectives;
 testing concept.                         description of the proposed
                                          activities, including the
                                          technology you will use; and
                                          proposed schedule from start
                                          to completion.
(3) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(4) Commercial lease stipulations and    A description of the measures
 compliance.                              you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   facility associated with your
                                          project.
(7) Deployment activities..............  A description of the safety,
                                          prevention, and environmental
                                          protection features or
                                          measures that you will use.
(8) Your proposed measures for           A description of the measures
 avoiding, minimizing, reducing,          you will use to avoid or
 eliminating, and monitoring              minimize adverse effects and
 environmental impacts.                   any potential incidental take,
                                          before you conduct activities
                                          on your lease, and how you
                                          will mitigate environmental
                                          impacts from your proposed
                                          activities, including a
                                          description of the measures
                                          you will use as required by
                                          subpart H of this part.
(9) CVA nomination, if required........  CVA nominations for reports in
                                          subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request to waive the CVA
                                          requirement, as required by
                                          Sec.   585.705(c).
(10) Reference information.............  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(11) Decommissioning and site clearance  A discussion of methodologies.
 procedures.
(12) Air quality information...........  Information as described in
                                          Sec.   585.659 of this
                                          section.
(13) A listing of all Federal, State,    A statement indicating whether
 and local authorizations or approvals    such authorization or approval
 required to conduct site assessment      has been applied for or
 activities on your lease.                obtained.
(14) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(15) Financial assurance information...  Statements attesting that the
                                          activities and facilities
                                          proposed in your SAP are or
                                          will be covered by an
                                          appropriate bond or other
                                          approved security, as required
                                          in Sec.  Sec.   585.515 and
                                          585.516.
(16) Other information.................  Additional information as
                                          requested by BOEM.
------------------------------------------------------------------------

    (b) You must provide the results of geophysical and geological 
surveys, hazards surveys, archaeological surveys (if required), and 
baseline collection studies (e.g., biological) with the supporting data 
in your SAP:

------------------------------------------------------------------------
         Information             Report contents          Including
------------------------------------------------------------------------
(1) Geotechnical............  The results from the  A description of all
                               geotechnical survey   relevant seabed and
                               with supporting       engineering data
                               data.                 and information to
                                                     allow for the
                                                     design of the
                                                     foundation for that
                                                     facility. You must
                                                     provide data and
                                                     information to
                                                     depths below which
                                                     the underlying
                                                     conditions will not
                                                     influence the
                                                     integrity or
                                                     performance of the
                                                     structure. This
                                                     could include a
                                                     series of sampling
                                                     locations (borings
                                                     and in situ tests)
                                                     as well as
                                                     laboratory testing
                                                     of soil samples,
                                                     but may consist of
                                                     a minimum of one
                                                     deep boring with
                                                     samples.
(2) Shallow hazards.........  The results from the  A description of
                               shallow hazards       information
                               survey with           sufficient to
                               supporting data.      determine the
                                                     presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                       (i) Shallow
                                                        faults;
                                                       (ii) Gas seeps or
                                                        shallow gas;
                                                       (iii) Slump
                                                        blocks or slump
                                                        sediments;
                                                       (iv) Hydrates;
                                                        and
                                                       (v) Ice scour of
                                                        seabed
                                                        sediments.

[[Page 618]]

 
(3) Archaeological resources  The results from the     (i) A description
                               archaeological           of the results
                               survey with              and data from
                               supporting data, if      the
                               required.                archaeological
                                                        survey;
                                                       (ii) A
                                                        description of
                                                        the historic and
                                                        prehistoric
                                                        archaeological
                                                        resources, as
                                                        required by the
                                                        National
                                                        Historic
                                                        Preservation Act
                                                        (NHPA) of 1966,
                                                        as amended.
(4) Geological survey.......  The results from the  A report that
                               geological survey     describes the
                               with supporting       results of a
                               data.                 geological survey
                                                     that includes
                                                     descriptions of:
                                                       (i) Seismic
                                                        activity at your
                                                        proposed site;
                                                       (ii) Fault zones;
                                                       (iii) The
                                                        possibility and
                                                        effects of
                                                        seabed
                                                        subsidence; and
                                                       (iv) The extent
                                                        and geometry of
                                                        faulting
                                                        attenuation
                                                        effects of
                                                        geologic
                                                        conditions near
                                                        your site.
(5) Biological survey.......  The results from the  A description of the
                               biological survey     results of a
                               with supporting       biological survey,
                               data.                 including
                                                     descriptions of the
                                                     presence of live
                                                     bottoms; hard
                                                     bottoms;
                                                     topographic
                                                     features; and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
------------------------------------------------------------------------

    (c) If you submit your COP or FERC license application with your SAP 
then:
    (1) You must provide sufficient data and information with your COP 
or FERC license application for BOEM and/or FERC to complete the needed 
reviews and NEPA analysis.
    (2) You may need to revise your COP or FERC license application and 
BOEM and/or FERC may need to conduct additional reviews, including NEPA 
analysis, if new information becomes available after you complete your 
site assessment activities.



Sec.  585.611  What information and certifications must I submit with
 my SAP to assist BOEM in complying with NEPA and other relevant laws?

    You must submit, with your SAP, detailed information to assist BOEM 
in complying with NEPA and other relevant laws as appropriate.
    (a) A SAP submitted for an area in which BOEM has not previously 
reviewed site assessment activities under NEPA or other applicable 
Federal laws, must describe those resources, conditions, and activities 
listed in the following table that could be affected by your proposed 
activities or that could affect the activities proposed in your SAP.
    (b) For a SAP submitted for an area in which BOEM has previously 
considered site assessment activities under applicable Federal law 
(e.g., a NEPA analysis and CZMA consistency determination for site 
assessment activities), BOEM will review the SAP to determine if its 
impacts are consistent with those previously considered. If the 
anticipated effects of your proposed SAP activities are significantly 
different than those previously anticipated, we may determine that 
additional NEPA and other relevant Federal reviews are required. In that 
case, BOEM will notify you of such determination, and you must submit a 
SAP that describes those resources, conditions, and activities listed in 
the following table that could be affected by your proposed activities 
or that could affect the activities proposed in your SAP, including:

------------------------------------------------------------------------
       Type of information:                      Including:
------------------------------------------------------------------------
(1) Hazard information............  Meteorology, oceanography, sediment
                                     transport, geology, and shallow
                                     geological or manmade hazards.
(2) Water quality.................  Turbidity and total suspended solids
                                     from construction.
(3) Biological resources..........  Benthic communities, marine mammals,
                                     sea turtles, coastal and marine
                                     birds, fish and shellfish,
                                     plankton, sea grasses, and other
                                     plant life.
(4) Threatened or endangered        As required by the Endangered
 species.                            Species Act (ESA) of 1973 (16
                                     U.S.C. 1531 et seq.).

[[Page 619]]

 
(5) Sensitive biological resources  Essential fish habitat, refuges,
 or habitats.                        preserves, special management areas
                                     identified in coastal management
                                     programs, sanctuaries, rookeries,
                                     hard bottom habitat, chemosynthetic
                                     communities, calving grounds,
                                     barrier islands, beaches, dunes,
                                     and wetlands.
(6) Archaeological resources......  As required by the NHPA (16 U.S.C.
                                     470 et seq.), as amended.
(7) Social and economic conditions  Employment, existing offshore and
                                     coastal infrastructure (including
                                     major sources of supplies,
                                     services, energy, and water), land
                                     use, subsistence resources and
                                     harvest practices, recreation,
                                     recreational and commercial fishing
                                     (including typical fishing seasons,
                                     location, and type), minority and
                                     lower income groups, coastal zone
                                     management programs, and viewshed.
(8) Coastal and marine uses.......  Military activities, vessel traffic,
                                     and energy and nonenergy mineral
                                     exploration or development.
(9) Consistency Certification.....  If required by CZMA, as appropriate:
                                     (i) 15 CFR part 930, subpart D, if
                                     the SAP is submitted prior to lease
                                     issuance; (ii) 15 CFR part 930,
                                     subpart E, if the SAP is submitted
                                     after lease issuance.
------------------------------------------------------------------------
(10) Other resources, conditions,   As identified by BOEM.
 and activities.
------------------------------------------------------------------------


[79 FR 21623, Apr. 17, 2014]



Sec.  585.612  How will my SAP be processed for Federal consistency
 under the Coastal Zone Management Act?

    Your SAP will be processed based on whether it is submitted before 
or after your lease is issued:

------------------------------------------------------------------------
                                     Consistency review of your SAP will
     If your SAP is submitted:             be handled as follows:
------------------------------------------------------------------------
(a) Before lease issuance.........  You will furnish a copy of your SAP,
                                     consistency certification, and
                                     necessary data and information
                                     pursuant to 15 CFR part 930,
                                     subpart D, to the applicable State
                                     CZMA agency or agencies and BOEM at
                                     the same time.
(b) After lease issuance..........  You will submit a copy of your SAP,
                                     consistency certification, and
                                     necessary data and information
                                     pursuant to 15 CFR part 930,
                                     subpart E to BOEM. BOEM will
                                     forward to the applicable State
                                     CZMA agency or agencies one paper
                                     copy and one electronic copy of
                                     your SAP, consistency
                                     certification, and necessary data
                                     and information required under 15
                                     CFR part 930, subpart E, after BOEM
                                     has determined that all information
                                     requirements for the SAP are met.
------------------------------------------------------------------------


[79 FR 21624, Apr. 17, 2014]



Sec.  585.613  How will BOEM process my SAP?

    (a) BOEM will review your submitted SAP, and additional information 
provided pursuant to Sec.  585.611, to determine if it contains the 
information necessary to conduct our technical and environmental 
reviews.
    (1) We will notify you if we deem your proposed facility or 
combination of facilities to be complex or significant;
    (2) We will notify you if your submitted SAP lacks any necessary 
information;
    (b) BOEM will prepare NEPA analysis, as appropriate.
    (c) As appropriate, we will coordinate and consult with relevant 
Federal and State agencies, executives of relevant local governments, 
and affected Indian Tribes and will provide to other Federal, State, and 
local agencies and affected Indian Tribes relevant nonproprietary data 
and information pertaining to your proposed activities.
    (d) During the review process, we may request additional information 
if we determine that the information provided is not sufficient to 
complete the review and approval process. If you fail to provide the 
requested information, BOEM may disapprove your SAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal laws (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your SAP.
    (1) If we approve your SAP, we will specify terms and conditions to 
be incorporated into your SAP. You must certify compliance with those 
terms

[[Page 620]]

and conditions required under Sec.  585.615(c); and
    (2) If we disapprove your SAP, we will inform you of the reasons and 
allow you an opportunity to submit a revised plan making the necessary 
corrections, and may suspend the term of your lease, as appropriate, to 
allow this to occur.

                    Activities Under an Approved SAP



Sec.  585.614  When may I begin conducting activities under my
 approved SAP?

    (a) You may begin conducting the activities approved in your SAP 
following BOEM approval of your SAP.
    (b) If you are installing a facility or a combination of facilities 
deemed by BOEM to be complex or significant, as provided in Sec.  
585.613(a)(1), you must comply with the requirements of subpart G of 
this part and submit your Safety Management System required by Sec.  
585.810 before construction may begin.



Sec.  585.615  What other reports or notices must I submit to BOEM
 under my approved SAP?

    (a) You must notify BOEM in writing within 30 days of completing 
installation activities approved in your SAP.
    (b) You must prepare and submit to BOEM a report annually on 
November 1 of each year that summarizes your site assessment activities 
and the results of those activities. BOEM will withhold trade secrets 
and commercial or financial information that is privileged or 
confidential from public disclosure under exemption 4 of the FOIA and as 
provided in Sec.  585.113.
    (c) You must submit a certification of compliance annually (or other 
frequency as determined by BOEM) with certain terms and conditions of 
your SAP that BOEM identifies under Sec.  585.613(e)(1). Together with 
your certification, you must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and monitoring methods and their effectiveness. If you identified 
measures that were not effective, you must include your recommendations 
for new mitigation measures or monitoring methods.



Sec.  585.616  [Reserved]



Sec.  585.617  What activities require a revision to my SAP, and when
 will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any activities 
not described in your approved SAP, describing in detail the type of 
activities you propose to conduct. We will determine whether the 
activities you propose are authorized by your existing SAP or require a 
revision to your SAP. We may request additional information from you, if 
necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved SAP. The frequency and extent of the review will be based on 
the significance of any changes in available information and on onshore 
or offshore conditions affecting, or affected by, the activities 
conducted under your SAP. If the review indicates that the SAP should be 
revised to meet the requirements of this part, we will require you to 
submit the needed revisions.
    (c) Activities for which a proposed revision to your SAP will likely 
be necessary include:
    (1) Activities not described in your approved SAP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Changes in the surface location of a facility or structure;
    (4) Addition of a facility or structure not contemplated in your 
approved SAP;
    (5) Changes in the location of your onshore support base from one 
State to another, or to a new base requiring expansion;
    (6) Changes in the location of bottom disturbances (anchors, chains, 
etc.) by 500 feet (152 meters) or greater from the approved locations. 
If a specific anchor pattern was approved as a mitigation measure to 
avoid contact with bottom features, any change in the proposed bottom 
disturbances would likely trigger the need for a revision;
    (7) Structural failure of one or more facilities; or
    (8) Changes to any other activity specified by BOEM.

[[Page 621]]

    (d) We may begin the appropriate NEPA analysis and other relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural resources; 
life (including human and wildlife); property; the marine, coastal, or 
human environment; or sites, structures, or objects of historical or 
archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.



Sec.  585.618  What must I do upon completion of approved site 
assessment activities?

    (a) If, prior to the expiration of your site assessment term, you 
timely submit a COP meeting the requirements of this subpart, or a 
complete FERC license application, that describes the continued use of 
existing facilities approved in your SAP, you may keep such facilities 
in place on your lease during the time that BOEM reviews your COP for 
approval or FERC reviews your license application for approval.
    (b) You are not required to initiate the decommissioning process for 
facilities that are authorized to remain in place under your approved 
COP or approved FERC license.
    (c) If, following the technical and environmental review of your 
submitted COP, BOEM determines that such facilities may not remain in 
place, you must initiate the decommissioning process, as provided in 
subpart I of this part.
    (d) If FERC determines that such facilities may not remain in place, 
you must initiate the decommissioning process as provided in subpart I 
of this part.
    (e) You must initiate the decommissioning process, as set forth in 
subpart I of this part, upon the termination of your lease.



Sec.  585.619  [Reserved]

         Construction and Operations Plan for Commercial Leases



Sec.  585.620  What is a Construction and Operations Plan (COP)?

    The COP describes your construction, operations, and conceptual 
decommissioning plans under your commercial lease, including your 
project easement. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and in accordance with the 
terms of Sec.  585.113.
    (a) Your COP must describe all planned facilities that you will 
construct and use for your project, including onshore and support 
facilities and all anticipated project easements.
    (b) Your COP must describe all proposed activities including your 
proposed construction activities, commercial operations, and conceptual 
decommissioning plans for all planned facilities, including onshore and 
support facilities.
    (c) You must receive BOEM approval of your COP before you can begin 
any of the approved activities on your lease.



Sec.  585.621  What must I demonstrate in my COP?

    Your COP must demonstrate that you have planned and are prepared to 
conduct the proposed activities in a manner that conforms to your 
responsibilities listed in Sec.  585.105(a) and:
    (a) Conforms to all applicable laws, implementing regulations, lease 
provisions, and stipulations or conditions of your commercial lease;
    (b) Is safe;
    (c) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (d) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;

[[Page 622]]

    (e) Uses best available and safest technology;
    (f) Uses best management practices; and
    (g) Uses properly trained personnel.



Sec.  585.622  How do I submit my COP?

    (a) You must submit one paper copy and one electronic version of 
your COP to BOEM at the address listed in Sec.  585.110(a).
    (b) You may submit information and a request for any project 
easement as part of your original COP submission or as a revision to 
your COP.



Sec. Sec.  585.623-585.625  [Reserved]

            Contents of the Construction and Operations Plan



Sec.  585.626  What must I include in my COP?

    (a) You must submit the results of the following surveys for the 
proposed site(s) of your facility(ies). Your COP must include the 
following information:

------------------------------------------------------------------------
        Information:            Report contents:         Including:
------------------------------------------------------------------------
(1) Shallow hazards.........  The results of the    Information
                               shallow hazards       sufficient to
                               survey with           determine the
                               supporting data.      presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                       (i) Shallow
                                                        faults;
                                                       (ii) Gas seeps or
                                                        shallow gas;
                                                       (iii) Slump
                                                        blocks or slump
                                                        sediments;
                                                       (iv) Hydrates; or
                                                       (v) Ice scour of
                                                        seabed
                                                        sediments.
(2) Geological survey         The results of the    Assessment of:
 relevant to the design and    geological survey    (i) Seismic activity
 siting of your facility.      with supporting       at your proposed
                               data.                 site;
                                                    (ii) Fault zones;
                                                    (iii) The
                                                     possibility and
                                                     effects of seabed
                                                     subsidence; and
                                                    (iv) The extent and
                                                     geometry of
                                                     faulting
                                                     attenuation effects
                                                     of geologic
                                                     conditions near
                                                     your site.
(3) Biological..............  The results of the    A description of the
                               biological survey     results of
                               with supporting       biological surveys
                               data.                 used to determine
                                                     the presence of
                                                     live bottoms, hard
                                                     bottoms, and
                                                     topographic
                                                     features, and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
(4) Geotechnical survey.....  The results of your   (i) The results of a
                               sediment testing      testing program
                               program with          used to investigate
                               supporting data,      the stratigraphic
                               the various field     and engineering
                               and laboratory test   properties of the
                               methods employed,     sediment that may
                               and the               affect the
                               applicability of      foundations or
                               these methods as      anchoring systems
                               they pertain to the   for your facility.
                               quality of the       (ii) The results of
                               samples, the type     adequate in situ
                               of sediment, and      testing, boring,
                               the anticipated       and sampling at
                               design application.   each foundation
                               You must explain      location, to
                               how the engineering   examine all
                               properties of each    important sediment
                               sediment stratum      and rock strata to
                               affect the design     determine its
                               of your facility.     strength
                               In your               classification,
                               explanation, you      deformation
                               must describe the     properties, and
                               uncertainties         dynamic
                               inherent in your      characteristics.
                               overall testing      (iii) The results of
                               program, and the      a minimum of one
                               reliability and       deep boring (with
                               applicability of      soil sampling and
                               each test method.     testing) at each
                                                     edge of the project
                                                     area and within the
                                                     project area as
                                                     needed to determine
                                                     the vertical and
                                                     lateral variation
                                                     in seabed
                                                     conditions and to
                                                     provide the
                                                     relevant
                                                     geotechnical data
                                                     required for
                                                     design.
(5) Archaeological resources  The results of the    A description of the
                               archaeological        historic and
                               resource survey       prehistoric
                               with supporting       archaeological
                               data.                 resources, as
                                                     required by the
                                                     NHPA (16 U.S.C. 470
                                                     et. seq.), as
                                                     amended.
(6) Overall site              An overall site       An analysis of the
 investigation.                investigation         potential for:
                               report for your      (i) Scouring of the
                               facility that         seabed;
                               integrates the       (ii) Hydraulic
                               findings of your      instability;
                               shallow hazards      (iii) The occurrence
                               surveys and           of sand waves;
                               geologic surveys,    (iv) Instability of
                               and, if required,     slopes at the
                               your subsurface       facility location;
                               surveys with         (v) Liquefaction, or
                               supporting data.      possible reduction
                                                     of sediment
                                                     strength due to
                                                     increased pore
                                                     pressures;
                                                       (vi) Degradation
                                                        of subsea
                                                        permafrost
                                                        layers;

[[Page 623]]

 
                                                       (vii) Cyclic
                                                        loading;
                                                       (viii) Lateral
                                                        loading;
                                                       (ix) Dynamic
                                                        loading;
                                                       (x) Settlements
                                                        and
                                                        displacements;
                                                       (xi) Plastic
                                                        deformation and
                                                        formation
                                                        collapse
                                                        mechanisms; and
                                                       (xii) Sediment
                                                        reactions on the
                                                        facility
                                                        foundations or
                                                        anchoring
                                                        systems.
------------------------------------------------------------------------

    (b) Your COP must include the following project-specific 
information, as applicable.

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(3) The construction and operation       A discussion of the objectives,
 concept.                                 description of the proposed
                                          activities, tentative schedule
                                          from start to completion, and
                                          plans for phased development,
                                          as provided in Sec.   585.629.
(4) Commercial lease stipulations and    A description of the measures
 compliance.                              you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore, including all anchor/
                                          mooring data.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   structure associated with your
                                          project and, unless BOEM
                                          provides otherwise, how you
                                          will use a CVA to review and
                                          verify each stage of the
                                          project.
(7) All cables and pipelines, including  Location, design and
 cables on project easements.             installation methods, testing,
                                          maintenance, repair, safety
                                          devices, exterior corrosion
                                          protection, inspections, and
                                          decommissioning.
(8) A description of the deployment      Safety, prevention, and
 activities.                              environmental protection
                                          features or measures that you
                                          will use.
(9) A list of solid and liquid wastes    Disposal methods and locations.
 generated.
(10) A listing of chemical products      A list of chemical products
 used (if stored volume exceeds           used; the volume stored on
 Environmental Protection Agency (EPA)    location; their treatment,
 Reportable Quantities).                  discharge, or disposal methods
                                          used; and the name and
                                          location of the onshore waste
                                          receiving, treatment, and/or
                                          disposal facility. A
                                          description of how these
                                          products would be brought
                                          onsite, the number of
                                          transfers that may take place,
                                          and the quantity that that
                                          will be transferred each time.
(11) A description of any vessels,       An estimate of the frequency
 vehicles, and aircraft you will use to   and duration of vessel/vehicle/
 support your activities.                 aircraft traffic.
(12) A general description of the        (i) Under normal conditions.
 operating procedures and systems.       (ii) In the case of accidents
                                          or emergencies, including
                                          those that are natural or
                                          manmade.
(13) Decommissioning and site clearance  A discussion of general
 procedures.                              concepts and methodologies.
(14) A listing of all Federal, State,    (i) The U.S. Coast Guard, U.S.
 and local authorizations, approvals,     Army Corps Of Engineers, and
 or permits that are required to          any other applicable
 conduct the proposed activities,         authorizations, approvals, or
 including commercial operations.         permits, including any
                                          Federal, State or local
                                          authorizations pertaining to
                                          energy gathering, transmission
                                          or distribution (e.g.,
                                          interconnection
                                          authorizations).
                                         (ii) A statement indicating
                                          whether you have applied for
                                          or obtained such
                                          authorization, approval, or
                                          permit.
(15) Your proposed measures for          A description of the measures
 avoiding, minimizing, reducing,          you will use to avoid or
 eliminating, and monitoring              minimize adverse effects and
 environmental impacts.                   any potential incidental take
                                          before you conduct activities
                                          on your lease, and how you
                                          will mitigate environmental
                                          impacts from your proposed
                                          activities, including a
                                          description of the measures
                                          you will use as required by
                                          subpart H of this part.
(16) Information you incorporate by      A listing of the documents you
 reference.                               referenced.
(17) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(18) Reference.........................  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(19) Financial assurance...............  Statements attesting that the
                                          activities and facilities
                                          proposed in your COP are or
                                          will be covered by an
                                          appropriate bond or security,
                                          as required by Sec.  Sec.
                                          585.515 and 585.516.

[[Page 624]]

 
(20) CVA nominations for reports         CVA nominations for reports in
 required in subpart G of this part.      subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request for a waiver under
                                          Sec.   585.705(c).
(21) Construction schedule.............  A reasonable schedule of
                                          construction activity showing
                                          significant milestones leading
                                          to the commencement of
                                          commercial operations.
(22) Air quality information...........  As described in Sec.   585.659
                                          of this section.
(23) Other information.................  Additional information as
                                          required by BOEM.
------------------------------------------------------------------------



Sec.  585.627  What information and certifications must I submit with
 my COP to assist the BOEM in complying with NEPA and other relevant laws?

    (a) You must submit with your COP detailed information to assist 
BOEM in complying with NEPA and other relevant laws. Your COP must 
describe those resources, conditions, and activities listed in the 
following table that could be affected by your proposed activities, or 
that could affect the activities proposed in your COP, including:

------------------------------------------------------------------------
       Type of information:                      Including:
------------------------------------------------------------------------
(1) Hazard information............  Meteorology, oceanography, sediment
                                     transport, geology, and shallow
                                     geological or manmade hazards.
(2) Water quality.................  Turbidity and total suspended solids
                                     from construction.
(3) Biological resources..........  Benthic communities, marine mammals,
                                     sea turtles, coastal and marine
                                     birds, fish and shellfish,
                                     plankton, seagrasses, and plant
                                     life.
(4) Threatened or endangered        As defined by the ESA (16 U.S.C.
 species.                            1531 et seq.).
(5) Sensitive biological resources  Essential fish habitat, refuges,
 or habitats.                        preserves, special management areas
                                     identified in coastal management
                                     programs, sanctuaries, rookeries,
                                     hard bottom habitat, chemosynthetic
                                     communities, calving grounds,
                                     barrier islands, beaches, dunes,
                                     and wetlands.
(6) Archaeological resources......  As required by the NHPA (16 U.S.C.
                                     470 et seq.), as amended.
(7) Social and economic resources.  Employment, existing offshore and
                                     coastal infrastructure (including
                                     major sources of supplies,
                                     services, energy, and water), land
                                     use, subsistence resources and
                                     harvest practices, recreation,
                                     recreational and commercial fishing
                                     (including typical fishing seasons,
                                     location, and type), minority and
                                     lower income groups, coastal zone
                                     management programs, and viewshed.
(8) Coastal and marine uses.......  Military activities, vessel traffic,
                                     and energy and nonenergy mineral
                                     exploration or development.
(9) Consistency Certification.....  As required by the CZMA regulations:
                                    (i) 15 CFR part 930, subpart D, if
                                     your COP is submitted before lease
                                     issuance.
                                    (ii) 15 CFR part 930, subpart E, if
                                     your COP is submitted after lease
                                     issuance.
(10) Other resources, conditions,   As identified by BOEM.
 and activities.
------------------------------------------------------------------------

    (b) You must submit one paper copy and one electronic copy of your 
consistency certification. Your consistency certification must include:
    (1) One copy of your consistency certification under either 
subsection 307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 
930.76 or subsection 307(c)(3)(A) of the CZMA (16 U.S.C. 1456(c)(3)(A)) 
and 15 CFR 930.57, stating that the proposed activities described in 
detail in your plans comply with the State(s) approved coastal 
management program(s) and will be conducted in a manner that is 
consistent with such program(s); and
    (2) ``Necessary data and information,'' as required by 15 CFR 
930.58.
    (c) You must submit your oil spill response plan, as required by 30 
CFR part 254.
    (d) You must submit your Safety Management System as required by 
Sec.  585.810.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21624, Apr. 17, 2014]



Sec.  585.628  How will BOEM process my COP?

    (a) BOEM will review your submitted COP, and the information 
provided pursuant to Sec.  585.627, to determine if it contains all the 
required information necessary to conduct our technical and 
environmental reviews. We will notify you if your submitted COP lacks 
any necessary information.

[[Page 625]]

    (b) BOEM will prepare an appropriate NEPA analysis.
    (c) If your COP is submitted after lease issuance, BOEM will forward 
one copy of your COP, consistency certification, and associated data and 
information under the CZMA to the applicable State CZMA agency or 
agencies after all information requirements for the COP are met.
    (d) As appropriate, BOEM will coordinate and consult with relevant 
Federal, State, and local agencies and affected Indian Tribes, and 
provide to them relevant nonproprietary data and information pertaining 
to your proposed activities.
    (e) During the review process, we may request additional information 
if we determine that the information provided is not sufficient to 
complete the review and approval process. If you fail to provide the 
requested information, BOEM may disapprove your COP.
    (f) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your COP.
    (1) If we approve your COP, we will specify terms and conditions to 
be incorporated into your COP. You must certify compliance with certain 
of those terms and conditions, as required under Sec.  585.633(b); and
    (2) If we disapprove your COP, we will inform you of the reasons and 
allow you an opportunity to resubmit a revised plan addressing the 
concerns identified, and may suspend the term of your lease, as 
appropriate, to allow this to occur.
    (g) If BOEM approves your project easement, BOEM will issue an 
addendum to your lease specifying the terms of the project easement. A 
project easement may include off-lease areas that:
    (1) Contain the sites on which cable, pipeline, or associated 
facilities are located;
    (2) Do not exceed 200 feet (61 meters) in width, unless safety and 
environmental factors during construction and maintenance of the 
associated cables or pipelines require a greater width; and
    (3) For associated facilities, are limited to the area reasonably 
necessary for power or pumping stations or other accessory facilities.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21625, Apr. 17, 2014]



Sec.  585.629  May I develop my lease in phases?

    In your COP, you may request development of your commercial lease in 
phases. In support of your request, you must provide details as to what 
portions of the lease will be initially developed for commercial 
operations and what portions of the lease will be reserved for 
subsequent phased development.



Sec.  585.630  [Reserved]

                    Activities Under an Approved COP



Sec.  585.631  When must I initiate activities under an approved COP?

    After your COP is approved, you must commence construction by the 
date given in the construction schedule required by Sec.  
585.626(b)(21), and included as a part of your approved COP, unless BOEM 
approves a deviation from your schedule.



Sec.  585.632  What documents must I submit before I may construct and
 install facilities under my approved COP?

    (a) You must submit to BOEM the documents listed in the following 
table:

------------------------------------------------------------------------
                                                        Requirements are
                      Document:                            found in:
------------------------------------------------------------------------
(1) Facility Design Report...........................     Sec.   585.701
(2) Fabrication and Installation Report..............     Sec.   585.702
------------------------------------------------------------------------

    (b) You must submit your Safety Management System, as required by 
Sec.  585.810 of this part.
    (c) These activities must fall within the scope of your approved 
COP. If they do not fall within the scope of your approved COP, you will 
be required to submit a revision to your COP, under Sec.  585.634, for 
BOEM approval before commencing the activity.



Sec.  585.633  How do I comply with my COP?

    (a) Based on BOEM's environmental and technical reviews, we will 
specify

[[Page 626]]

terms and conditions to be incorporated into your COP.
    (b) You must submit a certification of compliance annually (or other 
frequency as determined by BOEM) with certain terms and conditions of 
your COP that BOEM identifies. Together with your certification, you 
must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and monitoring methods, and their effectiveness. If you identified 
measures that were not effective, then you must make recommendations for 
new mitigation measures or monitoring methods.
    (c) As provided at Sec.  585.105(i), BOEM may require you to submit 
any supporting data and information.



Sec.  585.634  What activities require a revision to my COP, and when
 will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any activities 
not described in your approved COP, describing in detail the type of 
activities you propose to conduct. We will determine whether the 
activities you propose are authorized by your existing COP or require a 
revision to your COP. We may request additional information from you, if 
necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved COP. The frequency and extent of the review will be based on 
the significance of any changes in available information, and on onshore 
or offshore conditions affecting, or affected by, the activities 
conducted under your COP. If the review indicates that the COP should be 
revised to meet the requirement of this part, we will require you to 
submit the needed revisions.
    (c) Activities for which a proposed revision to your COP will likely 
be necessary include:
    (1) Activities not described in your approved COP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Change in the surface location of a facility or structure;
    (4) Addition of a facility or structure not described in your 
approved COP;
    (5) Change in the location of your onshore support base from one 
State to another or to a new base requiring expansion;
    (6) Changes in the location of bottom disturbances (anchors, chains, 
etc.) by 500 feet (152 meters) or greater from the approved locations 
(e.g., if a specific anchor pattern was approved as a mitigation measure 
to avoid contact with bottom features, any change in the proposed bottom 
disturbances would likely trigger the need for a revision);
    (7) Structural failure of one or more facilities; or
    (8) Change in any other activity specified by BOEM.
    (d) We may begin the appropriate NEPA analysis and relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural resources; 
life (including human and wildlife); property; the marine, coastal, or 
human environment; or sites, structures, or objects of historical or 
archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.



Sec.  585.635  What must I do if I cease activities approved in my COP
 before the end of my commercial lease?

    You must notify the BOEM, within 5 business days, any time you cease 
commercial operations, without an approved suspension, under your 
approved COP. If you cease commercial operations for an indefinite 
period which extends longer than 6 months, we may cancel your lease 
under Sec.  585.437 and, you must initiate the decommissioning process 
as set forth in subpart I of this part.

[[Page 627]]



Sec.  585.636  What notices must I provide BOEM following approval
 of my COP?

    You must notify BOEM in writing of the following events, within the 
time periods provided:
    (a) No later than 30 days after commencing activities associated 
with the placement of facilities on the lease area under a Fabrication 
and Installation Report.
    (b) No later than 30 days after completion of construction and 
installation activities under a Fabrication and Installation Report.
    (c) At least 7 days before commencing commercial operations.



Sec.  585.637  When may I commence commercial operations on my 
commercial lease?

    If you are conducting activities on your lease that:
    (a) Do not require a FERC license (i.e., wind), then you may 
commence commercial operations 30 days after the CVA or project engineer 
has submitted to BOEM the final Fabrication and Installation Report for 
the fabrication and installation review, as provided in Sec.  585.708.
    (b) Require a FERC license or exemption, then you may commence 
commercial operations when permitted by the terms of your license or 
exemption.



Sec.  585.638  What must I do upon completion of my commercial operations
 as approved in my COP or FERC license?

    (a) Upon completion of your approved activities under your COP, you 
must initiate the decommissioning process as set forth in subpart I of 
this part. You must submit your decommissioning application as provided 
in Sec. Sec.  585.905 and 585.906.
    (b) Upon completion of your approved activities under your FERC 
license, the terms of your FERC license will govern your decommissioning 
activities.



Sec.  585.639  [Reserved]

General Activities Plan Requirements For Limited Leases, ROW Grants, and 
                               RUE Grants



Sec.  585.640  What is a General Activities Plan (GAP)?

    (a) A GAP describes your proposed construction, activities, and 
conceptual decommissioning plans for all planned facilities, including 
testing of technology devices and onshore and support facilities that 
you will construct and use for your project, including any project 
easements for the assessment and development of your limited lease or 
grant.
    (b) You must receive BOEM approval of your GAP before you can begin 
any of the approved activities on your lease or grant. You must submit 
your GAP no later than 12 months from the date of the lease or grant 
issuance.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21625, Apr. 17, 2014]



Sec.  585.641  What must I demonstrate in my GAP?

    Your GAP must demonstrate that you have planned and are prepared to 
conduct the proposed activities in a manner that:
    (a) Conforms to all applicable laws, implementing regulations, lease 
provisions and stipulations;
    (b) Is safe;
    (c) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (d) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (e) Uses best available and safest technology;
    (f) Uses best management practices; and
    (g) Uses properly trained personnel.



Sec.  585.642  How do I submit my GAP?

    (a) You must submit one paper copy and one electronic version of 
your GAP to BOEM at the address listed in Sec.  585.110(a).

[[Page 628]]

    (b) If you have a limited lease, you may submit information on any 
project easement as part of your original GAP submission or as a 
revision to your GAP.



Sec. Sec.  585.643-585.644  [Reserved]

                 Contents of the General Activities Plan



Sec.  585.645  What must I include in my GAP?

    (a) You must provide the following results of geophysical and 
geological surveys, hazards surveys, archaeological surveys (if 
required), and baseline collection studies (e.g., biological) with the 
supporting data in your GAP:

------------------------------------------------------------------------
        Information:            Report contents:         Including:
------------------------------------------------------------------------
(1) Geotechnical............  The results from the  A description of all
                               geotechnical survey   relevant seabed and
                               with supporting       engineering data
                               data.                 and information to
                                                     allow for the
                                                     design of the
                                                     foundation for that
                                                     facility. You must
                                                     provide data and
                                                     information to
                                                     depths below which
                                                     the underlying
                                                     conditions will not
                                                     influence the
                                                     integrity or
                                                     performance of the
                                                     structure. This
                                                     could include a
                                                     series of sampling
                                                     locations (borings
                                                     and in situ tests)
                                                     as well as
                                                     laboratory testing
                                                     of soil samples,
                                                     but may consist of
                                                     a minimum of one
                                                     deep boring with
                                                     samples.
(2) Shallow hazards.........  The results from the  A description of
                               shallow hazards       information
                               survey with           sufficient to
                               supporting data.      determine the
                                                     presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                       (i) Shallow
                                                        faults;
                                                       (ii) Gas seeps or
                                                        shallow gas;
                                                       (iii) Slump
                                                        blocks or slump
                                                        sediments;
                                                       (iv) Hydrates; or
                                                       (v) Ice scour of
                                                        seabed
                                                        sediments.
(3) Archaeological resources  The results from the  (i) A description of
                               archaeological        the results and
                               survey with           data from the
                               supporting data, if   archaeological
                               required.             survey;
                                                       (ii) A
                                                        description of
                                                        the historic and
                                                        prehistoric
                                                        archaeological
                                                        resources, as
                                                        required by NHPA
                                                        (16 U.S.C. 470
                                                        et seq.), as
                                                        amended.
(4) Geological survey.......  The results from the  A report that
                               geological survey     describes the
                               with supporting       results of a
                               data.                 geological survey
                                                     that includes
                                                     descriptions of:
                                                       (i) Seismic
                                                        activity at your
                                                        proposed site;
                                                       (ii) Fault zones;
                                                       (iii) The
                                                        possibility and
                                                        effects of
                                                        seabed
                                                        subsidence; and
                                                       (iv) The extent
                                                        and geometry of
                                                        faulting
                                                        attenuation
                                                        effects of
                                                        geologic
                                                        conditions near
                                                        your site.
(5) Biological survey.......  The results from the  A description of the
                               biological survey     results of a
                               with supporting       biological survey,
                               data.                 including the
                                                     presence of live
                                                     bottoms, hard
                                                     bottoms, and
                                                     topographic
                                                     features, and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
------------------------------------------------------------------------

    (b) For all activities you propose to conduct under your GAP, you 
must provide the following information:

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) The site assessment or technology    A discussion of the objectives;
 testing concept.                         description of the proposed
                                          activities, including the
                                          technology you will use; and
                                          proposed schedule from start
                                          to completion.
(3) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(4) ROW, RUE or limited lease grant      A description of the measures
 stipulations, if known.                  you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.

[[Page 629]]

 
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   facility associated with your
                                          project.
(7) Deployment activities..............  A description of the safety,
                                          prevention, and environmental
                                          protection features or
                                          measures that you will use.
(8) A list of solid and liquid wastes    Disposal methods and locations.
 generated.
(9) A listing of chemical products used  A list of chemical products
 (only if stored volume exceeds USEPA     used; the volume stored on
 Reportable Quantities).                  location; their treatment,
                                          discharge, or disposal methods
                                          used; and the name and
                                          location of the onshore waste
                                          receiving, treatment, and/or
                                          disposal facility. A
                                          description of how these
                                          products would be brought
                                          onsite, the number of
                                          transfers that may take place,
                                          and the quantity that will be
                                          transferred each time.
(10) Reference information.............  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(11) Decommissioning and site clearance  A discussion of methodologies.
 procedures.
(12) Air quality information...........  As described in Sec.   585.659
                                          of this section.
(13) A listing of all Federal, State,    A statement indicating whether
 and local authorizations or approvals    such authorization or approval
 required to conduct site assessment      has been applied for or
 activities on your lease.                obtained.
(14) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(15) Financial assurance information...  Statements attesting that the
                                          activities and facilities
                                          proposed in your GAP are or
                                          will be covered by an
                                          appropriate bond or other
                                          approved security, as required
                                          in Sec.  Sec.   585.520 and
                                          585.521.
(16) Other information.................  Additional information as
                                          requested by BOEM.
------------------------------------------------------------------------

    (c) If you are applying for a project easement or constructing a 
facility, or a combination of facilities deemed by BOEM to be complex or 
significant, you must provide the following information in addition to 
what is required in paragraphs (a) and (b) of this section and comply 
with the requirements of subpart G of this part:

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) The construction and operation       A discussion of the objectives,
 concept.                                 description of the proposed
                                          activities, and tentative
                                          schedule from start to
                                          completion.
(2) All cables and pipelines, including  The location, design,
 cables on project easements.             installation methods, testing,
                                          maintenance, repair, safety
                                          devices, exterior corrosion
                                          protection, inspections, and
                                          decommissioning.
(3) A description of the deployment      Safety, prevention, and
 activities.                              environmental protection
                                          features or measures that you
                                          will use.
(4) A general description of the         (i) Under normal conditions.
 operating procedures and systems.       (ii) In the case of accidents
                                          or emergencies, including
                                          those that are natural or
                                          manmade.
(5) CVA nominations for reports          CVA nominations for reports in
 required in subpart G of this part.      subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request for a waiver under
                                          Sec.   585.705(c).
(6) Construction schedule..............  A reasonable schedule of
                                          construction activity showing
                                          significant milestones leading
                                          to the commencement of
                                          activities.
(7) Other information..................  Additional information as
                                          required by the BOEM.
------------------------------------------------------------------------

    (d) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure in 
accordance with the terms of Sec.  585.113.



Sec.  585.646  What information and certifications must I submit with
 my GAP to assist BOEM in complying with NEPA and other relevant laws?

    You must submit, with your GAP, detailed information to assist BOEM 
in

[[Page 630]]

complying with NEPA and other relevant laws as appropriate.
    (a) A GAP submitted for an area in which BOEM has not reviewed GAP 
activities under NEPA or other applicable Federal laws must describe 
those resources, conditions, and activities listed in the following 
table that could be affected by your proposed activities or that could 
affect the activities proposed in your GAP.
    (b) For a GAP submitted for an area in which BOEM has considered GAP 
activities under applicable Federal law (e.g., a NEPA analysis and CZMA 
consistency determination for the GAP activities), BOEM will review the 
GAP to determine if its impacts are consistent with those previously 
considered. If the anticipated effects of your proposed GAP activities 
are significantly different than those previously anticipated, we may 
determine that additional NEPA and other relevant Federal reviews are 
required. In that case, BOEM will notify you of such determination, and 
you must submit a GAP that describes those resources, conditions, and 
activities listed in the following table that could be affected by your 
proposed activities or that could affect the activities proposed in your 
GAP, including:

------------------------------------------------------------------------
       Type of information:                      Including:
------------------------------------------------------------------------
(1) Hazard information............  Meteorology, oceanography, sediment
                                     transport, geology, and shallow
                                     geological or manmade hazards.
(2) Water quality.................  Turbidity and total suspended solids
                                     from construction.
(3) Biological resources..........  Benthic communities, marine mammals,
                                     sea turtles, coastal and marine
                                     birds, fish and shellfish,
                                     plankton, sea grasses, and other
                                     plant life.
(4) Threatened or endangered        As required by the ESA (16 U.S.C.
 species.                            1531 et seq.).
(5) Sensitive biological resources  Essential fish habitat, refuges,
 or habitats.                        preserves, special management areas
                                     identified in coastal management
                                     programs, sanctuaries, rookeries,
                                     hard bottom habitat, chemosynthetic
                                     communities, calving grounds,
                                     barrier islands, beaches, dunes,
                                     and wetlands.
(6) Archaeological resources......  As required by NHPA (16 U.S.C. 470
                                     et seq.), as amended.
(7) Social and economic conditions  Employment, existing offshore and
                                     coastal infrastructure (including
                                     major sources of supplies,
                                     services, energy, and water), land
                                     use, subsistence resources and
                                     harvest practices, recreation,
                                     recreational and commercial fishing
                                     (including typical fishing seasons,
                                     location, and type), minority and
                                     lower income groups, coastal zone
                                     management programs, and viewshed.
(8) Coastal and marine uses.......  Military activities, vessel traffic,
                                     and energy and non-energy mineral
                                     exploration or development.
(9) Consistency Certification.....  If required by CZMA, as appropriate:
                                     (A) 15 CFR part 930, subpart D, if
                                     the GAP is submitted prior to lease
                                     or grant issuance; (B) 15 CFR part
                                     930, subpart E, if the GAP is
                                     submitted after lease or grant
                                     issuance.
(10) Other resources, conditions,   As required by BOEM.
 and activities.
------------------------------------------------------------------------


[79 FR 21625, Apr. 17, 2014]



Sec.  585.647  How will my GAP be processed for Federal consistency under
 the Coastal Zone Management Act?

    Your GAP will be processed based on whether it is submitted before 
or after your lease or grant is issued:

------------------------------------------------------------------------
                                     Consistency review of your GAP will
     If your GAP is submitted:             be handled as follows:
------------------------------------------------------------------------
(a) Before lease or grant issuance  You will furnish a copy of your GAP,
                                     consistency certification, and
                                     necessary data and information
                                     pursuant to 15 CFR part 930,
                                     subpart D, to the applicable State
                                     CZMA agency or agencies and BOEM at
                                     the same time.
(b) After lease or grant issuance.  You will submit a copy of your GAP,
                                     consistency certification, and
                                     necessary data and information
                                     pursuant to 15 CFR 930, subpart E
                                     to BOEM. BOEM will forward to the
                                     applicable State CZMA agency or
                                     agencies one paper copy and one
                                     electronic copy of your GAP,
                                     consistency certification, and
                                     necessary data and information
                                     required under 15 CFR part 930,
                                     subpart E, after BOEM has
                                     determined that all information
                                     requirements for the GAP are met.
------------------------------------------------------------------------


[[Page 631]]


[79 FR 21625, Apr. 17, 2014]



Sec.  585.648  How will BOEM process my GAP?

    (a) BOEM will review your submitted GAP, along with the information 
and certifications provided pursuant to Sec.  585.646, to determine if 
it contains all the required information necessary to conduct our 
technical and environmental reviews.
    (1) We will notify you if we deem your proposed facility or 
combination of facilities to be complex or significant; and
    (2) We will notify you if your submitted GAP lacks any necessary 
information.
    (b) BOEM will prepare appropriate NEPA analysis.
    (c) When appropriate, we will coordinate and consult with relevant 
State and Federal agencies and affected Indian Tribes and provide to 
other local, State, and Federal agencies and affected Indian Tribes 
relevant nonproprietary data and information pertaining to your proposed 
activities.
    (d) During the review process, we may request additional information 
if we determine that the information provided is not sufficient to 
complete the review and approval process. If you fail to provide the 
requested information, BOEM may disapprove your GAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your GAP.
    (1) If we approve your GAP, we will specify terms and conditions to 
be incorporated into your GAP. You must certify compliance with certain 
of those terms and conditions, as required under Sec.  585.653(c); and
    (2) If we disapprove your GAP, we will inform you of the reasons and 
allow you an opportunity to resubmit a revised plan making the necessary 
corrections, and may suspend the term of your lease or grant, as 
appropriate, to allow this to occur.



Sec.  585.649  [Reserved]

                    Activities Under an Approved GAP



Sec.  585.650  When may I begin conducting activities under my GAP?

    After BOEM approves your GAP, you may begin conducting the approved 
activities that do not involve a project easement or the construction of 
facilities on the OCS that BOEM has deemed to be complex or significant.



Sec.  585.651  When may I construct complex or significant OCS facilities
 on my limited lease or any facilities on my project easement proposed
 under my GAP?

    If you are applying for a project easement, or installing a facility 
or a combination of facilities on your limited lease deemed by BOEM to 
be complex or significant, as provided in Sec.  585.648(a)(1), you also 
must comply with the requirements of subpart G of this part and submit 
your Safety Management System description required by Sec.  585.810 
before construction may begin.



Sec.  585.652  How long do I have to conduct activities under an
 approved GAP?

    After BOEM approves your GAP, you have:
    (a) For a limited lease, 5 years to conduct your approved 
activities, unless we renew the term under Sec. Sec.  585.425 through 
585.429.
    (b) For a ROW grant or RUE grant, the time provided in the terms of 
the grant.



Sec.  585.653  What other reports or notices must I submit to BOEM
 under my approved GAP?

    (a) You must notify BOEM in writing within 30 days after completing 
installation activities approved in your GAP.
    (b) You must prepare and submit to BOEM annually a report that 
summarizes the findings from any activities you conduct under your 
approved GAP and the results of those activities. We will protect the 
information from public disclosure as provided in Sec.  585.113.
    (c) You must annually (or other frequency as determined by BOEM) 
submit a certification of compliance with those terms and conditions of 
your

[[Page 632]]

GAP that BOEM identifies under Sec.  585.648(e)(1). Together with your 
certification, you must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and monitoring methods and their effectiveness. If you identified 
measures that were not effective, you must include your recommendations 
for new mitigation measures or monitoring methods.



Sec.  585.654  [Reserved]



Sec.  585.655  What activities require a revision to my GAP, and when
 will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any activities 
not described in your approved GAP, describing in detail the type of 
activities you propose to conduct. We will determine whether the 
activities you propose are authorized by your existing GAP or require a 
revision to your GAP. We may request additional information from you, if 
necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved GAP. The frequency and extent of the review will be based on 
the significance of any changes in available information and on onshore 
or offshore conditions affecting, or affected by, the activities 
conducted under your GAP. If the review indicates that the GAP should be 
revised to meet the requirement of this part, we will require you to 
submit the needed revisions.
    (c) Activities for which a proposed revision to your GAP will likely 
be necessary include:
    (1) Activities not described in your approved GAP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Change in the surface location of a facility or structure;
    (4) Addition of a facility or structure not contemplated in your 
approved GAP;
    (5) Change in the location of your onshore support base from one 
State to another or to a new base requiring expansion;
    (6) Changes in the locations of bottom disturbances (anchors, 
chains, etc.) by 500 feet (152 meters) or greater from the approved 
locations. If a specific anchor pattern was approved as a mitigation 
measure to avoid contact with bottom features, any change in the 
proposed bottom disturbances would likely trigger the need for a 
revision;
    (7) Structural failure of one or more facilities; or
    (8) Change to any other activity specified by BOEM.
    (d) We may begin the appropriate NEPA analysis and any relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural resources; 
life (including human and wildlife); property; the marine, coastal, or 
human environment; or sites, structures, or objects of historical or 
archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.



Sec.  585.656  What must I do if I cease activities approved in my
 GAP before the end of my term?

    You must notify the BOEM any time you cease activities under your 
approved GAP without an approved suspension. If you cease activities for 
an indefinite period that exceeds 6 months, BOEM may cancel your lease 
or grant under Sec.  585.437, as applicable, and you must initiate the 
decommissioning process, as set forth in subpart I of this part.



Sec.  585.657  What must I do upon completion of approved activities
 under my GAP?

    Upon completion of your approved activities under your GAP, you must 
initiate the decommissioning process as set forth in subpart I of this 
part.

[[Page 633]]

You must submit your decommissioning application as provided in 
Sec. Sec.  585.905 and 585.906.

                      Cable and Pipeline Deviations



Sec.  585.658  Can my cable or pipeline construction deviate from my
 approved COP or GAP?

    (a) You must make every effort to ensure that all cables and 
pipelines are constructed in a manner that minimizes deviations from the 
approved plan under your lease or grant.
    (b) If BOEM determines that a significant change in conditions has 
occurred that would necessitate an adjustment to your ROW, RUE or lease 
before the commencement of construction of the cable or pipeline on the 
grant or lease, BOEM will consider modifications to your ROW grant, RUE 
grant, or your lease addendum for a project easement in connection with 
your COP or GAP.
    (c) If, after construction, it is determined that a deviation from 
the approved plan has occurred, you must:
    (1) Notify the operators of all leases (including mineral leases 
issued under this subchapter) and holders of all ROW grants or RUE 
grants (including all grants issued under this subchapter) which include 
the area where a deviation has occurred and provide BOEM with evidence 
of such notification;
    (2) Relinquish any unused portion of your lease or grant; and
    (3) Submit a revised plan for BOEM approval as necessary.
    (d) Construction of a cable or pipeline that substantially deviates 
from the approved plan may be grounds for cancellation of the lease or 
grant.



Sec.  585.659  What requirements must I include in my SAP, COP, or
 GAP regarding air quality?

    (a) You must comply with the Clean Air Act (42 U.S.C. 7409) and its 
implementing regulations, according to the following table.

------------------------------------------------------------------------
    If your project is located . . .              you must . . .
------------------------------------------------------------------------
(1) in the Gulf of Mexico west of        include in your plan any
 87.5[deg] west longitude (western Gulf   information required for BOEM
 of Mexico).                              to make the appropriate air
                                          quality determinations for
                                          your project.
(2) anywhere else on the OCS...........  follow the appropriate
                                          implementing regulations as
                                          promulgated by the EPA under
                                          40 CFR part 55.
------------------------------------------------------------------------

    (b) For air quality modeling that you perform in support of the 
activities proposed in your plan, you should contact the appropriate 
regulatory agency to establish a modeling protocol to ensure that the 
agency's needs are met and that the meteorological files used are 
acceptable before initiating the modeling work. In the western Gulf of 
Mexico (west of 87.5[deg] west longitude), you must submit to BOEM three 
copies of the modeling report and three sets of digital files as 
supporting information. The digital files must contain the formatted 
meteorological files used in the modeling runs, the model input file, 
and the model output file.



        Subpart G_Facility Design, Fabrication, and Installation

                                 Reports



Sec.  585.700  What reports must I submit to BOEM before installing
 facilities described in my approved SAP, COP, or GAP?

    (a) You must submit the following reports to BOEM before installing 
facilities described in your approved COP (Sec.  585.632(a)) and, when 
required by this part, your SAP (Sec.  585.614(b)) or GAP (Sec.  
585.651):
    (1) A Facility Design Report; and
    (2) A Fabrication and Installation Report.
    (b) You may begin to fabricate and install the approved facilities 
after BOEM notifies you that it has received your reports and has no 
objections. If BOEM receives the reports, but does

[[Page 634]]

not respond with objections within 60 days of receipt or 60 days after 
we approve your SAP, COP, or GAP, if you submitted your report with the 
plan, BOEM is deemed not to have objections to the reports, and you may 
commence fabrication and installation of your facility or facilities.
    (c) If BOEM has any objections, we will notify you verbally or in 
writing within 60 days of receipt of the report. Following initial 
notification of objections, BOEM may follow up with written 
correspondence outlining its specific objections to the report and 
request that certain actions be undertaken. You cannot commence 
activities addressed in such report until you resolve all objections to 
BOEM's satisfaction.



Sec.  585.701  What must I include in my Facility Design Report?

    (a) Your Facility Design Report provides specific details of the 
design of any facilities, including cables and pipelines that are 
outlined in your approved SAP, COP, or GAP. Your Facility Design Report 
must demonstrate that your design conforms to your responsibilities 
listed in Sec.  585.105(a). You must include the following items in your 
Facility Design Report:

------------------------------------------------------------------------
     Required documents         Required contents    Other requirements
------------------------------------------------------------------------
(1) Cover letter............  (i) Proposed          You must submit 1
                               facility              paper copy and 1
                               designations;         electronic copy.
                              (ii) Lease, ROW
                               grant or RUE grant
                               number;.
                              (iii) Area; name and
                               block numbers; and
                              (iv) The type of
                               facility.
(2) Location plat...........  (i) Latitude and      Your plat must be
                               longitude             drawn to a scale of
                               coordinates,          1 inch equals 100
                               Universal Mercator    feet and include
                               grid-system           the coordinates of
                               coordinates, state    the lease, ROW
                               plane coordinates     grant, or RUE grant
                               in the Lambert or     block boundary
                               Transverse Mercator   lines. You must
                               Projection System;    submit 1 paper copy
                              (ii) Distances in      and 1 electronic
                               feet from the         copy.
                               nearest block
                               lines. These
                               coordinates must be
                               based on the NAD
                               (North American
                               Datum) 83 datum
                               plane coordinate
                               system; and.
                              (iii) The location
                               of any proposed
                               project easement..
(3) Front, Side, and Plan     (i) Facility          Your drawing sizes
 View drawings.                dimensions and        must not exceed
                               orientation;          11 x
                              (ii) Elevations        17. You
                               relative to Mean      must submit 1 paper
                               Lower Low Water;      copy and 1
                               and.                  electronic copy.
                              (iii) Pile sizes and
                               penetration.
(4) Complete set of           The approved for      Your drawing sizes
 structural drawings.          construction          must not exceed
                               fabrication           11 x
                               drawings should be    17. You
                               submitted             must submit 1 paper
                               including, e.g.,      copy and 1
                              (i) Cathodic           electronic copy.
                               protection systems;
                              (ii) Jacket design;
                              (iii) Pile
                               foundations;
                              (iv) Mooring and
                               tethering systems;
                              (v) Foundations and
                               anchoring systems;
                               and.
                              (vi) Associated
                               cable and pipeline
                               designs..
(5) Summary of environmental  A summary of the      You must submit 1
 data used for design.         environmental data    paper copy and 1
                               used in the design    electronic copy. If
                               or analysis of the    you submitted these
                               facility. Examples    data as part of
                               of relevant data      your SAP, COP, or
                               include information   GAP, you may
                               on:                   reference the plan.
                                 (i) Extreme
                                  weather;.
                                 (ii) Seafloor
                                  conditions; and.
                                 (iii) Waves,
                                  wind, current,
                                  tides,
                                  temperature,
                                  snow and ice
                                  effects, marine
                                  growth, and
                                  water depth..

[[Page 635]]

 
(6) Summary of the            (i) Loading           You must submit 1
 engineering design data.      information (e.g.,    paper copy and 1
                               live, dead,           electronic copy.
                               environmental);
                              (ii) Structural
                               information (e.g.,
                               design-life;
                               material types;
                               cathodic protection
                               systems; design
                               criteria; fatigue
                               life; jacket
                               design; deck
                               design; production
                               component design;
                               foundation pilings
                               and templates, and
                               mooring or
                               tethering systems;
                               fabrication and
                               installation
                               guidelines); and.
                              (iii) Location of
                               foundation
                               boreholes and
                               foundation piles;
                               and.
                              (iv) Foundation
                               information (e.g.,
                               soil stability,
                               design criteria)..
(7) A complete set of design  Self-explanatory....  You must submit 1
 calculations.                                       paper copy and 1
                                                     electronic copy.
(8) Project-specific studies  All studies           You must submit 1
 used in the facility design   pertinent to          paper copy and 1
 or installation.              facility design or    electronic copy.
                               installation, e.g.,
                               oceanographic and
                               soil reports
                               including the
                               results of the
                               surveys required in
                               Sec.  Sec.
                               585.610(b),
                               585.627(a), or
                               585.645(a).
(9) Description of the loads  (i) Loads imposed by  You must submit 1
 imposed on the facility.      jacket;               paper copy and 1
                              (ii) Decks;            electronic copy.
                              (iii) Production
                               components;
                              (iv) Foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               and.
                              (v) Mooring or
                               tethering systems.
(10) Geotechnical Report....  A list of all data    You must submit 1
                               from borings and      paper copy and 1
                               recommended design    electronic copy.
                               parameters.
------------------------------------------------------------------------

    (b) For any floating facility, your design must meet the 
requirements of the U.S. Coast Guard for structural integrity and 
stability (e.g., verification of center of gravity). The design must 
also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.
    (c) You must provide the location of records, as required in Sec.  
585.714(c).
    (d) If you are required to use a CVA, the Facility Design Report 
must include one paper copy of the following certification statement: 
``The design of this structure has been certified by a BOEM approved CVA 
to be in accordance with accepted engineering practices and the approved 
SAP, GAP, or COP as appropriate. The certified design and as-built plans 
and specifications will be on file at (given location).''
    (e) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and in accordance with the terms of Sec.  
585.113.



Sec.  585.702  What must I include in my Fabrication and Installation
 Report?

    (a) Your Fabrication and Installation Report must describe how your 
facilities will be fabricated and installed in accordance with the 
design criteria identified in the Facility Design Report; your approved 
SAP, COP, or GAP; and generally accepted industry standards and 
practices. Your Fabrication and Installation Report must demonstrate how 
your facilities will be fabricated and installed in a manner that 
conforms to your responsibilities listed in Sec.  585.105(a). You must 
include the following items in your Fabrication and Installation Report:

------------------------------------------------------------------------
     Required documents         Required contents    Other requirements
------------------------------------------------------------------------
(1) Cover letter............  (i) Proposed          You must submit 1
                               facility              paper copy and 1
                               designation, lease,   electronic copy.
                               ROW grant, or RUE
                               grant number;
                              (ii) Area, name, and
                               block number; and
                              (iii) The type of
                               facility.

[[Page 636]]

 
(2) Schedule................  Fabrication and       You must submit 1
                               installation.         paper copy and 1
                                                     electronic copy.
(3) Fabrication information.  The industry          You must submit 1
                               standards you will    paper copy and 1
                               use to ensure the     electronic copy.
                               facilities are
                               fabricated to the
                               design criteria
                               identified in your
                               Facility Design
                               Report.
(4) Installation process      Details associated    You must submit 1
 information.                  with the deployment   paper copy and 1
                               activities,           electronic copy.
                               equipment, and
                               materials,
                               including onshore
                               and offshore
                               equipment and
                               support, and
                               anchoring and
                               mooring patterns.
(5) Federal, State, and       Either 1 copy of the  You must submit 1
 local permits (e.g., EPA,     permit or             paper copy and 1
 Army Corps of Engineers).     information on the    electronic copy.
                               status of the
                               application.
(6) Environmental             (i) Water discharge;  You must submit 1
 information.                 (ii) Waste disposal;   paper copy and 1
                              (iii) Vessel           electronic copy. If
                               information; and      you submitted these
                              (iv) Onshore waste     data as part of
                               receiving treatment   your SAP, COP, or
                               or disposal           GAP, you may
                               facilities..          reference the plan.
(7) Project easement........  Design of any         You must submit 1
                               cables, pipelines,    paper copy and 1
                               or facilities.        electronic copy.
                               Information on
                               burial methods and
                               vessels.
------------------------------------------------------------------------

    (b) You must provide the location of records, as required in Sec.  
585.714(c).
    (c) If you are required to use a CVA, the Fabrication and 
Installation Report must include one paper copy of the following 
certification statement: ``The fabrication and installation of this 
structure has been certified by a BOEM approved CVA to be in accordance 
with accepted engineering practices and the approved SAP, GAP, or COP as 
appropriate. The certified design and as-built plans and specifications 
will be on file at (given location).''
    (d) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and in accordance with the terms of Sec.  
585.113.



Sec.  585.703  What reports must I submit for project modifications
 and repairs?

    (a) You must verify and, in a report to us, certify that major 
repairs and major modifications to the project conform to accepted 
engineering practices.
    (1) A major repair is a corrective action involving structural 
members affecting the structural integrity of a portion of or all the 
facility.
    (2) A major modification is an alteration involving structural 
members affecting the structural integrity of a portion of or all the 
facility.
    (b) The report must also identify the location of all records 
pertaining to the major repairs or major modifications, as required in 
Sec.  585.714(c).
    (c) BOEM may require you to use a CVA for project modifications and 
repairs.



Sec.  585.704  [Reserved]

                      Certified Verification Agent



Sec.  585.705  When must I use a Certified Verification Agent (CVA)?

    You must use a CVA to review and certify the Facility Design Report, 
the Fabrication and Installation Report, and the Project Modifications 
and Repairs Report.
    (a) You must use a CVA to:
    (1) Ensure that your facilities are designed, fabricated, and 
installed in conformance with accepted engineering practices and the 
Facility Design Report and Fabrication and Installation Report;
    (2) Ensure that repairs and major modifications are completed in 
conformance with accepted engineering practices; and
    (3) Provide BOEM immediate reports of all incidents that affect the 
design, fabrication, and installation of the project and its components.
    (b) BOEM may waive the requirement that you use a CVA if you can 
demonstrate the following:

[[Page 637]]



------------------------------------------------------------------------
                                             Then BOEM may waive the
     If you demonstrate that . . .        requirement for a CVA for the
                                                    following:
------------------------------------------------------------------------
(1) The facility design conforms to a    The design of your
 standard design that has been used       structure(s).
 successfully in a similar environment,
 and the installation design conforms
 to accepted engineering practices.
(2) The manufacturer has successfully    The fabrication of your
 manufactured similar facilities, and     structure(s).
 the facility will be fabricated in
 conformance with accepted engineering
 practices.
(3) The installation company has         The installation of your
 successfully installed similar           structure(s).
 facilities in a similar offshore
 environment, and your structure(s)
 will be installed in conformance with
 accepted engineering practices.
(4) Repairs and major modifications      The repair or major
 will be completed in conformance with    modification of your
 accepted engineering practices.          structure(s).
------------------------------------------------------------------------

    (c) You must submit a request to waive the requirement to use a CVA 
to BOEM in writing, along with your SAP under Sec.  585.610(a)(9), COP 
under Sec.  585.626(b)(20), or GAP under Sec.  585.645(c)(5).
    (1) BOEM will review your request to waive the use of the CVA and 
notify you of our decision along with our decision on your SAP, COP, or 
GAP.
    (2) If BOEM does not waive the requirement for a CVA, you may file 
an appeal under Sec.  585.118.
    (3) If BOEM waives the requirement that you use a CVA, your project 
engineer must perform the same duties and responsibilities as the CVA, 
except as otherwise provided.



Sec.  585.706  How do I nominate a CVA for BOEM approval?

    (a) As part of your COP (as provided in Sec.  585.626(b)(20) and, 
when required by this part, your SAP (Sec.  585.610(a)(9)) or GAP (Sec.  
585.645(c)(5)), you must nominate a CVA for BOEM approval. You must 
specify whether the nomination is for the Facility Design Report, 
Fabrication and Installation Report, Modification and Repair Report, or 
for any combination of these.
    (b) For each CVA that you nominate, you must submit to BOEM a list 
of documents used in your design that you will forward to the CVA and a 
qualification statement that includes the following:
    (1) Previous experience in third-party verification or experience in 
the design, fabrication, installation, or major modification of offshore 
energy facilities;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology 
(including computer programs, hardware, and testing materials and 
equipment);
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with BOEM requirements and procedures, if 
any; and
    (7) The level of work to be performed by the CVA.
    (c) Individuals or organizations acting as CVAs must not function in 
any capacity that will create a conflict of interest, or the appearance 
of a conflict of interest.
    (d) The verification must be conducted by or under the direct 
supervision of registered professional engineers.
    (e) BOEM will approve or disapprove your CVA as part of its review 
of the COP or, when required, of your SAP or GAP.
    (f) You must nominate a new CVA for BOEM approval if the previously 
approved CVA:
    (1) Is no longer able to serve in a CVA capacity for the project; or
    (2) No longer meets the requirements for a CVA set forth in this 
subpart.



Sec.  585.707  What are the CVA's primary duties for facility design review?

    If you are required to use a CVA:
    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the design of the facility. The 
CVA must certify in the Facility Design Report to BOEM that the facility 
is designed to withstand the environmental

[[Page 638]]

and functional load conditions appropriate for the intended service life 
at the proposed location.
    (b) The CVA must conduct an independent assessment of all proposed:
    (1) Planning criteria;
    (2) Operational requirements;
    (3) Environmental loading data;
    (4) Load determinations;
    (5) Stress analyses;
    (6) Material designations;
    (7) Soil and foundation conditions;
    (8) Safety factors; and
    (9) Other pertinent parameters of the proposed design.
    (c) For any floating facility, the CVA must ensure that any 
requirements of the U.S. Coast Guard for structural integrity and 
stability (e.g., verification of center of gravity), have been met. The 
CVA must also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.



Sec.  585.708  What are the CVA's or project engineer's primary duties
 for fabrication and installation review?

    (a) The CVA or project engineer must do all of the following:
    (1) Use good engineering judgment and practice in conducting an 
independent assessment of the fabrication and installation activities;
    (2) Monitor the fabrication and installation of the facility as 
required by paragraph (b) of this section;
    (3) Make periodic onsite inspections while fabrication is in 
progress and verify the items required by Sec.  585.709;
    (4) Make periodic onsite inspections while installation is in 
progress and satisfy the requirements of Sec.  585.710; and
    (5) Certify in a report that project components are fabricated and 
installed in accordance with accepted engineering practices; your 
approved COP, SAP, or GAP (as applicable); and the Fabrication and 
Installation Report.
    (i) The report must also identify the location of all records 
pertaining to fabrication and installation, as required in Sec.  
585.714(c); and
    (ii) You may commence commercial operations or other approved 
activities 30 days after BOEM receives that certification report, unless 
BOEM notifies you within that time period of its objections to the 
certification report.
    (b) To comply with paragraph (a)(5) of this section, the CVA or 
project engineer must monitor the fabrication and installation of the 
facility to ensure that it has been built and installed according to the 
Facility Design Report and Fabrication and Installation Report.
    (1) If the CVA or project engineer finds that fabrication and 
installation procedures have been changed or design specifications have 
been modified, the CVA or project engineer must inform you; and
    (2) If you accept the modifications, then you must also inform BOEM.



Sec.  585.709  When conducting onsite fabrication inspections, what must
 the CVA or project engineer verify?

    (a) To comply with Sec.  585.708(a)(3), the CVA or project engineer 
must make periodic onsite inspections while fabrication is in progress 
and must verify the following fabrication items, as appropriate:
    (1) Quality control by lessee (or grant holder) and builder;
    (2) Fabrication site facilities;
    (3) Material quality and identification methods;
    (4) Fabrication procedures specified in the Fabrication and 
Installation Report, and adherence to such procedures;
    (5) Welder and welding procedure qualification and identification;
    (6) Structural tolerances specified, and adherence to those 
tolerances;
    (7) Nondestructive examination requirements and evaluation results 
of the specified examinations;
    (8) Destructive testing requirements and results;
    (9) Repair procedures;
    (10) Installation of corrosion-protection systems and splash-zone 
protection;
    (11) Erection procedures to ensure that overstressing of structural 
members does not occur;
    (12) Alignment procedures;
    (13) Dimensional check of the overall structure, including any 
turrets, turret-and-hull interfaces, any mooring line and chain and 
riser tensioning line segments; and

[[Page 639]]

    (14) Status of quality-control records at various stages of 
fabrication.
    (b) For any floating facilities, the CVA or project engineer must 
ensure that any requirements of the U.S. Coast Guard for structural 
integrity and stability (e.g., verification of center of gravity) have 
been met. The CVA or project engineer must also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.



Sec.  585.710  When conducting onsite installation inspections, what
 must the CVA or project engineer do?

    To comply with Sec.  585.708(a)(4), the CVA or project engineer must 
make periodic onsite inspections while installation is in progress and 
must, as appropriate, verify, witness, survey, or check, the 
installation items required by this section.
    (a) The CVA or project engineer must verify, as appropriate, all of 
the following:
    (1) Loadout and initial flotation procedures;
    (2) Towing operation procedures to the specified location, and 
review the towing records;
    (3) Launching and uprighting activities;
    (4) Submergence activities;
    (5) Pile or anchor installations;
    (6) Installation of mooring and tethering systems;
    (7) Final deck and component installations; and
    (8) Installation at the approved location according to the Facility 
Design Report and the Fabrication and Installation Report.
    (b) For a fixed or floating facility, the CVA or project engineer 
must verify that proper procedures were used during the following:
    (1) The loadout of the jacket, decks, piles, or structures from each 
fabrication site; and
    (2) The actual installation of the facility or major modification 
and the related installation activities.
    (c) For a floating facility, the CVA or project engineer must verify 
that proper procedures were used during the following:
    (1) The loadout of the facility;
    (2) The installation of foundation pilings and templates, and 
anchoring systems; and
    (3) The installation of the mooring and tethering systems.
    (d) The CVA or project engineer must conduct an onsite survey of the 
facility after transportation to the approved location.
    (e) The CVA or project engineer must spot-check the equipment, 
procedures, and recordkeeping as necessary to determine compliance with 
the applicable documents incorporated by reference and the regulations 
under this part.



Sec.  585.711  [Reserved]



Sec.  585.712  What are the CVA's or project engineer's reporting 
requirements?

    (a) The CVA or project engineer must prepare and submit to you and 
BOEM all reports required by this subpart. The CVA or project engineer 
must also submit interim reports to you and BOEM, as requested by the 
BOEM.
    (b) For each report required by this subpart, the CVA or project 
engineer must submit one electronic copy and one paper copy of each 
final report to BOEM. In each report, the CVA or project engineer must:
    (1) Give details of how, by whom, and when the CVA or project 
engineer activities were conducted;
    (2) Describe the CVA's or project engineer's activities during the 
verification process;
    (3) Summarize the CVA's or project engineer's findings; and
    (4) Provide any additional comments that the CVA or project engineer 
deems necessary.



Sec.  585.713  What must I do after the CVA or project engineer confirms
 conformance with the Fabrication and Installation Report on my
 commercial lease?

    After the CVA or project engineer files the certification report, 
you must notify BOEM within 10 business days after commencing commercial 
operations.



Sec.  585.714  What records relating to SAPs, COPs, and GAPs must I keep?

    (a) Until BOEM releases your financial assurance under Sec.  
585.534, you must

[[Page 640]]

compile, retain, and make available to BOEM representatives, within the 
time specified by BOEM, all of the following:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation examination 
records;
    (4) The inspection results from the inspections and assessments 
required by Sec. Sec.  585.820 through 585.825; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec.  585.824(b)(3).
    (b) You must record and retain the original material test results of 
all primary structural materials during all stages of construction until 
BOEM releases your financial assurance under Sec.  585.534. Primary 
material is material that, should it fail, would lead to a significant 
reduction in facility safety, structural reliability, or operating 
capabilities. Items such as steel brackets, deck stiffeners and 
secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide BOEM with the location of these records in the 
certification statement, as required in Sec. Sec.  585.701(c), 
585.703(b), and 585.708(a)(5)(i).



Subpart H_Environmental and Safety Management, Inspections, and Facility 
     Assessments for Activities Conducted Under SAPs, COPs and GAPs



Sec.  585.800  How must I conduct my activities to comply with safety
 and environmental requirements?

    (a) You must conduct all activities on your lease or grant under 
this part in a manner that conforms with your responsibilities in Sec.  
585.105(a), and using:
    (1) Trained personnel; and
    (2) Technologies, precautions, and techniques that will not cause 
undue harm or damage to natural resources, including their physical, 
atmospheric, and biological components.
    (b) You must certify compliance with those terms and conditions 
identified in your approved SAP, COP, or GAP, as required under Sec.  
585.615(c), Sec.  585.633(b), or Sec.  585.653(c).



Sec.  585.801  How must I conduct my approved activities to protect
 marine mammals, threatened and endangered species, and designated 
critical habitat?

    (a) You must not conduct any activity under your lease or grant that 
may affect threatened or endangered species or that may affect 
designated critical habitat of such species until the appropriate level 
of consultation is conducted, as required under the ESA, as amended (16 
U.S.C. 1531 et seq.), to ensure that your actions are not likely to 
jeopardize a threatened or endangered species and are not likely to 
destroy or adversely modify designated critical habitat.
    (b) You must not conduct any activity under your lease or grant that 
may result in an incidental taking of marine mammals until the 
appropriate authorization has been issued under the Marine Mammal 
Protection Act of 1972 (MMPA) as amended (16 U.S.C. 1361 et seq.).
    (c) If there is reason to believe that a threatened or endangered 
species may be present while you conduct your BOEM approved activities 
or may be affected by the direct or indirect effects of your actions:
    (1) You must notify us that endangered or threatened species may be 
present in the vicinity of the lease or grant or may be affected by your 
actions; and
    (2) We will consult with appropriate State and Federal fish and 
wildlife agencies and, after consultation, shall identify whether, and 
under what conditions, you may proceed.
    (d) If there is reason to believe that designated critical habitat 
of a threatened or endangered species may be affected by the direct or 
indirect effects of your BOEM approved activities:
    (1) You must notify us that designated critical habitat of a 
threatened or endangered species in the vicinity of the lease or grant 
may be affected by your actions; and
    (2) We will consult with appropriate State and Federal fish and 
wildlife agencies and, after consultation, shall identify whether, and 
under what conditions, you may proceed.

[[Page 641]]

    (e) If there is reason to believe that marine mammals may be 
incidentally taken as a result of your proposed activities:
    (1) You must agree to secure an authorization from National Oceanic 
and Atmospheric Administration (NOAA) or the U.S. Fish and Wildlife 
Service (FWS) for incidental taking, including taking by harassment, 
that may result from your actions; and
    (2) You must comply with all measures required by the NOAA or FWS, 
including measures to affect the least practicable impact on such 
species and its habitat and to ensure no immitigable adverse impact on 
the availability of the species for subsistence use.
    (f) Submit to us:
    (1) Measures designed to avoid or minimize adverse effects and any 
potential incidental take of the endangered or threatened species or 
marine mammals;
    (2) Measures designed to avoid likely adverse modification or 
destruction of designated critical habitat of such endangered or 
threatened species; and
    (3) Your agreement to monitor for the incidental take of the species 
and adverse effects on the critical habitat, and provide the results of 
the monitoring to BOEM as required; and
    (4) Your agreement to perform any relevant terms and conditions of 
the Incidental Take Statement that may result from the ESA consultation.
    (5) Your agreement to perform any relevant mitigation measures under 
an MMPA incidental take authorization.



Sec.  585.802  What must I do if I discover a potential archaeological
 resource while conducting my approved activities?

    (a) If you, your subcontractors, or any agent acting on your behalf 
discovers a potential archaeological resource while conducting 
construction activities, or any other activity related to your project, 
you must:
    (1) Immediately halt all seafloor-disturbing activities within the 
area of the discovery;
    (2) Notify BOEM of the discovery within 72 hours; and
    (3) Keep the location of the discovery confidential and not take any 
action that may adversely affect the archaeological resource until we 
have made an evaluation and instructed you on how to proceed.
    (b) We may require you to conduct additional investigations to 
determine if the resource is eligible for listing in the National 
Register of Historic Places under 36 CFR 60.4. We will do this if:
    (1) The site has been impacted by your project activities; or
    (2) Impacts to the site or to the area of potential effect cannot be 
avoided.
    (c) If investigations under paragraph (b) of this section indicate 
that the resource is potentially eligible for listing in the National 
Register of Historic Places, we will tell you how to protect the 
resource, or how to mitigate adverse effects to the site.
    (d) If we incur costs in protecting the resource, under section 
110(g) of the NHPA, we may charge you reasonable costs for carrying out 
preservation responsibilities under the OCS Lands Act.



Sec.  585.803  How must I conduct my approved activities to protect
 essential fish habitats identified and described under the 
Magnuson-Stevens Fishery Conservation and Management Act?

    (a) If, during the conduct of your approved activities, BOEM finds 
that essential fish habitat or habitat areas of particular concern may 
be adversely affected by your activities, BOEM must consult with 
National Marine Fisheries Service.
    (b) Any conservation recommendations adopted by BOEM to avoid or 
minimize adverse affects on Essential Fish Habitat will be incorporated 
as terms and conditions in the lease and must be adhered to by the 
applicant. BOEM may require additional surveys to define boundaries and 
avoidance distances.
    (c) If required, BOEM will specify the survey methods and 
instrumentations for conducting the biological survey and will specify 
the contents of the biological report.

[[Page 642]]



Sec. Sec.  585.804-585.809  [Reserved]

                        Safety Management Systems



Sec.  585.810  What must I include in my Safety Management System?

    You must submit a description of the Safety Management System you 
will use with your COP (provided under Sec.  585.627(d)) and, when 
required by this part, your SAP (as provided in Sec.  585.614(b)) or GAP 
(as provided in Sec.  585.651). You must describe:
    (a) How you will ensure the safety of personnel or anyone on or near 
your facilities;
    (b) Remote monitoring, control, and shut down capabilities;
    (c) Emergency response procedures;
    (d) Fire suppression equipment, if needed;
    (e) How and when you will test your Safety Management System; and
    (f) How you will ensure personnel who operate your facilities are 
properly trained.



Sec.  585.811  When must I follow my Safety Management System?

    Your Safety Management System must be fully functional when you 
begin activities described in your approved COP, SAP, or GAP. You must 
conduct all activities described in your approved COP, SAP, or GAP in 
accordance with the Safety Management System you described, as required 
by Sec.  585.810.



Sec.  585.812  [Reserved]

                        Maintenance and Shutdowns



Sec.  585.813  When do I have to report removing equipment from service?

    (a) The removal of any equipment from service may result in BOEM 
applying remedies, as provided in this part, when such equipment is 
necessary for implementing your approved plan. Such remedies may include 
an order from BOEM requiring you to replace or remove such equipment or 
facilities.
    (b)(1) You must report within 24 hours when equipment necessary for 
implementing your approved plan is removed from service for more than 12 
hours. If you provide an oral notification, you must submit a written 
confirmation of this notice within 3 business days, as required by Sec.  
585.105(c);
    (2) You do not have to report removing equipment necessary for 
implementing your plan if the removal is part of planned maintenance or 
repair activities; and
    (3) You must notify BOEM when you return the equipment to service.



Sec.  585.814  [Reserved]

           Equipment Failure and Adverse Environmental Effects



Sec.  585.815  What must I do if I have facility damage or an
 equipment failure?

    (a) If you have facility damage or the failure of a pipeline, cable, 
or other equipment necessary for you to implement your approved plan, 
you must make repairs as soon as practicable. If you have a major 
repair, you must submit a report of the repairs to BOEM, as required in 
Sec.  585.711.
    (b) If you are required to report any facility damage or failure 
under Sec.  585.831, BOEM may require you to revise your SAP, COP, or 
GAP to describe how you will address the facility damage or failure as 
required by Sec.  585.634 (COP), Sec.  585.617 (SAP), Sec.  585.655 
(GAP). You must submit a report of the repairs to BOEM, as required in 
Sec.  585.703.
    (c) BOEM may require that you analyze cable, pipeline, or facility 
damage or failure to determine the cause. If requested by BOEM, you must 
submit a comprehensive written report of the failure or damage to BOEM 
as soon as available.



Sec.  585.816  What must I do if environmental or other conditions
 adversely affect a cable, pipeline, or facility?

    If environmental or other conditions adversely affect a cable, 
pipeline, or facility so as to endanger the safety or the environment, 
you must:
    (a) Submit a plan of corrective action to BOEM within 30 days of the 
discovery of the adverse effect.
    (b) Take remedial action as described in your corrective action 
plan.
    (c) Submit to the BOEM a report of the remedial action taken within 
30 days after completion.

[[Page 643]]



Sec. Sec.  585.817-585.819  [Reserved]

                       Inspections and Assessment



Sec.  585.820  Will BOEM conduct inspections?

    BOEM will inspect OCS facilities and any vessels engaged in 
activities authorized under this part. We conduct these inspections:
    (a) To verify that you are conducting activities in compliance with 
subsection 8(p) of the OCS Lands Act; the regulations in this part; the 
terms, conditions, and stipulations of your lease or grant; approved 
plans; and other applicable laws and regulations.
    (b) To determine whether proper safety equipment has been installed 
and is operating properly according to your Safety Management System, as 
required in Sec.  585.810.



Sec.  585.821  Will BOEM conduct scheduled and unscheduled inspections?

    BOEM will conduct both scheduled and unscheduled inspections.



Sec.  585.822  What must I do when BOEM conducts an inspection?

    (a) When BOEM conducts an inspection, you must:
    (1) Provide access to all facilities on your lease (including your 
project easement) or grant; and
    (2) Make the following available for BOEM to inspect:
    (i) The area covered under a lease, ROW grant, or RUE grant;
    (ii) All improvements, structures, and fixtures on these areas; and
    (iii) All records of design, construction, operation, maintenance, 
repairs, or investigations on or related to the area.
    (b) You must retain these records in paragraph (a)(2)(iii) of this 
section until BOEM releases your financial assurance under Sec.  585.534 
and provide them to BOEM upon request, within the time period specified 
by BOEM.
    (c) You must demonstrate to the inspector how you are in compliance 
with your Safety Management System.



Sec.  585.823  Will BOEM reimburse me for my expenses related to
 inspections?

    Upon request, BOEM will reimburse you for food, quarters, and 
transportation that you provide for our representatives while they 
inspect your lease or grant facilities and associated activities. You 
must send us your reimbursement request within 90 days of the 
inspection.



Sec.  585.824  How must I conduct self-inspections?

    (a) You must develop a comprehensive annual self-inspection plan 
covering all of your facilities. You must keep this plan wherever you 
keep your records and make it available to BOEM inspectors upon request. 
Your plan must specify:
    (1) The type, extent, and frequency of in-place inspections that you 
will conduct for both the above-water and the below-water structures of 
all facilities and pertinent components of the mooring systems for any 
floating facilities; and
    (2) How you are monitoring the corrosion protection for both the 
above-water and below-water structures.
    (b) You must submit a report annually to us no later than November 1 
that must include:
    (1) A list of facilities inspected in the preceding 12 months;
    (2) The type of inspection employed, (i.e., visual, magnetic 
particle, ultrasonic testing); and
    (3) A summary of the inspection indicating what repairs, if any, 
were needed and the overall structural condition of the facility.



Sec.  585.825  When must I assess my facilities?

    (a) You must perform an assessment of the structure, when needed, 
based on the platform assessment initiators listed in sections 17.2.1-
17.2.5 of API RP 2A-WSD, Recommended Practice for Planning, Designing 
and Constructing Fixed Offshore Platforms--Working Stress Design (as 
incorporated by reference in Sec.  585.115).
    (b) You must initiate mitigation actions for structures that do not 
pass the assessment process of API RP 2A-WSD.
    (c) You must perform other assessments as required by BOEM.

[[Page 644]]



Sec. Sec.  585.826-585.829  [Reserved]

                  Incident Reporting and Investigation



Sec.  585.830  What are my incident reporting requirements?

    (a) You must report all incidents listed in Sec.  585.831 to BOEM, 
according to the reporting requirements for these incidents in 
Sec. Sec.  585.832 and 585.833.
    (b) These reporting requirements apply to incidents that occur on 
the area covered by your lease or grant under this part and that are 
related to activities resulting from the exercise of your rights under 
your lease or grant under this part.
    (c) Nothing in this subpart relieves you from providing notices and 
reports of incidents that may be required by other regulatory agencies.
    (d) You must report all spills of oil or other liquid pollutants in 
accordance with 30 CFR 254.46.



Sec.  585.831  What incidents must I report, and when must I report them?

    (a) You must report the following incidents to us immediately via 
oral communication, and provide a written follow-up report (paper copy 
or electronically transmitted) within 15 business days after the 
incident:
    (1) Fatalities;
    (2) Incidents that require the evacuation of person(s) from the 
facility to shore or to another offshore facility;
    (3) Fires and explosions;
    (4) Collisions that result in property or equipment damage greater 
than $25,000 (Collision means the act of a moving vessel (including an 
aircraft) striking another vessel, or striking a stationary vessel or 
object. Property or equipment damage means the cost of labor and 
material to restore all affected items to their condition before the 
damage, including, but not limited to, the OCS facility, a vessel, a 
helicopter, or the equipment. It does not include the cost of salvage, 
cleaning, dry docking, or demurrage);
    (5) Incidents involving structural damage to an OCS facility that is 
severe enough so that activities on the facility cannot continue until 
repairs are made;
    (6) Incidents involving crane or personnel/material handling 
activities, if they result in a fatality, injury, structural damage, or 
significant environmental damage;
    (7) Incidents that damage or disable safety systems or equipment 
(including firefighting systems);
    (8) Other incidents resulting in property or equipment damage 
greater than $25,000; and
    (9) Any other incidents involving significant environmental damage, 
or harm.
    (b) You must provide a written report of the following incidents to 
us within 15 days after the incident:
    (1) Any injuries that result in the injured person not being able to 
return to work or to all of their normal duties the day after the injury 
occurred; and
    (2) All incidents that require personnel on the facility to muster 
for evacuation for reasons not related to weather or drills.



Sec.  585.832  How do I report incidents requiring immediate
 notification?

    For an incident requiring immediate notification under Sec.  
585.831(a), you must notify BOEM verbally after aiding the injured and 
stabilizing the situation. Your verbal communication must provide the 
following information:
    (a) Date and time of occurrence;
    (b) Identification and contact information for the lessee, grant 
holder, or operator;
    (c) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury/fatality);
    (d) Lease number, OCS area, and block;
    (e) Platform/facility name and number, or cable or pipeline segment 
number;
    (f) Type of incident or injury/fatality;
    (g) Activity at time of incident; and
    (h) Description of the incident, damage, or injury/fatality.



Sec.  585.833  What are the reporting requirements for incidents
 requiring written notification?

    (a) For any incident covered under Sec.  585.831, you must submit a 
written report within 15 days after the incident to BOEM. The report 
must contain the following information:
    (1) Date and time of occurrence;

[[Page 645]]

    (2) Identification and contact information for each lessee, grant 
holder, or operator;
    (3) Name and telephone number of the contractor and the contractor's 
representative, if a contractor is involved in the incident or injury;
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or cable or pipeline segment 
number;
    (6) Type of incident or injury;
    (7) Activity at time of incident;
    (8) Description of incident, damage, or injury (including days away 
from work, restricted work, or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section if 
the report or form contains all required information.
    (c) BOEM may require you to submit additional information about an 
incident on a case-by-case basis.



                        Subpart I_Decommissioning

              Decommissioning Obligations and Requirements



Sec.  585.900  Who must meet the decommissioning obligations in 
this subpart?

    (a) Lessees are jointly and severally responsible for meeting 
decommissioning obligations for facilities on their leases, including 
all obstructions, as the obligations accrue and until each obligation is 
met.
    (b) Grant holders are jointly and severally liable for meeting 
decommissioning obligations for facilities on their grant, including all 
obstructions, as the obligations accrue and until each obligation is 
met.



Sec.  585.901  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you are or become a 
lessee or grant holder, and you either install, construct, or acquire by 
a BOEM-approved assignment a facility, cable, or pipeline, or you create 
an obstruction to other uses of the OCS.



Sec.  585.902  What are the general requirements for decommissioning
 for facilities authorized under my SAP, COP, or GAP?

    (a) Except as otherwise authorized by BOEM under Sec.  585.909, 
within 2 years following termination of a lease or grant, you must:
    (1) Remove or decommission all facilities, projects, cables, 
pipelines, and obstructions;
    (2) Clear the seafloor of all obstructions created by activities on 
your lease, including your project easement, or grant, as required by 
the BOEM.
    (b) Before decommissioning the facilities under your SAP, COP, or 
GAP, you must submit a decommissioning application and receive approval 
from the BOEM.
    (c) The approval of the decommissioning concept in the SAP, COP, or 
GAP is not an approval of a decommissioning application. However, you 
may submit your complete decommissioning application simultaneously with 
the SAP, COP, or GAP so that it may undergo appropriate technical and 
regulatory reviews at that time.
    (d) Following approval of your decommissioning application, you must 
submit a decommissioning notice under Sec.  585.908 to BOEM at least 60 
days before commencing decommissioning activities.
    (e) If you, your subcontractors, or any agent acting on your behalf 
discover any archaeological resource while conducting decommissioning 
activities, you must immediately halt bottom-disturbing activities 
within 1,000 feet of the discovery and report the discovery to us within 
72 hours. We will inform you how to conduct investigations to determine 
if the resource is significant and how to protect it. You, your 
subcontractors, or any agent acting on your behalf must keep the 
location of the discovery confidential and must not take any action that 
may adversely affect the archaeological resource until we have made an 
evaluation and told you how to proceed.
    (f) Provide BOEM with documentation of any coordination efforts you 
have made with the affected States, local, and Tribal governments.

[[Page 646]]



Sec.  585.903  What are the requirements for decommissioning
 FERC-licensed hydrokinetic facilities?

    You must comply with the decommissioning requirements in your BOEM-
issued lease. If you fail to comply with the decommissioning 
requirements of your lease then:
    (a) BOEM may call for the forfeiture of your bond or other financial 
assurance;
    (b) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure; and
    (c) BOEM may take enforcement action under Sec.  585.400 of this 
part.



Sec.  585.904  Can I request a departure from the decommissioning 
requirements?

    You may request a departure from the decommissioning requirements 
under Sec.  585.103.

                      Decommissioning Applications



Sec.  585.905  When must I submit my decommissioning application?

    You must submit your decommissioning application upon the earliest 
of the following dates:
    (a) 2 years before the expiration of your lease.
    (b) 90 days after completion of your commercial activities on a 
commercial lease.
    (c) 90 days after completion of your approved activities under a 
limited lease on a ROW grant or RUE grant.
    (d) 90 days after cancellation, relinquishment, or other termination 
of your lease or grant.



Sec.  585.906  What must my decommissioning application include?

    You must provide one paper copy and one electronic copy of the 
application. Include the following information in the application, as 
applicable.
    (a) Identification of the applicant including:
    (1) Lease operator, ROW grant holder, or RUE grant holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.
    (b) Identification and description of the facilities, cables, or 
pipelines you plan to remove or propose to leave in place, as provided 
in Sec.  585.909.
    (c) A proposed decommissioning schedule for your lease, ROW grant, 
or RUE grant, including the expiration or relinquishment date and 
proposed month and year of removal.
    (d) A description of the removal methods and procedures, including 
the types of equipment, vessels, and moorings (i.e., anchors, chains, 
lines, etc.) you will use.
    (e) A description of your site clearance activities.
    (f) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed facilities, cables, or 
pipelines and any required approvals.
    (g) A description of those resources, conditions, and activities 
that could be affected by or could affect your proposed decommissioning 
activities. The description must be as detailed as necessary to assist 
BOEM in complying with the NEPA and other relevant Federal laws.
    (h) The results of any recent biological surveys conducted in the 
vicinity of the structure and recent observations of turtles or marine 
mammals at the structure site.
    (i) Mitigation measures you will use to protect archaeological and 
sensitive biological features during removal activities.
    (j) A description of measures you will take to prevent unauthorized 
discharge of pollutants, including marine trash and debris, into the 
offshore waters.
    (k) A statement of whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.



Sec.  585.907  How will BOEM process my decommissioning application?

    (a) Based upon your inclusion of all the information required by 
Sec.  585.906, BOEM will compare your decommissioning application with 
the decommissioning general concept in your approved SAP, COP, or GAP to 
determine what technical and environmental reviews are needed.
    (b) You will likely have to revise your SAP, COP, or GAP, and BOEM

[[Page 647]]

will begin the appropriate NEPA analysis and other regulatory reviews as 
required, if BOEM determines that your decommissioning application 
would:
    (1) Result in a significant change in the impacts previously 
identified and evaluated in your SAP, COP, or GAP;
    (2) Require any additional Federal permits; or
    (3) Propose activities not previously identified and evaluated in 
your SAP, COP, or GAP.
    (c) During the review process, we may request additional information 
if we determine that the information provided is not sufficient to 
complete the review and approval process.
    (d) Upon completion of the technical and environmental reviews, we 
may approve, approve with conditions, or disapprove your decommissioning 
application.
    (e) If BOEM disapproves your decommissioning application, you must 
resubmit your application to address the concerns identified by BOEM.



Sec.  585.908  What must I include in my decommissioning notice?

    (a) The decommissioning notice is distinct from your decommissioning 
application and may only be submitted following approval of your 
decommissioning application, as described in Sec. Sec.  585.905 through 
585.907. You must submit a decommissioning notice at least 60 days 
before you plan to begin decommissioning activities.
    (b) Your decommissioning notice must include:
    (1) A description of any changes to the approved removal methods and 
procedures in your approved decommissioning application, including 
changes to the types of vessels and equipment you will use; and
    (2) An updated decommissioning schedule.
    (c) We will review your decommissioning notice and may require you 
to resubmit a decommissioning application if BOEM determines that your 
decommissioning activities would:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal permits; or
    (3) Propose activities not previously identified and evaluated.

                            Facility Removal



Sec.  585.909  When may BOEM authorize facilities to remain in place
 following termination of a lease or grant?

    (a) In your decommissioning application, you may request that 
certain facilities authorized in your lease or grant remain in place for 
other activities authorized in this part, elsewhere in this subchapter, 
or by other applicable Federal laws.
    (b) BOEM may approve such requests on a case-by-case basis 
considering the following:
    (1) Potential impacts to the marine environment;
    (2) Competing uses of the OCS;
    (3) Impacts on marine safety and National defense;
    (4) Maintenance of adequate financial assurance; and
    (5) Other factors determined by the Director.
    (c) Except as provided in paragraph (d) of this section, if BOEM 
authorizes facilities to remain in place, the former lessee or grantee 
under this part remains jointly and severally liable for decommissioning 
the facility unless satisfactory evidence is provided to BOEM showing 
that another party has assumed that responsibility and has secured 
adequate financial assurances.
    (d) In your decommissioning application, you may request that 
certain facilities authorized in your lease or grant be converted to an 
artificial reef or otherwise toppled in place. BOEM will evaluate all 
such requests.



Sec.  585.910  What must I do when I remove my facility?

    (a) You must remove all facilities to a depth of 15 feet below the 
mudline, unless otherwise authorized by BOEM.
    (b) Within 60 days after you remove a facility, you must verify to 
BOEM that you have cleared the site.

[[Page 648]]



Sec.  585.911  [Reserved]

                         Decommissioning Report



Sec.  585.912  After I remove a facility, cable, or pipeline, what
 information must I submit?

    Within 60 days after you remove a facility, cable, or pipeline, you 
must submit a written report to BOEM that includes the following:
    (a) A summary of the removal activities, including the date they 
were completed;
    (b) A description of any mitigation measures you took; and
    (c) If you used explosives, a statement signed by your authorized 
representative that certifies that the types and amount of explosives 
you used in removing the facility were consistent with those in the 
approved decommissioning application.

         Compliance With an Approved Decommissioning Application



Sec.  585.913  What happens if I fail to comply with my approved
 decommissioning application?

    If you fail to comply with your approved decommissioning plan or 
application:
    (a) BOEM may call for the forfeiture of your bond or other financial 
assurance;
    (b) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure; and
    (c) BOEM may take enforcement action under Sec.  585.400.



  Subpart J_Rights of Use and Easement for Energy- and Marine-Related 
                Activities Using Existing OCS Facilities

                          Regulated Activities



Sec.  585.1000  What activities does this subpart regulate?

    (a) This subpart provides the general provisions for authorizing and 
regulating activities that use (or propose to use) an existing OCS 
facility for energy- or marine-related purposes, that are not otherwise 
authorized under any other part of this subchapter or any other 
applicable Federal statute. Activities authorized under any other part 
of this subchapter or under any other Federal law that use (or propose 
to use) an existing OCS facility are not subject to this subpart.
    (b) BOEM will issue an Alternate Use RUE for activities authorized 
under this subpart.
    (c) At the discretion of the Director, an Alternate Use RUE may:
    (1) Permit alternate use activities to occur at an existing facility 
that is currently in use under an approved OCS lease; or
    (2) Limit alternate use activities at the existing facility until 
after previously authorized activities at the facility have ceased and 
the OCS lease terminates.



Sec. Sec.  585.1001-585.1003  [Reserved]

                     Requesting an Alternate Use RUE



Sec.  585.1004  What must I do before I request an Alternate Use RUE?

    If you are not the owner of the existing facility on the OCS and the 
lessee of the area in which the facility is located, you must contact 
the lessee and owner of the facility and reach a preliminary agreement 
as to the proposed activity for the use of the existing facility.



Sec.  585.1005  How do I request an Alternate Use RUE?

    To request an Alternate Use RUE, you must submit to BOEM all of the 
following:
    (a) The name, address, e-mail address, and phone number of an 
authorized representative.
    (b) A summary of the proposed activities for the use of an existing 
OCS facility, including:
    (1) The type of activities that would involve the use of the 
existing OCS facility;
    (2) A description of the existing OCS facility, including a map 
providing its location on the lease block;
    (3) The names of the owner of the existing OCS facility, the 
operator, the lessee, and any owner of operating rights on the lease at 
which the facility is located;

[[Page 649]]

    (4) A description of additional structures or equipment that will be 
required to be located on or in the vicinity of the existing OCS 
facility in connection with the proposed activities;
    (5) A statement indicating whether any of the proposed activities 
are intended to occur before existing activities on the OCS facility 
have ceased; and
    (6) A statement describing how existing activities at the OCS 
facility will be affected if proposed activities are to occur at the 
same time as existing activities at the OCS facility.
    (c) A statement affirming that the proposed activities sought to be 
approved under this subpart are not otherwise authorized by other 
provisions in this subchapter or any other Federal law.
    (d) Evidence that you meet the requirements of Sec.  585.106, as 
required by Sec.  585.107.
    (e) The signatures of the applicant, the owner of the existing OCS 
facility, and the lessee of the area in which the existing facility is 
located.



Sec.  585.1006  How will BOEM decide whether to issue an Alternate
 Use RUE?

    (a) We will consider requests for an Alternate Use RUE on a case-by-
case basis. In considering such requests, we will consult with relevant 
Federal agencies and evaluate whether the proposed activities involving 
the use of an existing OCS facility can be conducted in a manner that:
    (1) Ensures safety and minimizes adverse effects to the coastal and 
marine environments, including their physical, atmospheric, and 
biological components, to the extent practicable;
    (2) Does not inhibit or restrain orderly development of OCS mineral 
or energy resources; and
    (3) Avoids serious harm or damage to, or waste of, any natural 
resource (including OCS mineral deposits and oil, gas, and sulphur 
resources in areas leased or not leased), any life (including fish and 
other aquatic life), or property (including sites, structures, or 
objects of historical or archaeological significance);
    (4) Is otherwise consistent with subsection 8(p) of the OCS Lands 
Act; and
    (5) BOEM can effectively regulate.
    (b) Based on the evaluation that we perform under paragraph (a) of 
this section, the BOEM may authorize or reject, or authorize with 
modifications or stipulations, the proposed activity.



Sec.  585.1007  What process will BOEM use for competitively offering
 an Alternate Use RUE?

    (a) An Alternate Use RUE must be issued on a competitive basis 
unless BOEM determines, after public notice of the proposed Alternate 
Use RUE, that there is no competitive interest.
    (b) We will issue a public notice in the Federal Register to 
determine if there is competitive interest in using the proposed 
facility for alternate use activities. BOEM will specify a time period 
for members of the public to express competitive interest.
    (c) If we receive indications of competitive interest within the 
published timeframe, we will proceed with a competitive offering. As 
part of such competitive offering, each competing applicant must submit 
a description of the types of activities proposed for the existing 
facility, as well as satisfactory evidence that the competing applicant 
qualifies to hold a lease or grant on the OCS, as required in Sec. Sec.  
585.106 and 585.107, by a date we specify. We may request additional 
information from competing applicants, as necessary, to adequately 
evaluate the competing proposals.
    (d) We will evaluate all competing proposals to determine whether:
    (1) The proposed activities are compatible with existing activities 
at the facility; and
    (2) We have the expertise and resources available to regulate the 
activities effectively.
    (e) We will evaluate all proposals under the requirements of NEPA, 
CZMA, and other applicable laws.
    (f) Following our evaluation, we will select one or more acceptable 
proposals for activities involving the alternate use of an existing OCS 
facility, notify the competing applicants, and submit each acceptable 
proposal to the lessee and owner of the existing OCS facility. If the 
lessee and owner of the facility agree to accept a proposal, we will 
proceed to issue an Alternate Use RUE. If

[[Page 650]]

the lessee and owner of the facility are unwilling to accept any of the 
proposals that we deem acceptable, we will not issue an Alternate Use 
RUE.



Sec. Sec.  585.1008-585.1009  [Reserved]

                    Alternate Use RUE Administration



Sec.  585.1010  How long may I conduct activities under an Alternate
 Use RUE?

    (a) We will establish on a case-by-case basis, and set forth in the 
Alternate Use RUE, the length of time for which you are authorized to 
conduct activities approved in your Alternate Use RUE instrument.
    (b) In establishing this term, BOEM will consider the size and scale 
of the proposed alternate use activities, the type of alternate use 
activities, and any other relevant considerations.
    (c) BOEM may authorize renewal of Alternate Use RUEs at its 
discretion.



Sec.  585.1011  What payments are required for an Alternate Use RUE?

    We will establish rental or other payments for an Alternate Use RUE 
on a case-by-case basis, as set forth in the Alternate Use RUE grant, 
depending on our assessment of the following factors:
    (a) The effect on the original OCS Lands Act approved activity;
    (b) The size and scale of the proposed alternate use activities;
    (c) The income, if any, expected to be generated from the proposed 
alternate use activities; and
    (d) The type of alternate use activities.



Sec.  585.1012  What financial assurance is required for an Alternate
 Use RUE?

    (a) The holder of an Alternate Use RUE will be required to secure 
financial assurances in an amount determined by BOEM that is sufficient 
to cover all obligations under the Alternate Use RUE, including 
decommissioning obligations, and must retain such financial assurance 
amounts until all obligations have been fulfilled, as determined by 
BOEM.
    (b) We may revise financial assurance amounts, as necessary, to 
ensure that there is sufficient financial assurance to secure all 
obligations under the Alternate Use RUE.
    (c) We may reduce the amount of the financial assurance that you 
must retain if it is not necessary to cover existing obligations under 
the Alternate Use RUE.



Sec.  585.1013  Is an Alternate Use RUE assignable?

    (a) BOEM may authorize assignment of an Alternate Use RUE.
    (b) To request assignment of an Alternate Use RUE, you must submit a 
written request for assignment that includes the following information:
    (1) BOEM-assigned Alternate Use RUE number;
    (2) The names of both the assignor and the assignee, if applicable;
    (3) The names and telephone numbers of the contacts for both the 
assignor and the assignee;
    (4) The names, titles, and signatures of the authorizing officials 
for both the assignor and the assignee;
    (5) A statement affirming that the owner of the existing OCS 
facility and lessee of the lease in which the facility is located 
approve of the proposed assignment and assignee;
    (6) A statement that the assignee agrees to comply with and to be 
bound by the terms and conditions of the Alternate Use RUE;
    (7) Evidence required by Sec.  585.107 that the assignee satisfies 
the requirements of Sec.  585.106; and
    (8) A statement on how the assignee will comply with the financial 
assurance requirements set forth in the Alternate Use RUE.
    (c) The assignment takes effect on the date we approve your request.
    (d) The assignor is liable for all obligations that accrue under an 
Alternate Use RUE before the date we approve your assignment request. An 
assignment approval by BOEM does not relieve the assignor of liability 
for accrued obligations that the assignee, or a subsequent assignee, 
fails to perform.
    (e) The assignee and each subsequent assignee are liable for all 
obligations that accrue under an Alternate Use RUE after the date we 
approve the assignment request.

[[Page 651]]



Sec.  585.1014  When will BOEM suspend an Alternate Use RUE?

    (a) BOEM may suspend an Alternate Use RUE if:
    (1) Necessary to comply with judicial decrees;
    (2) Continued activities pursuant to the Alternate Use RUE pose an 
imminent threat of serious or irreparable harm or damage to natural 
resources; life (including human and wildlife); property; the marine, 
coastal, or human environment; or sites, structures, or objects of 
historical or archaeological significance;
    (3) The suspension is necessary for reasons of National security or 
defense; or
    (4) We have suspended or temporarily prohibited operation of the 
existing OCS facility that is subject to the Alternate Use RUE, and have 
determined that continued activities under the Alternate Use RUE are 
unsafe or cause undue interference with the operation of the original 
OCS Lands Act approved activity.
    (b) A suspension will extend the term of your Alternate Use RUE 
grant for the period of the suspension.



Sec.  585.1015  How do I relinquish an Alternate Use RUE?

    (a) You may voluntarily surrender an Alternate Use RUE by submitting 
a written request to us that includes the following:
    (1) The name, address, e-mail address, and phone number of an 
authorized representative;
    (2) The reason you are requesting relinquishment of the Alternate 
Use RUE;
    (3) BOEM-assigned Alternate Use RUE number;
    (4) The name of the associated OCS facility, its owner, and the 
lessee for the lease in which the OCS facility is located;
    (5) The name, title, and signature of your authorizing official 
(which must match exactly the name, title, and signature in the BOEM 
qualification records); and
    (6) A statement that you will adhere to the decommissioning 
requirements in the Alternate Use RUE.
    (b) We will not approve your relinquishment request until you have 
paid all outstanding rentals (or other payments) and fines.
    (c) The relinquishment takes effect on the date we approve your 
request.



Sec.  585.1016  When will an Alternate Use RUE be cancelled?

    The Secretary may cancel an Alternate Use RUE if it is determined, 
after notice and opportunity to be heard:
    (a) You no longer qualify to hold an Alternate Use RUE;
    (b) You failed to provide any additional financial assurance 
required by BOEM, replace or provide additional coverage for a de-valued 
bond, or replace a lapsed or forfeited bond within the prescribed time 
period;
    (c) Continued activity under the Alternate Use RUE is likely to 
cause serious harm or damage to natural resources; life (including human 
and wildlife); property; the marine, coastal, or human environment; or 
sites, structures, or objects of historical or archaeological 
significance;
    (d) Continued activity under the Alternate Use RUE is determined to 
be adversely impacting the original OCS Lands Act approved activities on 
the existing OCS facility;
    (e) You failed to comply with any of the terms and conditions of 
your approved Alternate Use RUE or your approved plan; or
    (f) You otherwise failed to comply with applicable laws or 
regulations.



Sec.  585.1017  [Reserved]

                  Decommissioning an Alternate Use RUE



Sec.  585.1018  Who is responsible for decommissioning an OCS facility
 subject to an Alternate Use RUE?

    (a) The holder of an Alternate Use RUE is responsible for all 
decommissioning obligations that accrue following the issuance of the 
Alternate Use RUE and which pertain to the Alternate Use RUE.
    (b) The lessee under the lease originally issued under 30 CFR part 
250 will remain responsible for decommissioning obligations that accrued 
before issuance of the Alternate Use RUE, as well as for decommissioning 
obligations that accrue following issuance of the Alternate Use RUE to 
the extent

[[Page 652]]

associated with continued activities authorized under other parts of 
this title.



Sec.  585.1019  What are the decommissioning requirements for an
 Alternate Use RUE?

    (a) Decommissioning requirements will be determined by BOEM on a 
case-by-case basis, and will be included in the terms of each Alternate 
Use RUE.
    (b) Decommissioning activities must be completed within 1 year of 
termination of the Alternate Use RUE.
    (c) If you fail to satisfy all decommissioning requirements within 
the prescribed time period, we will call for the forfeiture of your bond 
or other financial guarantee, and you will remain liable for all 
accidents or damages that might result from such failure.

[[Page 653]]



                          SUBCHAPTER C_APPEALS





PART 590_APPEAL PROCEDURES--Table of Contents



        Subpart A_Offshore Minerals Management Appeal Procedures

Sec.
590.1 What is the purpose of this subpart?
590.2 Who may appeal?
590.3 What is the time limit for filing an appeal?
590.4 How do I file an appeal?
590.5 Can I obtain an extension for filing my Notice of Appeal?
590.6 Are informal resolutions permitted?
590.7 Do I have to comply with the decision or order while my appeal is 
          pending?
590.8 How do I exhaust my administrative remedies?

Subpart B [Reserved]

    Authority: 5 U.S.C. 301 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1334.

    Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.



        Subpart A_Offshore Minerals Management Appeal Procedures



Sec.  590.1  What is the purpose of this subpart?

    The purpose of this subpart is to explain the procedures for appeals 
of Bureau of Ocean Energy Management (BOEM) Offshore Minerals Management 
(OMM) decisions and orders issued under subchapter C.



Sec.  590.2  Who may appeal?

    If you are adversely affected by an OMM official's final decision or 
order issued under 30 CFR chapter V, subchapter C, you may appeal that 
decision or order to the Interior Board of Land Appeals (IBLA). Your 
appeal must conform with the procedures found in this subpart and 43 CFR 
part 4, subpart E. A request for reconsideration of a BOEM decision 
concerning a lease bid, authorized in 30 CFR parts 556.47(e)(3), 
581.21(a)(1), or 585.118(c), is not subject to the procedures found in 
this part.



Sec.  590.3  What is the time limit for filing an appeal?

    You must file your appeal within 60 days after you receive OMM's 
final decision or order. The 60-day time period applies rather than the 
time period provided in 43 CFR 4.411(a). A decision or order is received 
on the date you sign a receipt confirming delivery or, if there is no 
receipt, the date otherwise documented.



Sec.  590.4  How do I file an appeal?

    For your appeal to be filed, BOEM must receive all of the following 
within 60 days after you receive the decision or order:
    (a) A written Notice of Appeal together with a copy of the decision 
or order you are appealing in the office of the OEMM officer that issued 
the decision or order. You cannot extend the 60-day period for that 
office to receive your Notice of Appeal; and
    (b) A nonrefundable processing fee of $150 paid with the Notice of 
Appeal.
    (1) You must pay electronically through the Fees for Services page 
on the BOEM Web site at http://www.boem.gov, and you must include a copy 
of the Pay.gov confirmation receipt page with your Notice of Appeal.
    (2) You cannot extend the 60-day period for payment of the 
processing fee.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21626, Apr. 17, 2014]



Sec.  590.5  Can I obtain an extension for filing my Notice of Appeal?

    You cannot obtain an extension of time to file the Notice of Appeal. 
See 43 CFR 4.411(c).



Sec.  590.6  Are informal resolutions permitted?

    (a) You may seek informal resolution with the issuing officer's next 
level supervisor during the 60-day period established in Sec.  590.3.
    (b) Nothing in this subpart precludes resolution by settlement of 
any appeal or matter pending in the administrative process after the 60-
day period established in Sec.  590.3.

[[Page 654]]



Sec.  590.7  Do I have to comply with the decision or order while
 my appeal is pending?

    (a) The decision or order is effective during the 60-day period for 
filing an appeal under Sec.  590.3 unless:
    (1) OMM notifies you that the decision or order, or some portion of 
it, is suspended during this period because there is no likelihood of 
immediate and irreparable harm to human life, the environment, any 
mineral deposit, or property; or
    (2) You post a surety bond under 30 CFR 550.1409 pending the appeal 
challenging an order to pay a civil penalty.
    (b) This section applies rather than 43 CFR 4.21(a) for appeals of 
OMM orders.
    (c) After you file your appeal, IBLA may grant a stay of a decision 
or order under 43 CFR 4.21(b); however, a decision or order remains in 
effect until IBLA grants your request for a stay of the decision or 
order under appeal.



Sec.  590.8  How do I exhaust my administrative remedies?

    (a) If you receive a decision or order issued under chapter V, 
subchapter C, you must appeal that decision or order to IBLA under 43 
CFR part 4, subpart E, to exhaust administrative remedies.
    (b) This section does not apply if the Assistant Secretary for Land 
and Minerals Management or the IBLA makes a decision or order 
immediately effective notwithstanding an appeal.

Subpart B [Reserved]

                        PARTS 591	599 [RESERVED]

[[Page 655]]



                              FINDING AIDS




  --------------------------------------------------------------------

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 657]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2019)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
       III  Administrative Conference of the United States (Parts 
                300--399)
        IV  Miscellaneous Agencies (Parts 400--599)
        VI  National Capital Planning Commission (Parts 600--699)

                    Title 2--Grants and Agreements

            Subtitle A--Office of Management and Budget Guidance 
                for Grants and Agreements
         I  Office of Management and Budget Governmentwide 
                Guidance for Grants and Agreements (Parts 2--199)
        II  Office of Management and Budget Guidance (Parts 200--
                299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements
       III  Department of Health and Human Services (Parts 300--
                399)
        IV  Department of Agriculture (Parts 400--499)
        VI  Department of State (Parts 600--699)
       VII  Agency for International Development (Parts 700--799)
      VIII  Department of Veterans Affairs (Parts 800--899)
        IX  Department of Energy (Parts 900--999)
         X  Department of the Treasury (Parts 1000--1099)
        XI  Department of Defense (Parts 1100--1199)
       XII  Department of Transportation (Parts 1200--1299)
      XIII  Department of Commerce (Parts 1300--1399)
       XIV  Department of the Interior (Parts 1400--1499)
        XV  Environmental Protection Agency (Parts 1500--1599)
     XVIII  National Aeronautics and Space Administration (Parts 
                1800--1899)
        XX  United States Nuclear Regulatory Commission (Parts 
                2000--2099)
      XXII  Corporation for National and Community Service (Parts 
                2200--2299)
     XXIII  Social Security Administration (Parts 2300--2399)
      XXIV  Department of Housing and Urban Development (Parts 
                2400--2499)
       XXV  National Science Foundation (Parts 2500--2599)
      XXVI  National Archives and Records Administration (Parts 
                2600--2699)

[[Page 658]]

     XXVII  Small Business Administration (Parts 2700--2799)
    XXVIII  Department of Justice (Parts 2800--2899)
      XXIX  Department of Labor (Parts 2900--2999)
       XXX  Department of Homeland Security (Parts 3000--3099)
      XXXI  Institute of Museum and Library Services (Parts 3100--
                3199)
     XXXII  National Endowment for the Arts (Parts 3200--3299)
    XXXIII  National Endowment for the Humanities (Parts 3300--
                3399)
     XXXIV  Department of Education (Parts 3400--3499)
      XXXV  Export-Import Bank of the United States (Parts 3500--
                3599)
     XXXVI  Office of National Drug Control Policy, Executive 
                Office of the President (Parts 3600--3699)
    XXXVII  Peace Corps (Parts 3700--3799)
     LVIII  Election Assistance Commission (Parts 5800--5899)
       LIX  Gulf Coast Ecosystem Restoration Council (Parts 5900--
                5999)

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--199)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
        IV  Office of Personnel Management and Office of the 
                Director of National Intelligence (Parts 1400--
                1499)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Parts 2100--2199)
       XIV  Federal Labor Relations Authority, General Counsel of 
                the Federal Labor Relations Authority and Federal 
                Service Impasses Panel (Parts 2400--2499)
       XVI  Office of Government Ethics (Parts 2600--2699)
       XXI  Department of the Treasury (Parts 3100--3199)
      XXII  Federal Deposit Insurance Corporation (Parts 3200--
                3299)
     XXIII  Department of Energy (Parts 3300--3399)
      XXIV  Federal Energy Regulatory Commission (Parts 3400--
                3499)
       XXV  Department of the Interior (Parts 3500--3599)
      XXVI  Department of Defense (Parts 3600--3699)

[[Page 659]]

    XXVIII  Department of Justice (Parts 3800--3899)
      XXIX  Federal Communications Commission (Parts 3900--3999)
       XXX  Farm Credit System Insurance Corporation (Parts 4000--
                4099)
      XXXI  Farm Credit Administration (Parts 4100--4199)
    XXXIII  Overseas Private Investment Corporation (Parts 4300--
                4399)
     XXXIV  Securities and Exchange Commission (Parts 4400--4499)
      XXXV  Office of Personnel Management (Parts 4500--4599)
     XXXVI  Department of Homeland Security (Parts 4600--4699)
    XXXVII  Federal Election Commission (Parts 4700--4799)
        XL  Interstate Commerce Commission (Parts 5000--5099)
       XLI  Commodity Futures Trading Commission (Parts 5100--
                5199)
      XLII  Department of Labor (Parts 5200--5299)
     XLIII  National Science Foundation (Parts 5300--5399)
       XLV  Department of Health and Human Services (Parts 5500--
                5599)
      XLVI  Postal Rate Commission (Parts 5600--5699)
     XLVII  Federal Trade Commission (Parts 5700--5799)
    XLVIII  Nuclear Regulatory Commission (Parts 5800--5899)
      XLIX  Federal Labor Relations Authority (Parts 5900--5999)
         L  Department of Transportation (Parts 6000--6099)
       LII  Export-Import Bank of the United States (Parts 6200--
                6299)
      LIII  Department of Education (Parts 6300--6399)
       LIV  Environmental Protection Agency (Parts 6400--6499)
        LV  National Endowment for the Arts (Parts 6500--6599)
       LVI  National Endowment for the Humanities (Parts 6600--
                6699)
      LVII  General Services Administration (Parts 6700--6799)
     LVIII  Board of Governors of the Federal Reserve System 
                (Parts 6800--6899)
       LIX  National Aeronautics and Space Administration (Parts 
                6900--6999)
        LX  United States Postal Service (Parts 7000--7099)
       LXI  National Labor Relations Board (Parts 7100--7199)
      LXII  Equal Employment Opportunity Commission (Parts 7200--
                7299)
     LXIII  Inter-American Foundation (Parts 7300--7399)
      LXIV  Merit Systems Protection Board (Parts 7400--7499)
       LXV  Department of Housing and Urban Development (Parts 
                7500--7599)
      LXVI  National Archives and Records Administration (Parts 
                7600--7699)
     LXVII  Institute of Museum and Library Services (Parts 7700--
                7799)
    LXVIII  Commission on Civil Rights (Parts 7800--7899)
      LXIX  Tennessee Valley Authority (Parts 7900--7999)
       LXX  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 8000--8099)
      LXXI  Consumer Product Safety Commission (Parts 8100--8199)
    LXXIII  Department of Agriculture (Parts 8300--8399)

[[Page 660]]

     LXXIV  Federal Mine Safety and Health Review Commission 
                (Parts 8400--8499)
     LXXVI  Federal Retirement Thrift Investment Board (Parts 
                8600--8699)
    LXXVII  Office of Management and Budget (Parts 8700--8799)
      LXXX  Federal Housing Finance Agency (Parts 9000--9099)
   LXXXIII  Special Inspector General for Afghanistan 
                Reconstruction (Parts 9300--9399)
    LXXXIV  Bureau of Consumer Financial Protection (Parts 9400--
                9499)
    LXXXVI  National Credit Union Administration (Parts 9600--
                9699)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Parts 
                9700--9799)
    XCVIII  Council of the Inspectors General on Integrity and 
                Efficiency (Parts 9800--9899)
      XCIX  Military Compensation and Retirement Modernization 
                Commission (Parts 9900--9999)
         C  National Council on Disability (Parts 10000--10049)
        CI  National Mediation Board (Part 10101)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 1--199)
         X  Privacy and Civil Liberties Oversight Board (Parts 
                1000--1099)

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Nutrition Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)
      VIII  Grain Inspection, Packers and Stockyards 
                Administration (Federal Grain Inspection Service), 
                Department of Agriculture (Parts 800--899)

[[Page 661]]

        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)
        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)
       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  Rural Telephone Bank, Department of Agriculture (Parts 
                1600--1699)
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)
     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
        XX  Local Television Loan Guarantee Board (Parts 2200--
                2299)
       XXV  Office of Advocacy and Outreach, Department of 
                Agriculture (Parts 2500--2599)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy Policy and New Uses, Department of 
                Agriculture (Parts 2900--2999)
       XXX  Office of the Chief Financial Officer, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  Office of Procurement and Property Management, 
                Department of Agriculture (Parts 3200--3299)
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  National Institute of Food and Agriculture (Parts 
                3400--3499)
      XXXV  Rural Housing Service, Department of Agriculture 
                (Parts 3500--3599)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
       XLI  [Reserved]
      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)

[[Page 662]]

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Parts 1--499)
         V  Executive Office for Immigration Review, Department of 
                Justice (Parts 1000--1399)

                 Title 9--Animals and Animal Products

         I  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 1--199)
        II  Grain Inspection, Packers and Stockyards 
                Administration (Packers and Stockyards Programs), 
                Department of Agriculture (Parts 200--299)
       III  Food Safety and Inspection Service, Department of 
                Agriculture (Parts 300--599)

                           Title 10--Energy

         I  Nuclear Regulatory Commission (Parts 0--199)
        II  Department of Energy (Parts 200--699)
       III  Department of Energy (Parts 700--999)
         X  Department of Energy (General Provisions) (Parts 
                1000--1099)
      XIII  Nuclear Waste Technical Review Board (Parts 1300--
                1399)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)
     XVIII  Northeast Interstate Low-Level Radioactive Waste 
                Commission (Parts 1800--1899)

                      Title 11--Federal Elections

         I  Federal Election Commission (Parts 1--9099)
        II  Election Assistance Commission (Parts 9400--9499)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)
       III  Federal Deposit Insurance Corporation (Parts 300--399)
        IV  Export-Import Bank of the United States (Parts 400--
                499)
         V  (Parts 500--599) [Reserved]
        VI  Farm Credit Administration (Parts 600--699)
       VII  National Credit Union Administration (Parts 700--799)
      VIII  Federal Financing Bank (Parts 800--899)
        IX  Federal Housing Finance Board (Parts 900--999)
         X  Bureau of Consumer Financial Protection (Parts 1000--
                1099)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XII  Federal Housing Finance Agency (Parts 1200--1299)
      XIII  Financial Stability Oversight Council (Parts 1300--
                1399)

[[Page 663]]

       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
       XVI  Office of Financial Research (Parts 1600--1699)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700--1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

         I  Small Business Administration (Parts 1--199)
       III  Economic Development Administration, Department of 
                Commerce (Parts 300--399)
        IV  Emergency Steel Guarantee Loan Board (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board (Parts 
                500--599)

                    Title 14--Aeronautics and Space

         I  Federal Aviation Administration, Department of 
                Transportation (Parts 1--199)
        II  Office of the Secretary, Department of Transportation 
                (Aviation Proceedings) (Parts 200--399)
       III  Commercial Space Transportation, Federal Aviation 
                Administration, Department of Transportation 
                (Parts 400--1199)
         V  National Aeronautics and Space Administration (Parts 
                1200--1299)
        VI  Air Transportation System Stabilization (Parts 1300--
                1399)

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Industry and Security, Department of 
                Commerce (Parts 700--799)
      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)
        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  National Technical Information Service, Department of 
                Commerce (Parts 1100--1199)

[[Page 664]]

      XIII  East-West Foreign Trade Board (Parts 1300--1399)
       XIV  Minority Business Development Agency (Parts 1400--
                1499)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399) [Reserved]

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

             Title 17--Commodity and Securities Exchanges

         I  Commodity Futures Trading Commission (Parts 1--199)
        II  Securities and Exchange Commission (Parts 200--399)
        IV  Department of the Treasury (Parts 400--499)

          Title 18--Conservation of Power and Water Resources

         I  Federal Energy Regulatory Commission, Department of 
                Energy (Parts 1--399)
       III  Delaware River Basin Commission (Parts 400--499)
        VI  Water Resources Council (Parts 700--799)
      VIII  Susquehanna River Basin Commission (Parts 800--899)
      XIII  Tennessee Valley Authority (Parts 1300--1399)

                       Title 19--Customs Duties

         I  U.S. Customs and Border Protection, Department of 
                Homeland Security; Department of the Treasury 
                (Parts 0--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  U.S. Immigration and Customs Enforcement, Department 
                of Homeland Security (Parts 400--599) [Reserved]

                     Title 20--Employees' Benefits

         I  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 1--199)
        II  Railroad Retirement Board (Parts 200--399)
       III  Social Security Administration (Parts 400--499)

[[Page 665]]

        IV  Employees' Compensation Appeals Board, Department of 
                Labor (Parts 500--599)
         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 700--799)
       VII  Benefits Review Board, Department of Labor (Parts 
                800--899)
      VIII  Joint Board for the Enrollment of Actuaries (Parts 
                900--999)
        IX  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 1000--1099)

                       Title 21--Food and Drugs

         I  Food and Drug Administration, Department of Health and 
                Human Services (Parts 1--1299)
        II  Drug Enforcement Administration, Department of Justice 
                (Parts 1300--1399)
       III  Office of National Drug Control Policy (Parts 1400--
                1499)

                      Title 22--Foreign Relations

         I  Department of State (Parts 1--199)
        II  Agency for International Development (Parts 200--299)
       III  Peace Corps (Parts 300--399)
        IV  International Joint Commission, United States and 
                Canada (Parts 400--499)
         V  Broadcasting Board of Governors (Parts 500--599)
       VII  Overseas Private Investment Corporation (Parts 700--
                799)
        IX  Foreign Service Grievance Board (Parts 900--999)
         X  Inter-American Foundation (Parts 1000--1099)
        XI  International Boundary and Water Commission, United 
                States and Mexico, United States Section (Parts 
                1100--1199)
       XII  United States International Development Cooperation 
                Agency (Parts 1200--1299)
      XIII  Millennium Challenge Corporation (Parts 1300--1399)
       XIV  Foreign Service Labor Relations Board; Federal Labor 
                Relations Authority; General Counsel of the 
                Federal Labor Relations Authority; and the Foreign 
                Service Impasse Disputes Panel (Parts 1400--1499)
        XV  African Development Foundation (Parts 1500--1599)
       XVI  Japan-United States Friendship Commission (Parts 
                1600--1699)
      XVII  United States Institute of Peace (Parts 1700--1799)

                          Title 23--Highways

         I  Federal Highway Administration, Department of 
                Transportation (Parts 1--999)

[[Page 666]]

        II  National Highway Traffic Safety Administration and 
                Federal Highway Administration, Department of 
                Transportation (Parts 1200--1299)
       III  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 1300--1399)

                Title 24--Housing and Urban Development

            Subtitle A--Office of the Secretary, Department of 
                Housing and Urban Development (Parts 0--99)
            Subtitle B--Regulations Relating to Housing and Urban 
                Development
         I  Office of Assistant Secretary for Equal Opportunity, 
                Department of Housing and Urban Development (Parts 
                100--199)
        II  Office of Assistant Secretary for Housing-Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 200--299)
       III  Government National Mortgage Association, Department 
                of Housing and Urban Development (Parts 300--399)
        IV  Office of Housing and Office of Multifamily Housing 
                Assistance Restructuring, Department of Housing 
                and Urban Development (Parts 400--499)
         V  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 500--599)
        VI  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 600--699) [Reserved]
       VII  Office of the Secretary, Department of Housing and 
                Urban Development (Housing Assistance Programs and 
                Public and Indian Housing Programs) (Parts 700--
                799)
      VIII  Office of the Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Section 8 Housing Assistance 
                Programs, Section 202 Direct Loan Program, Section 
                202 Supportive Housing for the Elderly Program and 
                Section 811 Supportive Housing for Persons With 
                Disabilities Program) (Parts 800--899)
        IX  Office of Assistant Secretary for Public and Indian 
                Housing, Department of Housing and Urban 
                Development (Parts 900--1699)
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XV  Emergency Mortgage Insurance and Loan Programs, 
                Department of Housing and Urban Development (Parts 
                2700--2799) [Reserved]
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
      XXIV  Board of Directors of the HOPE for Homeowners Program 
                (Parts 4000--4099) [Reserved]
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

[[Page 667]]

                           Title 25--Indians

         I  Bureau of Indian Affairs, Department of the Interior 
                (Parts 1--299)
        II  Indian Arts and Crafts Board, Department of the 
                Interior (Parts 300--399)
       III  National Indian Gaming Commission, Department of the 
                Interior (Parts 500--599)
        IV  Office of Navajo and Hopi Indian Relocation (Parts 
                700--899)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900--999)
        VI  Office of the Assistant Secretary, Indian Affairs, 
                Department of the Interior (Parts 1000--1199)
       VII  Office of the Special Trustee for American Indians, 
                Department of the Interior (Parts 1200--1299)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--End)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Alcohol and Tobacco Tax and Trade Bureau, Department 
                of the Treasury (Parts 1--399)
        II  Bureau of Alcohol, Tobacco, Firearms, and Explosives, 
                Department of Justice (Parts 400--699)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--299)
       III  Federal Prison Industries, Inc., Department of Justice 
                (Parts 300--399)
         V  Bureau of Prisons, Department of Justice (Parts 500--
                599)
        VI  Offices of Independent Counsel, Department of Justice 
                (Parts 600--699)
       VII  Office of Independent Counsel (Parts 700--799)
      VIII  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 800--899)
        IX  National Crime Prevention and Privacy Compact Council 
                (Parts 900--999)
        XI  Department of Justice and Department of State (Parts 
                1100--1199)

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)

[[Page 668]]

        II  Office of Labor-Management Standards, Department of 
                Labor (Parts 200--299)
       III  National Railroad Adjustment Board (Parts 300--399)
        IV  Office of Labor-Management Standards, Department of 
                Labor (Parts 400--499)
         V  Wage and Hour Division, Department of Labor (Parts 
                500--899)
        IX  Construction Industry Collective Bargaining Commission 
                (Parts 900--999)
         X  National Mediation Board (Parts 1200--1299)
       XII  Federal Mediation and Conciliation Service (Parts 
                1400--1499)
       XIV  Equal Employment Opportunity Commission (Parts 1600--
                1699)
      XVII  Occupational Safety and Health Administration, 
                Department of Labor (Parts 1900--1999)
        XX  Occupational Safety and Health Review Commission 
                (Parts 2200--2499)
       XXV  Employee Benefits Security Administration, Department 
                of Labor (Parts 2500--2599)
     XXVII  Federal Mine Safety and Health Review Commission 
                (Parts 2700--2799)
        XL  Pension Benefit Guaranty Corporation (Parts 4000--
                4999)

                      Title 30--Mineral Resources

         I  Mine Safety and Health Administration, Department of 
                Labor (Parts 1--199)
        II  Bureau of Safety and Environmental Enforcement, 
                Department of the Interior (Parts 200--299)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
         V  Bureau of Ocean Energy Management, Department of the 
                Interior (Parts 500--599)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)
       XII  Office of Natural Resources Revenue, Department of the 
                Interior (Parts 1200--1299)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)
            Subtitle B--Regulations Relating to Money and Finance
         I  Monetary Offices, Department of the Treasury (Parts 
                51--199)
        II  Fiscal Service, Department of the Treasury (Parts 
                200--399)
        IV  Secret Service, Department of the Treasury (Parts 
                400--499)
         V  Office of Foreign Assets Control, Department of the 
                Treasury (Parts 500--599)
        VI  Bureau of Engraving and Printing, Department of the 
                Treasury (Parts 600--699)
       VII  Federal Law Enforcement Training Center, Department of 
                the Treasury (Parts 700--799)

[[Page 669]]

      VIII  Office of Investment Security, Department of the 
                Treasury (Parts 800--899)
        IX  Federal Claims Collection Standards (Department of the 
                Treasury--Department of Justice) (Parts 900--999)
         X  Financial Crimes Enforcement Network, Department of 
                the Treasury (Parts 1000--1099)

                      Title 32--National Defense

            Subtitle A--Department of Defense
         I  Office of the Secretary of Defense (Parts 1--399)
         V  Department of the Army (Parts 400--699)
        VI  Department of the Navy (Parts 700--799)
       VII  Department of the Air Force (Parts 800--1099)
            Subtitle B--Other Regulations Relating to National 
                Defense
       XII  Defense Logistics Agency (Parts 1200--1299)
       XVI  Selective Service System (Parts 1600--1699)
      XVII  Office of the Director of National Intelligence (Parts 
                1700--1799)
     XVIII  National Counterintelligence Center (Parts 1800--1899)
       XIX  Central Intelligence Agency (Parts 1900--1999)
        XX  Information Security Oversight Office, National 
                Archives and Records Administration (Parts 2000--
                2099)
       XXI  National Security Council (Parts 2100--2199)
      XXIV  Office of Science and Technology Policy (Parts 2400--
                2499)
     XXVII  Office for Micronesian Status Negotiations (Parts 
                2700--2799)
    XXVIII  Office of the Vice President of the United States 
                (Parts 2800--2899)

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Corps of Engineers, Department of the Army, Department 
                of Defense (Parts 200--399)
        IV  Saint Lawrence Seaway Development Corporation, 
                Department of Transportation (Parts 400--499)

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)

[[Page 670]]

        IV  Office of Career, Technical and Adult Education, 
                Department of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599) 
                [Reserved]
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
       VII  Office of Educational Research and Improvement, 
                Department of Education (Parts 700--799) 
                [Reserved]
            Subtitle C--Regulations Relating to Education
        XI  (Parts 1100--1199) [Reserved]
       XII  National Council on Disability (Parts 1200--1299)

                          Title 35 [Reserved]

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
        VI  [Reserved]
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
         X  Presidio Trust (Parts 1000--1099)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
        XV  Oklahoma City National Memorial Trust (Parts 1500--
                1599)
       XVI  Morris K. Udall Scholarship and Excellence in National 
                Environmental Policy Foundation (Parts 1600--1699)

             Title 37--Patents, Trademarks, and Copyrights

         I  United States Patent and Trademark Office, Department 
                of Commerce (Parts 1--199)
        II  U.S. Copyright Office, Library of Congress (Parts 
                200--299)
       III  Copyright Royalty Board, Library of Congress (Parts 
                300--399)
        IV  National Institute of Standards and Technology, 
                Department of Commerce (Parts 400--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--199)
        II  Armed Forces Retirement Home (Parts 200--299)

[[Page 671]]

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Regulatory Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--1099)
        IV  Environmental Protection Agency and Department of 
                Justice (Parts 1400--1499)
         V  Council on Environmental Quality (Parts 1500--1599)
        VI  Chemical Safety and Hazard Investigation Board (Parts 
                1600--1699)
       VII  Environmental Protection Agency and Department of 
                Defense; Uniform National Discharge Standards for 
                Vessels of the Armed Forces (Parts 1700--1799)
      VIII  Gulf Coast Ecosystem Restoration Council (Parts 1800--
                1899)

          Title 41--Public Contracts and Property Management

            Subtitle A--Federal Procurement Regulations System 
                [Note]
            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 61-1--61-999)
   62--100  [Reserved]
            Subtitle C--Federal Property Management Regulations 
                System
       101  Federal Property Management Regulations (Parts 101-1--
                101-99)
       102  Federal Management Regulation (Parts 102-1--102-299)
  103--104  [Reserved]
       105  General Services Administration (Parts 105-1--105-999)
       109  Department of Energy Property Management Regulations 
                (Parts 109-1--109-99)
       114  Department of the Interior (Parts 114-1--114-99)
       115  Environmental Protection Agency (Parts 115-1--115-99)
       128  Department of Justice (Parts 128-1--128-99)
  129--200  [Reserved]
            Subtitle D--Other Provisions Relating to Property 
                Management [Reserved]
            Subtitle E--Federal Information Resources Management 
                Regulations System [Reserved]
            Subtitle F--Federal Travel Regulation System
       300  General (Parts 300-1--300-99)
       301  Temporary Duty (TDY) Travel Allowances (Parts 301-1--
                301-99)

[[Page 672]]

       302  Relocation Allowances (Parts 302-1--302-99)
       303  Payment of Expenses Connected with the Death of 
                Certain Employees (Part 303-1--303-99)
       304  Payment of Travel Expenses from a Non-Federal Source 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
   II--III  [Reserved]
        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--699)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1099)

                   Title 43--Public Lands: Interior

            Subtitle A--Office of the Secretary of the Interior 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Lands
         I  Bureau of Reclamation, Department of the Interior 
                (Parts 400--999)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10099)

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency, Department of 
                Homeland Security (Parts 0--399)
        IV  Department of Commerce and Department of 
                Transportation (Parts 400--499)

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 400--499)

[[Page 673]]

         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
        IX  Denali Commission (Parts 900--999)
         X  Office of Community Services, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 1000--1099)
        XI  National Foundation on the Arts and the Humanities 
                (Parts 1100--1199)
       XII  Corporation for National and Community Service (Parts 
                1200--1299)
      XIII  Administration for Children and Families, Department 
                of Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission of Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Parts 2300--2399)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
       III  Coast Guard (Great Lakes Pilotage), Department of 
                Homeland Security (Parts 400--499)
        IV  Federal Maritime Commission (Parts 500--599)

                      Title 47--Telecommunication

         I  Federal Communications Commission (Parts 0--199)
        II  Office of Science and Technology Policy and National 
                Security Council (Parts 200--299)
       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)
        IV  National Telecommunications and Information 
                Administration, Department of Commerce, and 
                National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 400--499)
         V  The First Responder Network Authority (Parts 500--599)

[[Page 674]]

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)
         3  Department of Health and Human Services (Parts 300--
                399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  Agency for International Development (Parts 700--799)
         8  Department of Veterans Affairs (Parts 800--899)
         9  Department of Energy (Parts 900--999)
        10  Department of the Treasury (Parts 1000--1099)
        12  Department of Transportation (Parts 1200--1299)
        13  Department of Commerce (Parts 1300--1399)
        14  Department of the Interior (Parts 1400--1499)
        15  Environmental Protection Agency (Parts 1500--1599)
        16  Office of Personnel Management, Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  Broadcasting Board of Governors (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        23  Social Security Administration (Parts 2300--2399)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        30  Department of Homeland Security, Homeland Security 
                Acquisition Regulation (HSAR) (Parts 3000--3099)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        51  Department of the Army Acquisition Regulations (Parts 
                5100--5199)
        52  Department of the Navy Acquisition Regulations (Parts 
                5200--5299)
        53  Department of the Air Force Federal Acquisition 
                Regulation Supplement (Parts 5300--5399) 
                [Reserved]
        54  Defense Logistics Agency, Department of Defense (Parts 
                5400--5499)
        57  African Development Foundation (Parts 5700--5799)
        61  Civilian Board of Contract Appeals, General Services 
                Administration (Parts 6100--6199)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

[[Page 675]]

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Pipeline and Hazardous Materials Safety 
                Administration, Department of Transportation 
                (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Motor Carrier Safety Administration, 
                Department of Transportation (Parts 300--399)
        IV  Coast Guard, Department of Homeland Security (Parts 
                400--499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation (Parts 1400--1499) 
                [Reserved]
       XII  Transportation Security Administration, Department of 
                Homeland Security (Parts 1500--1699)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)
        II  National Marine Fisheries Service, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 200--299)
       III  International Fishing and Related Activities (Parts 
                300--399)
        IV  Joint Regulations (United States Fish and Wildlife 
                Service, Department of the Interior and National 
                Marine Fisheries Service, National Oceanic and 
                Atmospheric Administration, Department of 
                Commerce); Endangered Species Committee 
                Regulations (Parts 400--499)
         V  Marine Mammal Commission (Parts 500--599)
        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

[[Page 677]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2019)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Conference of the United States    1, III
Advisory Council on Historic Preservation         36, VIII
Advocacy and Outreach, Office of                  7, XXV
Afghanistan Reconstruction, Special Inspector     5, LXXXIII
     General for
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              2, VII; 22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture, Department of                        2, IV; 5, LXXIII
  Advocacy and Outreach, Office of                7, XXV
  Agricultural Marketing Service                  7, I, IX, X, XI
  Agricultural Research Service                   7, V
  Animal and Plant Health Inspection Service      7, III; 9, I
  Chief Financial Officer, Office of              7, XXX
  Commodity Credit Corporation                    7, XIV
  Economic Research Service                       7, XXXVII
  Energy Policy and New Uses, Office of           2, IX; 7, XXIX
  Environmental Quality, Office of                7, XXXI
  Farm Service Agency                             7, VII, XVIII
  Federal Acquisition Regulation                  48, 4
  Federal Crop Insurance Corporation              7, IV
  Food and Nutrition Service                      7, II
  Food Safety and Inspection Service              9, III
  Foreign Agricultural Service                    7, XV
  Forest Service                                  36, II
  Grain Inspection, Packers and Stockyards        7, VIII; 9, II
       Administration
  Information Resources Management, Office of     7, XXVII
  Inspector General, Office of                    7, XXVI
  National Agricultural Library                   7, XLI
  National Agricultural Statistics Service        7, XXXVI
  National Institute of Food and Agriculture      7, XXXIV
  Natural Resources Conservation Service          7, VI
  Operations, Office of                           7, XXVIII
  Procurement and Property Management, Office of  7, XXXII
  Rural Business-Cooperative Service              7, XVIII, XLII
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII, XXXV
  Rural Telephone Bank                            7, XVI
  Rural Utilities Service                         7, XVII, XVIII, XLII
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force, Department of                          32, VII
  Federal Acquisition Regulation Supplement       48, 53
Air Transportation Stabilization Board            14, VI
Alcohol and Tobacco Tax and Trade Bureau          27, I
Alcohol, Tobacco, Firearms, and Explosives,       27, II
     Bureau of
AMTRAK                                            49, VII
American Battle Monuments Commission              36, IV
American Indians, Office of the Special Trustee   25, VII
Animal and Plant Health Inspection Service        7, III; 9, I

[[Page 678]]

Appalachian Regional Commission                   5, IX
Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI
Army, Department of                               32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase from People Who Are
Broadcasting Board of Governors                   22, V
  Federal Acquisition Regulation                  48, 19
Career, Technical, and Adult Education, Office    34, IV
     of
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chemical Safety and Hazard Investigation Board    40, VI
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X, XIII
Civil Rights, Commission on                       5, LXVIII; 45, VII
Civil Rights, Office for                          34, I
Council of the Inspectors General on Integrity    5, XCVIII
     and Efficiency
Court Services and Offender Supervision Agency    5, LXX
     for the District of Columbia
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce, Department of                           2, XIII; 44, IV; 50, VI
  Census Bureau                                   15, I
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Foreign-Trade Zones Board                       15, IV
  Industry and Security, Bureau of                15, VII
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II; 37, IV
  National Marine Fisheries Service               50, II, IV
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Technical Information Service          15, XI
  National Telecommunications and Information     15, XXIII; 47, III, IV
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office, United States      37, I
  Secretary of Commerce, Office of                15, Subtitle A
Commercial Space Transportation                   14, III
Commodity Credit Corporation                      7, XIV
Commodity Futures Trading Commission              5, XLI; 17, I
Community Planning and Development, Office of     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Financial Protection Bureau              5, LXXXIV; 12, X
Consumer Product Safety Commission                5, LXXI; 16, II
Copyright Royalty Board                           37, III
Corporation for National and Community Service    2, XXII; 45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Court Services and Offender Supervision Agency    5, LXX; 28, VIII
     for the District of Columbia
Customs and Border Protection                     19, I
Defense Contract Audit Agency                     32, I
Defense, Department of                            2, XI; 5, XXVI; 32, 
                                                  Subtitle A; 40, VII
  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII

[[Page 679]]

  Army Department                                 32, V; 33, II; 36, III; 
                                                  48, 51
  Defense Acquisition Regulations System          48, 2
  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  National Imagery and Mapping Agency             32, I
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 2, XI; 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
Denali Commission                                 45, IX
Disability, National Council on                   5, C; 34, XII
District of Columbia, Court Services and          5, LXX; 28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          2, XXXIV; 5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office of
  Career, Technical, and Adult Education, Office  34, IV
       of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  Elementary and Secondary Education, Office of   34, II
  Federal Acquisition Regulation                  48, 34
  Postsecondary Education, Office of              34, VI
  Secretary of Education, Office of               34, Subtitle A
  Special Education and Rehabilitative Services,  34, III
       Office of
Educational Research and Improvement, Office of   34, VII
Election Assistance Commission                    2, LVIII; 11, II
Elementary and Secondary Education, Office of     34, II
Emergency Oil and Gas Guaranteed Loan Board       13, V
Emergency Steel Guarantee Loan Board              13, IV
Employee Benefits Security Administration         29, XXV
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Policy, National Commission for        1, IV
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             2, IX; 5, XXIII; 10, II, 
                                                  III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            5, XXIV; 18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Environmental Protection Agency                   2, XV; 5, LIV; 40, I, IV, 
                                                  VII
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  24, I
     for
Executive Office of the President                 3, I
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                2, Subtitle A; 5, III, 
                                                  LXXVII; 14, VI; 48, 99
  National Drug Control Policy, Office of         2, XXXVI; 21, III
  National Security Council                       32, XXI; 47, 2

[[Page 680]]

  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II
  Trade Representative, Office of the United      15, XX
       States
Export-Import Bank of the United States           2, XXXV; 5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV
Farm Service Agency                               7, VII, XVIII
Federal Acquisition Regulation                    48, 1
Federal Aviation Administration                   14, I
  Commercial Space Transportation                 14, III
Federal Claims Collection Standards               31, IX
Federal Communications Commission                 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       5, XXXVII; 11, I
Federal Emergency Management Agency               44, I
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              5, XXIV; 18, I
Federal Financial Institutions Examination        12, XI
     Council
Federal Financing Bank                            12, VIII
Federal Highway Administration                    23, I, II
Federal Home Loan Mortgage Corporation            1, IV
Federal Housing Enterprise Oversight Office       12, XVII
Federal Housing Finance Agency                    5, LXXX; 12, XII
Federal Housing Finance Board                     12, IX
Federal Labor Relations Authority                 5, XIV, XLIX; 22, XIV
Federal Law Enforcement Training Center           31, VII
Federal Management Regulation                     41, 102
Federal Maritime Commission                       46, IV
Federal Mediation and Conciliation Service        29, XII
Federal Mine Safety and Health Review Commission  5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration       49, III
Federal Prison Industries, Inc.                   28, III
Federal Procurement Policy Office                 48, 99
Federal Property Management Regulations           41, 101
Federal Railroad Administration                   49, II
Federal Register, Administrative Committee of     1, I
Federal Register, Office of                       1, II
Federal Reserve System                            12, II
  Board of Governors                              5, LVIII
Federal Retirement Thrift Investment Board        5, VI, LXXVI
Federal Service Impasses Panel                    5, XIV
Federal Trade Commission                          5, XLVII; 16, I
Federal Transit Administration                    49, VI
Federal Travel Regulation System                  41, Subtitle F
Financial Crimes Enforcement Network              31, X
Financial Research Office                         12, XVI
Financial Stability Oversight Council             12, XIII
Fine Arts, Commission of                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Food and Drug Administration                      21, I
Food and Nutrition Service                        7, II
Food Safety and Inspection Service                9, III
Foreign Agricultural Service                      7, XV
Foreign Assets Control, Office of                 31, V
Foreign Claims Settlement Commission of the       45, V
     United States
Foreign Service Grievance Board                   22, IX
Foreign Service Impasse Disputes Panel            22, XIV
Foreign Service Labor Relations Board             22, XIV
Foreign-Trade Zones Board                         15, IV
Forest Service                                    36, II
General Services Administration                   5, LVII; 41, 105

[[Page 681]]

  Contract Appeals, Board of                      48, 61
  Federal Acquisition Regulation                  48, 5
  Federal Management Regulation                   41, 102
  Federal Property Management Regulations         41, 101
  Federal Travel Regulation System                41, Subtitle F
  General                                         41, 300
  Payment From a Non-Federal Source for Travel    41, 304
       Expenses
  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Temporary Duty (TDY) Travel Allowances          41, 301
Geological Survey                                 30, IV
Government Accountability Office                  4, I
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Gulf Coast Ecosystem Restoration Council          2, LIX; 40, VIII
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          2, III; 5, XLV; 45, 
                                                  Subtitle A
  Centers for Medicare & Medicaid Services        42, IV
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X, XIII
  Community Services, Office of                   45, X
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Indian Health Service                           25, V
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Homeland Security, Department of                  2, XXX; 5, XXXVI; 6, I; 8, 
                                                  I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection                   19, I
  Federal Emergency Management Agency             44, I
  Human Resources Management and Labor Relations  5, XCVII
       Systems
  Immigration and Customs Enforcement Bureau      19, IV
  Transportation Security Administration          49, XII
HOPE for Homeowners Program, Board of Directors   24, XXIV
     of
Housing and Urban Development, Department of      2, XXIV; 5, LXV; 24, 
                                                  Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Housing, Office of, and Multifamily Housing     24, IV
       Assistance Restructuring, Office of
  Inspector General, Office of                    24, XII
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Housing, Office of, and Multifamily Housing       24, IV
     Assistance Restructuring, Office of
Immigration and Customs Enforcement Bureau        19, IV
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
Independent Counsel, Offices of                   28, VI
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
   Secretary
[[Page 682]]

Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V
Industry and Security, Bureau of                  15, VII
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
     Archives and Records Administration
Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII, XV
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Interior, Department of                           2, XIV
  American Indians, Office of the Special         25, VII
       Trustee
  Endangered Species Committee                    50, IV
  Federal Acquisition Regulation                  48, 14
  Federal Property Management Regulations System  41, 114
  Fish and Wildlife Service, United States        50, I, IV
  Geological Survey                               30, IV
  Indian Affairs, Bureau of                       25, I, V
  Indian Affairs, Office of the Assistant         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Natural Resource Revenue, Office of             30, XII
  Ocean Energy Management, Bureau of              30, V
  Reclamation, Bureau of                          43, I
  Safety and Enforcement Bureau, Bureau of        30, II
  Secretary of the Interior, Office of            2, XIV; 43, Subtitle A
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, United States Agency   22, II
     for
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
International Trade Administration                15, III; 19, III
International Trade Commission, United States     19, II
Interstate Commerce Commission                    5, XL
Investment Security, Office of                    31, VIII
James Madison Memorial Fellowship Foundation      45, XXIV
Japan-United States Friendship Commission         22, XVI
Joint Board for the Enrollment of Actuaries       20, VIII
Justice, Department of                            2, XXVIII; 5, XXVIII; 28, 
                                                  I, XI; 40, IV
  Alcohol, Tobacco, Firearms, and Explosives,     27, II
       Bureau of
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             31, IX
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration Review, Executive Office for        8, V
  Independent Counsel, Offices of                 28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor, Department of                              2, XXIX; 5, XLII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV
  Employment and Training Administration          20, V
  Employment Standards Administration             20, VI
  Federal Acquisition Regulation                  48, 29
  Federal Contract Compliance Programs, Office    41, 60
     of
[[Page 683]]

  Federal Procurement Regulations System          41, 50
  Labor-Management Standards, Office of           29, II, IV
  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training Service,      41, 61; 20, IX
       Office of the Assistant Secretary for
  Wage and Hour Division                          29, V
  Workers' Compensation Programs, Office of       20, I, VII
Labor-Management Standards, Office of             29, II, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Libraries and Information Science, National       45, XVII
     Commission on
Library of Congress                               36, VII
  Copyright Royalty Board                         37, III
  U.S. Copyright Office                           37, II
Local Television Loan Guarantee Board             7, XX
Management and Budget, Office of                  5, III, LXXVII; 14, VI; 
                                                  48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II, LXIV
Micronesian Status Negotiations, Office for       32, XXVII
Military Compensation and Retirement              5, XCIX
     Modernization Commission
Millennium Challenge Corporation                  22, XIII
Mine Safety and Health Administration             30, I
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Morris K. Udall Scholarship and Excellence in     36, XVI
     National Environmental Policy Foundation
Museum and Library Services, Institute of         2, XXXI
National Aeronautics and Space Administration     2, XVIII; 5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National and Community Service, Corporation for   2, XXII; 45, XII, XXV
National Archives and Records Administration      2, XXVI; 5, LXVI; 36, XII
  Information Security Oversight Office           32, XX
National Capital Planning Commission              1, IV, VI
National Counterintelligence Center               32, XVIII
National Credit Union Administration              5, LXXXVI; 12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           2, XXXVI; 21, III
National Endowment for the Arts                   2, XXXII
National Endowment for the Humanities             2, XXXIII
National Foundation on the Arts and the           45, XI
     Humanities
National Geospatial-Intelligence Agency           32, I
National Highway Traffic Safety Administration    23, II, III; 47, VI; 49, V
National Imagery and Mapping Agency               32, I
National Indian Gaming Commission                 25, III
National Institute of Food and Agriculture        7, XXXIV
National Institute of Standards and Technology    15, II; 37, IV
National Intelligence, Office of Director of      5, IV; 32, XVII
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV
National Mediation Board                          5, CI; 29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI
National Park Service                             36, I
National Railroad Adjustment Board                29, III
National Railroad Passenger Corporation (AMTRAK)  49, VII
National Science Foundation                       2, XXV; 5, XLIII; 45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI

[[Page 684]]

National Security Council and Office of Science   47, II
     and Technology Policy
National Technical Information Service            15, XI
National Telecommunications and Information       15, XXIII; 47, III, IV, V
     Administration
National Transportation Safety Board              49, VIII
Natural Resources Conservation Service            7, VI
Natural Resource Revenue, Office of               30, XII
Navajo and Hopi Indian Relocation, Office of      25, IV
Navy, Department of                               32, VI
  Federal Acquisition Regulation                  48, 52
Neighborhood Reinvestment Corporation             24, XXV
Northeast Interstate Low-Level Radioactive Waste  10, XVIII
     Commission
Nuclear Regulatory Commission                     2, XX; 5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Ocean Energy Management, Bureau of                30, V
Oklahoma City National Memorial Trust             36, XV
Operations Office                                 7, XXVIII
Overseas Private Investment Corporation           5, XXXIII; 22, VII
Patent and Trademark Office, United States        37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       2, XXXVII; 22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 5, IV; 45, 
                                                  VIII
  Human Resources Management and Labor Relations  5, XCVII
       Systems, Department of Homeland Security
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Pipeline and Hazardous Materials Safety           49, I
     Administration
Postal Regulatory Commission                      5, XLVI; 39, III
Postal Service, United States                     5, LX; 39, I
Postsecondary Education, Office of                34, VI
President's Commission on White House             1, IV
     Fellowships
Presidential Documents                            3
Presidio Trust                                    36, X
Prisons, Bureau of                                28, V
Privacy and Civil Liberties Oversight Board       6, X
Procurement and Property Management, Office of    7, XXXII
Public Contracts, Department of Labor             41, 50
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Relocation Allowances                             41, 302
Research and Innovative Technology                49, XI
     Administration
Rural Business-Cooperative Service                7, XVIII, XLII
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII, XXXV
Rural Telephone Bank                              7, XVI
Rural Utilities Service                           7, XVII, XVIII, XLII
Safety and Environmental Enforcement, Bureau of   30, II
Saint Lawrence Seaway Development Corporation     33, IV
Science and Technology Policy, Office of          32, XXIV
Science and Technology Policy, Office of, and     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                5, XXXIV; 17, II

[[Page 685]]

Selective Service System                          32, XVI
Small Business Administration                     2, XXVII; 13, I
Smithsonian Institution                           36, V
Social Security Administration                    2, XXIII; 20, III; 48, 23
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State, Department of                              2, VI; 22, I; 28, XI
  Federal Acquisition Regulation                  48, 6
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
Surface Transportation Board                      49, X
Susquehanna River Basin Commission                18, VIII
Tennessee Valley Authority                        5, LXIX; 18, XIII
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     2, XII; 5, L
  Commercial Space Transportation                 14, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II
  Federal Motor Carrier Safety Administration     49, III
  Federal Railroad Administration                 49, II
  Federal Transit Administration                  49, VI
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 47, IV; 49, V
  Pipeline and Hazardous Materials Safety         49, I
       Administration
  Saint Lawrence Seaway Development Corporation   33, IV
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Transportation Statistics Bureau                49, XI
Transportation, Office of                         7, XXXIII
Transportation Security Administration            49, XII
Transportation Statistics Bureau                  49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury, Department of the                       2, X;5, XXI; 12, XV; 17, 
                                                  IV; 31, IX
  Alcohol and Tobacco Tax and Trade Bureau        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs and Border Protection                   19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal Claims Collection Standards             31, IX
  Federal Law Enforcement Training Center         31, VII
  Financial Crimes Enforcement Network            31, X
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  Investment Security, Office of                  31, VIII
  Monetary Offices                                31, I
  Secret Service                                  31, IV
  Secretary of the Treasury, Office of            31, Subtitle A
Truman, Harry S. Scholarship Foundation           45, XVIII
United States and Canada, International Joint     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
     and Water Commission, United States Section
U.S. Copyright Office                             37, II
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs, Department of                   2, VIII; 38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training Service,        41, 61; 20, IX
     Office of the Assistant Secretary for
Vice President of the United States, Office of    32, XXVIII
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I, VII
World Agricultural Outlook Board                  7, XXXVIII

[[Page 687]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations (CFR) that 
were made by documents published in the Federal Register since January 
1, 2014 are enumerated in the following list. Entries indicate the 
nature of the changes effected. Page numbers refer to Federal Register 
pages. The user should consult the entries for chapters, parts and 
subparts as well as sections for revisions.
For changes to this volume of the CFR prior to this listing, consult the 
annual edition of the monthly List of CFR Sections Affected (LSA). The 
LSA is available at www.govinfo.gov. For changes to this volume of the 
CFR prior to 2001, see the ``List of CFR Sections Affected, 1949-1963, 
1964-1972, 1973-1985, and 1986-2000'' published in 11 separate volumes. 
The ``List of CFR Sections Affected 1986-2000'' is available at 
www.govinfo.gov.

                                  2014

30 CFR
                                                                   79 FR
                                                                    Page
Chapter V
553 Authority citation revised.....................................73839
553.1 Revised......................................................73839
553.3 Amended......................................................73839
553.700--553.704 (Subpart G) Added.................................73840
585.102 (e) revised................................................21621
585.112 Amended....................................................21621
585.203 Revised....................................................21621
585.211 (c) revised................................................21621
585.212 (a) revised................................................21621
585.224 (b) revised................................................21621
585.231 (d), (e), (f) and (g)(2) revised...........................21622
585.235 (a) revised................................................21622
585.236 (a) revised................................................21622
585.303 Revised....................................................21623
585.306 (b) revised; (c) removed...................................21623
585.309 Introductory text revised..................................21623
585.500 (a) and (b) revised........................................21623
585.503 (a)(1) revised.............................................21623
585.505 (b) revised................................................21623
585.601 Introductory text and (a) revised; (b) removed; (c) and 
        (d) redesignated as new (b) and (c)........................21623
585.611 Revised....................................................21623
585.612 Revised....................................................21624
585.627 (a) and (b) revised........................................21624
585.628 (c) revised................................................21625
585.640 (b) revised................................................21625
585.646 Revised....................................................21625
585.647 Revised....................................................21625
590 Authority citation revised.....................................21626
590.4 (b)(1) revised...............................................21626

                                  2015

30 CFR
                                                                   80 FR
                                                                    Page
Chapter II
250.1704 Heading and introductory text revised; table amended......75810
Chapter V
519 Authority citation revised.....................................57096
    Removed........................................................81458
519.410 (b) amended................................................57096
550 Authority citation revised.....................................57096
550.126 Introductory text amended..................................57096
550.199 (d) revised................................................57096
550.1153 (d) amended...............................................57096
550.1454 Amended...................................................57096
550.1456 (b) revised...............................................57096
550.1462 Amended...................................................57096
550.1464 (b) revised...............................................57096
550.1495 (a)(1), (2) and (3) revised...............................57096
551 Authority citation revised.....................................57096
551.5 (d)(1) and (3) revised.......................................57096
551.7 (d)(4) revised...............................................57097
551.15 (e) revised.................................................57097

[[Page 688]]

553 Authority citation revised.....................................57097
553.5 (d) revised..................................................57097
556 Authority citation revised.....................................57097
556.0 (d) revised..................................................57097
556.54 (b) and (f) revised.........................................57097
560 Authority citation revised.....................................57097
560.3 (b) revised..................................................57097
580 Authority citation revised.....................................57097
580.13 (b) and (c) revised.........................................57097
580.80 (e) revised.................................................57098
581 Authority citation revised.....................................57098
581.33 (b) amended.................................................57098
582 Authority citation revised.....................................57098
582.40 (b) amended.................................................57098
585 Authority citation revised.....................................57098
585.110 (a) revised................................................57098
585.114 (d) revised................................................57098
585.115 (d) amended................................................57098

                                  2016

30 CFR
                                                                   81 FR
                                                                    Page
Chapter II
203 Nomenclature change; eff. 7-28-16..............................36148
203.3 (b) revised; eff. 7-28-16....................................36148
203.5 (a) amended; eff. 7-28-16....................................36148
250 Authority citation revised..............................36148, 46560
    Nomenclature change; eff. 7-28-16..............................36148
250.102 (b)(1), (11), (12) and (13) revised; (b)(19) added; eff. 
        7-28-16....................................................26013
    (b) table revised; eff. 7-28-16................................36148
250.105 Amended....................................................46560
250.107 (a)(1) and (2) amended; (a)(3), (4) and (e) added; eff. 7-
        28-16......................................................26014
    (c) revised; (d) removed; (e) redesignated as new (d)..........61915
250.114 (a) amended; eff. 7-28-16..................................36149
    Heading revised................................................61916
250.118 Undesignated center heading added; eff. 7-28-16............36149
250.125 (a) table revised; eff. 7-28-16............................26014
    (a) table revised..............................................61916
250.126 Revised; eff. 7-28-16......................................36149
250.188 (c) added..................................................46560
250.193 (e)(2)(i)(C) amended; eff. 7-28-16.........................36149
250.198 (h)(51), (63), (68) and (70) revised; (h)(88) amended; 
        (h)(89) through (94) added; eff. 7-28-16...................26015
    (d), (e) introductory text, (g) introductory text, (i) 
introductory text, (j) introductory text, (k) introductory text 
and (m) introductory text revised; eff. 7-28-16....................36149
    (h)(95) added..................................................46560
    (g)(1), (2), (3), (h)(1), (51), (52), (53), (55) through (62), 
(65), (66), (68), (70), (71), (73), (74), (93), (94) and (95) 
revised; (g)(6) and (7) removed; (g)(8) redesignated as new 
(g)(6); (h)(96) added..............................................61917
250.199 (e) revised; eff. 7-28-16..................................26015
250.292 (o) amended; (p) redesignated as (q); new (p) added; eff. 
        7-28-16....................................................26017
250.300 (b)(1) and (2) revised.....................................46560
250.400 Revised; eff. 7-28-16......................................26017
250.401 Removed; eff. 7-28-16......................................26017
250.402 Removed; eff. 7-28-16......................................26017
250.403 Removed; eff. 7-28-16......................................26017
250.405 Introductory text amended; eff. 7-28-16....................36149
250.406 Removed; eff. 7-28-16......................................26017
250.411 Revised; eff. 7-28-16......................................26017
250.413 (g) revised; eff. 7-28-16..................................26017
250.414 (c), (h) and (i) revised; (j) and (k) added; eff. 7-28-16 
                                                                   26017
250.415 (a) revised; eff. 7-28-16..................................26018
250.416 Revised; eff. 7-28-16......................................26018
250.417 Removed; eff. 7-28-16......................................26018
250.418 (g) and (h) revised; (i) removed; (j) redesignated as new 
        (i); eff. 7-28-16..........................................26018
    (j) added......................................................46561
250.420 Introductory text, (a)(5) and (c) revised; (a)(6) 
        redesignated as (a)(7); new (a)(6) and (b)(4) added; eff. 
        7-28-16....................................................26018
250.421 (b) and (f) revised; eff. 7-28-16..........................26018
250.423 Revised; eff. 7-28-16......................................26019
250.424 Removed; eff. 7-28-16......................................26019
250.425 Removed; eff. 7-28-16......................................26019
250.426 Removed; eff. 7-28-16......................................26019
250.427 (b) revised; eff. 7-28-16..................................26019
250.428 (b), (c) and (d) revised; (k) added; eff. 7-28-16..........26019
250.440 Removed; eff. 7-28-16......................................26020
250.441 Removed; eff. 7-28-16......................................26020
250.442 Removed; eff. 7-28-16......................................26020

[[Page 689]]

250.443 Removed; eff. 7-28-16......................................26020
250.444 Removed; eff. 7-28-16......................................26020
250.445 Removed; eff. 7-28-16......................................26020
250.446 Removed; eff. 7-28-16......................................26020
250.447 Removed; eff. 7-28-16......................................26020
250.448 Removed; eff. 7-28-16......................................26020
250.449 Removed; eff. 7-28-16......................................26020
250.450 Removed; eff. 7-28-16......................................26020
250.451 Removed; eff. 7-28-16......................................26020
250.452 Added......................................................46561
250.456 (i) amended; (j) removed; (k) redesignated as new (j); 
        eff. 7-28-16...............................................26020
250.462 Revised; eff. 7-28-16......................................26020
250.465 (b)(3) revised; eff. 7-28-16...............................26021
250.466 Removed; eff. 7-28-16......................................26021
250.467 Removed; eff. 7-28-16......................................26021
250.468 Removed; eff. 7-28-16......................................26021
250.469 Removed; eff. 7-28-16......................................26021
250.470 Undesignated center heading and section added..............46561
250.471 Added......................................................46561
250.472 Added......................................................46561
250.473 Added......................................................46561
250.500 Revised; eff. 7-28-16......................................26021
250.502 Removed; eff. 7-28-16......................................26021
250.506 Removed; eff. 7-28-16......................................26021
250.513 (b)(4) revised; eff. 7-28-16...............................26021
250.514 (d) removed; eff. 7-28-16..................................26021
250.515 Removed; eff. 7-28-16......................................26021
250.516 Removed; eff. 7-28-16......................................26021
250.517 Removed; eff. 7-28-16......................................26021
250.518 (b) removed; (c), (d) and (e) redesignated as new (b), (c) 
        and (d); new (e) and (f) added; eff. 7-28-16...............26021
250.518 (d) revised................................................61918
250.600 Revised; eff. 7-28-16......................................26021
250.602 Removed; eff. 7-28-16......................................26021
250.606 Removed; eff. 7-28-16......................................26021
250.610 Revised; eff. 7-28-16......................................36149
250.611 Revised; eff.7-28-16.......................................36149
250.613 (b)(3) revised; eff. 7-28-16...............................26021
250.614 (d) removed; eff. 7-28-16..................................26021
250.615 Removed; eff. 7-28-16......................................26021
250.616 Heading revised; (a) through (e) removed; (f), (g) and (h) 
        redesignated as new (a), (b) and (c); eff. 7-28-16.........26021
250.617 Removed; eff. 7-28-16......................................26021
250.618 Removed; eff. 7-28-16......................................26021
250.619 (b) removed; (c), (d) and (e) redesignated as new (b), (c) 
        and (d); new (e) and (f) added; eff. 7-28-16...............26021
    (d) revised....................................................61918
250.700--250.746 (Subpart G) Added; eff. 7-28-16...................26022
250.713 (b) amended; eff. 7-28-16..................................36150
250.720 (c) added..................................................46563
250.800--250.899 (Subpart H) Revised...............................61918
250.803 (b)(1) introductory text amended; eff. 7-28-16.............36150
250.806 (c) amended; eff. 7-28-16..................................36150
250.901 (a)(24) amended; eff. 7-28-16..............................36150
250.904 (b) amended; eff. 7-28-16..................................36150
    Regulation at 81 FR 36150 withdrawn............................40812
250.908 (a) table amended; eff. 7-28-16............................36150
250.920 (b) amended; eff. 7-28-16..................................36150
250.1000 (c)(3)(i), (iv), (4), (12)(ii), (13)(i) and (ii) revised; 
        eff. 7-28-16...............................................36150
250.1015 (e) removed; eff. 7-28-16.................................36150
250.1018 (c) removed; eff. 7-28-16.................................36150
250.1165 (b) amended; eff. 7-28-16.................................36150
250.1302 (a) amended; (c) and (d) revised; eff. 7-28-16............36150
250.1401 Removed; eff. 7-28-16.....................................36150
250.1403 Revised; interim; eff. 7-28-16............................41803
    Regulation at 81 FR 41803 confirmed............................80996
250.1455 (b)(2) revised; eff. 7-28-16..............................36150
250.1463 (b)(2) revised; eff. 7-28-16..............................36150
250.1490 Undesignated center heading and section removed; eff. 7-
        28-16......................................................36151
250.1491 Removed; eff. 7-28-16.....................................36151
250.1495 Undesignated center heading and section removed; eff. 7-
        28-16......................................................36151
250.1496 Removed; eff. 7-28-16.....................................36151
250.1497 Removed; eff. 7-28-16.....................................36151
250.1609 (b) amended; eff. 7-28-16.................................36151

[[Page 690]]

250.1612 Revised; eff. 7-28-16.....................................26037
250.1703 (b) and (e) revised; (f) redesignated as (g); new (f) 
        added; eff. 7-28-16........................................26037
250.1704 (g) revised; (h) and (i) redesignated as (i) and (j); new 
        (h) added; eff. 7-28-16....................................26037
    Table amended..................................................80591
250.1705 Removed; eff. 7-28-16.....................................26037
250.1706 Heading revised; (a) through (e) removed; (f), (g) and 
        (h) redesignated as new (a), (b) and (c); eff. 7-28-16.....26037
250.1707 Removed; eff. 7-28-16.....................................26038
250.1708 Removed; eff. 7-28-16.....................................26038
250.1709 Removed; eff. 7-28-16.....................................26038
250.1715 (a)(3)(iii)(B) revised; eff. 7-28-16......................26038
250.1717 Removed; eff. 7-28-16.....................................26038
250.1721 (g) removed; (h) redesignated as new (g); eff. 7-28-16....26038
250.1920 (b)(5) revised; (e) added; eff. 7-28-16...................36151
    (b)(5), (c) and (d) amended; (f) and (g) added.................46563
251.15 Revised; eff. 7-28-16.......................................36151
252.2 Amended; eff. 7-28-16........................................36151
254.1 Heading, (a), (b), (d) and (e) revised; eff. 7-28-16.........36151
254.2 Revised; eff. 7-28-16........................................36151
254.3 Revised; eff. 7-28-16........................................36151
254.4 Revised; eff. 7-28-16........................................36152
254.5 (a), (b) and (d) revised; eff. 7-28-16.......................36152
254.6 Amended; eff. 7-28-16........................................36152
    Amended........................................................46563
254.7 Revised; eff. eff. 7-28-16...................................36152
254.9 (a) amended; eff. 7-28-16....................................36152
254.20 Amended; eff. 7-28-16.......................................36152
254.21 Heading, (a), (b) introductory text and (1) revised; eff. 
        7-28-16....................................................36152
254.22 Heading, introductory text, (a), (c) and (d) amended; eff. 
        7-28-16....................................................36152
254.23 Introductory text amended; eff. 7-28-16.....................36152
254.25 Amended; eff. 7-28-16.......................................36152
254.30 Revised; eff. 7-28-16.......................................36152
254.41 (d) amended; eff. 7-28-16...................................36153
254.42 (a), (b)(2) and (e) revised; (f), (h) and (i) amended; eff. 
        7-28-16....................................................36153
254.43 (a) amended; eff. 7-28-16...................................36153
254.44 (a) amended; eff. 7-28-16...................................36153
254.45 (a) amended; eff. 7-28-16...................................36153
254.46 (b)(2) amended; eff. 7-28-16................................36153
254.47 (d) amended; eff. 7-28-16...................................36153
254.51 Heading amended; eff. 7-28-16...............................36153
254.52 Heading amended; eff. 7-28-16...............................36153
254.53 Heading and (a) introductory text amended; eff. 7-28-16.....36153
254.54 Amended; eff. 7-28-16.......................................36153
254.55 Added.......................................................46563
254.65--254.90 (Subpart E) Added...................................46564
256.0 Removed; eff. 7-28-16........................................36153
256.2 Removed; eff. 7-28-16........................................36153
256.3 Removed; eff. 7-28-16........................................36153
256.4 Removed; eff. 7-28-16........................................36153
256.5 Removed; eff. 7-28-16........................................36153
256.7 (j) added; eff. 7-28-16......................................36153
256.8 Removed; eff. 7-28-16........................................36153
256.9 Removed; eff. 7-28-16........................................36153
256.10 Removed; eff. 7-28-16.......................................36153
256.11 Removed; eff. 7-28-16.......................................36153
256.12 Removed; eff. 7-28-16.......................................36153
256.8 Removed; eff. 7-28-16........................................36153
256 Subparts B through I removed; eff. 7-28-16.....................36153
256.62--256.73 (Subpart B) Redesignated from Subpart J; eff. 7-28-
        16.........................................................36153
256.62--256.73 (Subpart J) Redesignated as Subpart B; eff. 7-28-16
                                                                   36153
256.62 Removed; eff. 7-28-16.......................................36153
256.63 Removed; eff. 7-28-16.......................................36153
256.64 Removed; eff. 7-28-16.......................................36153
256.65 Removed; eff. 7-28-16.......................................36153
256.66 Removed; eff. 7-28-16.......................................36153
256.67 Removed; eff. 7-28-16.......................................36153
256.68 Removed; eff. 7-28-16.......................................36153
256.76--256.77 (Subpart C) Redesignated from Subpart K; eff. 7-28-
        16.........................................................36153
256.76--256.77 (Subpart K) Redesignated as Subpart C; eff. 7-28-16
                                                                   36153
256.76 Removed; eff. 7-28-16.......................................36153
256.79--256.80 (Subpart D) Redesignated from Subpart L; eff. 7-28-
        16.........................................................36153
256.79--256.80 (Subpart L) Redesignated as Subpart D; eff. 7-28-16
                                                                   36153
256.80 Removed; eff. 7-28-16.......................................36153

[[Page 691]]

256 Subparts M and N removed; eff. 7-28-16.........................36153
280.25 (a)(2) amended; eff. 7-28-16................................36153
280.28 (a) amended; eff. 7-28-16...................................36153
282.0 Existing text designated as (a) and amended; (b) added; eff. 
        7-28-16....................................................36153
282.3 Amended; eff. 7-28-16........................................36153
282.13 (d) and (e)(2) revised; eff. 7-28-16........................36153
282.14 (c) amended; eff. 7-28-16...................................36154
282.27 (d)(2) revised; eff. 7-28-16................................36154
290 Authority citation revised.....................................36154
290.4 (b)(1) revised; eff. 7-28-16.................................36154
291.1 (a) and (e) amended; eff. 7-28-16............................36154
291.103 Introductory text amended; eff. 7-28-16....................36154
291.106 (a) amended; eff. 7-28-16..................................36154
291.107 (a) and (b)(1) amended; eff. 7-28-16.......................36154
291.108 (a) revised; eff. 7-28-16..................................36154
291.109 (a)(1) and (b) amended; eff. 7-28-16.......................36154
Chapter V
550 Authority citation revised.......................18152, 43069, 46564
    Policy statement...............................................46599
550.105 Amended....................................................46565
550.120 Added......................................................18152
550.121 Added......................................................18152
550.145 Redesignated as 550.146....................................18152
550.146 Redesignated as 550.147; redesignated from 550.145.........18152
550.147 Redesignated from 550.146..................................18152
550.197 Introductory text amended; (b)(5) and (c) revised; (d) 
        added......................................................18152
550.200 (a) amended................................................46565
550.204 Added......................................................46565
550.206 Revised....................................................46565
550.220 (a) revised; (c) added.....................................46565
550.400 (Subpart D) Added..........................................18152
550.1403 Revised; interim; eff. 8-1-16.............................43069
553 Authority citation revised.....................................43069
553.51 (a) revised; interim; eff. 8-1-16...........................43069
556 Revised........................................................18152
    Policy statement...............................................46599
556.105 Amended....................................................70358
556.403 Correctly revised..........................................34275
559 Removed........................................................18174
560.1 Redesignated as 560.101......................................18175
560.2 Redesignated as 560.102......................................18175
560.3 Redesignated as 560.103......................................18175
560.100 Added......................................................18175
560.101 Redesignated as 560.200; redesignated from 560.1...........18175
560.102 Redesignated as 560.201; redesignated from 560.2 and 
        revised....................................................18175
560.103 Redesignated from 560.3....................................18175
560.110 Redesignated as 560.202....................................18175
560.111 Redesignated as 560.203....................................18175
560.112 Redesignated as 560.210....................................18175
560.113 Redesignated as 560.211....................................18175
560.114 Redesignated as 560.212....................................18175
560.115 Redesignated as 560.213....................................18175
560.116 Redesignated as 560.214....................................18175
560.120 Redesignated as 560.220....................................18175
560.121 Redesignated as 560.221....................................18175
560.122 Redesignated as 560.222....................................18175
560.123 Redesignated as 560.223....................................18175
560.124 Redesignated as 560.224....................................18175
560.130 Redesignated as 560.230....................................18175
560.200 Redesignated from 560.101..................................18175
560.201 Redesignated from 560.102..................................18175
560.202 Redesignated from 560.110..................................18175
560.203 Redesignated from 560.111..................................18175
560.210 Redesignated from 560.112..................................18175
560.211 Redesignated from 560.113..................................18175
560.212 Redesignated from 560.114..................................18175
560.213 Redesignated from 560.115..................................18175
560.214 Redesignated from 560.116..................................18175
560.220 Redesignated from 560.120..................................18175
560.221 Redesignated from 560.121..................................18175
560.222 Redesignated from 560.122..................................18175
560.223 Redesignated from 560.123..................................18175
560.224 Redesignated from 560.124..................................18175
560.230 Redesignated from 560.130..................................18175
560.300 (Subpart C) Added..........................................18175

[[Page 692]]

560.301--560.302 (Subpart D) Removed...............................18176
560.500--560.502 (Subpart E) Added.................................18176

                                  2017

30 CFR
                                                                   82 FR
                                                                    Page
Chapter II
Chapter II Policy statement........................................50532
250.171 Introductory text revised..................................26744
250.180 (a)(1), (b), (d), (e), (g) and (j) revised.................26744
250.1403 Revised....................................................9138
Chapter IV
Chapter IV Policy statement........................................50532
Chapter V
Chapter V Policy statement.........................................50532
550.1403 Revised...................................................10711
553.51 (a) revised.................................................10711
583 Added..........................................................45973

                                  2018

30 CFR
                                                                   83 FR
                                                                    Page
Chapter II
250.198 (g)(6) removed; (g) introductory text, (1), (2), (3), 
        (h)(1), (52), (55), (59), (60), (61), (65), (68), (70), 
        (71), and (96) revised; (g)(4) and (5) redesignated as new 
        (g)(6) and (7); new (g)(4), new (5), and (o) added; new 
        (g)(6), new (7), (h)(58), (62), and (73) amended...........49255
250.800 (a) revised................................................49256
250.801 (a) revised................................................49256
250.802 (a), (c), and (d) revised..................................49256
250.803 Revised....................................................49256
250.814 (d) revised................................................49257
250.820 Revised....................................................49257
250.821 (a) introductory text and (1) revised......................49257
250.828 (c) revised................................................49257
250.833 Introductory text revised..................................49257
250.834 Revised....................................................49257
250.836 Revised....................................................49257
250.837 (a), (b), and (c)(5) revised...............................49257
250.841 (c) added..................................................49257
250.842 Revised....................................................49257
250.851 (a)(2) revised.............................................49259
250.852 (e)(1) and (4) revised.....................................49259
250.853 (b) and (c) amended; (d) added.............................49259
250.867 (a) revised; (d) added.....................................49259
250.870 (a) introductory text and (a)(2) revised...................49259
250.872 Revised....................................................49259
250.873 (b)(3) revised.............................................49260
250.874 (g)(2) revised.............................................49262
250.876 Revised....................................................49262
250.880 (a) introductory text, (1), (c)(1)(i), (2)(iv), (4)(i), 
        and (iii) revised..........................................49262
250.1002 (b)(1), (2), and (4) revised..............................49263
250.1007 (a)(4)(i)(D) revised......................................49263
250.1403 Revised....................................................2540
Chapter V
550.1403 Revised....................................................8933
553.51 (a) revised..................................................8933
553.702 Revised.....................................................2542

                                  2019

   (Regulations published from January 1, 2019, through July 1, 2019)

30 CFR
                                                                   84 FR
                                                                    Page
Chapter II
250.115 Added; eff. 7-15-19........................................21968
250.198 Revised; eff. 7-15-19......................................21969
250.292 (p) revised; eff. 7-15-19..................................21973
250.413 (g) revised; eff. 7-15-19..................................21973
250.414 (c)(2) and (3) revised; eff. 7-15-19.......................21973
250.420 (a)(6) revised; eff. 7-15-19...............................21973
250.421 (c) through (f) revised; eff. 7-15-19......................21974
250.423 (a) and (b) revised; eff. 7-15-19..........................21974
250.427 (b) revised; eff. 7-15-19..................................21974
250.428 (c) and (d) revised; eff. 7-15-19..........................21974
250.433 (b) revised; eff. 7-15-19..................................21975
250.461 (b) revised; eff. 7-15-19..................................21975
250.462 (b) introductory text, (e)(1)(ii), (2)(i), (3), and (4) 
        revised; eff. 7-15-19......................................21975
250.518 (e)(1) revised; (g) added; eff. 7-15-19....................21976
250.519 Revised; eff. 7-15-19......................................21976
250.522 Revised; eff. 7-15-19......................................21976
250.525 (d) revised; eff. 7-15-19..................................21976
250.526 Revised; eff. 7-15-19......................................21976
250.530 (b) revised; eff. 7-15-19..................................21976

[[Page 693]]

250.601 Amended; eff. 7-15-19......................................21976
250.616 Removed; eff. 7-15-19......................................21976
250.619 (e)(1) revised; (g) added; eff. 7-15-19....................21976
250.712 (g) and (h) added; eff. 7-15-19............................21976
250.720 (a)(1) revised; (a)(3) and (d) added; eff. 7-15-19.........21976
250.722 (a)(2) revised; eff. 7-15-19...............................21977
250.723 Introductory text and (c)(3) revised; eff. 7-15-19.........21977
250.724 Revised; eff. 7-15-19......................................21977
250.730 Revised; eff. 7-15-19......................................21977
250.731 (a)(5) and (c) revised; (d) and (f) removed; (e) 
        redesignated as new (d); eff. 7-15-19......................21978
250.732 Revised; eff. 7-15-19......................................21978
250.733 (a)(1) and (b)(1) revised; (e) added; eff. 7-15-19.........21979
250.734 (a)(6)(vi) removed; (a)(1)(ii), (3), (4), (6)(v), (16), 
        and (b) revised; eff. 7-15-19..............................21980
250.735 (a) revised; eff. 7-15-19..................................21981
250.736 (d)(5) revised; eff. 7-15-19...............................21981
250.737 (a)(4) redesignated as (a)(5); new (a)(4) and (d)(13) 
        added; (b) introductory text, (2), (3), (c), (d)(2)(ii), 
        (3)(iii), (iv), (v), (4)(i), (iii), (v), (5), (10), 
        (12)(iv), and (vi) revised; (d)(4)(vi) removed; eff. 7-15-
        19.........................................................21981
250.738 (b) introductory text, (3), (4), (f), (i), (m), and (o) 
        revised; eff. 7-15-19......................................21983
250.739 (b) introductory text revised; eff. 7-15-19................21983
250.750--250.751 Undesignated center heading added; eff. 7-15-19 
                                                                   21983
250.750 Added; eff. 7-15-19........................................21983
250.751 Added; eff. 7-15-19........................................21984
250.760 Undesignated center heading and section added; eff. 7-15-
        19.........................................................21984
250.842 Revised....................................................24705
250.851 (a)(2) revised.............................................24706
250.873 (b)(3) revised.............................................24707
250.1403 Revised...................................................10992
250.1703 (b) revised; eff. 7-15-19.................................21984
250.1704 (g)(4) added; (h)(2) revised; eff. 7-15-19................21984
250.1706 Removed; eff. 7-15-19.....................................21985
250.1713 Removed; eff. 7-15-19.....................................21985
250.1716 (b)(3) revised; eff. 7-15-19..............................21985
250.1722 (d) introductory text revised; eff. 7-15-19...............21985
Chapter V
550.1403 Revised...................................................11224
553.51 (a) revised.................................................11224


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