[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2011 Edition]
[From the U.S. Government Printing Office]



[[Page 1]]

          

          Title 30

Mineral Resources


________________________

Parts 200 to 699

                         Revised as of July 1, 2011

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2011
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

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                            Table of Contents



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

  Title 30:
          Chapter II--Bureau of Ocean Energy Management, 
          Regulation, and Enforcement, Department of the 
          Interior                                                   3
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 515
  Finding Aids:
      Table of CFR Titles and Chapters........................     529
      Alphabetical List of Agencies Appearing in the CFR......     549
      List of CFR Sections Affected...........................     559

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

                     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 
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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

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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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    Director,
    Office of the Federal Register.
    July 1, 2011.







[[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, 2011.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.

[[Page 1]]



                       TITLE 30--MINERAL RESOURCES




                  (This book contains parts 200 to 699)

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

chapter ii--Bureau of Ocean Energy Management, Regulation, 
  and Enforcement, Department of the Interior...............         203

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

[[Page 3]]



     CHAPTER II--BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION, AND 
                 ENFORCEMENT, DEPARTMENT OF THE INTERIOR




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

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
203             Relief or reduction in royalty rates........           5
219             Distribution and disbursement of royalties, 
                    rentals, and bonuses....................          44
                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................          49
251             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         281
252             Outer Continental Shelf (OCS) oil and gas 
                    information program.....................         295
253             Oil spill financial responsibility for 
                    offshore facilities.....................         301
254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         314
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         327
259             Mineral leasing: Definitions................         357
260             Outer Continental Shelf oil and gas leasing.         357
270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         364
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         365
281             Leasing of minerals other than oil, gas, and 
                    sulphur in the Outer Continental Shelf..         377
282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         390
285             Renewable energy alternate uses of existing 
                    facilities on the Outer Continental 
                    Shelf...................................         412
                          SUBCHAPTER C--APPEALS
290             Appeals procedures..........................         508

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291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         509

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT


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 MMS'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 MMS'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 Sec. 203.0 
          and Sec. Sec. 203.40 through 203.47 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 MMS 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 MMS take to evaluate my application?
203.66 What happens if MMS 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 MMS consider in determining 
          economic viability?
203.69 If my application is approved, what royalty relief will I 
          receive?

[[Page 6]]

203.70 What information must I provide after MMS approves relief?
203.71 How does MMS 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 MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS 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 MMS under Sec. Sec. 203.60-203.77 
          for my lease, unit or project if prices rise significantly?
203.79 How do I appeal MMS'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 MMS'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.



                      Subpart A_General Provisions

    Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.



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 250, 
subpart A, and does not produce gas or oil, or meets those producibility 
requirements and MMS agrees it is not commercially producible; and
    (5) For which you have provided the notices and information required 
under Sec. 203.47.
    Complete application means an original and two copies of the six 
reports consisting of the data specified in 30 CFR 203.81, 203.83 and 
203.85 through

[[Page 7]]

203.89, along with one set of digital information, which MMS 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 MMS 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 Development and Production 
Plan, a Development Operations Coordination Document (DOCD), or a 
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 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

[[Page 8]]

under a DOCD or a Supplement approved by the Secretary of the Interior 
after November, 28, 1995.
    Nonbinding assessment means an opinion by MMS 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 MMS 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 MMS 
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 means 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 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

[[Page 9]]

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 an MMS-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 part 250, subpart A 
of this title. Sunk costs include the rig mobilization and material 
costs for the discovery well that you incurred before its spud date.
    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 part 
250, subpart A of

[[Page 10]]

this chapter 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.

[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69 
FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004; 73 FR 69504, Nov. 
18, 2008]



Sec. 203.1  What is MMS'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 MMS 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.

[63 FR 2616, Jan. 16, 1998, as amended at 73 FR 69506, Nov. 18, 2008]



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
    If you have a lease . . .      And if you . . .        you . . .
------------------------------------------------------------------------
(a) With earnings that cannot     Would abandon       A reduced royalty
 sustain production (i.e., End-    otherwise           rate on current
 of-life lease).                   potentially         monthly
                                   recoverable         production and a
                                   resources but       higher royalty
                                   seek to increase    rate on
                                   production by       additional
                                   operating beyond    monthly
                                   the point at        production. (See
                                   which the lease     Sec. Sec.
                                   is economic under   203.50 through
                                   the existing        203.56.)
                                   royalty rate.
(b) Located in a designated GOM   Propose an          A royalty
 deep water area (i.e., 200        expansion project   suspension for a
 meters or greater) and acquired   and can             minimum
 in a lease sale held before       demonstrate your    production volume
 November 28, 1995, or after       project is          plus any
 November 28, 2000.                uneconomic          additional
                                   without royalty     production large
                                   relief.             enough to make
                                                       the project
                                                       economic (see
                                                       Sec. Sec.
                                                       203.60 through
                                                       203.79).

[[Page 11]]

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


[67 FR 1872, Jan. 15, 2002, as amended at 73 FR 69506, Nov. 18, 2008]



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 MMS 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 Pay.gov 
Web site and you must include a copy of the Pay.gov confirmation receipt 
page with your application or assessment. The Pay.gov Web site may be 
accessed through a link on the MMS Offshore Web site at: http://
www.mms.gov/offshore/ homepage or directly through Pay.gov at: https://
www.pay.gov/paygov/.

[73 FR 49946, Aug. 25, 2008]



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-  ------------------------------------------
                   Information elements                        life       Expansion     Pre-act     Development
                                                              lease        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 and 203.90 
through 203.91 to retain royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                   Confirmation elements                       life       Expansion     Pre-act     Development
                                                              lease        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-  ------------------------------------------
                    Approval conditions                        life                     Pre-act     Development
                                                              lease       Expansion      lease        project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required            X
 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% of net              X
 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 and 
203.74 through 203.75 describe, the prerequisites for a redetermination 
of our royalty relief decision.

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

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

[[Page 13]]



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

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                Relief withdrawn or reduced                    life       Expansion     Pre-act     Development
                                                              lease        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 that   .........              X          X               X
 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 pre-  .........              X          X               X
 production costs prior to start of production............
(8) Amount of relief volume is produced...................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------


[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]



Sec. 203.5  What is MMS'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 1010-0071. The title of this 
information collection is ``30 CFR part 203, Relief or Reduction in 
Royalty Rates.''
    (b) The MMS 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 a benefit 
or are mandatory according to 43 U.S.C. 1331 et

[[Page 14]]

seq. The MMS will protect information considered proprietary under 
applicable law and under regulations at 30 CFR 203.63, ``How do I assess 
my chances for getting relief?'' and 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[74 FR 46907, Sept. 14, 2009]



               Subpart B_OCS Oil, Gas, and Sulfur General

    Source: 63 FR 2618, Jan. 16, 1998, unless otherwise noted.

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

    Source: 73 FR 69506, Nov. 18, 2008, unless otherwise noted.



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
 qualified phase 3 ultra-deep well     Then your lease earns an RSV on
              that is:                  this volume of gas production:
------------------------------------------------------------------------
(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    4 BCF plus 600 MCF times sidetrack
 that is a phase 2 ultra-deep well,   measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      25 BCF.
(4) An ultra-deep short sidetrack    0 BCF.
 that 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.

[[Page 15]]

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

------------------------------------------------------------------------
  If you have a qualified phase 2      Then your lease earns an RSV on
    ultra-deep well that is . .         this volume of gas production:
------------------------------------------------------------------------
(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

[[Page 16]]

your lease is part of a unit and Sec. 203.43(a)(2), 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 Sec. 216.53. 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 an MMS-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 an MMS-
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 an MMS-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 MMS 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 MMS 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 MMS 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 MMS 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 MMS deems were 
unavoidable.



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

    (a) You must pay 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. 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

[[Page 20]]

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 Sec. 218.54 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

    Source: 69 FR 3510, Jan. 26, 2004, unless otherwise noted.



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 of this part. 
(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.

[73 FR 69510, Nov. 18, 2008]



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.

------------------------------------------------------------------------
                               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.

[[Page 21]]

 
(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 qualified phase 1 ultra-deep     Then your lease earns an RSV on
           well that is:                this volume of gas production:
------------------------------------------------------------------------
(1) An original well with a          15 BCF.
 perforated 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 sidetrack
 interval the top of which is from    measured depth (rounded to the
 15,000 to less than 18,000 feet      nearest 100 feet) but no more than
 TVD SS,                              15 BCF.
(3) An original well with a          25 BCF.
 perforated 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 sidetrack
 interval the top of which is at      measured depth (rounded to the
 least 18,000 feet TVD SS,            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 is . .        Then you earn an RSV on this amount of gas production:
                      .
----------------------------------------------------------------------------------------------------------------
(1) An original well or a sidetrack with a     0 BCF.
 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 interval     4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
 the top of which is 18,000 feet TVD SS or      nearest 100 feet) but no more than 10 BCF.
 deeper,
----------------------------------------------------------------------------------------------------------------

    (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 depth equals 
15.7 BCF because paragraph

[[Page 22]]

(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.

[73 FR 69510, Nov. 18, 2008]



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

[73 FR 69512, Nov. 18, 2008]



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 Sec. 216.53, 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 
an MMS-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 an MMS-approved unit. Under the unit

[[Page 24]]

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 in Sec. 203.48, you must apply the RSV prescribed under 
Sec. 203.41 as required under the following paragraphs (c)(1) through 
(c)(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 an MMS-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.

[73 FR 69512, Nov. 18, 2008]



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

    (a) You must notify the MMS 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:

[[Page 25]]

    (1) Provide written notification to the MMS Regional Supervisor for 
Production and Development that production has begun; and
    (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 MMS 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 MMS 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 MMS deems were 
unavoidable.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 73 FR 69512, 69513, Nov. 18, 2008]



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. 
204.46.

----------------------------------------------------------------------------------------------------------------
  If you have a certified unsuccessful well        Then your lease earns an RSS on this volume of oil and gas
                   that is:                       production as prescribed in this section and Sec.  203.46:
----------------------------------------------------------------------------------------------------------------
(1) An original well and your lease has not    5 BCFE.
 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 sidetrack measured depth (rounded to
 depth of at least 10,000 feet) and your        the nearest 100 feet) but no more than 5 BCFE.
 lease has not produced gas or oil from a
 deep well or an ultra-deep well,
(3) An original well or a sidetrack (with a    2 BCFE.
 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 Sec. 216.53.
    (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

[[Page 26]]

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 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, MMS 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.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 
FR 25198, May 4, 2007; 73 FR 15890, Mar. 26, 2008. Redesignated and 
amended at 73 FR 69512, 69513, Nov. 18, 2008; 74 FR 46907, Sept. 14, 
2009]



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. 204.47(b),
    (2) From, or allocated under an MMS-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

[[Page 27]]

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 an MMS-approved unit 
agreement to, your lease.
    (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 an MMS-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to an MMS-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 an MMS-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.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69514, Nov. 18, 2008]



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 
MMS 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 MMS Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows MMS 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 250, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 250, subpart A; 
and
    (2) Information that allows MMS 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.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 69512, 69514, Nov. 18, 2008]



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.

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

[[Page 28]]

 
(3) Entirely more than 200 meters and  on any date,                                $4.55 per MMBtu, adjusted
 entirely less than 400 meters deep,                                                annually after calendar year
                                                                                    2007 for inflation 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 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 Sec. 218.54 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.

[73 FR 69514, Nov. 18, 2008]



Sec. 203.49  May I substitute the deep gas drilling provisions in 

Sec. 203.0 and Sec. Sec. 203.40 through 203.47 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 MMS 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.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69515, Nov. 18, 2008]

                  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.

[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]



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 MMS Regional Director. Your MMS regional office will provide 
specific guidance on the report formats. A

[[Page 29]]

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 MMS grant?

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

[[Page 30]]

  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).

[73 FR 69515, Nov. 18, 2008]



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 250, 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 MMS 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.
    (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 
MMS 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 MMS 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.

[73 FR 69515, Nov. 18, 2008]



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

[[Page 31]]

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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



Sec. 203.65  How long will MMS 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 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--
------------------------------------------------------------------------
We need more records to audit sunk   Ask to extend the 120-day or 180-
 costs.                               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.
We cannot evaluate your application  Add another 30 days. We may add
 for a valid reason, such as          more than 30 days, but only if you
 missing vital information or         agree.
 inconsistent or inconclusive
 supporting data.
We need more data, explanations, or  Ask to extend the 120-day or 180-
 revision.                            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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



Sec. 203.66  What happens if MMS 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
 If you apply for royalty relief   decide within the    As long as you
               for                  time specified
------------------------------------------------------------------------
(a) An authorized field.........  You get the         Abide by Sec.
                                   minimum             Sec.  203.70 and
                                   suspension          203.76.
                                   volumes specified
                                   in Sec.  203.69.
(b) An expansion project........  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   the first year of   203.76.
                                   production.

[[Page 32]]

 
(c) A development project.......  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   initial             203.76.
                                   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.
------------------------------------------------------------------------


[67 FR 1875, Jan. 15, 2002]



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.

[67 FR 1876, Jan. 15, 2002]



Sec. 203.68  What pre-application costs will MMS 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   Whether a development project
 discovery well on each lease.            or an expansion project needs
                                          relief to become economic.
------------------------------------------------------------------------


[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]



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

[[Page 33]]

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

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008; 73 FR 69515, Nov. 18, 2008]



Sec. 203.70  What information must I provide after MMS 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 MMS Regional Office for your region will prescribe the 
formats.

------------------------------------------------------------------------
                                                           Due date
         Required report            When due to MMS       extensions
------------------------------------------------------------------------
(a) Fabricator's confirmation     Within 18 months    MMS Director may
 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     justification
                                   of production       from you, the MMS
                                   that is subject     Regional Director
                                   to the approved     for your region
                                   royalty             may extend the
                                   suspension volume.  due date up to 30
                                                       days.
------------------------------------------------------------------------


[67 FR 1876, Jan. 15, 2002, as amended at 73 FR 69515, Nov. 18, 2008]

[[Page 34]]



Sec. 203.71  How does MMS 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 lease   We will not change  Production from
 to your authorized field after    your authorized     the assigned
 we approve relief.                field's royalty     eligible lease(s)
                                   suspension volume   counts toward the
                                   determined under    royalty
                                   Sec.  203.69.      suspension volume
                                                       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 Sec.
                                                       260.114 of this
                                                       chapter.
(2) We assign a pre-Act or post-  We will not change  The assigned
 November 2000 deep water lease    your field's        lease(s) may
 to your field after we approve    royalty             share in any
 your application.                 suspension volume.  remaining royalty
                                                       relief by 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 that  In our evaluation   (i) You toll the
 you operate to your field while   of your             time period for
 we are evaluating your            authorized field,   evaluation until
 application.                      we will take into   you modify your
                                   account the value   application to be
                                   of any royalty      consistent with
                                   relief the added    the newly
                                   lease already has   constituted
                                   under Sec.         field;
                                   260.114 or its     (ii) We have an
                                   lease document.     additional 60
                                   If we find your     days to review
                                   authorized field    the new
                                   still needs         information; and
                                   additional         (iii) The assigned
                                   royalty             pre-Act lease or
                                   suspension          royalty
                                   volume, that        suspension lease
                                   volume will be at   shares the
                                   least the           royalty
                                   combined royalty    suspension we
                                   suspension volume   grant to the
                                   to which all        newly constituted
                                   added leases on     field. An
                                   the field are       eligible lease
                                   entitled, or the    does not share
                                   minimum             the royalty
                                   suspension volume   suspension we
                                   of the authorized   grant to the new
                                   field, whichever    field. If you do
                                   is greater.         not agree to
                                                       toll, we will
                                                       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 Sec.
                                                       260.114 of this
                                                       chapter.
(4) We assign another operator's  We will change      (i) You both toll
 lease to your field while we      your field's        the time period
 are evaluating your application.  minimum             for evaluation
                                   suspension volume   until both of you
                                   provided the        modify your
                                   assigned lease      application to be
                                   joins the           consistent with
                                   application and     the new field;
                                   is entitled to a   (ii) We have an
                                   larger minimum      additional 60
                                   suspension volume.  days 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.

[[Page 35]]

 
(5) We reassign a well on a pre-  The past            For any field
 Act, eligible, or royalty         production from     based relief, the
 suspension lease from field A     the well counts     past production
 to field B.                       toward the          for that well
                                   royalty             will not count
                                   suspension volume   toward any
                                   that we grant       royalty
                                   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
                                                       Sec.  260.114 if
                                                       the well is on an
                                                       eligible lease or
                                                       under Sec.
                                                       260.124 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008]



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 MMS 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
    (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.

[[Page 36]]

    (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.

[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67 
FR 1878, Jan. 15, 2002]



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 MMS 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 within18 months of the date we approved your 
application, unless the MMS 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 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

[[Page 37]]

granting royalty relief under this section. You must pay royalties and 
late-payment interest determined under 30 U.S.C. 1721 and Sec. 218.54 
of this chapter on all volumes for which you used the royalty 
suspension. You also may be subject to penalties under other provisions 
of law.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]



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 MMS Regional office for your region.

[73 FR 69516, Nov. 18, 2008]



Sec. 203.78  Do I keep relief approved by MMS under 

Sec. Sec. 203.60-203.77 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 MMS 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.

----------------------------------------------------------------------------------------------------------------
                  For . . .                                    The base price threshold is . . .
----------------------------------------------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,                 set by statute.
(2) Post-November 2000 deep water leases in    indicated in your original lease agreement or, if none, those in
 the GOM or leases offshore of Alaska for       the Notice of Sale under which your lease was issued.
 which the lease or Notice of Sale set a base
 price threshold,
(3) Post-November 2000 deep water leases in    the threshold set by statute for pre-Act leases.
 the GOM or leases offshore of Alaska 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) 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 
Sec. 218.54 of this chapter) 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 
Sec. 218.54 of this chapter) 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):
    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less,

[[Page 38]]

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 part 230 of this chapter 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.

[73 FR 69516, Nov. 18, 2008]



Sec. 203.79  How do I appeal MMS'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 MMS Director a letter within 15 
days that also states your reasons. The MMS 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 MMS Director and stating your reasons. The MMS 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 means 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.

[67 FR 1879, Jan. 15, 2002, as amended at 73 FR 69516, Nov. 18, 2008]

[[Page 39]]

                            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-  ------------------------------------------
                     Required reports                          life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.....................         X               X          X               X
(2) Net revenue & relief justification report.............         X
(3) Economic viability & relief justification report (RSVP  .........              X          X               X
 model imputs 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 MMS 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002; 73 
FR 69516, Nov. 18, 2008]



Sec. 203.82  What is MMS'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(b) and part 250 of this chapter.

[[Page 40]]

    (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.
    (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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000; 74 
FR 46907, Sept. 14, 2009]



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 we 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).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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, MMS. 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 220.013 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.

[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]

[[Page 41]]



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, MMS. Clearly justify each parameter you set 
in every scenario you 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 MMS 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;

[[Page 42]]

    (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;
    (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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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

[[Page 43]]

    (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 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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;

[[Page 44]]

    (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 existed on the application submission date).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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 MMS 
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.

[63 FR 2618, Jan. 16, 1998, as amended at 73 FR 69516, Nov. 18, 2008]



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).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]

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]



PART 219_DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES--Table of Contents



Subpart A--General Provision [Reserved]

Subpart B--Oil and Gas, General [Reserved]

Subpart C [Reserved]

                     Subpart D_Oil and Gas, Offshore

Sec.
219.410 What does this subpart contain?
219.411 What definitions apply to this subpart?
219.412 How will the qualified OCS revenues be divided?
219.413 How will the coastal political subdivisions of Gulf producing 
          States share in the qualified OCS revenues?
219.414 How will MMS determine each Gulf producing State's share of the 
          qualified OCS revenues?
219.415 How will bonus and royalty credits affect revenues allocated to 
          Gulf producing States?
219.416 How will the qualified OCS revenues be allocated to coastal 
          political subdivisions within the Gulf producing States?
219.417 How will MMS disburse qualified OCS revenues to the coastal 
          political subdivisions if, during any fiscal year, there are 
          no applicable leased tracts in

[[Page 45]]

          the 181 Area in the Eastern Gulf of Mexico Planning Area?
219.418 When will funds be disbursed to Gulf producing States and 
          eligible coastal political subdivisions?

    Authority: Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.

    Source: 49 FR 37347, Sept. 21, 1984, unless otherwise noted.

Subpart A--General Provisions [Reserved]

Subpart B--Oil and Gas, General [Reserved]

Subpart C [Reserved]



                     Subpart D_Oil and Gas, Offshore

    Source: 73 FR 78629, Dec. 23, 2008, unless otherwise noted.



Sec. 219.410  What does this subpart contain?

    (a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs 
the Secretary of the Interior to disburse a portion of the rentals, 
royalties, bonus, and other sums derived from certain Outer Continental 
Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama, 
Louisiana, Mississippi, and Texas (collectively identified as the Gulf 
producing States); to eligible coastal political subdivisions within 
those States; and to the Land and Water Conservation Fund. Shared GOMESA 
revenues are reserved for the following purposes:
    (1) Projects and activities for the purposes of coastal protection, 
including conservation, coastal restoration, hurricane protection, and 
infrastructure directly affected by coastal wetland losses.
    (2) Mitigation of damage to fish, wildlife, or natural resources.
    (3) Implementation of a federally-approved marine, coastal, or 
comprehensive conservation management plan.
    (4) Mitigation of the impact of OCS activities through the funding 
of onshore infrastructure projects.
    (5) Planning assistance and administrative costs not-to-exceed 3 
percent of the amounts received.
    (b) This subpart sets forth the formula and methodology MMS will use 
to determine the amount of revenues to be disbursed and the amount to be 
allocated to each Gulf producing State and each eligible coastal 
political subdivision. For questions related to the revenue sharing 
provisions in this subpart, please contact: Chief, Financial Management, 
Minerals Revenue Management; P.O. Box 25165; Denver Federal Center, 
Building 85; MS-350B1; Denver, CO 80225-0165, or at (303) 231-3429.



Sec. 219.411  What definitions apply to this subpart?

    Terms in this subpart have the following meaning:
    181 Area means the area identified in map 15, page 58, of the 
Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 
1997-2002, dated August 1996, of the Minerals Management Service, 
available in the Office of the Director of the Minerals Management 
Service, excluding the area offered in OCS Lease Sale 181, held on 
December 5, 2001.
    181 Area in the Eastern Planning Area is comprised of the area of 
overlap of the two geographic areas defined as the ``181 Area'' and the 
``Eastern Planning Area.''
    181 South Area means any area--
    (1) Located--
    (i) South of the 181 Area;
    (ii) West of the Military Mission Line; and
    (iii) In the Central Planning Area;
    (2) Excluded from the Proposed Final Outer Continental Shelf Oil and 
Gas Leasing Program for 1997-2002, dated August 1996, of the Minerals 
Management Service; and
    (3) Included in the areas considered for oil and gas leasing, as 
identified in map 8, page 37, of the document entitled, Draft Proposed 
Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012, 
dated February 2006.
    Applicable leased tract means a tract that is subject to a lease 
under section 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources, 
and is located fully or partially in either the 181 Area in the

[[Page 46]]

Eastern Planning Area, or in the 181 South Area.
    Central Planning Area means the Central Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Coastal political subdivision means a political subdivision of a 
Gulf producing State any part of which political subdivision is--
    (1) Within the coastal zone (as defined in section 304 of the 
Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf 
producing State as of December 20, 2006; and
    (2) Not more than 200 nautical miles from the geographic center of 
any leased tract.
    Coastline 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. This is the same definition 
used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).
    Distance means the minimum great circle distance.
    Eastern Planning Area means the Eastern Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Gulf producing State means each of the States of Alabama, Louisiana, 
Mississippi, and Texas.
    Leased tract means any tract that is subject to a lease under 
section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources.
    Military Mission Line means the north-south line at 86[deg]41[min] 
W. longitude.
    Qualified OCS revenues mean--
    (1) The term qualified OCS revenues means, in the case of each of 
fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and 
other sums received by the U.S. from leases entered into on or after 
December 20, 2006, located:
    (i) In the 181 Area in the Eastern Planning Area; and
    (ii) In the 181 South Area.
    (iii) For applicable leased tracts intersected by the planning area 
administrative boundary line (e.g., separating the GOM Central Planning 
Area from the Eastern Planning Area), only the percent of revenues 
equivalent to the percent of surface acreage in the 181 Area in the 
Eastern Planning Area will be considered qualified OCS revenues.
    (2) Exclusions to the term qualified OCS revenues include:
    (i) Revenues from the forfeiture of a bond or other surety securing 
obligations other than royalties;
    (ii) Civil penalties;
    (iii) Royalties taken by the Secretary in-kind and not sold;
    (iv) User fees; and
    (v) Lease revenues explicitly circumscribed from GOMESA revenue 
sharing by statute or appropriations law.



Sec. 219.412  How will the qualified OCS revenues be divided?

    For each of the fiscal years 2007 through 2016, 50 percent of the 
qualified OCS revenues will be placed in a special U.S. Treasury account 
from which 75 percent of the revenues will be disbursed to the Gulf 
producing States, and 25 percent will be disbursed to the Land and Water 
Conservation Fund. Each Gulf producing State will receive at least 10 
percent of the qualified OCS revenues available for allocation to the 
Gulf producing States each fiscal year.

       Revenue Distribution of Qualified OCS Revenues Under GOMESA
------------------------------------------------------------------------
                                                         Percentage of
                                                         qualified OCS
         Recipient of qualified OCS revenues                revenues
                                                           (percent)
------------------------------------------------------------------------
U.S. Treasury (General Fund).........................               50
Land and Water Conservation Fund.....................               12.5
Gulf Producing States................................               30
Gulf Producing State Coastal Political Subdivisions..                7.5
------------------------------------------------------------------------



Sec. 219.413  How will the coastal political subdivisions of Gulf

producing States share in the qualified OCS revenues?

    Of the revenues allocated to a Gulf producing State, 20 percent will 
be distributed to the coastal political subdivisions within that State.

[[Page 47]]



Sec. 219.414  How will MMS determine each Gulf producing State's share of the qualified OCS revenues?

    (a) The MMS will determine the geographic centers of each applicable 
leased tract and, using the great circle distance method, will determine 
the closest distance from the geographic centers of each applicable 
leased tract to each Gulf producing State's coastline.
    (b) Based on these distances, we will calculate the qualified OCS 
revenues to be disbursed to each Gulf producing State using the 
following procedure:
    (1) For each Gulf producing State, we will calculate and total, over 
all applicable leased tracts, the mathematical inverses of the distances 
between the points on the State's coastline that are closest to the 
geographic centers of the applicable leased tracts and the geographic 
centers of the applicable leased tracts. For applicable leased tracts 
intersected by the planning area administrative boundary line, the 
geographic center used for the inverse distance determination will be 
the geographic center of the entire lease as if it were not intersected.
    (2) For each Gulf producing State, we will divide the sum of each 
State's inverse distances, from all applicable leased tracts, by the sum 
of the inverse distances from all applicable leased tracts across all 
four Gulf producing States. We will multiply the result by the amount of 
qualified OCS revenues to be shared as shown below. In the formulas, 
IAL, ILA, IMS, and ITX represent the sum of the inverses of the closest 
distances between Alabama, Louisiana, Mississippi, and Texas and all 
applicable leased tracts, respectively.

Alabama Share = (IAL / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues
Louisiana Share = (ILA / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Mississippi Share = (IMS / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Texas Share = (ITX / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues

    (3) If in any fiscal year, this calculation results in less than a 
10 percent allocation of the qualified OCS revenues to any Gulf 
producing State, we will recalculate the distribution. We will allocate 
10 percent of the qualified OCS revenues to the State and recalculate 
the other States' shares of the remaining qualified OCS revenues 
omitting the State receiving the 10 percent minimum share and its 10 
percent share from the calculation.



Sec. 219.415  How will bonus and royalty credits affect revenues allocated 

to Gulf producing States?

    If bonus and royalty credits issued under Section 104(c) of the Gulf 
of Mexico Energy Security Act are used to pay bonuses or royalties on 
leases in the 181 Area located in the Eastern Planning Area and the 181 
South Area, then there will be a corresponding reduction in qualified 
OCS revenues available for distribution.



Sec. 219.416  How will the qualified OCS revenues be 

allocated to coastal political subdivisions within the Gulf producing States?

    The MMS will disburse funds to the coastal political subdivisions in 
accordance with the following criteria:
    (a) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's population 
bears to the population of all coastal political subdivisions in the 
producing State;
    (b) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's miles of 
coastline bears to the number of miles of coastline of all coastal 
political subdivisions in the producing State. Except that, for the 
State of Louisiana, proxy coastline lengths for coastal political 
subdivisions without a coastline will be considered to be \1/3\ the 
average length of the coastline of all political subdivisions within 
Louisiana having a coastline.
    (c) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in amounts that are 
inversely proportional to the respective distances between the 
geographic center of each applicable leased tract and the point in each 
coastal political subdivision that is closest to the geographic center 
of each applicable leased tract. Except that, an applicable leased tract 
will be

[[Page 48]]

excluded from this calculation if any portion of the tract is located in 
a geographic area that was subject to a leasing moratorium on January 1, 
2005, unless that tract was in production on that date.



Sec. 219.417  How will MMS disburse qualified OCS revenues to the coastal 

political subdivisions if, during any fiscal year, there are no applicable leased 
          tracts in the 181 Area in the Eastern Gulf of Mexico Planning 
          Area?

    If, during any fiscal year, there are no applicable leased tracts in 
the 181 Area in the Eastern Gulf of Mexico Planning Area, MMS will 
disburse funds to the coastal political subdivisions in accordance with 
the following criteria:
    (a) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's population bears to the population 
of all coastal political subdivisions in the State; and
    (b) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's miles of coastline bears to the 
number of miles of coastline of all coastal political subdivisions in 
the State. Except that, for the State of Louisiana, proxy coastline 
lengths for coastal political subdivisions without a coastline will be 
considered to be \1/3\ the average length of the coastline of all 
political subdivisions within Louisiana having a coastline.



Sec. 219.418  When will funds be disbursed to Gulf producing States and 

eligible coastal political subdivisions?

    (a) The MMS will disburse allocated funds in the fiscal year after 
MMS collects the qualified OCS revenues. For example, MMS will disburse 
funds in fiscal year 2010 from the qualified OCS revenues collected 
during fiscal year 2009.
    (b) We intend to disburse funds on or before March 31st of the year 
following the fiscal year of qualified OCS revenues.

[[Page 49]]



                          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 MMS 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 and operate electrical equipment?
250.115 How do I determine well producibility?
250.116 How do I determine producibility if my well is in the Gulf of 
          Mexico?
250.117 How does a determination of well producibility affect royalty 
          status?
250.118 Will MMS approve gas injection?
250.119 Will MMS approve subsurface gas storage?
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 Will MMS allow gas storage on unleased lands?
250.124 Will MMS 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 MMS conduct inspections?
250.131 Will MMS notify me before conducting an inspection?
250.132 What must I do when MMS conducts an inspection?
250.133 Will MMS reimburse me for my expenses related to inspections?

                            Disqualification

250.135 What will MMS do if my operating performance is unacceptable?
250.136 How will MMS 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 How do I designate an operator?
250.144 How do I designate a new operator when a designation of operator 
          terminates?
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?

                        Right-of-Use and Easement

250.160 When will MMS grant me a right-of-use and easement, and what 
          requirements must I meet?
250.161 What else must I submit with my application?
250.162 May I continue my right-of-use and easement after the 
          termination of any lease on which it is situated?
250.163 If I have a State lease, will MMS grant me a right-of-use and 
          easement?
250.164 If I have a State lease, what conditions apply for a right-of-
          use and easement?
250.165 If I have a State lease, what fees do I have to pay for a right-
          of-use and easement?

[[Page 50]]

250.166 If I have a State lease, what surety bond must I have for a 
          right-of-use and easement?

                               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?

      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 When may the Secretary cancel my lease and when am I compensated 
          for cancellation?
250.182 When may the Secretary cancel a lease at the exploration stage?
250.183 When may MMS or the Secretary extend or cancel a lease at the 
          development and production stage?
250.184 What is the amount of compensation for lease cancellation?
250.185 When is there no compensation for a lease cancellation?

                 Information and Reporting Requirements

250.186 What reporting information and report forms must I submit?
250.187 What are MMS' incident reporting requirements?
250.188 What incidents must I report to MMS 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 MMS 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 apparent violations.
250.194 How must I protect archaeological resources?
250.195 What notification does MMS 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 What criteria must the Exploration Plan (EP), Development and 
          Production Plan (DPP), or Development Operations Coordination 
          Document (DOCD) meet?
250.203 Where can wells be located under an EP, DPP, or DOCD?
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?
250.206 How do I submit the EP, DPP, or DOCD?

                          Ancillary Activities

250.207 What ancillary activities may I conduct?
250.208 If I conduct ancillary activities, what notices must I provide?
250.209 What is the MMS review process for the notice?
250.210 If I conduct ancillary activities, what reporting and data/
          information retention requirements must I satisfy?

                   Contents of Exploration Plans (EP)

250.211 What must the EP include?
250.212 What information must accompany the EP?
250.213 What general information must accompany the EP?
250.214 What geological and geophysical (G&G) information must accompany 
          the EP?
250.215 What hydrogen sulfide (H2S) information must 
          accompany the EP?
250.216 What biological, physical, and socioeconomic information must 
          accompany the EP?
250.217 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the EP?
250.218 What air emissions information must accompany the EP?
250.219 What oil and hazardous substance spills information must 
          accompany the EP?

[[Page 51]]

250.220 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the EP?
250.221 What environmental monitoring information must accompany the EP?
250.222 What lease stipulations information must accompany the EP?
250.223 What mitigation measures information must accompany the EP?
250.224 What information on support vessels, offshore vehicles, and 
          aircraft you will use must accompany the EP?
250.225 What information on the onshore support facilities you will use 
          must accompany the EP?
250.226 What Coastal Zone Management Act (CZMA) information must 
          accompany the EP?
250.227 What environmental impact analysis (EIA) information must 
          accompany the EP?
250.228 What administrative information must accompany the EP?

                 Review and Decision Process for the EP

250.231 After receiving the EP, what will MMS do?
250.232 What actions will MMS take after the EP is deemed submitted?
250.233 What decisions will MMS make on the EP and within what 
          timeframe?
250.234 How do I submit a modified EP or resubmit a disapproved EP, and 
          when will MMS make a decision?
250.235 If a State objects to the EP's coastal zone consistency 
          certification, what can I do?

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)

250.241 What must the DPP or DOCD include?
250.242 What information must accompany the DPP or DOCD?
250.243 What general information must accompany the DPP or DOCD?
250.244 What geological and geophysical (G&G) information must accompany 
          the DPP or DOCD?
250.245 What hydrogen sulfide (H2S) information must 
          accompany the DPP or DOCD?
250.246 What mineral resource conservation information must accompany 
          the DPP or DOCD?
250.247 What biological, physical, and socioeconomic information must 
          accompany the DPP or DOCD?
250.248 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the DPP or 
          DOCD?
250.249 What air emissions information must accompany the DPP or DOCD?
250.250 What oil and hazardous substance spills information must 
          accompany the DPP or DOCD?
250.251 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the DPP?
250.252 What environmental monitoring information must accompany the DPP 
          or DOCD?
250.253 What lease stipulations information must accompany the DPP or 
          DOCD?
250.254 What mitigation measures information must accompany the DPP or 
          DOCD?
250.255 What decommissioning information must accompany the DPP or DOCD?
250.256 What related facilities and operations information must 
          accompany the DPP or DOCD?
250.257 What information on the support vessels, offshore vehicles, and 
          aircraft you will use must accompany the DPP or DOCD?
250.258 What information on the onshore support facilities you will use 
          must accompany the DPP or DOCD?
250.259 What sulphur operations information must accompany the DPP or 
          DOCD?
250.260 What Coastal Zone Management Act (CZMA) information must 
          accompany the DPP or DOCD?
250.261 What environmental impact analysis (EIA) information must 
          accompany the DPP or DOCD?
250.262 What administrative information must accompany the DPP or DOCD?

             Review and Decision Process for the DPP or DOCD

250.266 After receiving the DPP or DOCD, what will MMS do?
250.267 What actions will MMS take after the DPP or DOCD is deemed 
          submitted?
250.268 How does MMS respond to recommendations?
250.269 How will MMS evaluate the environmental impacts of the DPP or 
          DOCD?
250.270 What decisions will MMS make on the DPP or DOCD and within what 
          timeframe?
250.271 For what reasons will MMS disapprove the DPP or DOCD?
250.272 If a State objects to the DPP's or DOCD's coastal zone 
          consistency certification, what can I do?
250.273 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

250.280 How must I conduct activities under the approved EP, DPP, or 
          DOCD?
250.281 What must I do to conduct activities under the approved EP, DPP, 
          or DOCD?
250.282 Do I have to conduct post-approval monitoring?

[[Page 52]]

250.283 When must I revise or supplement the approved EP, DPP, or DOCD?
250.284 How will MMS require revisions to the approved EP, DPP, or DOCD?
250.285 How do I submit revised and supplemental EPs, DPPs, or DOCDs?

                    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?

                Conservation Information Documents (CID)

250.296 When and how must I submit a CID or a revision to a CID?
250.297 What information must a CID contain?
250.298 How long will MMS take to evaluate and make a decision on the 
          CID?
250.299 What operations require approval of the CID?

               Subpart C_Pollution Prevention and Control

250.300 Pollution prevention.
250.301 Inspection of facilities.
250.302 Definitions concerning air quality.
250.303 Facilities described in a new or revised Exploration Plan or 
          Development and Production Plan.
250.304 Existing facilities.

                Subpart D_Oil and Gas Drilling Operations

                          General Requirements

250.400 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
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 What additional safety measures must I take when I conduct 
          drilling operations on a platform that has producing wells or 
          has other hydrocarbon flow?
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 and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore drilling 
          unit (MODU)?
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 pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner 
          pressure tests?
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?

               Blowout Preventer (BOP) System Requirements

250.440 What are the general requirements for BOP systems and system 
          components?

[[Page 53]]

250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP system?
250.443 What associated systems and related equipment must all BOP 
          systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and 
          drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment or 
          systems?

                       Drilling Fluid Requirements

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 (AMP) or 
          an End of Operations Report to MMS?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?

                            Hydrogen Sulfide

250.490 Hydrogen sulfide.

            Subpart E_Oil and Gas Well-Completion Operations

250.500 General requirements.
250.501 Definition.
250.502 Equipment movement.
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506 Crew instructions.
250.507-250.508 [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 Blowout prevention equipment.
250.516 Blowout preventer system tests, inspections, and maintenance.
250.517 Tubing and wellhead equipment.

                       Casing Pressure Management

250.518 What are the requirements for casing pressure management?
250.519 How often do I have to monitor for casing pressure?
250.520 When do I have to perform a casing diagnostic test?
250.521 How do I manage the thermal effects caused by initial production 
          on a newly completed or recompleted well?
250.522 When do I have to repeat casing diagnostic testing?
250.523 How long do I keep records of casing pressure and diagnostic 
          tests?
250.524 When am I required to take action from my casing diagnostic 
          test?
250.525 What do I submit if my casing diagnostic test requires action?
250.526 What must I include in my notification of corrective action?
250.527 What must I include in my casing pressure request?
250.528 What are the terms of my casing pressure request?
250.529 What if my casing pressure request is denied?
250.530 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 Equipment movement.
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606 Crew instructions.
250.607-250.608 [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.
250.613 Approval and reporting for well-workover operations.

[[Page 54]]

250.614 Well-control fluids, equipment, and operations.
250.615 Blowout prevention equipment.
250.616 Blowout preventer system testing, records, and drills.
250.617 What are my BOP inspection and maintenance requirements?
250.618 Tubing and wellhead equipment.
250.619 Wireline operations.

Subpart G [Reserved]

             Subpart H_Oil and Gas Production Safety Systems

250.800 General requirements.
250.801 Subsurface safety devices.
250.802 Design, installation, and operation of surface production-safety 
          systems.
250.803 Additional production system requirements.
250.804 Production safety-system testing and records.
250.805 Safety device training.
250.806 Safety and pollution prevention equipment quality assurance 
          requirements.
250.807 Additional requirements for subsurface safety valves and related 
          equipment installed in high pressure high temperature (HPHT) 
          environments.
250.808 Hydrogen sulfide.

                   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?
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 MMS 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 Abandonment and out-of-service requirements for DOI pipelines.
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 Bond requirements for pipeline right-of-way holders.
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.

[[Page 55]]

              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 When must I conduct a static bottomhole pressure survey?

                         Classifying Reservoirs

250.1154 How do I determine if my reservoir is sensitive?
250.1155 What information must I submit for sensitive reservoirs?

                      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?

               Flaring, 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?
250.1303 How do I apply for voluntary unitization?
250.1304 How will MMS require unitization?

            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties

250.1400 How does MMS begin the civil penalty process?
250.1401 Index table.
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will MMS review for potential civil penalties?
250.1405 When is a case file developed?
250.1406 When will MMS 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 the Bureau of Ocean Energy Management, Regulation, and 
          Enforcement (BOEMRE) 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 BOEMRE inform me of violations without a period to 
          correct?

[[Page 56]]

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 BOEMRE 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 BOEMRE reduce my penalty once it is assessed?
250.1477 How may BOEMRE collect the penalty?

                           Criminal Penalties

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

                          Bonding Requirements

250.1490 What standards must my BOEMRE-specified surety instrument meet?
250.1491 How will BOEMRE determine the amount of my bond or other surety 
          instrument?

                     Financial Solvency Requirements

250.1495 How do I demonstrate financial solvency?
250.1496 How will BOEMRE determine if I am financially solvent?
250.1497 When will BOEMRE monitor my financial solvency?

          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 MMS measure training results?
250.1508 What must I do when MMS administers written or oral tests?
250.1509 What must I do when MMS administers or requires hands-on, 
          simulator, or other types of testing?
250.1510 What will MMS 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.
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?

[[Page 57]]

250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 When must I submit decommissioning applications and reports?

                       Permanently Plugging Wells

250.1710 When must I permanently plug all wells on a lease?
250.1711 When will MMS 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 MMS 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 After I permanently plug a well, what information must I 
          submit?

                        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 MMS 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 Definitions.
250.1904 Documents incorporated by reference
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 criteria for hazards analyses 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 criteria for training 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?
250.1921-250.1923 [Reserved]
250.1924 How will BOEMRE determine if my SEMS program is effective?
250.1925 May BOEMRE direct me to conduct additional audits?
250.1926 What qualifications must an independent third party or my 
          designated and qualified personnel meet?
250.1927 What happens if BOEMRE 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?


[[Page 58]]


    Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.

    Source: 53 FR 10690, Apr. 1, 1988, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.

    Editorial Note: Nomenclature changes to part 250 appear at 71 FR 
46399 and 46400, Aug. 14, 2006.



                            Subpart A_General

    Source: 64 FR 72775, Dec. 28, 1999, unless otherwise noted.

                    Authority and Definition of Terms



Sec. 250.101  Authority and applicability.

    The Secretary of the Interior (Secretary) authorized the Minerals 
Management Service (MMS) 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, MMS 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) 30 CFR part 250 contains the regulations of the MMS 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 MMS 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
------------------------------------------------------------------------
                                                Refer to  30 CFR 250
           For information about                     subpart or
------------------------------------------------------------------------
(1) Applications for permit to drill......  D.
(2) Development and Production Plans (DPP)  B.
(3) Downhole commingling..................  K.
(4) Exploration Plans (EP)................  B.
(5) Flaring...............................  K.
(6) Gas measurement.......................  L.
(7) Off-lease geological and geophysical    30 CFR 251.
 permits.
(8) Oil spill financial responsibility      30 CFR 253.
 coverage.
(9) Oil and gas production safety systems.  H.
(10) Oil spill response plans.............  30 CFR 254.
(11) Oil and gas well-completion            E.
 operations.
(12) Oil and gas well-workover operations.  F.
(13) Decommissioning Activities...........  Q.
(14) Platforms and structures.............  I.
(15) Pipelines and Pipeline Rights-of-Way.  J.
(16) Sulphur operations...................  P.
(17) Training.............................  O.
(18) Unitization..........................  M.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 70 FR 51500, Aug. 30, 2005; 72 FR 25198, May 4, 
2007]



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

    MMS 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 MMS.



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

    To appeal orders or decisions issued under MMS 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

[[Page 59]]

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, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Ancillary activities means 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 MMS 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.
    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.

[[Page 60]]

    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 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 means approvals granted by the appropriate MMS 
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 MMS of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the MMS officer with authority and 
responsibility for operations or other designated program functions for 
a district within an MMS 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 
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 means 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 means 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. 250.303, 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

[[Page 61]]

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 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 Sec. 250.303, 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.
    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:

[[Page 62]]

    (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 means 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 MMS-approved assignee of the lease, and 
the owner or the MMS-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 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 includes 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 includes, 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.

[[Page 63]]

    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 means 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 MMS-approved designated agent of the 
lessee(s), or the holder of operating rights under an MMS-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 means 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 MMS officer with responsibility and 
authority for a Region within MMS.
    Regional Supervisor means the MMS officer with responsibility and 
authority for operations or other designated program functions within an 
MMS 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).

[[Page 64]]

    Routine operations, for the purposes of subpart F, means 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.
    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 means 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 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 means 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.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 8422, Feb. 20, 2003; 70 
FR 41573, July 19, 2005; 70 FR 51500, Aug. 30, 2005; 71 FR 23862, Apr. 
25, 2006; 75 FR 20288, Apr. 19, 2010]

                          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.

[[Page 65]]



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; and
    (2) Maintaining all equipment and work areas in a safe condition.
    (b) You must immediately control, remove, or otherwise correct any 
hazardous oil and gas accumulation or other health, safety, or fire 
hazard.
    (c) You must use the best available and safest technology (BAST) 
whenever practical on all exploration, development, and production 
operations. In general, we consider your compliance with MMS regulations 
to be the use of BAST.
    (d) The Director may require additional measures to ensure the use 
of BAST:
    (1) To avoid the failure of equipment that would have a significant 
effect on safety, health, or the environment;
    (2) If it is economically feasible; and
    (3) If the benefits outweigh the costs.

[64 FR 72775, Dec. 28, 1999, as amended at 73 FR 20171, Apr. 15, 2008]



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), incorporated 
by reference as specified in 30 CFR 250.198.
    (b) All cranes installed on fixed platforms must be equipped with a 
functional anti-two block device.
    (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), incorporated by reference as specified in 30 CFR 250.198.
    (d) All cranes manufactured after March 17, 2003, and installed on a 
fixed platform, must meet the requirements of API Spec 2C, incorporated 
by reference as specified in 30 CFR 250.198.
    (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.

[68 FR 7426, Feb. 14, 2003, as amended at 72 FR 12092, Mar. 15, 2007; 74 
FR 46907, Sept. 14, 2009]



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

[[Page 66]]

    (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.
    (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 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

[[Page 67]]

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.
    (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 (incorporated by 
reference as specified 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 (incorporated by reference as 
specified 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.

[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 219, Jan. 4, 2000; 68 
FR 43298, July 22, 2003]



Sec. 250.115  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. 
250.116 of this subpart.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must either:
    (1) Allow the District Manager to witness each test that you conduct 
under this section; or
    (2) Receive the District Manager's 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. 250.116  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. 250.115 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 
MMS 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.

[[Page 68]]



Sec. 250.117  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 202.53.



Sec. 250.118  Will MMS 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 MMS 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  Will MMS approve subsurface gas storage?

    The Regional Supervisor may authorize subsurface storage of gas on 
the OCS, on and off-lease, for later commercial benefit. To receive MMS 
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. 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 
Sec. 250.119, 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 an MMS-
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.



Sec. 250.123  Will MMS 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. 250.160 through 250.166 of this subpart.



Sec. 250.124  Will MMS 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 MMS 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.

[[Page 69]]



                            Service Fee Table
------------------------------------------------------------------------
  Service--processing of the
          following:                  Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of    $164..................  Sec.
 Operator.                                               250.143(d).
(2) Right-of-Use and Easement   $2,569................  Sec.  250.165.
 for State lessee.
(3) Suspension of Operations/   $1,968................  Sec.
 Suspension of Production (SOO/                          250.171(e).
 SOP) Request.
(4) Exploration Plan (EP).....  $3,442 for each         Sec.
                                 surface location; no    250.211(d).
                                 fee for revisions.
(5) Development and Production  $3,971 for each well    Sec.
 Plan (DPP) or Development       proposed; no fee for    250.241(e).
 Operations Coordination         revisions.
 Document (DOCD).
(6) Deepwater Operations Plan.  $3,336................  Sec.
                                                         250.292(p).
(7) Conservation Information    $25,629...............  Sec.
 Document.                                               250.296(a).
(8) Application for Permit to   $1,959 for initial      Sec.
 Drill (APD; Form MMS-123).      applications only; no   250.410(d);
                                 fee for revisions.      Sec.  250.411;
                                                         Sec.  250.460;
                                                         Sec.
                                                         250.513(b);
                                                         Sec.  250.515;
                                                         Sec.
                                                         250.1605; Sec.
                                                          250.1617(a);
                                                         Sec.
                                                         250.1622.
(9) Application for Permit to   $116..................  Sec.  250.460;
 Modify (APM; Form MMS-124).                             Sec.
                                                         250.465(b);
                                                         Sec.
                                                         250.513(b);
                                                         Sec.  250.515;
                                                         Sec.
                                                         250.613(b);
                                                         Sec.  250.615;
                                                         Sec.
                                                         250.1618(a);
                                                         Sec.
                                                         250.1622; Sec.
                                                          250.1704(g).
(10) New Facility Production    $5,030 A component is   Sec.
 Safety System Application for   a piece of equipment    250.802(e).
 facility with more than 125     or ancillary system
 components.                     that is protected by
                                 one or more of the
                                 safety devices
                                 required by API RP
                                 14C (incorporated by
                                 reference as
                                 specified in Sec.
                                 250.198); $13,238
                                 additional fee will
                                 be charged if MMS
                                 deems it necessary to
                                 visit a facility
                                 offshore, and $6,884
                                 to visit a facility
                                 in a shipyard.
(11) New Facility Production    $1,218 Additional fee   Sec.
 Safety System Application for   of $8,313 will be       250.802(e).
 facility with 25-125            charged if MMS deems
 components.                     it necessary to visit
                                 a facility offshore,
                                 and $4,766 to visit a
                                 facility in a
                                 shipyard.
(12) New Facility Production    $604..................  Sec.
 Safety System Application for                           250.802(e).
 facility with fewer than 25
 components.
(13) Production Safety System   $561..................  Sec.
 Application--Modification                               250.802(e).
 with more than 125 components
 reviewed.
(14) Production Safety System   $201..................  Sec.
 Application--Modification                               250.802(e).
 with 25-125 components
 reviewed.
(15) Production Safety System   $85...................  Sec.
 Application--Modification                               250.802(e).
 with fewer than 25 components
 reviewed.
(16) Platform Application--     $21,075...............  Sec.
 Installation--Under the                                 250.905(k).
 Platform Verification Program.
(17) Platform Application--     $3,018................  Sec.
 Installation--Fixed Structure                           250.905(k).
 Under the Platform Approval
 Program.
(18) Platform Application--     $1,536................  Sec.
 Installation--Caisson/Well                              250.905(k).
 Protector.
(19) Platform Application--     $3,601................  Sec.
 Modification/Repair.                                    250.905(k).
(20) New Pipeline Application   $3,283................  Sec.
 (Lease Term).                                           250.1000(b).
(21) Pipeline Application--     $1,906................  Sec.
 Modification (Lease Term).                              250.1000(b).
(22) Pipeline Application--     $3,865................  Sec.
 Modification (ROW).                                     250.1000(b).
(23) Pipeline Repair            $360..................  Sec.
 Notification.                                           250.1008(e).
(24) Pipeline Right-of-Way      $2,569................  Sec.
 (ROW) Grant Application.                                250.1015(a).
(25) Pipeline Conversion of     $219..................  Sec.
 Lease Term to ROW.                                      250.1015(a).
(26) Pipeline ROW Assignment..  $186..................  Sec.
                                                         250.1018(b).
(27) 500 Feet From Lease/Unit   $3,608................  Sec.
 Line Production Request.                                250.1156(a).
(28) Gas Cap Production         $4,592................  Sec.  250.1157.
 Request.
(29) Downhole Commingling       $5,357................  Sec.
 Request.                                                250.1158(a).
(30) Complex Surface            $3,760................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).

[[Page 70]]

 
(31) Simple Surface             $1,271................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(32) Voluntary Unitization      $11,698...............  Sec.
 Proposal or Unit Expansion.                             250.1303(d).
(33) Unitization Revision.....  $831..................  Sec.
                                                         250.1303(d).
(34) Application to Remove a    $4,342................  Sec.  250.1727.
 Platform or Other Facility.
(35) Application to             $1,059................  Sec.
 Decommission a Pipeline                                 250.1751(a) or
 (Lease Term).                                           Sec.
                                                         250.1752(a).
(36) Application to             $2,012................  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.

[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 
72 FR 25199, May 4, 2007; 73 FR 49946, Aug. 25, 2008; 75 FR 20288, Apr. 
19, 2010]



Sec. 250.126  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 a link on the MMS 
Offshore Web site at: http://www.mms.gov/offshore/ homepage or directly 
through Pay.gov at: https://www.pay.gov/paygov/.
    (a) If you submitted an application through eWell, you must use the 
interactive payment feature in that system, which directs you through 
Pay.gov.
    (b) For applications not submitted electronically through eWell, you 
must use credit card or automated clearing house (ACH) payments through 
the Pay.gov Web site, and you must include a copy of the Pay.gov 
confirmation receipt page with your application.

[73 FR 49947, Aug. 25, 2008]

                        Inspection of Operations



Sec. 250.130  Why does MMS conduct inspections?

    MMS 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 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 MMS notify me before conducting an inspection?

    MMS conducts both scheduled and unscheduled inspections.



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

    (a) When MMS 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

[[Page 71]]

    (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 MMS reimburse me for my expenses related to inspections?

    Upon request, MMS will reimburse you for food, quarters, and 
transportation that you provide for MMS 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 MMS do if my operating performance is unacceptable?

    If your operating performance is unacceptable, MMS 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 MMS officials before imposing a disqualification.



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

    In determining if your operating performance is unacceptable, MMS 
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 MMS 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 orally.............  Give you an oral approval..  You must then confirm the oral request by
                                                                        sending us a written request within 72
                                                                        hours.
(b) Request approval in writing.........  Give you an oral approval    We will send you a written approval
                                           if quick action is needed.   afterward. It will include any
                                                                        conditions that we place on the oral
                                                                        approval.
(c) Request approval orally for gas       Give you an oral approval..  You don't have to follow up with a
 flaring.                                                               written 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 MMS 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 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.

[65 FR 6536, Feb. 10, 2000]

[[Page 72]]



Sec. 250.143  How do I designate an operator?

    (a) You must provide the Regional Supervisor an executed Designation 
of Operator form (Form MMS-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 service fee listed in Sec. 250.125 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 MMS in a single submittal, which is subject 
to only one filing fee.

[64 FR 72775, Dec. 28, 1999, as amended at 70 FR 49876, Aug. 25, 2005; 
72 FR 25200, May 4, 2007]



Sec. 250.144  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. 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, 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, 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 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. For example, the 
first well completed for production on Facility A would be

[[Page 73]]

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

[[Page 74]]

                        Right-of-use and Easement



Sec. 250.160  When will MMS grant me a right-of-use and easement, and what 

requirements must I meet?

    MMS 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 MMS.
    (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 256.35 (Qualification 
of lessees); establish a regional Company File as required by MMS; 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 MMS 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:
    (1) You obtain a right-of-use and easement after January 12, 2004; 
or
    (2) You ask MMS 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 MMS as shown in the following 
table:

------------------------------------------------------------------------
               If...                               Then...
------------------------------------------------------------------------
(1) Your right-of-use and easement   You must pay a rental of $5 per
 site is located in water depths of   acre per year with a minimum of
 less than 200 meters;                $450 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, 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 of   acre per year with a minimum 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 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 69311, Dec. 12, 2003; 
69 FR 29433, May 24, 2004; 72 FR 25200, May 4, 2007; 73 FR 49948, Aug. 
25, 2008]



Sec. 250.161  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

[[Page 75]]

    (d) A schedule for constructing any new facilities, drilling or 
completing any wells, anticipated production rates, and productive life 
of existing production facilities.



Sec. 250.162  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. 250.163  If I have a State lease, will MMS grant me a right-of-use and easement?

    (a) MMS 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) MMS 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. 250.164  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 subject to MMS 
regulations, 30 CFR parts 250 through 282, and any terms and conditions 
that the Regional Director prescribes.
    (b) For the whole or fraction of the first calendar year, and 
annually after that, you must pay to MMS, in advance, an annual rental 
payment.



Sec. 250.165  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. 250.125; and
    (b) The first year's rental as specified in Sec. 250.160(g).

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.166  If I have a State lease, what surety bond must I have for

a right-of-use and easement?

    (a) Before MMS 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 256.54 (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.

                               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

[[Page 76]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.170  How long does a suspension last?

    (a) MMS 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. MMS 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) MMS 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 MMS must receive the request before the end of the lease 
term (i.e., end of primary term, end of the 180-day 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. Sec. 250.115, 250.116, or 
250.1603 (SOP only);
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec. 250.125 of this subpart.

[70 FR 49876, Aug. 25, 2005]



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. MMS 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 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:

[[Page 77]]

    (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) 5 years; or
    (ii) 8 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.
    (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

[[Page 78]]

(c)(2), (c)(3), and (c)(4)(i) and (ii) of this section.

[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 44360, July 2, 2002; 70 
FR 74663, Dec. 16, 2005; 72 FR 25200, May 4, 2007]



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 Sec. 218.154.



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

    If MMS 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) MMS 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 250, 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 180 days of the 
primary term, and whenever production resumes during the last 180 days 
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 256). 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 180 days 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. Sec. 250.172, 250.173, 250.174, or 250.175 before the end of 
the 180th day 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 unless you resume 
operations or receive an SOO or an SOP from the Regional Supervisor 
under Sec. 250.172, 250.173, 250.174, or 250.175 before the end of the 
180th day after you stop operations.
    (e) You may ask the Regional Supervisor to allow you more than 180 
days 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

[[Page 79]]

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 180-day period 
after having ceased, or whenever drilling or well-reworking operations 
begin before the end of the 180-day 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 180-day period.



Sec. 250.181  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 256, you are entitled to compensation under Sec. 250.184. Section 
250.185 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. 250.182  When may the Secretary cancel a lease at the exploration stage?

    MMS may not approve an exploration plan (EP) under 30 CFR part 250, 
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. 250.183  When may MMS or the Secretary extend or cancel a lease at 

the development and production stage?

    (a) MMS may extend your lease if you submit a DPP and the Regional

[[Page 80]]

Supervisor disapproves the plan according to the regulations in 30 CFR 
part 250, subpart B. Following the disapproval:
    (1) MMS will allow you to hold the lease for 5 years, or less time 
at your request;
    (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 250, 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. 250.184  What is the amount of compensation for lease cancellation?

    When the Secretary cancels a lease under Sec. Sec. 250.181, 250.182 
or 250.183 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. 250.185  When is there no compensation for a lease cancellation?

    You will not receive compensation from MMS for lease cancellation 
if:
    (a) MMS 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 250, 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 MMS 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. 250.186  What reporting information and report forms must I submit?

    (a) You must submit information and reports as MMS 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 MMS's forms. You must arrange the data 
on your form identical to the MMS form. If you generate your own form 
and it omits terms and conditions contained on the official MMS form, we 
will consider it to contain the omitted terms and conditions.

[[Page 81]]

    (3) You may submit digital data when the Region/District is equipped 
to accept it.
    (b) When MMS 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.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 19644, Apr. 17, 2006, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.187  What are MMS' incident reporting requirements?

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

[71 FR 19644, Apr. 17, 2006]



Sec. 250.188  What incidents must I report to MMS 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

[[Page 82]]

in property or equipment damage greater than $25,000.

[71 FR 19644, Apr. 17, 2006]



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.

[71 FR 19644, Apr. 17, 2006]



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.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.191  How does MMS conduct incident investigations?

    Any investigation that MMS 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 MMS. 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

[[Page 83]]

expenses must be similar to mileage and fees the U.S. District Courts 
allow.

[71 FR 19645, Apr. 17, 2006]



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 
MMS GOM OCS Region, use Form MMS-132) 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 MMS when you resume production; and
    (4) Submit the statistics either by MMS district, or the total 
figures for your operations in an MMS 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 MMS-143, Facility/Equipment Damage Report, to 
make this and all subsequent reports. In lieu of submitting Form MMS-143 
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.

[73 FR 64545, Oct. 30, 2008]



Sec. 250.193  Reports and investigations of apparent violations.

    Any person may report to MMS an apparent violation or failure to 
comply with any provision of the Act, any provision of a lease, license, 
or permit issued under the Act, or any provision of any regulation or 
order issued under the Act. When MMS receives a report of an apparent 
violation, or when an MMS employee detects an apparent violation after 
making an initial determination of the validity, MMS will investigate 
according to MMS procedures.



Sec. 250.194  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

[[Page 84]]

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 Regional Director. If investigations determine that the resource is 
significant, the Regional Director will tell you how to protect it.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 23862, Apr. 25, 2006; 
72 FR 25200, May 4, 2007]



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

    You must notify the appropriate MMS 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.

[71 FR 23862, Apr. 25, 2006]



Sec. 250.196  Reimbursements for reproduction and processing costs.

    (a) MMS 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 MMS for the Regional Director to inspect or select and 
retain;
    (2) MMS 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) MMS 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 MMS 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) MMS will not reimburse you for data acquisition costs or for the 
costs of analyzing or processing geological information or interpreting 
geological or geophysical information.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 23862, Apr. 25, 2006]



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

    MMS will protect data and information that you submit under this 
part, and part 203 of 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.
    (a) All data and information you submit on MMS forms will be made 
available to the public upon submission, except as specified in the 
following table:

[[Page 85]]



------------------------------------------------------------------------
                                     Data and
                                 information not
         On form . . .             immediately     Excepted data will be
                                available are . .   made available . . .
                                        .
------------------------------------------------------------------------
(1) MMS-123, Application for    Items 15, 16, 22   When the well goes on
 Permit to Drill.                through 25.        production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(2) MMS-123S, Supplemental APD  Items 3, 7, 8, 15  When the well goes on
 Information Sheet.              and 17.            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(3) MMS-124, Application for    Item 17..........  When the well goes on
 Permit to Modify.                                  production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(4) MMS-125, End of Operations  Items 12, 13, 17,  When the well goes on
 Report.                         21, 22, 26         production or
                                 through 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) MMS-126, Well Potential     Item 101.........  2 years after you
 Test Report.                                       submit it.
(6) MMS-127, Sensitive          Items 124 through  2 years after the
 Reservoir Information Report.   168.               effective date of
                                                    the Sensitive
                                                    Reservoir
                                                    Information Report.
(7) MMS-133 Well Activity       Item 10 Fields     When the well goes on
 Report.                         [WELLBORE START    production or
                                 DATE, TD DATE,     according to the
                                 OP STATUS, END     table in paragraph
                                 DATE, MD, TVD,     (b) of this section,
                                 AND MW PPG].       whichever is
                                 Item 11 Fields     earlier.
                                 [WELLBORE START
                                 DATE, TD DATE,
                                 PLUGBACK DATE,
                                 FINAL MD, AND
                                 FINAL TVD] and
                                 Items 12 through
                                 15.
(8) MMS-133S Open Hole Data     Boxes 7 and 8....  When the well goes on
 Report.                                            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(9) MMS-137 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) MMS-140, Bottomhole        All items........  2 years after the
 Pressure Survey Report.                            date of the survey.
------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                 If                     MMS will release          At this time            Special provisions
----------------------------------------------------------------------------------------------------------------
(1) The Director determines that     Geophysical data,       At any time...........  MMS will release data and
 data and information are needed      Geological data                                 information only if
 for specific scientific or           Interpreted G&G                                 release would further the
 research purposes for the            information,                                    national interest without
 Government.                          Processed G&G                                   unduly damaging the
                                      information, Analyzed                           competitive position of
                                      geological                                      the lessee.
                                      information.
(2) Data or information is           Geophysical data,       60 days after MMS       MMS will release the data
 collected with high-resolution       Geological data,        receives the data or    and information earlier
 systems (e.g., bathymetry, side-     Interpreted G&G         information, if the     than 60 days if the
 scan sonar, subbottom profiler,      information,            Regional Supervisor     Regional Supervisor
 and magnetometer) to comply with     Processed geological    deems it necessary.     determines it is needed by
 safety or environmental protection   information, Analyzed                           affected States to make
 requirements.                        geological                                      decisions under subpart B.
                                      information.                                    The Regional Supervisor
                                                                                      will reconsider earlier
                                                                                      release if you satisfy him/
                                                                                      her that it would unduly
                                                                                      damage your competitive
                                                                                      position.
(3) Your lease is no longer in       Geophysical data,       When your lease         This release time applies
 effect.                              Geological data,        terminates.             only if the provisions in
                                      Processed G&G                                   this table governing high-
                                      information                                     resolution systems and the
                                      Interpreted G&G                                 provisions in Sec.  252.7
                                      information, Analyzed                           do not apply. The release
                                      geological                                      time applies to the
                                      information.                                    geophysical data and
                                                                                      information only if
                                                                                      acquired postlease for a
                                                                                      lessee's exclusive use.

[[Page 86]]

 
(4) Your lease is still in effect..  Geophysical data        10 years after you      This release time applies
                                      Processed geophysical   submit the data and     only if the provisions in
                                      information,            information.            this table governing high-
                                      Interpreted G&G                                 resolution systems and the
                                      information.                                    provisions in Sec.  252.7
                                                                                      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 still in effect    Geological data,        2 years after the       These release times apply
 and within the primary term          Analyzed geological     required submittal      only if the provisions in
 specified in the lease.              information.            date or 60 days after   this table governing high-
                                                              a lease sale if any     resolution systems and the
                                                              portion of an offered   provisions in Sec.  252.7
                                                              lease is within 50      do not apply. If the
                                                              miles of a well,        primary term specified in
                                                              whichever is later.     the lease is extended
                                                                                      under the heading of
                                                                                      ``Suspensions'' in this
                                                                                      subpart, the extension
                                                                                      applies to this provision.
(6) Your lease is in effect and      Geological data,        2 years after the       None.
 beyond the primary term specified    Analyzed geological     required submittal
 in the lease.                        information.            date.
(7) Data or information is           Descriptions of         When the well goes on   Directional survey data may
 submitted on well operations.        downhole locations,     production or when      be released earlier to the
                                      operations, and         geological data is      owner of an adjacent lease
                                      equipment.              released according to   according to Subpart D of
                                                              Sec. Sec.             this part.
                                                              250.197(b)(5) and
                                                              (b)(6), whichever
                                                              occurs earlier.
(8) Data and information are         Any data or             At any time...........  None.
 obtained from beneath unleased       information obtained.
 land as a result of a well
 deviation that has not been
 approved by the District Manager
 or Regional Supervisor.
(9) Except for high-resolution data  G&G data, analyzed      Geological data and     None.
 and information released under       geological              information: 10 years
 paragraph (b)(2) of this section     information,            after MMS issues the
 data and information acquired by a   processed and           permit; Geophysical
 permit under part 251 are            interpreted G&G         data: 50 years after
 submitted by a lessee under 30 CFR   information.            MMS issues the
 part 203 or part 250.                                        permit; Geophysical
                                                              information: 25 years
                                                              after MMS issues the
                                                              permit.
----------------------------------------------------------------------------------------------------------------

    (c) MMS may allow limited inspection, but only by persons with a 
direct interest in related MMS 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 part 203 of this 
chapter that MMS 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) Make field determinations; or
    (7) Determine eligibility for royalty relief.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 16039, Mar. 30, 2006. 
Redesignated and amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May 
4, 2007]

                               References



Sec. 250.198  Documents incorporated by reference.

    (a) The MMS 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

[[Page 87]]

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 MMS will 
publish any changes to a document in the Federal Register and amend this 
section.
    (2) The MMS may make the rule amending the document effective 
without prior opportunity for public comment when MMS 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 MMS 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 section 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. If any incorporated document uses the word should, it 
means must for purposes of these regulations.
    (b) The MMS 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 MMS official.
    (d) You may inspect these documents at the Minerals Management 
Service, 381 Elden Street, Room 3313, Herndon, Virginia 20170; phone: 
703-787-1587; 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, P. O. Box 
9094, Farmington Hill, MI 48333-9094: http://www.concrete.org; phone: 
248-848-3700:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95) and Commentary (ACI 318R-95), incorporated by 
reference at Sec. 250.901(a), (d).
    (2) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec. 250.901(a), (d).
    (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(a), (d).
    (2) [Reserved]
    (g) American National Standards Institute (ANSI), ANSI/ASME Codes, 
ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY 
10036; http://www.ansi.org; phone: 212-642-4900; and/or American Society 
of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, 
NJ 07007-2900; http://www.asme.org; phone: 973-882-5155:
    (1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for 
Construction of Power Boilers; including Appendices, 2004 Edition; and 
July 1, 2005 Addenda, and all Section I Interpretations Volume 55, 
incorporated by reference at Sec. 250.803(b)(1), (b)(1)(i); and Sec. 
250.1629(b)(1), (b)(1)(i);
    (2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for 
Construction of Heating Boilers; including

[[Page 88]]

Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, 
I, K, L, and M, and the Guide to Manufacturers Data Report Forms, 2004 
Edition; July 1, 2005 Addenda, and all Section IV Interpretations Volume 
55, incorporated by reference at Sec. 250.803(b)(1), (b)(1)(i); and 
Sec. 250.1629(b)(1), (b)(1)(i);
    (3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; 
July 1, 2005 Addenda, Divisions 1 and 2, and all Section VIII 
Interpretations Volumes 54 and 55, incorporated by reference at Sec. 
250.803(b)(1), (b)(1)(i); and Sec. 250.1629(b)(1), (b)(1)(i);
    (4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings 
incorporated by reference at Sec. 250.1002(b)(2);
    (5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems incorporated by reference at Sec. 250.1002(a);
    (6) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality 
Assurance and Certification of Safety and Pollution Prevention Equipment 
Used in Offshore Oil and Gas Operations, incorporated by reference at 
Sec. 250.806(a)(2)(i);
    (7) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at, Sec. 250.490(g)(4)(iv), 
(j)(13)(ii).
    (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, Downstream Segment, Ninth Edition, June 
2006, Product No. C51009; incorporated by reference at Sec. 
250.803(b)(1); and Sec. 250.1629(b)(1);
    (2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007, Product No. G2DGINT; 
incorporated by reference at Sec. 250.901(a), (d);
    (3) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007, Product 
No. G2EXINT; incorporated by reference at Sec. 250.901(a), (d);
    (4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007, Product No. G2INTMET; incorporated by 
reference at Sec. 250.901(a), (d);
    (5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994, 
Order No. 852-01002; 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, Order No. 852-022A1; incorporated by reference at Sec. 
250.1202(l)(4);
    (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, Order No. H30023; 
incorporated by reference at Sec. 250.1202(l)(4);
    (8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice 
for the Manual Gauging of Petroleum and Petroleum Products, Second 
Edition, August 2005, Product No. H301A02; incorporated by reference at 
Sec. 250.1202(l)(4);
    (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, Product No. H301B2; incorporated by reference at Sec. 
250.1202(l)(4);
    (10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005, Product No. H04013; incorporated by 
reference at Sec. 250.1202(a)(3), (f)(1);
    (11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003, Product No. H04023; incorporated 
by reference at Sec. 250.1202(a)(3), (f)(1);
    (12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005, Order No. H04042; 
incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter

[[Page 89]]

Provers, Second Edition, May 2000, reaffirmed: August 2005, Order No. 
H04052; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003, Order No. 
H04062; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard 
Test Measures, Second Edition, December 1998; reaffirmed 2003, Order No. 
H04072; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (16) API MPMS, Chapter 5--Metering, Section 1--General 
Considerations for Measurement by Meters, Fourth Edition, September 
2005, Product No. H05014; incorporated by reference at Sec. 
250.1202(a)(3);
    (17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid 
Hydrocarbons by Displacement Meters, Third Edition, September 2005, 
Product No. H05023; incorporated by reference at Sec. 250.1202(a)(3);
    (18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, Product 
No. H05035; incorporated by reference at Sec. 250.1202(a)(3);
    (19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005, Product No. H05044; 
incorporated by reference at Sec. 250.1202(a)(3);
    (20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security 
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, 
August 2005, Product No. H50502; incorporated by reference at Sec. 
250.1202(a)(3);
    (21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007, Order No. H30121; incorporated by reference at 
Sec. 250.1202(a)(3);
    (22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007, 
Order No. 852-30126; incorporated by reference at Sec. 250.1202(a)(3);
    (23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007, 
Order No. 852-30127; incorporated by reference at Sec. 250.1202(a)(3);
    (24) API MPMS, Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; Product No. H07001; incorporated by 
reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Order No. H08013; incorporated by 
reference at Sec. 250.1202(b)(4)(i), (l)(4);
    (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, Order No. H08022; 
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Product 
No. H09012; incorporated by reference at Sec. 250.1202(a)(3), (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, Product No. H09022; 
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Product No. H10013; incorporated 
by reference at Sec. 250.1202(a)(3), (l)(4);
    (30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007, Product No. H10022; incorporated by reference at Sec. 
250.1202(a)(3), (l)(4);
    (31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in

[[Page 90]]

Crude Oil by the Centrifuge Method (Laboratory Procedure), Third 
Edition, May 2008, Product No. H10033; incorporated by reference at 
Sec. 250.1202(a)(3), (l)(4);
    (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, Order No. 
H10043; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Product No. 
H10092; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, API Stock No. H27000; incorporated by reference at Sec. 
250.1202(a)(3), (g)(3), (l)(4);
    (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, Order No. 852-27307; incorporated by 
reference at Sec. 250.1202(a)(3), (g)(4);
    (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, Order No. H27308; incorporated 
by reference at Sec. 250.1202(a)(3);
    (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, Order No. H12021; incorporated 
by reference at Sec. 250.1202(a)(3), (g)(1), (g)(2);
    (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, Product No. H12223; incorporated by reference 
at Sec. 250.1202(a)(3), (g)(1), (g)(2);
    (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, Order No. 852-30350; incorporated by reference at Sec. 
250.1203(b)(2);
    (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, Order No. H14324; incorporated by reference at Sec. 
250.1203(b)(2);
    (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, Product No. H143303; incorporated by reference at Sec. 
250.1203(b)(2);
    (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; Adopted as Tentative Standard, 
1972; Revised and Adopted as Standard, 1976; Revised 1984, 1986, 1996, 
2009; Product No. H140503; incorporated by reference at Sec. 
250.1203(b)(2);
    (43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006, Order No. H30346; incorporated by reference 
at Sec. 250.1203(b)(2);
    (44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006, Order No. H14082; incorporated by reference at 
Sec. 250.1203(b)(2);

[[Page 91]]

    (45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006, Order No. 852-30701; 
incorporated by reference at Sec. 250.1202(k)(1);
    (46) API MPMS, Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 1--Electronic Gas Measurement, First Edition, 
August 1993; reaffirmed, July 2005, Order No. 852-30730; incorporated by 
reference at Sec. 250.1203(b)(4);
    (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; Product No. G2AWSD; incorporated by reference at Sec. 
250.901(a), (d); Sec. 250.908(a); Sec. 250.919(b)(2); Sec. 
250.920(a), (b), (c), (d), (e), (f);
    (48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007, Product No. G02D06; incorporated by reference at 
Sec. 250.108(a);
    (49) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001, Order No. 
G2FPS1; incorporated by reference at Sec. 250.901(a), (d);
    (50) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008, Product No. G02I03; 
incorporated by reference at Sec. 250.901(a), (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; Order 
No. G02RD1; incorporated by reference at Sec. 250.800(b)(2); Sec. 
250.901(a), (d); Sec. 250.1002(b)(5);
    (52) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008, 
Product No. G2SK03; incorporated by reference at Sec. 250.800(b)(3); 
Sec. 250.901(a), (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, Product No. 
G02SM1; incorporated by reference at Sec. 250.901(a), (d);
    (54) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997, Order 
No. G02T02; incorporated by reference at Sec. 250.901(a), (d);
    (55) API RP 14B, Recommended Practice for Design, Installation, 
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, 
October 2005, also available as ISO 10417: 2004, (Identical) Petroleum 
and natural gas industries--Subsurface safety valve systems--Design, 
installation, operation and redress, Product No. GX14B05; incorporated 
by reference at Sec. 250.801(e)(4); Sec. 250.804(a)(1)(i);
    (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; Product No. C14C07; incorporated by reference at Sec. 250.125(a); 
Sec. 250.292(j); Sec. 250.802(b), (e)(2); Sec. 250.803(a), (b)(2)(i), 
(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); Sec. 250.804(a), (a)(6); 
Sec. 250.1002(d); Sec. 250.1004(b)(9); Sec. 250.1628(c), (d)(2); 
Sec. 250.1629(b)(2), (b)(4)(v); Sec. 250.1630(a);
    (57) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; reaffirmed, March 2007, Order No. 811-07185; incorporated by 
reference at Sec. 250.802(e)(3); Sec. 250.1628(b)(2), (d)(3);
    (58) API RP 14F, Design, Installation, and Maintenance of Electrical 
Systems for Fixed and Floating Offshore Petroleum Facilities for 
Unclassified and Class I, Division 1 and Division 2 Locations, Fifth 
Edition, July 2008, Product No. G14F05; incorporated by reference at 
Sec. 250.114(c); Sec. 250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);
    (59) 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, First Edition, September 2001, reaffirmed: March 2007; 
Product No. G14FZ1; incorporated by reference at Sec. 250.114(c); Sec. 
250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);

[[Page 92]]

    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; Product No. G14G04; incorporated by reference at 
Sec. 250.803(b)(8), (b)(9)(v); Sec. 250.1629(b)(3), (b)(4)(v);
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007, Product No. G14H05; incorporated 
by reference at Sec. 250.802(d); Sec. 250.804(a)(5);
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
reaffirmed: March 2007; Product No. G14J02; incorporated by reference at 
Sec. 250.800(b)(1); Sec. 250.901(a)(14);
    (63) API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells, Third Edition, March 1997; 
reaffirmed September 2004, Order No. G53003; incorporated by reference 
at Sec. 250.442(c); Sec. 250.446(a); Sec. 250.516(g)(1); Sec. 
250.516(h); and Sec. 250.617(a)(1), and (b);
    (64) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002, Product 
No. G56001; incorporated by reference at Sec. 250.415(e);
    (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, Second Edition, 
November 1997; reaffirmed November 2002, Product No. C50002; 
incorporated by reference at Sec. 250.114(a); Sec. 250.459; Sec. 
250.802(e)(4)(i); Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3), 
(d)(4)(i); Sec. 250.1629(b)(4)(i);
    (66) 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 November 2002, Order No. C50501; incorporated 
by reference at Sec. 250.114(a); Sec. 250.459; Sec. 250.802(e)(4)(i); 
Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3), (d)(4)(i); Sec. 
250.1629(b)(4)(i);
    (67) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 2003, 
Order No. H25560; incorporated by reference at Sec. 250.1202(l)(4);
    (68) ANSI/API Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007 
(Identical), Petroleum, petrochemical and natural gas industries--Sector 
specific requirements--Requirements for product and service supply 
organizations, Eighth Edition, December 2007, Effective Date: June 15, 
2008, Product No. GXQ108; incorporated by reference at Sec. 
250.806(a)(2)(ii);
    (69) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004, 
Product No. G02C06; incorporated by reference at Sec. 250.108(c), (d);
    (70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas 
Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February 
1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption; 
ISO 10423:2003 (Modified), Petroleum and natural gas industries--
Drilling and production equipment--Wellhead and Christmas tree 
equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3, 
June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1, 
February 2008; Addendum 2, 3, and 4, December 2008; Product No. GX06A19; 
incorporated by reference at Sec. 250.806(a)(3); Sec. 250.1002(b)(1), 
(b)(2);
    (71) API Spec. 6AV1, Specification for Verification Test of Wellhead 
Surface Safety Valves and Underwater Safety Valves for Offshore Service, 
First Edition, February 1, 1996; reaffirmed January 2003, Order No. 
G06AV1; incorporated by reference at Sec. 250.806(a)(3);
    (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; Product 
No. GX6D23; incorporated by reference at Sec. 250.1002(b)(1);

[[Page 93]]

    (73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October 2005, Effective Date: May 1, 2006; 
also available as ISO 10432:2004, Product No. GX14A11; incorporated by 
reference at Sec. 250.806(a)(3);
    (74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008; Effective Date: January 1, 2009, Contains API 
Monogram Annex as Part of U.S. National Adoption; ISO 13628-2:2006 
(Identical), Petroleum and natural gas industries--Design and operation 
of subsea production systems--Part 2: Unbonded flexible pipe systems for 
subsea and marine application; Product No. GX17J03; incorporated by 
reference at Sec. 250.803(b)(2)(iii); Sec. 250.1002(b)(4); Sec. 
250.1007(a)(4);
    (75) API Standard 2551, Measurement and Calibration of Horizontal 
Tanks, First Edition, 1965; reaffirmed March 2002, API Stock No. H25510; 
incorporated by reference at Sec. 250.1202(l)(4);
    (76) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007 (ASTM designation: D 1408-65; date of joint API/ASTM 
approval, 1965); incorporated by reference at Sec. 250.1202(l)(4);
    (77) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; Order No. 852-
25550; incorporated by reference at Sec. 250.1202(l)(4).
    (78) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006, Product No. G09001, incorporated by 
reference at Sec. 250.518.
    (79) API RP 65-Part 2, Isolating Potential Flow Zones During Well 
Construction; First Edition, May 2010; Product No. G65201; incorporated 
by reference at Sec. 250.415(f).
    (80) 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, Product No. G07503; 
incorporated by reference at Sec. Sec. 250.1900, 250.1900(c), 
250.1902(c), 250.1903, 250.1909, 250.1920(a) and (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: 610-832-9500:
    (1) ASTM Standard C 33-07, approved December 15, 2007, Standard 
Specification for Concrete Aggregates; incorporated by reference at 
Sec. 250.901(a), (d);
    (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(a), (d);
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at Sec. 
250.901(a), (d);
    (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(a), (d);
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec. 250.901(a), (d);
    (j) American Welding Society (AWS), AWS Codes, 550 NW, LeJeune Road, 
Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel; incorporated by 
reference at Sec. 250.901(a), (d);
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel; 
incorporated by reference at Sec. 250.901(a), (d);
    (3) AWS D3.6M:1999, Specification for Underwater Welding; 
incorporated by reference at Sec. 250.901(a), (d).
    (k) National Association of Corrosion Engineers (NACE), NACE 
Standards, 1440 South Creek Drive, Houston, TX 77084; http://
www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Item No. 21302, Standard Material 
Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion 
Cracking Resistance in Sour Oilfield Environments; incorporated by 
reference at Sec. 250.901(a), Sec. 250.490(p)(2);
    (2) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended 
Practice, Corrosion Control of Steel Fixed Offshore Structures 
Associated with Petroleum Production; incorporated by reference at Sec. 
250.901(a), (d).

[75 FR 22222, Apr. 28, 2010, as amended at 75 FR 23584, May 4, 2010; 75 
FR 63372, Oct. 14, 2010; 75 FR 63649, Oct. 15, 2010]

[[Page 94]]



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 MMS uses the information. The 
associated MMS 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. 250.197, Data and information 
to be made available to the public; parts 251 and 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.
    (e) MMS is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or MMS Form        Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform MMS of actions taken
 including Forms MMS-132, Evacuation      to comply with general
 Statistics; MMS-143, Facility/           operational requirements on
 Equipment Damage Report; MMS-1123,       the OCS. To ensure that
 Designation of Operator; MMS-1832,       operations on the OCS meet
 Notification of Incidents of             statutory and regulatory
 Noncompliance.                           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.
                                          To allow MMS to rapidly assess
                                          damage and project any
                                          disruption of oil and gas
                                          production from the OCS after
                                          a major natural occurrence.
(2) Subpart B, Exploration and           To inform MMS, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151), including Forms MMS-137, OCS      development, and production
 Plan Information Form; MMS-139, EP Air   operations on the OCS. To
 Quality Screening Checklist; MMS-138,    ensure that operations on the
 DOCD Air Quality Screening Checklist,    OCS are planned to comply with
 MMS-141, ROV Survey Report Form; MMS-    statutory and regulatory
 142, Environmental Impact Analysis       requirements, will be safe and
 Worksheet.                               protect the human, marine, and
                                          coastal environment, and will
                                          result in diligent
                                          exploration, development, and
                                          production of leases.
(3) Subpart C, Pollution Prevention and  To inform MMS of measures to be
 Control (1010-0057).                     taken to prevent water and air
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent water and air
                                          pollution.
(4) Subpart D, Oil and Gas and Drilling  To inform MMS of the equipment
 Operations (1010-0141), including        and procedures to be used in
 Forms MMS-123, Application for Permit    drilling operations on the
 to Drill; MMS-123S, Supplemental APD     OCS. To ensure that drilling
 Information Sheet; MMS-124,              operations are safe and
 Application for Permit to Modify; MMS-   protect the human, marine, and
 125, End of Operations Report; MMS-      coastal environment.
 133, Well Activity Report; MMS-133S,
 Open Hole Data Report.
(5) Subpart E, Oil and Gas Well-         To inform MMS of the equipment
 Completion Operations (1010-0067).       and procedures to be used in
                                          well-completion operations on
                                          the OCS. To ensure that well-
                                          completion operations are safe
                                          and protect the human, marine,
                                          and coastal environment.
(6) Subpart F, Oil and Gas Well          To inform MMS of the equipment
 Workover Operations (1010-0043).         and procedures to be used
                                          during well-workover
                                          operations on the OCS. To
                                          ensure that well-workover
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(7) Subpart H, Oil and Gas Production    To inform MMS of the equipment
 Safety Systems (1010-0059).              and procedures to be used
                                          during production operations
                                          on the OCS. To ensure that
                                          production operations are safe
                                          and protect the human, marine,
                                          and coastal environment.
(8) Subpart I, Platforms and Structures  To provide MMS with information
 (1010-0149).                             regarding the design,
                                          fabrication, and installation
                                          of platforms on the OCS. To
                                          ensure the structural
                                          integrity of platforms
                                          installed on the OCS.

[[Page 95]]

 
(9) Subpart J, Pipelines and Pipeline    To provide MMS with information
 Rights-of-Way (1010-0050).               regarding the design,
                                          installation, and operation of
                                          pipelines on the OCS. To
                                          ensure that pipeline
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(10) Subpart K, Oil and Gas Production   To inform MMS of production
 Rates (1010-0041), including Forms MMS-  rates for hydrocarbons
 126, Well Potential Test Report; MMS-    produced on the OCS. To ensure
 127, Sensitive Reservoir Information     economic maximization of
 Report; MMS-128, Semiannual Well Test    ultimate hydrocarbon recovery.
 Report; MMS-140 Bottomhole Pressure
 Survey Report.
(11) Subpart L, Oil and Gas Production   To inform MMS of the
 Measurement, Surface Commingling, and    measurement of production,
 Security (1010-0051).                    commingling of hydrocarbons,
                                          and site security plans. To
                                          ensure that produced
                                          hydrocarbons are measured and
                                          commingled to provide for
                                          accurate royalty payments and
                                          security is maintained.
(12) Subpart M, Unitization (1010-0068)  To inform MMS of the
                                          unitization of leases. To
                                          ensure that unitization
                                          prevents waste, conserves
                                          natural resources, and
                                          protects correlative rights.
(13) 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.
(14) Subpart O, Well Control and         To inform MMS of training
 Production Safety Training (1010-0128).  program curricula, course
                                          schedules, and attendance. To
                                          ensure that training programs
                                          are technically accurate and
                                          sufficient to meet safety and
                                          environmental requirements,
                                          and that workers are properly
                                          trained to operate on the OCS.
(15) Subpart P, Sulphur Operations       To inform MMS of sulphur
 (1010-0086).                             exploration and development
                                          operations on the OCS. To
                                          ensure that OCS sulphur
                                          operations are safe; protect
                                          the human, marine, and coastal
                                          environment; and will result
                                          in diligent exploration,
                                          development, and production of
                                          sulphur leases.
(16) Subpart Q, Decommissioning          To determine that
 Activities (1010-0142).                  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.
(17) Subpart S, Safety and               The SEMS program will describe
 Environmental Management Systems (1010-  management commitment to
 0186), including Form MMS-131,           safety and the environment, as
 Performance Measures Data.               well as policies and
                                          procedures to assure safety
                                          and environmental protection
                                          while conducting OCS
                                          operations (including those
                                          operations conducted by
                                          contractor and subcontractor
                                          personnel). The information
                                          collected is the form to
                                          gather the raw Performance
                                          Measures Data relating to risk
                                          and number of accidents,
                                          injuries, and oil spills
                                          during OCS activities.
(18) Form MMS-144, Rig Movement          The rig notification
 Notification Report (form used in the    requirement is essential for
 GOM OCS Region), Subparts D, E, F,       MMS inspection scheduling and
 (1010-0150).                             to verify that the equipment
                                          being used complies with
                                          approved permits.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 71 FR 23863, Apr. 25, 2006; 72 FR 25200, May 4, 
2007; 73 FR 64546, Oct. 30, 2008; 74 FR 46908, Sept. 14, 2009; 75 FR 
20289, Apr. 19, 2010; 75 FR 63649, Oct. 15, 2010]



                     Subpart B_Plans and Information

    Source: 70 FR 51501, Aug. 30, 2005, unless otherwise noted.

                           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:
    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
    MMS means Minerals Management Service
    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 96]]

    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before MMS for a decision (see Sec. Sec. 250.232(d) and 
250.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see Sec. 250.233(b)(2) and Sec. 250.270(b)(2)) 
that is pending before MMS 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 an MMS 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 MMS has disapproved (see Sec. Sec. 
250.234(b), 250.272(a), and 250.273(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. 250.283(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. 250.283(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 MMS 
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 (DOCD).  activities on a lease or unit in the
                                Western GOM.
(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) 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.
                                250.105) 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.  250.209,
                                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 97]]

    (1) Sufficient applicable information or analysis is readily 
available to MMS;
    (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 MMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.202  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. 250.203  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. 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.



Sec. 250.206  How do I submit the EP, DPP, or DOCD?

    (a) Number of copies. When you submit an EP, DPP, or DOCD to MMS, 
you must provide:

[[Page 98]]

    (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 EP, DPP, or DOCD by certain affected States and other reviewing 
entities.
    (b) Electronic submission. You may submit part or all of your EP, 
DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional 
Supervisor for further guidance.
    (c) Withdrawal after submission. You may withdraw your proposed EP, 
DPP, or DOCD at any time for any reason. Notify the appropriate MMS OCS 
Region if you do.

                          Ancillary Activities



Sec. 250.207  What ancillary activities may I conduct?

    Before or after you submit an EP, DPP, or DOCD to MMS, 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. 250.208  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. 250.207(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
    (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 MMS at least 15 calendar days before you 
conduct any other ancillary activity (see Sec. 250.207(b) and (c)) in 
addition to those listed in Sec. 250.207(a); and
    (2) Notify other users of the OCS before you conduct any ancillary 
activity.



Sec. 250.209  What is the MMS review process for the notice?

    The Regional Supervisor will review any notice required under Sec. 
250.208(a) and (b)(1) to ensure that your ancillary activity complies 
with the performance standards listed in Sec. 250.202(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. 250.210  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, MMS 
will protect and disclose the data and information in these reports in 
accordance with Sec. 250.197(b).

[[Page 99]]

    (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. 250.207(a)), including any such data and information you obtained 
from previous leaseholders or unit operators. You must submit such data 
and information to MMS for inspection and possible retention upon 
request at any time before lease or unit termination. When applicable, 
MMS will protect and disclose such submitted data and information in 
accordance with Sec. 250.197(b).

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]

                   Contents of Exploration Plans (EP)



Sec. 250.211  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 third definition of ``facility'' under Sec. 250.105).
    (d) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.212  What information must accompany the EP?

    The following information must accompany your EP:
    (a) General information required by Sec. 250.213;
    (b) Geological and geophysical (G&G) information required by Sec. 
250.214;
    (c) Hydrogen sulfide information required by Sec. 250.215;
    (d) Biological, physical, and socioeconomic information required by 
Sec. 250.216;
    (e) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.217;
    (f) Air emissions information required by Sec. 250.218;
    (g) Oil and hazardous substance spills information required by Sec. 
250.219;
    (h) Alaska planning information required by Sec. 250.220;
    (i) Environmental monitoring information required by Sec. 250.221;
    (j) Lease stipulations information required by Sec. 250.222;
    (k) Mitigation measures information required by Sec. 250.223;
    (l) Support vessels and aircraft information required by Sec. 
250.224;
    (m) Onshore support facilities information required by Sec. 
250.225;
    (n) Coastal zone management information required by Sec. 250.226;
    (o) Environmental impact analysis information required by Sec. 
250.227; and
    (p) Administrative information required by Sec. 250.228.



Sec. 250.213  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

[[Page 100]]

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. 250.200) 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 256, subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your EP according to 30 CFR 
part 253; 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. 250.214  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 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

[[Page 101]]

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. 250.215  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 Sec. 250.490(c), a request that the 
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 Sec. 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. 250.216  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 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. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information regarding 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.217  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:

[[Page 102]]

    (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. 250.218  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.
    (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. 250.303 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

[[Page 103]]

amounts ``E'' calculated using the formulas in Sec. 250.303(d). When 
MMS 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. 250.303 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. 250.219  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. 250.220  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 blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft.
    (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.



Sec. 250.221  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

[[Page 104]]

oil spill on the environmentally sensitive resources at the FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.222  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. 250.223  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.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.224  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. 250.213(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. 
250.217(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. 250.225  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.

[[Page 105]]

    (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 
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. 250.217) and the types and 
quantities of such wastes.



Sec. 250.226  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. 250.227  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

[[Page 106]]

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.
    (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.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.228  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. 250.231  After receiving the EP, what will MMS 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. 250.212), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(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. 250.232  What actions will MMS take after the EP is deemed submitted?

    (a) State and CZMA consistency reviews. Within 2 working days after 
deeming your EP submitted under Sec. 250.231, 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) MMS 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. 250.202.
    (c) MMS environmental impact evaluation. The Regional Supervisor 
will evaluate the environmental impacts of

[[Page 107]]

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 amended, is subject to the requirements of Sec. 250.231.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.233  What decisions will MMS 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. 
250.231, or receives the last amendment to your proposed EP, whichever 
occurs later.
    (b) MMS 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  The Regional
                               applicable            Supervisor will
                               requirements.         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          The Regional
 your proposed EP.             Supervisor finds      Supervisor will
                               that it is            notify you in
                               inconsistent with     writing of the
                               the lease, the Act,   decision and
                               the regulations       describe the
                               prescribed under      modifications you
                               the Act, or other     must make to your
                               Federal laws.         proposed EP to
                                                     ensure it complies
                                                     with all applicable
                                                     requirements.
(3) Disapprove your EP......  Your proposed         (i) The Regional
                               activities would      Supervisor will
                               probably cause        notify you in
                               serious harm or       writing of the
                               damage to life        decision and
                               (including fish or    describe the
                               other aquatic         reason(s) for
                               life); property;      disapproving your
                               any mineral (in       EP.
                               areas leased or not  (ii) MMS may cancel
                               leased); the          your lease and
                               national security     compensate you
                               or defense; or the    under 43 U.S.C.
                               marine, coastal, or   1334(a)(2)(C) and
                               human environment;    the implementing
                               and you cannot        regulations in Sec.
                               modify your            Sec.  250.182,
                               proposed activities   250.184, and
                               to avoid such         250.185 and 30 CFR
                               condition(s).         256.77.
------------------------------------------------------------------------


[70 FR 51501, Aug. 30, 2005, as amended at 74 FR 46908, Sept. 14, 2009]



Sec. 250.234  How do I submit a modified EP or resubmit a disapproved EP, and when will MMS make a decision?

    (a) Modified EP. If the Regional Supervisor requires you to modify 
your proposed EP under Sec. 250.233(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. 250.233(b)(3), you may resubmit the disapproved EP if there 
is a change in the conditions that were the basis of its disapproval.
    (c) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 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. 250.235  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. 250.233(a) or Sec. 250.234(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

[[Page 108]]

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.
    (c) Withdraw your EP. Withdraw your EP if you decide not to conduct 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005; 71 FR 12438, Mar. 10, 2006]

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)



Sec. 250.241  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. 250.105); 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 third definition of ``facility'' under Sec. 250.105).
    (d) Production facilities. A description of the production 
platforms, satellite structures, subsea wellheads and manifolds, lease 
term pipelines (see definition at Sec. 250.105), 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 third definition of 
``facility'' under Sec. 250.105).
    (e) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.242  What information must accompany the DPP or DOCD?

    The following information must accompany your DPP or DOCD.
    (a) General information required by Sec. 250.243;
    (b) G&G information required by Sec. 250.244;
    (c) Hydrogen sulfide information required by Sec. 250.245;
    (d) Mineral resource conservation information required by Sec. 
250.246;
    (e) Biological, physical, and socioeconomic information required by 
Sec. 250.247;
    (f) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.248;
    (g) Air emissions information required by Sec. 250.249;
    (h) Oil and hazardous substance spills information required by Sec. 
250.250;
    (i) Alaska planning information required by Sec. 250.251;

[[Page 109]]

    (j) Environmental monitoring information required by Sec. 250.252;
    (k) Lease stipulations information required by Sec. 250.253;
    (l) Mitigation measures information required by Sec. 250.254;
    (m) Decommissioning information required by Sec. 250.255;
    (n) Related facilities and operations information required by Sec. 
250.256;
    (o) Support vessels and aircraft information required by Sec. 
250.257;
    (p) Onshore support facilities information required by Sec. 
250.258;
    (q) Sulphur operations information required by Sec. 250.259;
    (r) Coastal zone management information required by Sec. 250.260;
    (s) Environmental impact analysis information required by Sec. 
250.261; and
    (t) Administrative information required by Sec. 250.262.



Sec. 250.243  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. 250.200) 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 256, 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 253; 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.

[[Page 110]]

    (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. 250.244  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 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. 250.245  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 Sec. 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) H2S 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 Sec. 
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

[[Page 111]]

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 
methodologies outlined in 40 CFR part 68.



Sec. 250.246  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. 250.247  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. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information related 
to your proposed development and production activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.248  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

[[Page 112]]

    (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.
    (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. 250.249  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.

[[Page 113]]

    (e) Non-exempt facilities. A description of how you will comply with 
Sec. 250.303 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. 
250.303(d). When MMS 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. 250.303 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.



Sec. 250.250  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. 250.251  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. 250.252  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

[[Page 114]]

    (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 an oil spill on the environmentally sensitive 
resources of the FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.253  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 your proposed development 
and production activities must accompany your DPP or DOCD.



Sec. 250.254  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.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.255  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. 250.256  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. 250.257  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

[[Page 115]]

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. 250.243(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 of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec. 
250.248(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. 250.258  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. 250.248(a)) 
and the types and quantities of such wastes.



Sec. 250.259  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.

[[Page 116]]



Sec. 250.260  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).

[70 FR 51501, Aug. 30, 2005, as amended at 73 FR 20171, Apr. 15, 2008]



Sec. 250.261  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:
    (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.

[[Page 117]]

    (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.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.262  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
    (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. 250.266  After receiving the DPP or DOCD, what will MMS 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. 250.242), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(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. 250.267  What actions will MMS 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. 250.266, 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

[[Page 118]]

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. 250.266, 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 
MMS 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) MMS 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. 250.202.
    (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 or DOCD, the Regional 
Supervisor may determine that your DPP or DOCD, as amended, is subject 
to the requirements of Sec. 250.266.



Sec. 250.268  How does MMS 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. 250.269  How will MMS 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 MMS 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 MMS 
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. 250.270  What decisions will MMS 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:

[[Page 119]]

    (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. 250.267(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, MMS 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) MMS 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 DPP or DOCD  It complies with all  The Regional
                               applicable            Supervisor will
                               requirements.         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     It fails to make      The Regional
 your proposed DPP or DOCD.    adequate provisions   Supervisor will
                               for safety,           notify you in
                               environmental         writing of the
                               protection, or        decision and
                               conservation of       describe the
                               natural resources     modifications you
                               or otherwise does     must make to your
                               not comply with the   proposed DPP or
                               lease, the Act, the   DOCD to ensure it
                               regulations           complies with all
                               prescribed under      applicable
                               the Act, or other     requirements.
                               Federal laws.
(3) Disapprove your DPP or    Any of the reasons    (i) The Regional
 DOCD.                         in Sec.  250.271     Supervisor will
                               apply.                notify you in
                                                     writing of the
                                                     decision and
                                                     describe the
                                                     reason(s) for
                                                     disapproving your
                                                     DPP or DOCD; and
                                                    (ii) MMS may cancel
                                                     your lease and
                                                     compensate you
                                                     under 43 U.S.C.
                                                     1351(h)(2)(C) and
                                                     the implementing
                                                     regulations in Sec.
                                                      Sec.  250.183,
                                                     250.184, and
                                                     250.185 and 30 CFR
                                                     256.77.
------------------------------------------------------------------------


[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.271  For what reasons will MMS 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

[[Page 120]]

interest of national security. In that event, you do not need to 
resubmit your DPP or DOCD for approval under Sec. 250.273(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. 250.272  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 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. 250.273  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. 250.270(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. 250.270(b)(3), and except as provided in 
Sec. 250.271(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) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 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. 250.280  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 MMS enforcement action, including civil 
penalties; and

[[Page 121]]

    (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. 250.185(b) and 30 CFR 
256.77.
    (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. 250.281  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 Regional 
Supervisor:
    (1) Approval of applications for permits to drill (APDs) (see Sec. 
250.410);
    (2) Approval of production safety systems (see Sec. 250.800);
    (3) Approval of new platforms and other structures (or major 
modifications to platforms and other structures) (see Sec. 250.905);
    (4) Approval of applications to install lease term pipelines (see 
Sec. 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 District Manager or 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 MMS 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.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.282  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 MMS 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

[[Page 122]]

specify requirements for preparing and submitting these reports.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.283  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 
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. 250.284  How will MMS 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. 250.285  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. 250.231 through Sec. 250.235 for EPs and Sec. 250.266 through 
Sec. 250.273 for DPPs and DOCDs.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25201, May 4, 2007]

                    Deepwater Operations Plans (DWOP)



Sec. 250.286  What is a DWOP?

    (a) A DWOP is a plan that provides sufficient information for MMS 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 Exploration Plans, 
Development and Production Plans, and Development Operations 
Coordination Documents. MMS

[[Page 123]]

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 MMS 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.



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 
MMS 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;

[[Page 124]]

    (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; and
    (p) Payment of the service fee listed in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.293  What operations require approval of the DWOP?

    You may not begin production until MMS 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.

                Conservation Information Documents (CID)



Sec. 250.296  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. 250.125.
    (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.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.297  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 MMS 
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. 250.115 or Sec. 250.116:
    (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 pay, porosity, water 
saturations, pressures, formation volume factor);

[[Page 125]]

    (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. 250.298  How long will MMS 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 MMS does not act within 150 calendar 
days, your CID is considered approved.
    (b) MMS 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. MMS 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 
MMS 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. 250.299  What operations require approval of the CID?

    You may not begin production before you receive MMS approval of the 
CID.



               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,

[[Page 126]]

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.
    (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 which 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.
    (2) Approval of the method of disposal of drill cuttings, sand, and 
other well solids shall be obtained from the District Manager.
    (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.
    (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

[[Page 127]]

facility's daily operations report, as appropriate, and reported to the 
District Manager.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32099, July 15, 1991. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.301  Inspection of facilities.

    (a) 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.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 13996, Mar. 25, 1997. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.302  Definitions concerning air quality.

    For purposes of Sec. Sec. 250.303 and 250.304 of this part:
    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 means 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 means 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.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32100, July 15, 1991. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]

[[Page 128]]



Sec. 250.303  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. 250.303 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 shall require 
the lessee to refer to the information required in Sec. 250.218 or 
Sec. 250.249 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. 250.249(a) or Sec. 
250.218(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E=3400D2/3 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

[[Page 129]]

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) Except for temporary facilities, the lessee also shall use an 
approved 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   3-hour
                                                 \1\    maximum  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.


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 affect 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 the area significantly affected by the lessee's offshore 
operations.

[[Page 130]]

    (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.

[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31, 1988; 53 FR 26067, July 
11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 
70 FR 51518, Aug. 30, 2005]



Sec. 250.304  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. 250.218 or 250.249 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

[[Page 131]]

lessee shall use the highest annual total amount of emissions from the 
facility for each air pollutant calculated in Sec. 250.218(a) or 
250.249(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 Sec. 250.174 of this 
part.
    (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 time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 
70 FR 51519, Aug. 30, 2005]

[[Page 132]]



                Subpart D_Oil and Gas Drilling Operations

                          General Requirements



Sec. 250.400  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operating rights 
owners, operators, and their contractors and subcontractors.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.401  What must I do to keep wells under control?

    You must take necessary precautions to keep wells under control at 
all times. You must:
    (a) Use the best available and safest drilling technology to monitor 
and evaluate well conditions and to minimize the potential for the well 
to flow or kick;
    (b) Have a person onsite during drilling operations who represents 
your interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the drilling crew maintains continuous surveillance on the rig 
floor from the beginning of drilling 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 subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure the 
safety and protection of personnel, equipment, natural resources, and 
the environment.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.402  When and how must I secure a well?

    Whenever you interrupt drilling operations, you must install a 
downhole safety device, such as a cement plug, bridge plug, or packer. 
You must install the device at an appropriate depth within a properly 
cemented casing string or liner.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location; or
    (3) Repair to major drilling or well-control equipment.
    (b) For floating drilling operations, the District Manager may 
approve the use of blind or blind-shear rams or pipe rams and an inside 
BOP if you don't have time to install a downhole safety device or if 
special circumstances occur.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.403  What drilling unit movements must I report?

    (a) You must report the movement of all drilling units on and off 
drilling locations to the District Manager. This includes both MODU and 
platform rigs. You must inform the District Manager 24 hours before:
    (1) The arrival of an MODU on location;
    (2) The movement of a platform rig to a platform;
    (3) The movement of a platform rig to another slot;
    (4) The movement of an MODU to another slot; and
    (5) The departure of an MODU 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) In the Gulf of Mexico OCS Region, you must report drilling unit 
movements on form MMS-144, Rig Movement Notification Report.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 take device to shut 
down

[[Page 133]]

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.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.406  What additional safety measures must I take when I conduct drilling 

operations on a platform that has producing wells or has other hydrocarbon 
          flow?

    You must take the following safety measures when you conduct 
drilling operations on a platform with producing wells or that has other 
hydrocarbon flow:
    (a) You must install an emergency shutdown station near the 
driller's console;
    (b) You must shut in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a drilling rig 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 drilling unit between wells on a platform;
    (3) A mobile offshore drilling unit (MODU) moves within 500 feet of 
a platform. You may resume production once the MODU is in place, 
secured, and ready to begin drilling operations.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 MMS-123) (see Sec. 
250.414(h)). Procedures for obtaining approval are described in section 
250.141 of this part.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



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)).

[68 FR 8423, Feb. 20, 2003]

                     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. 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);

[[Page 134]]

    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 253; and
    (d) Submit the following to the District Manager:
    (1) An original and two complete copies of Form MMS-123, Application 
for Permit to Drill (APD), and Form MMS-123S, Supplemental APD 
Information Sheet;
    (2) A separate public information copy of forms MMS-123 and MMS-123S 
that meets the requirements of Sec. 250.186; and
    (3) Payment of the service fee listed in Sec. 250.125.

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006; 72 
FR 25201, May 4, 2007]



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

    In addition to forms MMS-123 and MMS-123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
 Information that you must include with an         Where to find a
                    APD                              description
------------------------------------------------------------------------
(a) Plat that shows locations of the         Sec.  250.412
 proposed well.
(b) Design criteria used for the proposed    Sec.  250.413
 well.
(c) Drilling prognosis.....................  Sec.  250.414
(d) Casing and cementing programs..........  Sec.  250.415
(e) Diverter and BOP systems descriptions..  Sec.  250.416
(f) Requirements for using an MODU.........  Sec.  250.417
(g) Additional information.................  Sec.  250.418
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



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;
    (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.

[68 FR 8423, Feb. 20, 2003]



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 estimated pore pressures, formation 
fracture gradients, proposed drilling fluid weights, 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.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures

[[Page 135]]

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 between proposed drilling fluid 
weights and estimated pore pressures. This safe drilling margin may be 
shown on the plot required by Sec. 250.413(g);
    (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 alternative 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternative procedures afford 
an equal or greater degree of protection, safety, or performance, or why 
you need the departures; and
    (i) Projected plans for well testing (refer to Sec. 250.460 for 
safety requirements).

[68 FR 8423, Feb. 20, 2003]



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

    Your casing and cementing programs must include:
    (a) Hole sizes and casing sizes, including: weights; grades; 
collapse, and burst values; types of connection; and setting depths 
(measured and true vertical depth (TVD));
    (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 (incorporated by reference as specified 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
    (f) A written description of how you evaluated the best practices 
included in API RP 65-Part 2, Isolating Potential Flow Zones During Well 
Construction (incorporated by reference as specified in Sec. 250.198). 
Your written description must identify the mechanical barriers and 
cementing practices you will use for each casing string (reference API 
RP 65-Part 2, Sections 3 and 4).

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 8903, Feb. 28, 2007; 75 
FR 63372, Oct. 14, 2010; 75 FR 76632, Dec. 9, 2010]



Sec. 250.416  What must I include in the diverter and BOP descriptions?

    You must include in the diverter and BOP descriptions:
    (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 annular BOP 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;
    (c) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and pods, location of choke and kill lines, and associated 
valves;

[[Page 136]]

    (e) Independent third party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe in the hole under maximum 
anticipated surface pressure. The documentation must include test 
results and calculations of shearing capacity of all pipe to be used in 
the well including correction for MASP;
    (f) When you use a subsea BOP stack, independent third party 
verification that shows:
    (1) the BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will be 
used; and
    (g) The qualifications of the independent third party referenced in 
paragraphs (e) and (f) of this section:
    (1) The independent third party in paragraph (e) in this section 
must be a technical classification society; an API-licensed 
manufacturing, inspection, or certification firm; or a licensed 
professional engineering firm capable of providing the verifications 
required under this part. The independent third party must not be the 
original equipment manufacturer (OEM).
    (2) You must:
    (i) Include evidence that the firm you are using is reputable, the 
firm or its employees hold appropriate licenses to perform the 
verification in the appropriate jurisdiction, the firm carries industry-
standard levels of professional liability insurance, and the firm has no 
record of violations of applicable law.
    (ii) Ensure that an official representative of BOEMRE will have 
access to the location to witness any testing or inspections, and verify 
information submitted to BOEMRE. Prior to any shearing ram tests or 
inspections, you must notify the District Manager at least 24 hours in 
advance.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63372, Oct. 14, 2010]



Sec. 250.417  What must I provide if I plan to use a mobile offshore drilling unit (MODU)?

    If you plan to use a MODU, you must provide:
    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling location. This information must include the maximum 
environmental and operational conditions that the unit 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, the District 
Manager may approve your APD but require you to collect and report this 
information during operations. Under this circumstance, the District 
Manager has the right to revoke the approval of the APD if information 
collected during operations show that the drilling unit is not capable 
of performing at the proposed location.
    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD, you may reference that 
information. The District Manager may require you to conduct additional 
surveys and soil borings before approving the APD if additional 
information is needed to make a determination that the conditions are 
capable of supporting the drilling unit.
    (c) Frontier areas. (1) If the design of the drilling unit 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 unit's design. If required, you must obtain 
the third-party review according to Sec. 250.915 through Sec. 250.918. 
You may submit this information before submitting an APD.
    (2) If you plan to drill in a frontier area, you must have a 
contingency plan that addresses design and operating limitations of the 
drilling unit. Your plan must identify the actions

[[Page 137]]

necessary to maintain safety and prevent damage to the environment. 
Actions must include the suspension, curtailment, or modification of 
drilling or rig 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) U.S. Coast Guard (USCG) documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the USCG. 
You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (e) Floating drilling unit. If you use a floating drilling unit, you 
must indicate that you have a contingency plan for moving off location 
in an emergency situation.
    (f) Inspection of unit. The drilling unit must be available for 
inspection by the District Manager before commencing operations.
    (g) Once the District Manager has approved a MODU for use, you do 
not need to re-submit the information required by this section for 
another APD to use the same MODU unless changes in equipment affect its 
rated capacity to operate in the District.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



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 some 
cement to facilitate casing removal upon well abandonment;
    (h) Certification of your casing and cementing program as required 
in Sec. 250.420(a)(6);
    (i) Description of qualifications required by Sec. 250.416(f) of 
any independent third party; and
    (j) Such other information as the District Manager may require.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63372, Oct. 14, 2010]

                    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 requirements of this section and of Sec. Sec. 
250.421 through 250.428.
    (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; and
    (6) Include certification signed by a Registered Professional 
Engineer that there will be at least two independent tested barriers, 
including one mechanical barrier, across each flow path during well 
completion activities and that the casing and cementing design is 
appropriate for the purpose for which it is intended under expected 
wellbore conditions. The Registered Professional Engineer must be 
registered in a State in the United States. Submit this certification 
with your APD (Form MMS-123).

[[Page 138]]

    (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) For the final casing string (or liner if it is your final 
string), you must install dual mechanical barriers in addition to 
cement, to prevent flow in the event of a failure in the cement. These 
may include dual float valves, or one float valve and a mechanical 
barrier. You must submit documentation to BOEMRE 30 days after 
installation of the dual mechanical barriers.
    (c) Cementing requirements. 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 of the casing or before commencing completion operations.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63373, Oct. 14, 2010]



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.

------------------------------------------------------------------------
                                        Casing             Cementing
           Casing type               requirements        requirements
------------------------------------------------------------------------
(a) Drive or Structural.........  Set by driving,     If you drilled a
                                   jetting, or         portion of this
                                   drilling to the     hole, you must
                                   minimum depth as    use enough cement
                                   approved or         to fill the
                                   prescribed by the   annular space
                                   District Manager.   back to the
                                                       mudline.
(b) Conductor...................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space
                                   engineering and     back to the
                                   geologic factors.   mudline.
                                   These factors      Verify annular
                                   include the         fill by observing
                                   presence or         cement returns.
                                   absence of          If you cannot
                                   hydrocarbons,       observe cement
                                   potential           returns, use
                                   hazards, and        additional cement
                                   water depths.       to ensure fill-
                                  Set casing           back to the
                                   immediately         mudline.
                                   before drilling    For drilling on an
                                   into formations     artificial island
                                   known to contain    or when using a
                                   oil or gas. If      glory hole, you
                                   you encounter oil   must discuss the
                                   or gas or           cement fill level
                                   unexpected          with the District
                                   formation           Manager.
                                   pressure before
                                   the planned
                                   casing point, you
                                   must set casing
                                   immediately.
(c) Surface.....................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space to
                                   engineering and     at least 200 feet
                                   geologic factors.   inside the
                                   These factors       conductor casing.
                                   include the        When geologic
                                   presence or         conditions such
                                   absence of          as near-surface
                                   hydrocarbons,       fractures and
                                   potential           faulting exist,
                                   hazards, and        you must use
                                   water depths.       enough cement to
                                                       fill the
                                                       calculated
                                                       annular space to
                                                       the mudline.
(d) Intermediate................  Design casing and   Use enough cement
                                   select setting      to cover and
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones and
                                   geologic            isolate abnormal
                                   characteristics     pressure
                                   or wellbore         intervals from
                                   conditions.         normal 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
                                   select setting      to cover or
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones
                                   geologic            above the shoe.
                                   characteristics    As a minimum, you
                                   or wellbore         must cement the
                                   conditions.         annular space at
                                                       least 500 feet
                                                       above the casing
                                                       shoe and 500 feet
                                                       above the
                                                       uppermost
                                                       hydrocarbon-
                                                       bearing zone.

[[Page 139]]

 
(f) Liners......................  If you use a liner  Same as cementing
                                   as conductor or     requirements for
                                   surface casing,     specific casing
                                   you must set the    types. For
                                   top of the liner    example, a liner
                                   at least 200 feet   used as
                                   above the           intermediate
                                   previous casing/    casing must be
                                   liner shoe.         cemented
                                  If you use a liner   according to the
                                   as an               cementing
                                   intermediate        requirements for
                                   string below a      intermediate
                                   surface string or   casing.
                                   production casing
                                   below an
                                   intermediate
                                   string, you must
                                   set the top of
                                   the liner at
                                   least 100 feet
                                   above the
                                   previous casing
                                   shoe..
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.423  What are the requirements for pressure testing casing?

    (a) The table in this section describes the minimum test pressures 
for each string of casing. You may not resume drilling or other down-
hole 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 re-cement, repair the casing, 
or run additional casing to provide a proper seal. The District Manager 
may approve or require other casing test pressures.

------------------------------------------------------------------------
             Casing type                     Minimum test pressure
------------------------------------------------------------------------
 (1) Drive or Structural............  Not required.
 (2) Conductor......................  200 psi.
 (3) Surface, Intermediate, and       70 percent of its minimum internal
 Production.                           yield.
------------------------------------------------------------------------

    (b) You must ensure proper installation of casing or liner in the 
subsea wellhead or liner hanger.
    (1) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of each casing string or liner.
    (2) 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 liner.
    (3) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (4) You must document all your test results and make them available 
to BOEMRE upon request.
    (c) You must perform a negative pressure test on all wells to ensure 
proper casing installation. You must perform this test for the 
intermediate and production casing strings.
    (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 BOEMRE upon request.

[75 FR 63373, Oct. 14, 2010]



Sec. 250.424  What are the requirements for prolonged drilling operations?

    If wellbore operations continue for more than 30 days within a 
casing string run to the surface:
    (a) You must stop drilling operations as soon as practicable, and 
evaluate the effects of the prolonged operations on continued drilling 
operations and

[[Page 140]]

the life of the well. At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Manager before you begin 
repairs.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.425  What are the requirements for pressure testing liners?

    (a) You must test each drilling liner (and liner-lap) to a pressure 
at least equal to the anticipated pressure to which the liner will be 
subjected during the formation pressure-integrity test below that liner 
shoe, or subsequent liner shoes if set. The District Manager may approve 
or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a minimum 
of 500 psi above the formation fracture pressure at the casing shoe into 
which the liner is lapped.
    (c) You may not resume drilling or other down-hole 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 re-cement, repair the liner, or run additional casing/
liner to provide a proper seal.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.426  What are the recordkeeping requirements for casing and liner pressure tests?

    You must record the time, date, and results of each pressure test in 
the driller's report maintained under standard industry practice. In 
addition, you must record each test on a pressure chart and have your 
onsite representative sign and date the test as being correct.

[68 FR 8423, Feb. 20, 2003]



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 margin 
identified in the approved APD. When you cannot maintain this safe 
margin, you must suspend drilling operations and remedy the situation.

[68 FR 8423, Feb. 20, 2003]



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     Submit a revised casing program to the
 pressures or conditions that      District Manager for approval.
 warrant revising your casing
 design.

[[Page 141]]

 
(b) Need to increase casing       Submit those changes to the District
 setting depths more than 100      Manager for approval.
 feet true vertical depth (TVD)
 from the approved APD due to
 conditions encountered during
 drilling operations.
(c) Have indication of            (1) Pressure test the casing shoe; (2)
 inadequate cement job (such as    Run a temperature survey; (3) Run a
 lost returns, cement              cement bond log; or (4) Use a
 channeling, or failure of         combination of these techniques.
 equipment).
(d) Inadequate cement job.......  Re-cement or take other remedial
                                   actions as approved by the District
                                   Manager.
(e) Primary cement job that did   Isolate those intervals from normal
 not isolate abnormal pressure     pressures by squeeze cementing before
 intervals.                        you complete; suspend operations; or
                                   abandon the well, whichever occurs
                                   first.
(f) Decide to produce a well      Have at least two cemented casing
 that was not originally           strings (does not include liners) in
 contemplated for production.      the well. Note: All producing wells
                                   must have at least two cemented
                                   casing strings.
(g) Want to drill a well without  Submit geologic data and information
 setting conductor casing.         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         Submit information to the District
 required cement for the surface   Manager that demonstrates the use of
 casing during floating drilling   less cement is necessary.
 operations to provide
 protection from burst and
 collapse pressures.
(i) Cement across a permafrost    Use cement that sets before it freezes
 zone.                             and has a low heat of hydration.
(j) Leave the annulus opposite a  Fill the annulus with a liquid that
 permafrost zone uncemented.       has a freezing point below the
                                   minimum permafrost temperature and
                                   minimizes opposite a corrosion.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

                      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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[[Page 142]]



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


[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]

               Blowout Preventer (BOP) System Requirements



Sec. 250.440  What are the general requirements for BOP systems and system components?

    You must design, install, maintain, test, and use the BOP system and 
system components to ensure well control. The working-pressure rating of 
each BOP component must exceed maximum anticipated surface pressures. 
The BOP system includes the BOP stack and associated BOP systems and 
equipment.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, 
and one BOP equipped with blind or blind-shear rams.
    (b) Your surface BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP, 
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear 
rams. The blind-shear rams must be capable of shearing the drill pipe 
that is in the hole.

[[Page 143]]

    (c) You must install an accumulator system that provides 1.5 times 
the volume of fluid capacity necessary to close and hold closed all BOP 
components. The system must perform with a minimum pressure of 200 psi 
above the precharge pressure without assistance from a charging system. 
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.
    (d) In addition to the stack and accumulator system, you must 
install the associated BOP systems and equipment required by the 
regulations in this subpart.

[68 FR 8423, Feb. 20, 2003, as amended at 74 FR 46908, Sept. 14, 2009]



Sec. 250.442  What are the requirements for a subsea BOP system?

    When you drill with a subsea BOP system, you must install the BOP 
system before drilling below the surface casing. The District Manager 
may require you to install a subsea BOP system before drilling below the 
conductor casing if proposed casing setting depths or local geology 
indicate the need. The table in this paragraph outlines your 
requirements.

------------------------------------------------------------------------
  When drilling with a subsea BOP
         system, you must:                 Additional requirements
------------------------------------------------------------------------
(a) Have at least four remote-       You must have at least one annular
 controlled, hydraulically operated   BOP, two BOPs equipped with pipe
 BOPs.                                rams, and one BOP equipped with
                                      blind-shear rams. The blind-shear
                                      rams must be capable of shearing
                                      any drill pipe in the hole under
                                      maximum anticipated surface
                                      pressures.
(b) Have an operable dual-pod
 control system to ensure proper
 and independent operation of the
 BOP system.
(c) Have an accumulator system to    The accumulator system must meet or
 provide fast closure of the BOP      exceed the provisions of Section
 components and to operate all        13.3, Accumulator Volumetric
 critical functions in case of a      Capacity, in API RP 53,
 loss of the power fluid connection   Recommended Practices for Blowout
 to the surface.                      Prevention Equipment Systems for
                                      Drilling Wells (incorporated by
                                      reference as specified in Sec.
                                      250.198). The District Manager may
                                      approve a suitable alternate
                                      method.
(d) Have a subsea BOP stack          At a minimum, the ROV must be
 equipped with remotely operated      capable of closing one set of pipe
 vehicle (ROV) intervention           rams, closing one set of blind-
 capability.                          shear rams and unlatching the
                                      LMRP.
(e) Maintain an ROV and have a       The crew must be trained in the
 trained ROV crew on each floating    operation of the ROV. The training
 drilling rig on a continuous         must include simulator training on
 basis. The crew must examine all     stabbing into an ROV intervention
 ROV related well control equipment   panel on a subsea BOP stack.
 (both surface and subsea) to
 ensure that it is properly
 maintained and capable of shutting
 in the well during emergency
 operations.
(f) Provide autoshear and deadman    (1) Autoshear system means a safety
 systems for dynamically positioned   system that is designed to
 rigs.                                automatically shut in the wellbore
                                      in the event of a disconnect of
                                      the LMRP. When the autoshear is
                                      armed, a disconnect of the LMRP
                                      closes the shear rams. This is
                                      considered a ``rapid discharge''
                                      system.
                                     (2) Deadman System means a safety
                                      system that is designed to
                                      automatically close 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.
                                     (3) You may also have an acoustic
                                      system.
(g) Have operational or physical     Incorporate enable buttons on
 barrier(s) on BOP control panels     control panels to ensure two-
 to prevent accidental disconnect     handed operation for all critical
 functions.                           functions.
(h) Clearly label all control        Label other BOP control panels such
 panels for the subsea BOP system.    as hydraulic control panel.
(i) Develop and use a management     The management system must include
 system for operating the BOP         written procedures for operating
 system, including the prevention     the BOP stack and LMRP (including
 of accidental or unplanned           proper techniques to prevent
 disconnects of the system.           accidental disconnection of these
                                      components) and minimum knowledge
                                      requirements for personnel
                                      authorized to operate and maintain
                                      BOP components.
(j) Establish minimum requirements   Personnel must have:
 for personnel authorized to
 operate critical BOP equipment.
                                        (1) Training in deepwater well
                                         control theory and practice
                                         according to the requirements
                                         of 30 CFR 250, subpart O; and
                                        (2) A comprehensive knowledge of
                                         BOP hardware and control
                                         systems.
(k) Before removing the marine       You must maintain sufficient
 riser, displace the fluid in the     hydrostatic pressure or take other
 riser with seawater.                 suitable precautions to compensate
                                      for the reduction in pressure and
                                      to maintain a safe and controlled
                                      well condition.

[[Page 144]]

 
(l) Install the BOP stack in a       Your glory hole must be deep enough
 glory hole when in ice-scour area.   to ensure that the top of the
                                      stack is below the deepest
                                      probable ice-scour depth.
------------------------------------------------------------------------


[75 FR 63373, Oct. 14, 2010]



Sec. 250.443  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 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.
    (b) At least two BOP control stations. One station must be on the 
drilling floor. You must locate the other station in a readily 
accessible location away from the drilling floor.
    (c) Side outlets on the BOP stack for separate kill and choke lines. 
If your stack does not have side outlets, you must install a drilling 
spool with side outlets.
    (d) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be 
remote-controlled. In addition:
    (1) You must install the choke line above the bottom ram;
    (2) You may install the kill line below the bottom ram; and
    (3) For a surface BOP system, 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.
    (e) A fill-up line above the uppermost BOP.
    (f) Locking devices installed on the ram-type BOPs.
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated surface pressure.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.444  What are the choke manifold requirements?

    (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 rated working pressure at 
least as great as the rated working pressure 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 rated working pressure at least as 
great as the rated working pressure of the ram BOPs.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.445  What are the requirements for kelly valves, inside BOPs, and

drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly valve installed below the swivel (upper kelly valve);
    (b) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (c) If you drill with a mud motor and use drill pipe instead of a 
kelly, you must install one kelly valve above, and one strippable kelly 
valve below, the joint of drill pipe used in place of a kelly;
    (d) On a top-drive system equipped with a remote-controlled valve, 
you must install a strippable kelly-type valve below the remote-
controlled valve;
    (e) An inside BOP in the open position located on the rig floor. You 
must

[[Page 145]]

be able to install an inside BOP for each size connection in the drill 
string;
    (f) 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 drill string;
    (g) When running casing, you must have a safety valve in the open 
position available on the rig floor to fit the casing string being run 
in the hole;
    (h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e. kelly-type valve 
in a top-drive system) must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit each 
manual valve.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.446  What are the BOP maintenance and inspection requirements?

    (a) You must maintain and inspect your BOP system to ensure that the 
equipment functions properly. The BOP maintenance and inspections must 
meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, Recommended Practices for 
Blowout Prevention Equipment Systems for Drilling Wells (incorporated by 
reference as specified in Sec. 250.198). You must document the 
procedures used, record the results of your BOP inspections and 
maintenance actions, and make available to BOEMRE upon request. You must 
maintain your records on the rig for 2 years or from the date of your 
last major inspection, whichever is longer;
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine riser 
at least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect subsea equipment.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]



Sec. 250.447  When must I pressure test the BOP system?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly valves, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Manager may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Manager may allow you to omit this test if you didn't remove 
the BOP stack to run the casing string or liner and the required BOP 
test pressures for the next section of the hole are not greater than the 
test pressures for the previous BOP test. You must indicate in your APD 
which casing strings and liners meet these criteria.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:
    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) for the 
applicable section of hole. Before you may test BOP equipment to the 
MASP plus 500 psi, the District Manager must

[[Page 146]]

have approved those test pressures in your APD.
    (c) High pressure test for annular-type BOPs. The high pressure test 
must equal 70 percent of the rated working pressure of the equipment or 
to a pressure approved in your APD.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes. However, for surface BOP systems and surface 
equipment of a subsea BOP system, a 3-minute test duration is acceptable 
if you record your test pressures on the outermost half of a 4-hour 
chart, on a 1-hour chart, or on a digital recorder. If the equipment 
does not hold the required pressure during a test, you must correct the 
problem and retest the affected component(s).

[68 FR 8423, Feb. 20, 2003]



Sec. 250.449  What additional BOP testing requirements must I meet?

    You must meet the following additional BOP testing requirements:
    (a) Use water to test a surface BOP system;
    (b) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system;
    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram BOP during stump 
tests and at all casing points;
    (e) The interval between any blind or blind-shear ram BOP pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe ram BOPs against the largest 
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annular and ram BOPs every 7 days between pressure 
tests;
    (i) Actuate safety valves assembled with proper casing connections 
before running casing;
    (j) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APD or APM for District Manager approval. You must:
    (1) ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP; and
    (2) document all your test results and make them available to BOEMRE 
upon request;
    (k) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor.
    (1) You must submit test procedures with your APD or APM for 
District Manager approval.
    (2) You must document all your test results and make them available 
to BOEMRE upon request.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]



Sec. 250.450  What are the recordkeeping requirements for BOP tests?

    You must record the time, date, and results of all pressure tests, 
actuations, and inspections of the BOP system, system components, and 
marine riser in the driller's report. In addition, you must:
    (a) Record BOP test pressures on pressure charts;
    (b) Require your onsite representative to sign and date BOP test 
charts and reports as correct;
    (c) Document 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 the control station and pod used during the test;
    (e) Identify any problems or irregularities observed during BOP 
system testing and record actions taken to remedy the problems or 
irregularities; and
    (f) Retain all records, including pressure charts, driller's report, 
and referenced documents pertaining to BOP

[[Page 147]]

tests, actuations, and inspections at the facility for the duration of 
drilling.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.451  What must I do in certain situations involving BOP equipment or systems?

    The table in this section describes actions that lessees must take 
when certain situations occur with BOP systems during drilling 
activities.

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the         Correct the problem and
 required pressure during a test.            retest the affected
                                             equipment.
(b) Need to repair or replace a surface or  First place the well in a
 subsea BOP system.                          safe, controlled condition
                                             (e.g., before drilling out
                                             a casing shoe or after
                                             setting a cement plug,
                                             bridge plug, or a packer).
(c) Need to postpone a BOP test due to      Record the reason for
 well-control problems such as lost          postponing the test in the
 circulation, formation fluid influx, or     driller's report and
 stuck drill pipe.                           conduct the required BOP
                                             test on the first trip out
                                             of the hole.
(d) BOP control station or pod that does    Suspend further drilling
 not function properly.                      operations until that
                                             station or pod is operable.
(e) Want to drill with a tapered drill-     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 drill string.
(f) Install casing rams in a BOP stack....  Test the ram bonnets before
                                             running casing.
(g) Want to use an annular BOP with a       Demonstrate that your well
 rated working pressure less than the        control procedures or the
 anticipated surface pressure.               anticipated well conditions
                                             will not place demands
                                             above its rated working
                                             pressure and obtain
                                             approval from the District
                                             Manager.
(h) Use a subsea BOP system in an ice-      Install the BOP stack in a
 scour area.                                 glory hole. The glory hole
                                             must be deep enough to
                                             ensure that the top of the
                                             stack is below the deepest
                                             probable ice-scour depth.
(i) You activate blind-shear rams or        Retrieve, physically
 casing shear rams during a well control     inspect, and conduct a full
 situation, in which pipe or casing is       pressure test of the BOP
 sheared.                                    stack after the situation
                                             is fully controlled.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]

                       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.

[68 FR 8423, Feb. 20, 2003]



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;

[[Page 148]]

    (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;
    (j) Before displacing kill-weight drilling fluid from the wellbore, 
you must obtain prior approval from the District Manager. To obtain 
approval, you must submit with your APD or APM your reasons for 
displacing the kill-weight drilling 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 that are in place for 
each flow path,
    (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 fluids entering and leaving 
the wellbore; and
    (k) 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.

[68 FR 8423, Feb. 20, 2003; 68 FR 14274, Mar. 24, 2003, as amended at 75 
FR 63374, Oct. 14, 2010]



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 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

[[Page 149]]

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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 (incorporated by reference as specified 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 (incorporated by 
reference as specified 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.

[68 FR 8423, Feb. 20, 2003]

                       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 MMS-123) or in an 
Application for Permit to Modify (APM) (form MMS-124). 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;

[[Page 150]]

    (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.

[68 FR 8423, Feb. 20, 2003]



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

    For this subpart, MMS 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.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.462  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with each drilling 
crew. Your drill must familiarize the crew with its roles and functions 
so that all crew members can perform their duties promptly and 
efficiently.
    (a) Well-control drill plan. You must prepare a well control drill 
plan for each well. Your plan must outline the assignments for each crew 
member and establish times to complete each portion of the drill. You 
must post a copy of the well control drill plan on the rig floor or 
bulletin board.
    (b) Timing of drills. You must conduct each drill during a period of 
activity that minimizes the risk to drilling operations. The timing of 
your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.
    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) MMS ordered drill. An MMS authorized representative may require 
you to conduct a well control drill during an MMS inspection. The MMS 
representative will consult with your onsite representative before 
requiring the drill.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.463  Who establishes field drilling rules?

    (a) The District Manager may establish field drilling rules 
different from

[[Page 151]]

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.

[68 FR 8423, Feb. 20, 2003]

            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 MMS?

    (a) You must submit an APM (form MMS-124) or an End of Operations 
Report (form MMS-125) 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 your       Submit form MMS-   Receive written or
 drilling plan, change major     124 or request     oral approval from
 drilling equipment, or          oral approval.     the District Manager
 plugback.                                          before you begin the
                                                    intended operation.
                                                    If you get an
                                                    approval, you must
                                                    submit form MMS-124
                                                    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 final    Immediately        Submit a plat
 surface location, water         Submit a form      certified by a
 depth, and the rotary kelly     MMS-124.           registered land
 bushing elevation.                                 surveyor that meets
                                                    the requirements of
                                                    Sec.  250.412.
(3) Move a drilling unit from   Submit forms MMS-  Submit appropriate
 a wellbore before completing    124 and MMS-125    copies of the well
 a well.                         within 30 days     records.
                                 after 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 MMS-124) 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 MMS-124 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 form 
MMS-124 with detailed information about the work to the District 
Manager, unless you have already provided sufficient information in a 
Well Activity Report, form MMS-133 (Sec. 250.468(b)).

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.466  What records must I keep?

    You must keep complete, legible, and accurate records for each well. 
You must keep drilling records onsite while drilling activities 
continue. After completion of drilling activities, you must keep all 
drilling and other well records for the time periods shown in Sec. 
250.467. You may keep these records at a location of your choice. The 
records must contain complete information on all of the following:
    (a) Well operations;
    (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
    (g) All other information required by the District Manager in the 
interests of resource evaluation, waste prevention, conservation of 
natural resources, and

[[Page 152]]

the protection of correlative rights, safety, and environment.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



Sec. 250.467  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...........................  Ninety days after you complete
                                          drilling operations.
(b) Casing and liner pressure tests,     Two years after the completion
 diverter tests, and BOP tests.           of drilling operations.
(c) Completion of a well or of any       You permanently plug and
 workover activity that materially        abandon the well or until you
 alters the completion configuration or   forward the records with a
 affects a hydrocarbon-bearing zone.      lease assignment.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



Sec. 250.468  What well records am I required to submit?

    (a) You must submit 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 to MMS. Each Region will provide specific instructions for 
submitting well logs and surveys.
    (b) For drilling operations in the GOM OCS Region, you must submit 
form MMS-133, Well Activity Report, to the District Manager on a weekly 
basis.
    (c) For drilling operations in the Pacific or Alaska OCS Regions, 
you must submit form MMS-133, Well Activity Report, to the District 
Manager on a daily basis.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.469  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. 250.466;
    (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 prescribes 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.

[68 FR 8423, Feb. 20, 2003]

                            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:

[[Page 153]]

    (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 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 MMS 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;

[[Page 154]]

    (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 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,

[[Page 155]]

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 (incorporated by reference 
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:
    (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

[[Page 156]]

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.
    (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.

[[Page 157]]

    (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:
    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by MMS 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 SO2 concentration 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 (incorporated by reference 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.

[[Page 158]]

    (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 
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 MMS in the event of an H2S release? You must 
notify MMS 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

[[Page 159]]

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 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 H\2\S-bearing fluids in conformance 
with NACE Standard MR0175-03 (incorporated by reference 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.

[[Page 160]]

    (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-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

[[Page 161]]

by atomic hydrogen when H2S is present.

[62 FR 3795, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 65 FR 15864, Mar. 24, 2000. Redesignated and 
amended at 68 FR 8423, 8434, Feb. 20, 2003; 71 FR 19645, Apr. 17, 2006; 
72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007; 75 FR 20289, Apr. 
19, 2010]



            Subpart E_Oil and Gas Well-Completion Operations



Sec. 250.500  General requirements.

    Well-completion 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. 250.501  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  Equipment movement.

    The movement of well-completion rigs and related equipment on and 
off a platform or from well to well on the same platform, including 
rigging up and rigging down, shall be conducted in a safe manner. All 
wells in the same well-bay which are capable of producing hydrocarbons 
shall 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 well-
completion rigs and related equipment, unless otherwise approved by the 
District Manager. 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. The well from which the rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the blowout preventer (BOP) system and installing the tree.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47752, Nov. 15, 1990. 
Redesignated at 63 FR 29479, May 29, 1998]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8434, Feb. 20, 2003]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



Sec. 250.506  Crew instructions.

    Prior to engaging in well-completion operations, crew members shall 
be instructed in the safety requirements of the operations to be 
performed, possible hazards to be encountered, and

[[Page 162]]

general safety considerations to protect personnel, equipment, and the 
environment. Date and time of safety meetings shall be recorded and 
available at the facility for review by MMS representatives.



Sec. Sec. 250.507-250.508  [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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. 
Redesignated at 63 FR 29479, May 29, 1998]



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.

[74 FR 46908, Sept. 14, 2009]



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.

[74 FR 46908, Sept. 14, 2009]



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 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 MMS-123 and MMS-
123S), 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 MMS-124) for approval of such operations.
    (b) You must submit the following with Form MMS-124 (or with Form 
MMS-123; Form MMS-123S):
    (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) When the well-completion is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown,

[[Page 163]]

information pursuant to Sec. 250.490 of this part; and
    (5) 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 MMS-125), including a 
schematic of the tubing and subsurface equipment.
    (d) You must submit public information copies of Form MMS-125 
according to Sec. 250.186.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 68 FR 8434, Feb. 20, 2003; 71 FR 19646, Apr. 17, 
2006; 71 FR 40911, July 19, 2006; 72 FR 25201, May 4, 2007]



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.



Sec. 250.515  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 
rating of the BOP system and BOP system components shall exceed the 
expected surface pressure to which they may be subjected. If the 
expected surface pressure exceeds the rated working pressure of the 
annular preventer, the lessee shall submit with Form MMS-124 or Form 
MMS-123, as appropriate, a well-control procedure that indicates how the 
annular preventer will be utilized, and the pressure limitations that 
will be applied during each mode of pressure control.
    (b) The minimum BOP system for well-completion operations must meet 
the appropriate standards from the following table:

------------------------------------------------------------------------
                                           The minimum BOP stack must
                 When                               include
------------------------------------------------------------------------
(1) The expected pressure is less      Three BOPs consisting of an
 than 5,000 psi,.                       annular, one set of pipe rams,
                                        and one set of blind-shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings,.                       and one set of blind-shear rams.
(3) You handle multiple tubing         Four BOPs consisting of an
 strings simultaneously,.               annular, one set of pipe rams,
                                        one set of dual pipe rams, and
                                        one set of blind-shear rams.
(4) You use a tapered drill string,..  At least one set of pipe rams
                                        that are capable of sealing
                                        around each size of drill
                                        string. 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 string. You may substitute
                                        one set of variable bore rams
                                        for two sets of pipe rams.
(5) You use a subsea BOP stack.......  The requirements in Sec.
                                        250.442(a) of this part.
------------------------------------------------------------------------


[[Page 164]]

    (c) The BOP systems for well completions must be equipped with the 
following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
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 and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost.
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components 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.
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke 
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided that two readily accessible manual valves are in place and the 
check valve is placed between the manual valves and the pump. This 
equipment shall have a pressure rating at least equivalent to the ram 
preventers.
    (d) 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-
completion operations. 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.
    (e) The subsea BOP system for well-completions must meet the 
requirements in Sec. 250.442 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 62 29479, May 29, 1998, as 
amended at 68 FR 8434, Feb. 20, 2003; 74 FR 46908, Sept. 14, 2009; 75 FR 
63375, Oct. 14, 2010]



Sec. 250.516  Blowout preventer system tests, inspections, and maintenance.

    (a) BOP pressure testing timeframes. You must pressure test your BOP 
system:
    (1) When installed; and
    (2) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before 12 a.m. (midnight) on the 
14th day following the conclusion of the previous test. However, the 
District Manager may require testing every 7 days if conditions or BOP 
performance warrant.
    (b) BOP test pressures. When you test the BOP system, you must 
conduct a low pressure and a high pressure test for each BOP component. 
Each individual pressure test must hold pressure long enough to 
demonstrate that the tested component(s) holds the required pressure. 
The District Manager may approve or require other test pressures or 
practices. Required test pressures are as follows:
    (1) All low pressure tests must be between 200 and 300 psi. Any 
initial pressure above 300 psi must be bled back to a pressure between 
200 and 300 psi before starting the test. If the initial pressure 
exceeds 500 psi, you must bleed back to zero and reinitiate the test. 
You must conduct the low pressure test before the high pressure test.
    (2) For ram-type BOP's, choke manifold, and other BOP equipment, the 
high pressure test must equal the rated working pressure of the 
equipment.
    (3) For annular-type BOP's, the high pressure test must equal 70 
percent of the rated working pressure of the equipment.
    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes.
    (1) For surface BOP systems and surface equipment of a subsea BOP 
system, a 3-minute test duration is acceptable if you record your test 
pressures on the outermost half of a 4-hour

[[Page 165]]

chart, on a 1-hour chart, or on a digital recorder.
    (2) If the equipment does not hold the required pressure during a 
test, you must remedy the problem and retest the affected component(s).
    (d) Additional BOP testing requirements. You must:
    (1) Use water to test the surface BOP system;
    (2) Stump test a subsurface BOP system before installation. You must 
use water to stump test a subsea BOP system. You may use drilling or 
completion fluids to conduct subsequent tests of a subsea BOP system;
    (3) Alternate tests between control stations and pods. If a control 
station or pod is not functional, you must suspend further completion 
operations until that station or pod is operable;
    (4) Pressure test the blind or blind-shear ram at least every 30 
days;
    (5) Function test annulars and rams every 7 days;
    (6) Pressure-test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools;
    (7) Test affected BOP components following the disconnection or 
repair of any well-pressure containment seal in the wellhead or BOP 
stack assembly;
    (8) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APM for District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to 
BOEMRE upon request; and
    (9) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor.
    (i) You must submit test procedures with your APM for District 
Manager approval.
    (ii) You must document all your test results and make them available 
to BOEMRE upon request.
    (e) Postponing BOP tests. You may postpone a BOP test if you have 
well-control problems. You must conduct the required BOP test as soon as 
possible (i.e., first trip out of the hole) after the problem has been 
remedied. You must record the reason for postponing any test in the 
driller's report.
    (f) Weekly crew drills. You must conduct a weekly drill to 
familiarize all personnel engaged in well-completion operations with 
appropriate safety measures.
    (g) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec. 250.198). You must document the procedures used, 
record the results, and make them available to BOEMRE upon request. You 
must maintain your records on the rig for 2 years or from the date of 
your last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The District Manager may 
approve alternate methods and frequencies to inspect a marine riser.
    (h) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec. 
250.198). You must document the procedures used, record the results, and 
make available to BOEMRE upon request. You must maintain your records on 
the rig for 2 years or from the date of your last major inspection, 
whichever is longer.
    (i) BOP test records. You must record the time, date, and results of 
all pressure tests, actuations, crew drills, and

[[Page 166]]

inspections of the BOP system, system components, and marine riser in 
the driller's report. In addition, you must:
    (1) Record BOP test pressures on pressure charts;
    (2) Have your onsite representative certify (sign and date) BOP test 
charts and reports as correct;
    (3) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. You may reference a 
BOP test plan if it is available at the facility;
    (4) Identify the control station or pod used during the test;
    (5) Identify any problems or irregularities observed during BOP 
system and equipment testing and record actions taken to remedy the 
problems or irregularities;
    (6) Retain all records including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of the completion activity; 
and
    (7) After completion of the well, you must retain all the records 
listed in paragraph (i)(6) of this section 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.
    (j) Alternate methods. The District Manager may require, or approve, 
more frequent testing, as well as different test pressures and 
inspection methods, or other practices.

[63 FR 29607, June 1, 1998, as amended at 75 FR 63375, Oct. 14, 2010]



Sec. 250.517  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) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure-tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) When the tree is installed, you must equip wells to monitor for 
casing pressure according to the following chart:

------------------------------------------------------------------------
                                 you must equip *   so you can monitor *
       If you have * * *               * *                  * *
------------------------------------------------------------------------
(1) fixed platform wells,.....  the wellhead,....  all annuli (A, B, C,
                                                    D, etc., annuli).
(2) subsea wells,.............  the tubing head,.  the production casing
                                                    annulus (A annulus).
(3) hybrid* wells,............  the surface        all annuli at the
                                 wellhead,.         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.

    (d) 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.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec. 250.801 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753 Nov. 15, 1990. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 75 FR 
23584, May 4, 2010]

                       Casing Pressure Management

    Source: 75 FR 23584, May 4, 2010, unless otherwise noted.

[[Page 167]]



Sec. 250.518  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 (incorporated by reference as 
specified 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 follow the requirements 
of this subpart.



Sec. 250.519  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
       If you have * * *         you must monitor   pressure data 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     daily,...........  day for each casing.
 casing pressure request on a
 manned fixed platform,
(e) wells operating under a     weekly,..........  week for each casing.
 casing pressure request on an
 unmanned fixed platform,
------------------------------------------------------------------------



Sec. 250.520  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 diagnostic
        If you have a * * *                     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.



Sec. 250.521  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.



Sec. 250.522  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         immediately.
 approved term has expired,.
(b) your well, previously on gas lift,   immediately on the production
 has been shut-in or returned to          casing (A annulus). The
 flowing status without gas lift for      production casing (A annulus)
 more than 180 days,                      of wells on active gas lift
                                          are exempt from diagnostic
                                          testing.
(c) your casing pressure request         within 30 days.
 becomes invalid,.
(d) a casing or riser has an increase    within 30 days.
 in pressure greater than 200 psig over
 the previous casing diagnostic test,
(e) after any corrective action has      within 30 days.
 been taken to remediate undesirable
 casing pressure, either as a result of
 a casing pressure request denial or
 any other action,

[[Page 168]]

 
(f) your fixed platform well production  once per year, not to exceed 12
 casing (A annulus) has pressure          months between tests.
 exceeding 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,
------------------------------------------------------------------------



Sec. 250.523  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.



Sec. 250.524  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.



Sec. 250.525  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:           to the appropriate:      and it must include:        You must also:
----------------------------------------------------------------------------------------------------------------
(a) a notification of corrective       District Manager and     requirements under Sec. submit an Application
 action; or,                            copy the Regional          250.526.               for Permit to Modify
                                        Supervisor, Field                                 or Corrective Action
                                        Operations,                                       Plan within 30 days of
                                                                                          the diagnostic test.
(b) a casing pressure request,.......  Regional Supervisor,     requirements under Sec.
                                        Field Operations,          250.527.
----------------------------------------------------------------------------------------------------------------



Sec. 250.526  What must I include in my notification of corrective action?

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



Sec. 250.527  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);

[[Page 169]]

    (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;
    (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.



Sec. 250.528  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.



Sec. 250.529  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).



Sec. 250.530  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.



             Subpart F_Oil and Gas Well-Workover Operations



Sec. 250.600  General requirements.

    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 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.



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

[[Page 170]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 71 FR 11313, Mar. 7, 2006]



Sec. 250.602  Equipment movement.

    The movement of well-workover rigs and related equipment on and off 
a platform or from well to well on the same platform, including rigging 
up and rigging down, shall be conducted in a safe manner. All wells in 
the same well-bay which are capable of producing hydrocarbons shall 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 well-workover 
rigs and related equipment unless otherwise approved by the District 
Manager. 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. 
The well to which a well-workover rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the tree and installing and testing the blowout-preventer (BOP) 
system. The well from which a well-workover rig or related equipment is 
to be moved shall also be equipped with a back pressure valve prior to 
removing the BOP system and installing the tree. Coiled tubing units, 
snubbing units, or wireline units may be moved onto a platform without 
shutting in wells.



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 64 FR 9065, Feb. 24, 1999; 68 FR 8435, Feb. 20, 
2003]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



Sec. 250.606  Crew instructions.

    Prior to engaging in 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

[[Page 171]]

meetings shall be recorded and available at the facility for review by a 
Minerals Management Service representative.



Sec. Sec. 250.607-250.608  [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 
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.

    No later than May 31, 1989, diesel engine air intakes shall be 
equipped with a device to shut down the diesel engine in the event of 
runaway. Diesel engines which are continuously attended shall be 
equipped with either remote operated manual or automatic shutdown 
devices. Diesel engines which are not continuously attended shall be 
equipped with automatic shutdown devices.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.611  Traveling-block safety device.

    After May 31, 1989, all units being used for well-workover 
operations which have both a traveling block and a crown block shall be 
equipped with a safety device which is designed to prevent the traveling 
block from striking the crown block. The device shall be checked for 
proper operation weekly and after each drill-line slipping operation. 
The results of the operational check shall be entered in the operations 
log.



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 MMS-124, Application for Permit to 
Modify.
    (b) You must submit the following with Form MMS-124:
    (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) 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
    (4) Payment of the service fee listed in Sec. 250.125.
    (c) The following additional information shall be submitted with 
Form MMS-124 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.

[[Page 172]]

    (d) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124, 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 MMS-125, 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.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 
35824, June 6, 2000; 68 FR 8435, Feb. 20, 2003; 71 FR 40912, July 19, 
2006; 72 FR 25201, May 4, 2007]



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.



Sec. 250.615  Blowout prevention equipment.

    (a) The BOP system, 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 
rating of the BOP system and system components shall exceed the expected 
surface pressure to which they may be subjected. If the expected surface 
pressure exceeds the rated working pressure of the annular preventer, 
the lessee shall submit with Form MMS-124, requesting approval of the 
well-workover operation, a well-control procedure that indicates how the 
annular preventer will be utilized, and the pressure limitations that 
will be applied during each mode of pressure control.
    (b) The minimum BOP system for well-workover operations with the 
tree removed must meet the appropriate standards from the following 
table:

------------------------------------------------------------------------
                                           The minimum BOP stack must
                 When                               include
------------------------------------------------------------------------
(1) The expected pressure is less      Three BOPs consisting of an
 than 5,000 psi,.                       annular, one set of pipe rams,
                                        and one set of blind-shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings,.                       and one set of blind-shear rams.
(3) You handle multiple tubing         Four BOPs consisting of an
 strings simultaneously,.               annular, one set of pipe rams,
                                        one set of dual pipe rams, and
                                        one set of blind-shear rams.

[[Page 173]]

 
(4) You use a tapered drill string,..  At least one set of pipe rams
                                        that are capable of sealing
                                        around each size of drill
                                        string. 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 string. You may substitute
                                        one set of variable bore rams
                                        for two sets of pipe rams.
(5) You use a subsea BOP stack.......  The requirements in Sec.
                                        250.442(a) of this part.
------------------------------------------------------------------------

    (c) The BOP systems for well-workover operations with the tree 
removed must be equipped with the following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
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 and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost;
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components 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. At least one of the valves on the choke-
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided two readily accessible manual valves are in place and the check 
valve is placed between the manual valves and the pump. This equipment 
shall have a pressure rating at least equivalent to the ram preventers.
    (d) The minimum BOP-system components for well-workover operations 
with the tree in place and performed through the wellhead inside of 
conventional tubing using small-diameter jointed pipe (usually \3/4\ 
inch to 1\1/4\ inch) as a work string, i.e., small-tubing operations, 
shall include the following:
    (1) Two sets of pipe rams, and
    (2) One set of blind rams.
    (e) The subsea BOP system for well-workover operations must meet the 
requirements in Sec. 250.442 of this part.
    (f) 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 for
BOP system when expected surface   expected surface   wells with returns
pressures are less than or equal     pressures are     taken through an
          to 3,500 psi            greater than 3,500   outlet on the BOP
                                          psi                stack
------------------------------------------------------------------------
Stripper or annular-type well     Stripper or         Stripper or
 control component.                annular-type well   annular-type well
                                   control component.  control
                                                       component.
Hydraulically-operated blind      Hydraulically-      Hydraulically-
 rams.                             operated blind      operated blind
                                   rams.               rams.
Hydraulically-operated shear      Hydraulically-      Hydraulically-
 rams.                             operated shear      operated shear
                                   rams.               rams.
Kill line inlet.................  Kill line inlet...  Kill line inlet.
Hydraulically-operated two-way    Hydraulically-      Hydraulically-
 slip rams.                        operated two-way    operated two-way
                                   slip rams.          slip rams.
                                                      Hydraulically-
                                                       operated pipe
                                                       rams.
Hydraulically-operated pipe rams  Hydraulically-      A flow tee or
                                   operated pipe       cross.
                                   rams..             Hydraulically-
                                  Hydraulically-       operated pipe
                                   operated blind-     rams.
                                   shear rams. These  Hydraulically-
                                   rams should be      operated blind-
                                   located as close    shear rams on
                                   to the tree as      wells with
                                   practical.          surface 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.
------------------------------------------------------------------------


[[Page 174]]

    (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 downhole check valves, you must describe alternate procedures 
and equipment in Form MMS-124, 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.
    (g) 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.
    (h) 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 68 FR 8435, Feb. 20, 2003; 71 FR 11313, Mar. 7, 2006; 71 FR 
29710, May 23, 2006; 74 FR 46908, Sept. 14, 2009; 75 FR 63375, Oct. 14, 
2010]



Sec. 250.616  Blowout preventer system testing, records, and drills.

    (a) BOP pressure tests. When you pressure test the BOP system you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill lines, 
and valves, manifolds, strippers, and safety valves. Surface BOP systems 
must be pressure tested with water.
    (1) Low pressure tests. All BOP system components must be 
successfully tested to a low pressure between 200 and 300 psi. Any 
initial pressure equal to or greater than 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.

[[Page 175]]

    (2) High pressure tests. All BOP system components must be 
successfully tested to the rated working pressure of the BOP equipment, 
or as otherwise approved by the District Manager. The annular-type BOP 
must be successfully tested at 70 percent of its rated working pressure 
or as otherwise approved by the District Manager.
    (3) Other testing requirements. Variable bore pipe rams must be 
pressure tested against the largest and smallest sizes of tubulars in 
use (jointed pipe, seamless pipe) in the well.
    (b) The BOP systems shall be tested at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations shall be 
suspended until the nonfunctional, system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams shall be tested at least once every 30 days during operation. 
A longer period between blowout preventer tests is allowed when there is 
a stuck pipe or pressure-control operation and remedial efforts are 
being performed. The tests shall be conducted as soon as possible and 
before normal operations resume. The reason for postponing testing shall 
be entered into the operations log.
    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) All personnel engaged in well-workover operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) You may conduct a stump test for the BOP system on location. A 
plan describing the stump test procedures must be included in your Form 
MMS-124, Application for Permit to Modify, and must be approved by the 
District Manager.
    (e) You must test the coiled tubing connector to a low pressure of 
200 to 300 psi, followed by a high pressure test to the rated working 
pressure of the connector or the expected surface pressure, whichever is 
less. 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.
    (f) You must record test pressures during BOP and coiled tubing 
tests on a pressure chart, or with a digital recorder, unless otherwise 
approved by the District Manager. The test interval for each BOP system 
component must be 5 minutes, except for coiled tubing operations, which 
must include a 10 minute high-pressure test for the coiled tubing 
string. Your representative at the facility must certify that the charts 
are correct.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system, system components, and 
marine risers 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. For a subsea system, the pod 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 operation log may 
instead be referenced in the operations log. All records including 
pressure charts, operations log, and referenced documents pertaining to 
BOP tests, actuations, and inspections, shall be available for MMS 
review at the facility for the duration of well-workover activity. 
Following completion of the well-workover activity, all such records 
shall be retained for a period of 2 years

[[Page 176]]

at the facility, at the lessee's filed office nearest the OCS facility, 
or at another location conveniently available to the District Manager.
    (h) Stump test a subsea BOP system before installation. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APM for District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to 
BOEMRE upon request; and
    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor. You must:
    (i) Submit test procedures with your APM for District Manager 
approval.
    (ii) Document the results of each test and make them available to 
BOEMRE upon request.
    (3) Use water to stump test a subsea BOP system. You may use 
drilling or completion fluids to conduct subsequent tests of a subsea 
BOP system.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 1915, Jan. 18, 1991. Redesignated at 63 FR 29479, May 29, 1998; 71 FR 
11313, Mar. 7, 2006; 75 FR 63376, Oct. 14, 2010]



Sec. 250.617  What are my BOP inspection and maintenance requirements?

    (a) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec. 250.198). You must document the procedures used, 
record the results, and make them available to BOEMRE upon request. You 
must maintain your records on the rig for 2 years or from the date of 
your last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The District Manager may 
approve alternate methods and frequencies to inspect a marine riser.
    (b) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec. 
250.198). You must document the procedures used, record the results, and 
make them available to BOEMRE upon request. You must maintain your 
records on the rig for 2 years or from the date of your last major 
inspection, whichever is longer.

[75 FR 63376, Oct. 14, 2010]



Sec. 250.618  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) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) When reinstalling the tree, you must:
    (1) Equip wells to monitor for casing pressure according to the 
following chart:

[[Page 177]]



------------------------------------------------------------------------
                                 you must equip *   so you can monitor *
       If you have * * *               * *                  * *
------------------------------------------------------------------------
(i) fixed platform wells,.....  the wellhead,....  all annuli (A, B, C,
                                                    D, etc., annuli).
(ii) subsea wells,............  the tubing head,.  the production casing
                                                    annulus (A annulus).
(iii) hybrid* wells,..........  the surface        all annuli at the
                                 wellhead,.         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.

    (2) Follow the casing pressure management requirements in subpart E 
of this part.
    (d) 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.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec. 250.801 of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990. Redesignated and amended at 63 FR 29479, 29485, 
May 29, 1998; 75 FR 23586, May 4, 2010. Further redesignated at 75 FR 
63376, Oct. 14, 2010]



Sec. 250.619  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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998. Further redesignated at 75 FR 63376, Oct. 14, 2010]

Subpart G [Reserved]



             Subpart H_Oil and Gas Production Safety Systems



Sec. 250.800  General requirements.

    (a) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety and protection 
of the human, marine, and coastal environments. Production safety 
systems operated in subfreezing climates shall utilize equipment and 
procedures selected with consideration of floating ice, icing, and other 
extreme environmental conditions that may occur in the area. Production 
shall not commence until the production safety system has been approved 
and a preproduction inspection has been requested by the lessee.
    (b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you must 
do all of the following:
    (1) Comply with API RP 14J (incorporated by reference as specified 
in 30 CFR 250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(incorporated by reference as specified in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (incorporated by reference as specified 
in 30 CFR

[[Page 178]]

250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Sec. Sec. 250.900 through 250.921 
of this part.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 70 FR 41574, July 19, 2005]



Sec. 250.801  Subsurface safety devices.

    (a) General. All tubing installations open to hydrocarbon-bearing 
zones shall be equipped with subsurface safety devices that will shut 
off the flow from the well in the event of an emergency unless, after 
application and justification, the well is determined by the District 
Manager to be incapable of natural flowing. These devices may consist of 
a surface-controlled subsurface safety valve (SSSV), a subsurface-
controlled SSSV, an injection valve, a tubing plug, or a tubing/annular 
subsurface safety device, and any associated safety valve lock or 
landing nipple.
    (b) Specifications for SSSV's. Surface-controlled and subsurface-
controlled SSSV's and safety valve locks and landing nipples installed 
in the OCS shall conform to the requirements in Sec. 250.806 of this 
part.
    (c) Surface-controlled SSSV's. All tubing installations open to a 
hydrocarbon-bearing zone which is capable of natural flow shall be 
equipped with a surface-controlled SSSV, except as specified in 
paragraphs (d), (f), and (g) of this section. The surface controls may 
be located on the site or a remote location. Wells not previously 
equipped with a surface-controlled SSSV and wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV in 
accordance with paragraph (d)(2) of this section shall be equipped with 
a surface-controlled SSSV when the tubing is first removed and 
reinstalled.
    (d) Subsurface-controlled SSSV's. Wells may be equipped with 
subsurface-controlled SSSV's in lieu of a surface-controlled SSSV 
provided the lessee demonstrates to the District Manager's satisfaction 
that one of the following criteria are met:
    (1) Wells not previously equipped with surface-controlled SSSV's 
shall be so equipped when the tubing is first removed and reinstalled,
    (2) The subsurface-controlled SSSV is installed in wells completed 
from a single-well or multiwell satellite caisson or seafloor 
completions, or
    (3) The subsurface-controlled SSSV is installed in wells with a 
surface-controlled SSSV that has become inoperable and cannot be 
repaired without removal and reinstallation of the tubing.
    (e) Design, installation, and operation of SSSV's. The SSSV's shall 
be designed, installed, operated, and maintained to ensure reliable 
operation.
    (1) The device shall be installed at a depth of 100 feet or more 
below the seafloor within 2 days after production is established. When 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formation, or paraffins, an alternate setting depth of the 
subsurface safety device may be approved by the District Manager.
    (2) Until a subsurface safety device is installed, the well shall be 
attended in the immediate vicinity so that emergency actions may be 
taken while the well is open to flow. During testing and inspection 
procedures, the well shall not be left unattended while open to 
production unless a properly operating subsurface-safety device has been 
installed in the well.
    (3) The well shall not be open to flow while the subsurface safety 
device is removed, except when flowing of the well is necessary for a 
particular operation such as cutting paraffin, bailing sand, or similar 
operations.
    (4) All SSSV's must be inspected, installed, maintained, and tested 
in accordance with American Petroleum Institute Recommended Practice 
14B, Recommended Practice for Design, Installation, Repair, and 
Operation of Subsurface Safety Valve Systems (incorporated by reference 
as specified in Sec. 250.198).
    (f) Subsurface safety devices in shut-in wells. New completions 
(perforated but not placed on production) and completions shut in for a 
period of 6 months shall be equipped with either (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. The setting

[[Page 179]]

depth of the subsurface safety device shall be approved by the District 
Manager on a case-by-case basis, when warranted by conditions such as 
permafrost, unstable bottom conditions, hydrate formations, and 
paraffins.
    (g) Subsurface safety devices in injection wells. A surface-
controlled SSSV or an injection valve capable of preventing backflow 
shall be installed in all injection wells. This requirement is not 
applicable if the District Manager concurs that the well is incapable of 
flowing. The lessee shall verify the no-flow condition of the well 
annually.
    (h) Temporary removal for routine operations. (1) Each wireline- or 
pumpdown-retrievable subsurface safety device may be removed, without 
further authorization or notice, for a routine operation which does not 
require the approval of a Form MMS-124, Application for Permit to 
Modify, in Sec. 250.601 of this part for a period not to exceed 15 
days.
    (2) The well shall be identified by a sign on the wellhead stating 
that the subsurface safety device has been removed. The removal of the 
subsurface safety device shall be noted in the records as required in 
Sec. 250.804(b) of this part. If the master valve is open, a trained 
person shall be in the immediate vicinity of the well to attend the well 
so that emergency actions may be taken, if necessary.
    (3) A platform well shall be monitored, but a person need not 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 or a pump-through 
plug installed in the tubing at least 100 feet below the mud line and 
the master valve closed, unless otherwise approved by the District 
Manager.
    (4) The well shall not be allowed to flow while the subsurface 
safety device is removed, except when flowing the well is necessary for 
that particular operation. The provisions of this paragraph are not 
applicable to the testing and inspection procedures in Sec. 250.804 of 
this part.
    (i) Additional safety equipment. All tubing installations in which a 
wireline- or pumpdown-retrievable subsurface safety device is installed 
after the effective date of this subpart shall be equipped with a 
landing nipple with flow couplings or other protective equipment above 
and below to provide for the setting of the SSSV. The control system for 
all surface-controlled SSSV's shall be an integral part of the platform 
Emergency Shutdown System (ESD). 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 SSSV's shall close in 
response to shut-in signals from the ESD and in response to the fire 
loop or other fire detection devices.
    (j) Emergency action. In the event of an emergency, such as an 
impending storm, any well not equipped with a subsurface safety device 
and which is capable of natural flow shall have the device properly 
installed as soon as possible with due consideration being given to 
personnel safety.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 
2007]



Sec. 250.802  Design, installation, and operation of surface production-safety systems.

    (a) General. All production facilities, including separators, 
treaters, compressors, headers, and flowlines shall be designed, 
installed, and maintained in a manner which provides for efficiency, 
safety of operation, and protection of the environment.
    (b) Platforms. 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 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 therein to determine 
the effects and requirements of these components on the safety system. 
Safety device requirements for pipelines are under Sec. 250.1004.
    (c) Specification for surface safety valves (SSV) and underwater 
safety valves (USV). All wellhead SSV's, USV's, and their actuators 
which are

[[Page 180]]

installed in the OCS shall conform to the requirements in Sec. 250.806 
of this part.
    (d) Use of SSV's and USV's. All SSVs and USVs must be inspected, 
installed, maintained, and tested in accordance with API RP 14H, 
Recommended Practice for Installation, Maintenance, and Repair of 
Surface Safety Valves and Underwater Safety Valves Offshore 
(incorporated by reference as specified in Sec. 250.198). If any SSV or 
USV does not operate properly or if any fluid flow is observed during 
the leakage test, the valve shall be repaired or replaced.
    (e) Approval of safety-systems design and installation features. 
Prior to installation, the lessee shall submit, in duplicate for 
approval to the District Manager a production safety system application 
containing information relative to 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 other location conveniently available to the 
District Manager. All approvals are subject to field verifications. The 
application shall include the following:
    (1) A schematic flow diagram showing tubing pressure, size, 
capacity, design working pressure of separators, flare scrubbers, 
treaters, storage tanks, compressors, pipeline pumps, metering devices, 
and other hydrocarbon-handling vessels.
    (2) A schematic piping flow diagram (API RP 14C, Figure E, 
incorporated by reference as specified in Sec. 250.198) and the related 
Safety analysis Function Evaluation chart (API RP 14C, subsection 4.3c, 
incorporated by reference as specified 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 
(incorporated by reference as specified in Sec. 250.198).
    (4) Electrical system information including the following:
    (i) A plan for 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 (incorporated by reference as specified in Sec. 
250.198), and outlining areas in which potential ignition sources, other 
than electrical, are to be installed. The area outlined will include the 
following information:
    (A) All major production equipment, wells, and other significant 
hydrocarbon sources and a description of the type of decking, ceiling, 
walls (e.g., grating or solid) and firewalls; and
    (B) Location of generators, control rooms, panel boards, major 
cabling/conduit routes, and identification of the primary wiring method 
(e.g., type cable, conduit, or wire).
    (ii) Elementary electrical schematic of any platform safety shut-
down system with a functional legend.
    (5) 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 new installations 
conform to the approved designs of this subpart.
    (6) The design and schematics of the installation and maintenance of 
all fire- and gas-detection systems shall include the following:
    (i) Type, location, and number of detection sensors;
    (ii) Type and kind of alarms, 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.
    (7) The service fee listed in Sec. 250.125. The fee you must pay 
will be determined by the number of components

[[Page 181]]

involved in the review and approval process.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60024, Nov. 26, 1996. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, 
Jan. 4, 2000; 67 FR 51759, Aug. 9, 2002; 71 FR 40912, July 19, 2006; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



Sec. 250.803  Additional production system requirements.

    (a) For all production platforms, you must comply with the following 
production safety system requirements, in addition to the requirements 
of Sec. 250.802 of this subpart and the requirements of API RP 14C 
(incorporated by reference as specified in 30 CFR 250.198).
    (b) Design, installation, and operation of additional production 
systems--(1) Pressure and fired vessels. 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. 
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) (incorporated by reference as specified in Sec. 250.198).
    (i) Pressure relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves 
shall conform to the valve-sizing and pressure-relieving requirements 
specified in these documents; however, the relief valves, except 
completely redundant relief valves, shall be set no higher than the 
maximum-allowable working pressure of the vessel. All relief valves and 
vents shall be piped in such a way as to prevent fluid from striking 
personnel or ignition sources.
    (ii) Steam generators operating at less than 15 pounds per square 
inch gauge (psig) shall be equipped with a level safety low (LSL) sensor 
which will shut off the fuel supply when the water level drops below the 
minimum safe level. Steam generators operating at greater than 15 psig 
require, in addition to an LSL, a water-feeding device which will 
automatically control the water level.
    (iii) The lessee shall use pressure recorders to establish the new 
operating pressure ranges of pressure vessels at any time when there is 
a change in operating pressures that requires new settings for the high-
pressure shut-in sensor and/or the low-pressure shut-in sensor as 
provided herein. The pressure-recorder charts used to determine current 
operating pressure ranges shall be maintained at the lessee's field 
office nearest the OCS facility or at other locations conveniently 
available to the District Manager. The high-pressure shut-in 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 (5 percent or 5 psi, whichever is 
greater) the relief valve's set pressure to assure that the pressure 
source is shut in before the relief valve activates. The low-pressure 
shut-in sensor shall activate no lower than 15 percent or 5 psi, 
whichever is greater, below the lowest pressure in the operating range. 
The activation of low-pressure sensors on pressure vessels which operate 
at less than 5 psi shall be approved by the District Manager on a case-
by-case basis.
    (2) Flowlines. (i) You must equip flowlines from wells with high- 
and low-pressure shut-in sensors located in accordance with section A.1 
and Figure A1 of API RP 14C (incorporated by reference as specified in 
Sec. 250.198). The lessee shall use pressure recorders to establish the 
new operating pressure ranges of flowlines at any time when there is a 
significant change in operating pressures. The most recent pressure-
recorder charts used to determine operating pressure ranges shall be 
maintained at the lessee's field office nearest the OCS facility or at 
other locations conveniently available to the District Manager. The 
high-pressure shut-in sensor(s) shall be set no higher than 15 percent 
or 5 psi, whichever is greater, above the highest operating pressure of 
the line. But in all cases, it shall be set sufficiently below the 
maximum shut-in wellhead pressure or the

[[Page 182]]

gas-lift supply pressure to assure actuation of the SSV. The low-
pressure shut-in sensor(s) shall be set no lower than 15 percent or 5 
psi, whichever is greater, below the lowest operating pressure of the 
line in which it is installed.
    (ii) If a well flows directly to the pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) shall 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:
    (A) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. The platform flare 
scrubber shall be designed to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of liquid 
hydrocarbons which may be relieved to the vessel.
    (B) Two SSV's with independent high-pressure sensors installed with 
adequate volume upstream of any block valve to allow sufficient time for 
the valve(s) to close before exceeding the maximum allowable working 
pressure.
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (A) Review the manufacturer's Design Methodology Verification Report 
and the independent verification agent's (IVA's) certificate for the 
design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of API Spec 17J 
(incorporated by reference as specified in 30 CFR 250.198);
    (B) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (C) Submit to the MMS District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the MMS 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 API Spec 17J (incorporated by 
reference as specified in 30 CFR 250.198).
    (3) Safety sensors. All shutdown devices, valves, and pressure 
sensors shall function in a manual reset mode. Sensors with integral 
automatic reset shall be equipped with an appropriate device to override 
the automatic reset mode. All pressure sensors shall be equipped to 
permit testing with an external pressure source.
    (4) ESD. The ESD 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:
    (i) The manually operated ESD valve(s) shall be quick-opening and 
nonrestricted to enable the rapid actuation of the shutdown system. Only 
ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve.
    (ii) Closure of the SSV shall not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV shall close in not more than 2 minutes after the shut-in 
signal has closed the SSV. Design-delayed closure time greater than 2 
minutes shall be justified by the lessee based on the individual well's 
mechanical/production characteristics and be approved by the District 
Manager.
    (iii) A schematic of the ESD which indicates the control functions 
of all safety devices for the platforms shall be maintained by the 
lessee on the platform or at the lessee's field office nearest the OCS 
facility or other location conveniently available to the District 
Manager.
    (5) Engines--(i) Engine exhaust. You must equip engine exhausts to 
comply with the insulation and personnel protection requirements of API 
RP 14C, section 4.2c(4) (incorporated by reference as specified in Sec. 
250.198). Exhaust piping from diesel engines must be equipped with spark 
arresters.
    (ii) Diesel engine air intake. All diesel engine air intakes must be 
equipped with a device to shutdown 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

[[Page 183]]

equipped with automatic shutdown devices.
    (6) Glycol dehydration units. A pressure relief system or an 
adequate vent shall be installed on the glycol regenerator (reboiler) 
which will prevent overpressurization. The discharge of the relief valve 
shall be vented in a nonhazardous manner.
    (7) Gas compressors. You must equip compressor installations with 
the following protective equipment as required in API RP 14C, Sections 
A4 and A8 (incorporated by reference as specified in Sec. 250.198).
    (i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a 
Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL 
to protect each interstage and suction scrubber.
    (ii) A Temperature Safety High (TSH) on each compressor discharge 
cylinder.
    (iii) The PSH and PSL shut-in sensors and LSH shut-in controls 
protecting compressor suction and interstage scrubbers shall be 
designated to actuate automatic shutdown valves (SDV) 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 
SDV's installed in compressor suction and fuel gas piping shall 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 a compressor suction shall be diverted to the pipeline 
or shut in at the wellhead.
    (iv) A blowdown valve is required on the discharge line of all 
compressor installations of 1,000 horsepower (746 kilowatts) or greater.
    (8) Firefighting systems. Firefighting systems for both open and 
totally enclosed platforms installed for extreme weather conditions or 
other reasons shall conform to subsection 5.2, Firewater systems, of API 
RP 14G (incorporated by reference as specified in Sec. 250.198), Fire 
Prevention and Control Open Type Offshore Production Platforms, and 
shall require approval of the District Manager. The following additional 
requirements shall apply for both open- and closed-production platforms:
    (i) A firewater system consisting of rigid pipe with firehose 
stations or fixed firewater monitors shall be installed. The firewater 
system shall be installed to provide needed protection in all areas 
where production-handling equipment is located. A fixed waterspray 
system shall be installed in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during a platform shut-in. If necessary, 
an alternate fuel or power supply shall be installed to provide for this 
pump-operating time unless an alternate firefighting 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.
    (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.
    (v) For operations in subfreezing climates, the lessee shall furnish 
evidence to the District Manager that the firefighting system is 
suitable for the conditions.
    (9) 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 which is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations over 25 percent of the lower explosive 
limit (LEL). 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

[[Page 184]]

of sufficient size to all 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 (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).
    (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 which 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 incorporated by 
reference as specified in Sec. 250.198).
    (10) Electrical equipment. Electrical equipment and systems shall be 
designed, installed, and maintained in accordance with the requirements 
in Sec. 250.114 of this part.
    (11) Erosion. A program of erosion control shall be in effect for 
wells or fields having a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. Records by lease, indicating the wells 
which have erosion-control programs in effect and the results of the 
programs, shall be maintained by the lessee for a period of 2 years and 
shall be made available to MMS upon request.
    (c) General platform operations. (1) Surface or subsurface 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 
surface or subsurface safety device which is temporarily out of service 
shall be flagged.
    (2) When wells are disconnected from producing facilities and blind 
flanged, 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:
    (i) Automatic fail-close SSV's on wellhead assemblies, and
    (ii) The PSH and PSL shut-in sensors in flowlines from wells.
    (3) 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 compliance with API RP 14C or this subpart is not 
required.
    (4) All open-ended lines connected to producing facilities and wells 
shall be plugged or blind-flanged, except those lines designed to be 
open-ended such as flare or vent lines.
    (d) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities shall be conducted according to the 
specific requirements in Sec. Sec. 250.109 through 250.113 of this 
part.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988. Redesignated at 
63 FR 29479, 29485, May 29, 1998]

    Editorial Note: For Federal Register citations affecting Sec. 
250.803, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.fdsys.gov.



Sec. 250.804  Production safety-system testing and records.

    (a) Inspection and testing. The safety-system devices shall be 
successfully inspected and tested by the lessee at the interval 
specified below or more frequently if operating conditions warrant. 
Testing must be in accordance

[[Page 185]]

with API RP 14C, Appendix D (incorporated by reference as specified in 
Sec. 250.198), and the following:
    (1) Testing requirements for subsurface safety devices are as 
follows:
    (i) Each surface-controlled subsurface safety device installed in a 
well, including such devices in shut-in and injection wells, shall be 
tested in place for proper operation when installed or reinstalled and 
thereafter at intervals not exceeding 6 months. If the device does not 
operate properly, or if a liquid leakage rate in excess of 200 cubic 
centimeters per minute or a gas leakage rate in excess of 5 cubic feet 
per minute is observed, the device shall be removed, repaired and 
reinstalled, or replaced. Testing shall be in accordance with API RP 14B 
to ensure proper operation.
    (ii) Each subsurface-controlled SSSV installed in a well shall be 
removed, inspected, and repaired or adjusted, as necessary, and 
reinstalled or replaced at intervals not exceeding 6 months for those 
valves not installed in a landing nipple and 12 months for those valves 
installed in a landing nipple.
    (iii) Each tubing plug installed in a well shall be inspected for 
leakage by opening the well to possible flow at intervals not exceeding 
6 months. If a liquid leakage rate in excess of 200 cubic centimeters 
per minute or a gas leakage rate in excess of 5 cubic feet per minute is 
observed, the device shall be removed, repaired and reinstalled, or 
replaced. An additional tubing plug may be installed in lieu of removal.
    (iv) Injection valves shall be tested in the manner as outlined for 
testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage 
rates outlined in paragraph (a)(1)(iii) of this section shall apply.
    (2) All PSV's shall be 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. Weighted disk vent valves used 
as PSV's on atmospheric tanks may be disassembled and inspected in lieu 
of function testing.
    (3) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be tested at least once each 
calendar month, but at no time will more than 6 weeks elapse between 
tests:
    (i) All PSH and PSL,
    (ii) All LSH and LSL controls,
    (iii) All automatic inlet SDV's which are actuated by a sensor on a 
vessel or compressor, and
    (iv) All SDV's in liquid discharge lines and actuated by vessel low-
level sensors.
    (4) The following electronic pressure transmitters and level sensors 
must be tested at least once every 3 months, but at no time may more 
than 120 days elapse between tests:
    (i) All PSH and PSL, and
    (ii) All LSH and LSL controls.
    (5) All SSV's and USV's shall be tested for operation and for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The SSV's and USV's must be tested in 
accordance with the test procedures specified in API RP 14H 
(incorporated by reference as specified in Sec. 250.198). If the SSV or 
USV does not operate properly or if any fluid flow is observed during 
the leakage test, the valve shall be repaired or replaced.
    (6) All flowline Flow Safety Valves (FSV) shall be checked for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The FSV's must be tested for leakage 
in accordance with the test procedures specified in API RP 14C, Appendix 
D, section D4, table D2, subsection D (incorporated by reference as 
specified in Sec. 250.198). If the leakage measured exceeds a liquid 
flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet 
per minute, the FSV's shall be repaired or replaced.
    (7) The TSH shutdown controls installed on compressor installations 
which can be nondestructively tested shall be tested every 6 months and 
repaired or replaced as necessary.
    (8) All pumps for firewater systems shall be inspected and operated 
weekly.
    (9) All fire- (flame, heat, or smoke) detection systems shall be 
tested for operation and recalibrated every 3 months provided that 
testing can be performed in a nondestructive manner. Open flame or 
devices operating at temperatures which could ignite a methane-air 
mixture shall not be used.

[[Page 186]]

All combustible gas-detection systems shall be calibrated every 3 
months.
    (10) All TSH devices shall be tested at least once every 12 months, 
excluding those addressed in paragraph (a)(7) of this section and those 
which would be destroyed by testing. Burner safety low and flow safety 
low devices shall also be tested at least once every 12 months.
    (11) The ESD shall be tested for operation at least once each 
calendar month, but at no time shall more than 6 weeks elapse between 
tests. The test shall be conducted 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.
    (12) 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 integrated 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 subsurface and surface safety device installed. These 
records shall be maintained by the lessee at the lessee's field office 
nearest the OCS facility or other locations conveniently available to 
the District Manager. These records shall be available for review by a 
representative of MMS. The records shall show the present status and 
history of each device, including dates and details of installation, 
removal, inspection, testing, repairing, adjustments, and 
reinstallation.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753, Nov. 15, 1990; 62 
FR 5331, Feb. 5, 1997. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 65 FR 35824, June 6, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 
47, Jan. 2, 2003]



Sec. 250.805  Safety device training.

    Personnel installing, inspecting, testing, and maintaining these 
safety devices and personnel operating the production platforms shall be 
qualified in accordance with subpart O.



Sec. 250.806  Safety and pollution prevention equipment quality assurance requirements.

    (a) General requirements. (1) Except as provided in paragraph (b)(1) 
of this section, you may install only certified safety and pollution 
prevention equipment (SPPE) in wells located on the OCS. SPPE includes 
the following:
    (i) Surface safety valves (SSV) and actuators;
    (ii) Underwater safety valves (USV) and actuators; and
    (iii) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples.
    (2) Certified SPPE is equipment the manufacturer certifies as 
manufactured under a quality assurance program MMS recognizes. MMS 
considers all other SPPE as noncertified. MMS recognizes two quality 
assurance programs:
    (i) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality 
Assurance and Certification of Safety and Pollution Prevention Equipment 
Used in Offshore Oil and Gas Operations; and
    (ii) API Spec Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry (incorporated by 
reference as specified in Sec. 250.198).
    (3) All SSV's and USV's must meet the technical specifications of 
API Spec 6A and 6AV1. All SSSVs must meet the technical specifications 
of API Specification 14A (incorporated by reference as specified in 
Sec. 250.198). However, SSSVs and related equipment planned to be used 
in high pressure high temperature environments must meet the additional 
requirements set forth in Sec. 250.807.
    (4) For information on all standards mentioned in this section, see 
Sec. 250.198.
    (b) Use of noncertified SPPE. (1) Before April 1, 1998, you may 
continue to use and install noncertified SPPE if it was in your 
inventory as of April 1, 1988, and was included in a list of 
noncertified SPPE submitted to MMS prior to August 29, 1988.
    (2) On or after April 1, 1998:
    (i) You may not install additional noncertified SPPE; and
    (ii) When noncertified SPPE that is already in service requires 
offsite repair, remanufacturing, or hot work

[[Page 187]]

such as welding, you must replace it with certified SPPE.
    (c) Recognizing other quality assurance programs. The MMS will 
consider recognizing other quality assurance programs covering the 
manufacture of SPPE. If you want MMS to evaluate other quality assurance 
programs, submit relevant information about the program and reasons for 
recognition by MMS to the Chief, Office of Offshore Regulatory Programs; 
Minerals Management Service; MS-4020; 381 Elden Street, Herndon, 
Virginia 20170-4817.

[62 FR 42671, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 63 FR 37068, July 9, 1998; 65 FR 76935, Dec. 8, 2000; 72 
FR 12096, Mar. 15, 2007; 73 FR 20171, Apr. 15, 2008; 75 FR 1279, Jan. 
11, 2010; 75 FR 22226, Apr. 28, 2010]



Sec. 250.807  Additional requirements for subsurface safety valves 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), Application for Permit to Modify (APM), or 
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 analysis;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing process and procedures used; and
    (3) An explanation of why the analysis, process, 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 psig 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 psig 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.

[75 FR 1280, Jan. 11, 2010]



Sec. 250.808  Hydrogen sulfide.

    Production operations 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, shall be conducted in 
accordance with that section and other relevant requirements of subpart 
H, Production Safety Systems.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8435, Feb. 20, 2003. Further redesignated at 
75 FR 1280, Jan. 11, 2010]



                   Subpart I_Platforms and Structures

    Source: 70 FR 41575, July 19, 2005, unless otherwise noted.

                   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. 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

[[Page 188]]

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           (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 structural changes that materially      including the industry
 alter the approved plan or cause a      standards in Sec.  250.901.
 major deviation from approved          (ii) Before you make a major
 operations and any modification that    modification to a floating
 increases loading on a platform by 10   platform, you must obtain
 percent or more.                        approval from both the MMS and
                                         the USCG for the modification.
(3) Major repair of damage to any       (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 corrective operations involving         including the industry
 structural members affecting the        standards in Sec.  250.901.
 structural integrity of a portion or   (ii) Before you make a major
 all of the platform.                    repair to a floating platform,
                                         you must obtain approval from
                                         both the MMS and the USCG for
                                         the repair.
(4) Convert an existing platform at     (i) The Regional Supervisor will
 the current location for a new          determine on a case-by-case
 purpose.                                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          (i) The Regional Supervisor will
 offshore drilling unit (MODU) for a     determine on a case-by-case
 new purpose.                            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 MMS 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. 
250.909-250.918 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), MMS will cancel the approved platform application 1 year after 
the approval has been granted if the platform has not been installed. If 
MMS cancels the approval, you must resubmit your platform application 
and receive MMS 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, MMS will 
identify the date when the installation approval will be cancelled (if 
installation has not occurred) during the application and approval 
process. If MMS cancels your installation approval, you must resubmit 
your platform application and receive

[[Page 189]]

MMS approval if you still plan to install the platform.

[70 FR 41575, July 19, 2005; 71 FR 16859, Apr. 4, 2006, as amended at 73 
FR 20171, Apr. 15, 2008; 73 FR 64546, Oct. 30, 2008]



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, 
(incorporated by reference as specified in Sec. 250.198);
    (4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim 
Guidance for Design of Offshore Structures for Hurricane Conditions, 
(incorporated by reference as specified in Sec. 250.198);
    (5) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, (incorporated by 
reference as specified in Sec. 250.198);
    (6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, (incorporated by reference as specified in Sec. 
250.198);
    (7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, 
and Constructing Fixed Offshore Platforms--Working Stress Design 
(incorporated by reference as specified in Sec. 250.198);
    (8) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (incorporated by reference as 
specified in Sec. 250.198);
    (9) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Drilling Units (incorporated by reference as specified in Sec. 
250.198);
    (10) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as 
specified in Sec. 250.198);
    (11) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (incorporated by 
reference as specified in Sec. 250.198);
    (12) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (incorporated by reference as specified in Sec. 250.198);
    (13) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (incorporated by reference as 
specified in Sec. 250.198);
    (14) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (incorporated by reference 
as specified 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 (incorporated by reference as specified in Sec. 250.198);
    (16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete (incorporated by reference as 
specified in Sec. 250.198);
    (17) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement (incorporated by reference as 
specified in Sec. 250.198);
    (18) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete 
(incorporated by reference as specified in Sec. 250.198);
    (19) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements (incorporated by reference 
as specified in Sec. 250.198);
    (20) AWS D1.1, Structural Welding Code--Steel, including Commentary, 
(incorporated by reference as specified in Sec. 250.198);
    (21) AWS D1.4, Structural Welding Code--Reinforcing Steel, 
(incorporated by reference as specified in Sec. 250.198);

[[Page 190]]

    (22) AWS D3.6M, Specification for Underwater Welding, (incorporated 
by reference as specified in Sec. 250.198);
    (23) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (incorporated by reference as 
specified 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.
    (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:

------------------------------------------------------------------------
            Industry standard                   Applicable to * * *
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code     Fixed and floating platform,
 Requirements for Reinforced Concrete       as appropriate.
 (ACI 318-95) and Commentary (ACI 318R-
 95).
(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     Fixed platforms
 and Construction of Fixed Offshore
 Concrete Structures, 1984; reapproved
 1997.
(17) API RP 14J, RP for Design and         Floating platforms.
 Hazards Analysis for Offshore Production
 Facilities;.
(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..
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 72 FR 12096, Mar. 15, 2007; 
73 FR 20169, Apr. 15, 2008; 73 FR 64546, Oct. 30, 2008; 75 FR 22226, 
Apr. 28, 2010]



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 MMS 
representatives for the functional life of all platforms:
    (1) The as-built drawings;

[[Page 191]]

    (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 MMS 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 MMS 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 MMS 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,        three copies. If,
                                   lease number,       your facility is
                                   area, name, and     subject to the
                                   block number, and   Platform
                                   the type of         Verficiation
                                   facility your       Program (PVP),
                                   facility (e.g.,     you must submit
                                   drilling,           four copies.
                                   production,
                                   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.
(b) Location plat...............  Latitude and        Your plat must be
                                   longitude           drawn to a scale
                                   coordinates,        of 1 inch equals
                                   Universal           2,000 feet and
                                   Mercator grid-      include the
                                   system              coordinates of
                                   coordinates,        the lease block
                                   state plane         boundary lines.
                                   coordinates in      You must submit
                                   the Lambert or      three
                                   Transverse
                                   Mercator
                                   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 View    Platform            Your drawing sizes
 drawings.                         dimensions and      must not exceed
                                   orientation,        11 x
                                   elevations          17.
                                   relative to         You must submit
                                   M.L.L.W. (Mean      three copies
                                   Lower Low Water),   (four copies for
                                   and pile sizes      PVP
                                   and penetration.    applications).

[[Page 192]]

 
(d) Complete set of structural    The approved for    Your drawing sizes
 drawings.                         construction        must not exceed
                                   fabrication         11 x
                                   drawings should     17.
                                   be submitted        You must submit
                                   including; e.g.,    one 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
 data.                             environmental       one copy.
                                   data 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 engineering    Loading             You must submit
 design data.                      information         one copy.
                                   (e.g., live,
                                   dead,
                                   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
 used in the platform design or    pertinent to        one copy of each
 installation.                     platform design     study.
                                   or installation,
                                   e.g.,
                                   oceanographic and/
                                   or soil reports
                                   including the
                                   overall site
                                   investigative
                                   report required
                                   in section
                                   250.906.
(h) Description of the loads      Loads imposed by    You must submit
 imposed on the facility.          jacket; decks;      one 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 factors     A summary of        You must submit
 utilized.                         pertinent derived   one 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
 inspection plan.                  described in Sec.  one copy.
                                     250.919..
(k) Certification statement.....  The following       An authorized
                                   statement: ``The    company
                                   design of this      representative
                                   structure has       must sign the
                                   been certified by   statement. You
                                   a recognized        must submit one
                                   classification      copy.
                                   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.
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 71 FR 40912, July 19, 2006; 
73 FR 64546, Oct. 30, 2008]



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:

[[Page 193]]

    (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) Liquifaction, 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;
    (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 (incorporated by reference as 
specified in 30 CFR 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 analysis must
 redundancy to prevent catastrophic   indicate a maximum calculated life
 failure of the platform or           of twice the design life of the
 structure under consideration.       platform.

[[Page 194]]

 
(2) There is not sufficient          The results of a fatigue analysis
 structural redundancy to prevent     must indicate a minimum calculated
 catastrophic failure of the          life or three times the design
 platform or structure.               life of the platform.
(3) The desirable degree of          The results of a fatigue analysis
 redundancy is significantly          must indicate a minimum calculated
 reduced as a result of fatigue       life of three times the design
 damage.                              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.

                      Platform Verification Program



Sec. 250.909  What is the Platform Verification Program?

    The Platform Verification Program is the MMS 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:

------------------------------------------------------------------------
              If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a  The entire platform is subject to
 buoyant offshore facility that       the Platform Verification Program
 does not have a ship-shaped hull.    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 structures that
 buoyant offshore facility with a     may be associated with a floating
 ship-shaped hull.                    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

[[Page 195]]

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 MMS and the 
USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by MMS on a case-by-case 
basis.

[70 FR 41575, July 19, 2005; 71 FR 28080, May 15, 2006]



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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



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 with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD). 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

[[Page 196]]

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.
    (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 MMS 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 250.901(b); and the requirements of this subpart.

[[Page 197]]

    (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 judgement 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-     Conduct an independent assessment
 ship-shaped floating facilities.     of all proposed:
                                     (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;
    (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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



Sec. 250.917  What are the CVA's primary duties during the fabrication phase?

    (a) The CVA must use good engineering judgement 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:

[[Page 198]]



------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For all fixed platforms and non- Make periodic onsite inspections
 ship-shaped floating facilities.     while fabrication is in 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 tolerences
                                      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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



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:

------------------------------------------------------------------------
                                         Operation or equipment to be
         The CVA must . . .                    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;

[[Page 199]]

 
                                     (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          (i) The loadout of the jacket,
 floating platform).                  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          (i) The loadout of the platform;
 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       (i) Equipment;
 determine compliance with the       (ii) Procedures; and
 applicable documents listed in      (iii) Recordkeeping.
 Sec.  250.901(a); the alternative
 codes, rules and standards
 approved under 250.901(b); the
 requirements listed in Sec.
 250.903 and 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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]

          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.
    (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 (incorporated by reference as specified 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

[[Page 200]]

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 MMS before you make major repairs of any damage 
unless you meet the requirements of Sec. 250.900(c).

[73 FR 64547, Oct. 30, 2008]



Sec. 250.920  What are the MMS 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. If MMS 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, or inadequate deck height your 
platform 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 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 MMS 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.

[73 FR 64548, Oct. 30, 2008]



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.



             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.

[[Page 201]]

    (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 by April 14, 1999 or the date a pipeline 
begins service, whichever is later.
    (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 MMS upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point by April 14, 1999, the MMS Regional Supervisor and 
the Department of Transportation (DOT) Office of Pipeline Safety (OPS) 
Regional Director may jointly determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may write to the MMS Regional Supervisor to request an exception to this 
requirement for an individual facility or area. The Regional Supervisor, 
in consultation with the OPS Regional Director 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, MMS 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 MMS Regional Supervisor recognize that valve as the last point 
MMS will exercise its regulatory authority.
    (9) A pipeline segment is not subject to MMS 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 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 MMS 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 MMS 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 Office

[[Page 202]]

of Pipeline Safety (OPS) Regional Director.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under MMS regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to MMS regulations governing design and construction.
    (i) The operator's request must be in the form of a written petition 
to the OPS Regional Director and the MMS Regional Supervisor.
    (ii) The MMS Regional Supervisor and the OPS Regional Director 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).

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 34597, June 25, 1998; 63 FR 43880, Aug. 17, 
1998; 65 FR 46095, July 27, 2000; 71 FR 40912, July 19, 2006]



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.
    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

[[Page 203]]

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).

[53 FR 10690, Apr. 1, 1998. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 63 FR 43881, Aug. 17, 1998; 65 FR 46096, July 27, 2000; 67 
FR 35405, May 17, 2002; 72 FR 25201, May 4, 2007]



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] TC15NO91.019


For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 (incorporated by reference as specified in 30 CFR 
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 
American Petroleum Institute (API) Spec 6A, API Spec 6D, 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 B16.5, API Spec 6A, or the equivalent 
(incorporated by reference as specified in 30 CFR 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 
API Spec 17J, incorporated by reference as specified in 30 CFR 250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other floating platforms according to the design standards of API RP 
2RD, Design of Risers for Floating Production Systems (FPSs) and Tension 
Leg Platforms (TLPs), incorporated by reference as specified in 30 CFR 
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

[[Page 204]]

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 (incorporated by reference as 
specified 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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 67 FR 51760, Aug. 9, 2002; 70 FR 41583, July 19, 2005; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



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 
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

[[Page 205]]

encirclement clamp able to withstand the anticipated pipeline pressure.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988; 57 FR 26997, 
June 17, 1992. Redesignated at 63 FR 29479, May 29, 1998, as amended at 
72 FR 25201, May 4, 2007]



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 
(incorporated by reference as specified 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998; 67 
FR 51760, Aug. 9, 2002; 72 FR 25201, May 4, 2007]



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 206]]

    (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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



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.
------------------------------------------------------------------------


[67 FR 35405, May 17, 2002]



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 207]]

    (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 API Spec 17J (incorporated by reference as specified 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.

[53 FR 10690, Apr. 1, 1988, as amended at 59 FR 53094, Oct. 21, 1994. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 43881, 
Aug. 17, 1998; 67 FR 35406, May 17, 2002; 70 FR 41583, July 19, 2005; 72 
FR 25201, May 4, 2007; 73 FR 64548, Oct. 30, 2008]



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

[[Page 208]]

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.
    (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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 71 FR 40912, July 19, 2006]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



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

[[Page 209]]

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 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 
Minerals Management Service (MMS). 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1011  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 part 256) 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.

[[Page 210]]

    (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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay MMS 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   You must pay a rental of $5 per
 in water depths of less than 200     acre per year with a minimum of
 meters;                              $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   You must pay a rental of $7.50 per
 in water depths of 200 meters or     acre per year with a minimum of
 greater;                             $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 MMS an annual rental of $75 for use of 
the affected area.
    (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 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement under 30 CFR 
250.1013.

[68 FR 69312, Dec. 12, 2003, as amended at 69 FR 29433, May 24, 2004]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]

[[Page 211]]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



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 MMS 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 MMS (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 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 MMS regional 
office.
    (e) Notwithstanding the provisions of paragraph (a) of this section, 
the requirements to pay filing fees under that paragraph are suspended 
until January 3, 2006.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 
42598, Aug. 5, 1999. Further redesignated and amended at 68 FR 69311, 
69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 
2005]



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,

[[Page 212]]

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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1988. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



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 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

[[Page 213]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998. 
Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



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 Sec. 250.1011 of this 
subpart. 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.
    (c) Notwithstanding the provisions of paragraph (b) of this section, 
the requirement to pay a filing fee under that paragraph is suspended 
until January 3, 2006.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 
49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 67 FR 35406, May 17, 2002. Further redesignated and 
amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]



              Subpart K_Oil and Gas Production Requirements

    Source: 75 FR 20289, Apr. 19, 2010, unless otherwise noted.

                                 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:

[[Page 214]]



------------------------------------------------------------------------
                                            And you must submit to the
           You must conduct:                   Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all    Form MMS-126, Well Potential
 new, recompleted, or reworked well       Test Report, along with the
 completions within 30 days of the date   supporting data as listed in
 of first continuous production.          the table in Sec.  250.1167,
                                          within 15 days after the end
                                          of the test period.
(2) At least one well test during a      Results on Form MMS-128,
 calendar half-year for each producing    Semiannual Well Test Report,
 completion.                              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 MMS-126.



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) An MMS 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. 250.1153  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       Annual static bottomhole
 producing completions.                   pressure surveys in a
                                          sufficient 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 215]]

MMS-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 MMS-140, 
Bottomhole Pressure Survey Report, showing a calculated bottomhole 
pressure or any measured data.

                         Classifying Reservoirs



Sec. 250.1154  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. 250.1167, 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. 250.1167, with 
your request.



Sec. 250.1155  What information must I submit for sensitive reservoirs?

    You must submit to the Regional Supervisor an original and two 
copies of Form MMS-127; one of the copies must be a public information 
copy in accordance with Sec. Sec. 250.186 and 250.197, and marked 
``Public Information.'' You must also submit two copies of the 
supporting information, as listed in the table in Sec. 250.1167. 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. 250.1167(a)(2)) or previously 
submitted well logs (Sec. 250.1167(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. 250.1154(c).

                      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 MMS 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 216]]

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 217]]



------------------------------------------------------------------------
               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).
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations when you cannot contact the MMS 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 part 202 of this title. You must value any gas or liquid 
hydrocarbons avoidably lost or wasted under the provisions of part 206 
of this title.
    (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 218]]

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 part 202 of this title. You must value any liquid 
hydrocarbons avoidably lost or wasted under the provisions of part 206 
of this title.



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 Minerals Revenue Management on Form MMS-4054 
(Oil and Gas Operations Report), in accordance with Sec. 210.102 of 
this title.
    (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 219]]

years and have them available for inspection by MMS representatives.
    (2) After 2 years, you must maintain the records, allow MMS 
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 MMS representatives.
    (ii) After 2 years, you must maintain the recordings, allow MMS 
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 H2S?

    (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, 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 Sec. 250.303, to determine the 
potential effect of facility emissions. The Regional Supervisor may 
require monitoring and reporting, or may restrict or prohibit flaring, 
under Sec. Sec. 250.303 and 250.304.
    (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 220]]

    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the 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 MMS-
127 and supporting data as required in Sec. 250.1167, and any 
additional information required by the Regional Supervisor.
    (c) You must report to Minerals Revenue Management the volumes of 
oil, gas, or other substances injected, produced, or produced for a 
second time under Sec. 210.102 of this title.



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 MMS and the State of 
Alaska, MMS and the Alaska Oil and Gas Conservation Commission will 
jointly determine appropriate reporting requirements to minimize or 
eliminate duplicate reporting requirements.
    (c) Every time you are required to submit Form MMS-127 under Sec. 
250.1155, you must request an MER for each producing sensitive reservoir 
in the Alaska OCS Region, unless otherwise instructed by the Regional 
Supervisor.



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 forms identified in columns 1 and 2 and for the approvals 
required under this subpart identified in columns 3 through 6:

----------------------------------------------------------------------------------------------------------------
                                                                                                      Production
                                    WPT MMS-    SRI MMS-                                              within 500-
                                     126 (2      127 (2      Gas cap     Downhole       Reservoir       ft of a
                                     copies)     copies)   production  commingling  reclassification    unit or
                                                                                                      lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface,     ..........  ..........    [radic]      [radic]   ................    [radic]
     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          [radic]     [radic]     [radic]      [radic]        [radic]        [radic]
     penetration 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      ..........          *     [radic]      [radic]
     total net sand penetrated
     for each well, identified at
     the penetration point.......
    (4) Net hydrocarbon isopach    ..........          *     [radic]      [radic]
     with net feet of pay for
     each well, identified at the
     penetration point...........
(b) Seismic data:
    (1) Representative seismic     ..........  ..........    [radic]      [radic]   ................    [radic]
     lines, including strike and
     dip lines that confirm the
     structure; indicate polarity
    (2) Amplitude extraction of    ..........  ..........    [radic]      [radic]        [radic]        [radic]
     seismic horizon, if
     applicable..................
(c) Logs:
    (1) Well log sections with       [radic]     [radic]     [radic]      [radic]        [radic]        [radic]
     tops and bottoms of the
     reservoir(s) and proposed or
     existing perforations.......
    (2) Structural cross-sections  ..........  ..........    [radic]      [radic]        [radic]              *
     showing the subject well and
     nearby wells................
(d) Engineering data:

[[Page 221]]

 
    (1) Estimated recoverable      ..........    [radic]    [dagger]     [dagger]   ................    [radic]
     reserves for 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    ..........  ..........    [radic]      [radic]   ................    [radic]
     current and proposed
     conditions..................
    (3) The drive mechanism of     ..........    [radic]     [radic]      [radic]        [radic]        [radic]
     each reservoir..............
    (4) Pressure data, by date,    ..........  ..........    [radic]      [radic]        [radic]
     and whether they are
     estimated or measured.......
    (5) Production data and        ..........  ..........    [radic]      [radic]        [radic]
     decline curve 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         ..........    [radic]     [radic]      [radic]        [radic]        [radic]
     whether or not it is
     competitive as defined under
     Sec.  250.105..............
    (3) Operator name, lessee      ..........  ..........    [radic]      [radic]   ................    [radic]
     name(s), block, lease
     number, royalty rate, and
     unit number (if applicable)
     of all relevant leases......
    (4) Geologic overview of       ..........  ..........    [radic]      [radic]        [radic]        [radic]
     project.....................
    (5) Explanation of why the     ..........  ..........    [radic]      [radic]   ................    [radic]
     proposed completion scenario
     will maximize ultimate
     recovery....................
    (6) List of all wells in       ..........  ..........    [radic]      [radic]        [radic]        [radic]
     subject reservoirs that have
     ever produced or been used
     for injection...............
----------------------------------------------------------------------------------------------------------------
[radic] 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

    Source: 63 FR 26370, May 12, 1998, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



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           Sec.  250.1202(a)
 measuring liquid hydrocarbons?.
 2. What are the requirements for liquid    Sec.  250.1202(b)
 hydrocarbon royalty meters?.
 3. What are the requirements for run       Sec.  250.1202(c)
 tickets?.
 4. What are the requirements for liquid    Sec.  250.1202(d)
 hydrocarbon royalty meter provings?.
 5. What are the requirements for           Sec.  250.1202(e)
 calibrating a master meter used in
 royalty meter provings?.
 6. What are the requirements for           Sec.  250.1202(f)
 calibrating mechanical-displacement
 provers and tank provers?.
 7. What correction factors must a lessee   Sec.  250.1202(g)
 use when proving meters with a mechanical
 displacement prover, tank prover, or
 master meter?............................

[[Page 222]]

 
 8. What are the requirements for           Sec.  250.1202(h)
 establishing and 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   Sec.  250.1202(l)
 and inventory tank facilities?.
13. To which meters do MMS requirements     Sec.  250.1203(a)
 for gas measurement apply?.
14. What are the requirements for           Sec.  250.1203(b)
 measuring gas?.
15. What are the requirements for gas       Sec.  250.1203(c)
 meter calibrations?.
16. What must a lessee do if a gas meter    Sec.  250.1203(d)
 is out of calibration or malfunctioning?.
17. What are the requirements when natural  Sec.  250.1203(e)
 gas from a Federal lease is transferred
 to a gas plant before royalty
 determination?...........................
18. What are the requirements for           Sec.  250.1203(f)
 measuring gas lost or used on a lease?.
19. What are the requirements for the       Sec.  250.1204(a)
 surface commingling of production?.
20. What are the requirements for a         Sec.  250.1204(b)
 periodic well test used for allocation?.
21. What are the requirements for site      Sec.  250.1205(a)
 security?.
22. What are the requirements for using     Sec.  250.1205(b)
 seals?.
------------------------------------------------------------------------


[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



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 30 CFR 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.

[[Page 223]]

    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.
    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 set of conditions and the 
indicated volume at those same conditions.
    Pipeline (retrograde) condensate--liquid hydrocarbons which drop out 
of the separated gas stream at any point in a pipeline during 
transmission to shore.
    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).

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20171, Apr. 15, 
2008; 74 FR 40073, Aug. 11, 2009]



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 that will accurately measure the 
liquid hydrocarbons produced from a lease or unit;
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS as incorporated by reference in 30 
CFR 250.198, when obtaining net standard volume and associated 
measurement parameters; and

[[Page 224]]

    (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 MMS-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 30 CFR 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;
    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? You must:
    (1) Permit MMS 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

[[Page 225]]

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; and
    (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:
    (1) The change in prover volume due to the effect of temperature on 
steel (Cts);
    (2) The change in prover volume due to the effect of pressure on 
steel (Cps);
    (3) The change in liquid volume due to the effect of temperature on 
a liquid (Ctl); and
    (4) The change in liquid volume due to the effect of pressure on a 
liquid (Cpl).
    (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 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:

[[Page 226]]

    (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 30 CFR 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 MMS 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 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 
correction factors and procedures in the API MPMS as incorporated by 
reference in 30 CFR 250.198.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28 
1999; 71 FR 40912, July 19, 2006; 72 FR 25201, May 4, 2007; 73 FR 20171, 
Apr. 15, 2008; 74 FR 40073, Aug. 11, 2009]



Sec. 250.1203  Gas measurement.

    (a) To which meters do MMS requirements for gas measurement apply? 
MMS 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

[[Page 227]]

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 
to ensure accurate and verifiable measurement. You must follow the 
recommendations in API MPMS as incorporated by reference in 30 CFR 
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 as referenced in 30 CFR 250.198.
    (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 MMS representatives to witness calibrations.
    (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 MMS 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.

[[Page 228]]

    (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 212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28, 
1999; 71 FR 40912, July 19, 2006; 74 FR 40073, Aug. 11, 2009]



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.

[63 FR 26370, May 12, 1998. Redesignated at 63 FR 29479, May 29, 1998; 
63 FR 33853, June 22, 1998; 71 FR 40913, July 19, 2006; 73 FR 20171, 
Apr. 15, 2008; 74 FR 40073, Aug. 11, 2009]



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 must contain the name of the 
facility operator, the size of the tank, and the tank number;
    (3) Not bypass MMS-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

[[Page 229]]

    (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 MMS inspection.



                          Subpart M_Unitization

    Source: 62 FR 5331, Feb. 5, 1997, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



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.
    (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) MMS orders or approves a suspension of production or operations 
for your lease.

[[Page 230]]

    (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 
MMS 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) MMS orders or approves a suspension of operations under Sec. 
250.170.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20172, Apr. 15, 
2008]



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 Development and Production Plan 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 Regional Supervisor, you and the other 
affected lessees must submit for approval a joint plan of operations. 
You must submit the joint plan within 90 days after the Regional 
Supervisor makes a final determination that the reservoir is 
competitive. The joint plan must provide for the development and/or 
production of the reservoir. You may submit supplemental plans for the 
Regional Supervisor's approval.
    (d) If you and the other affected lessees cannot reach an agreement 
on a joint Development and Production Plan within the approved period of 
time, each lessee must submit a separate plan to the Regional 
Supervisor. The Regional Supervisor will hold a hearing to resolve 
differences in the separate plans. If the differences in the separate 
plans are not resolved at the hearing and the Regional Supervisor 
determines that unitization is necessary under Sec. 250.1301(b), MMS 
will initiate unitization under Sec. 250.1304.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



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.

[[Page 231]]

    (b) The unit agreement must comply with the requirements of this 
part. MMS will maintain and provide a model unit agreement for you to 
follow. If MMS revises the model, MMS 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.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 70 FR 49876, Aug. 25, 2005]



Sec. 250.1304  How will MMS 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 MMS 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, MMS 
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 MMS 
provides all lessees of the proposed unit area written notice and an 
opportunity for a hearing. If you want MMS to hold a hearing, you must 
request it 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) MMS will not hold a hearing under this paragraph until at least 
30 days after MMS 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

[[Page 232]]

Regional Supervisor under 30 CFR part 290.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



            Subpart N_Outer Continental Shelf Civil Penalties

    Source: 62 FR 42668, Aug. 8, 1997, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.

            Outer Continental Shelf Lands Act Civil Penalties



Sec. 250.1400  How does MMS begin the civil penalty process?

    This subpart explains MMS'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 MMS determines, 
on the basis of available evidence, that a violation occurred and a 
civil penalty review is appropriate, it will prepare a case file. MMS 
will appoint a Reviewing Officer.



Sec. 250.1401  Index table.

    The following table is an index of the sections in this subpart:

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


[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 250.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means an MMS document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is an MMS regulatory enforcement tool 
used in addition to Notices of Incidents of Noncompliance and directed 
suspensions of production or other operations.
    Reviewing Officer means an MMS 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.

[62 FR 42668, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 71 FR 23864, Apr. 25, 2006]



Sec. 250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $35,000 per day per violation.

[72 FR 8899, Feb. 28, 2007]

    Effective Date Note: At 76 FR 38296, June 30, 2011, Sec. 250.1403 
was revised, effective Aug. 1, 2011. For the convenience of the user, 
the revised text is set forth as follows:



Sec. 250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $40,000 per day per violation.

[[Page 233]]



Sec. 250.1404  Which violations will MMS review for potential civil penalties?

    MMS will review each of the following violations for potential civil 
penalties:
    (a) Violations that you do not correct within the period MMS grants;
    (b) Violations that MMS 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 253.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 63 FR 42711, Aug. 11, 1998; 64 FR 9066, Feb. 24, 
1999]



Sec. 250.1405  When is a case file developed?

    MMS 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.

[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 250.1406  When will MMS 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.

[62 FR 42668, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998; 
64 FR 9066, Feb. 24, 1999]



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 
Regional Adjudication 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 Regional Adjudication 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 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

[[Page 234]]

under Sec. Sec. 256.53(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. 256.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
MMS 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.

[64 FR 26257, May 13, 1999, as amended at 65 FR 2875, Jan. 19, 2000]

 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.

[76 FR 38558, July 1, 2011]

                   Penalties After a Period To Correct



Sec. 250.1451  What may the Bureau of Ocean Energy Management, Regulation, and Enforcement

(BOEMRE) 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 BOEMRE Leasing Office in your respective Region.

[76 FR 38558, July 1, 2011]



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).

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]



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

[[Page 235]]

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.

[76 FR 38558, July 1, 2011]



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 30 CFR 250.1490 through 
250.1497, 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).

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]

                  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.

[76 FR 38558, July 1, 2011]

[[Page 236]]



Sec. 250.1461  How will BOEMRE 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 subpart 
H of part 1218.

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]



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 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 30 CFR 250.1490 through 
250.1497, 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).

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]

                           General Provisions



Sec. 250.1470  How does BOEMRE 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.

[76 FR 38558, July 1, 2011]



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), BOEMRE will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.

[76 FR 38558, July 1, 2011]

[[Page 237]]



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.

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]



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.

[76 FR 38558, July 1, 2011]



Sec. 250.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec. Sec. 250.1453 or 250.1461, if you do not request a hearing 
on the record under Sec. Sec. 250.1454, 250.1456, 250.1462, or 250.1464
    (b) If you request a hearing on the record under Sec. Sec. 
250.1454, 250.1456, 250.1462, or 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 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. Sec. 250.1454, 250.1456, 
250.1462, or 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.

[76 FR 38558, July 1, 2011]



Sec. 250.1476  Can BOEMRE 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.

[76 FR 38558, July 1, 2011]



Sec. 250.1477  How may BOEMRE collect the penalty?

    (a) BOEMRE 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

[[Page 238]]

determined, may be deducted from any sum owing to you by the United 
States.

[76 FR 38558, July 1, 2011]

                           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.

[76 FR 38558, July 1, 2011]

                          Bonding Requirements



Sec. 250.1490  What standards must my BOEMRE-specified surety instrument meet?

    (a) A BOEMRE-specified surety instrument must be in a form specified 
in BOEMRE instructions. BOEMRE will give you written information and 
standard forms for BOEMRE-specified surety instrument requirements.
    (b) BOEMRE 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 BOEMRE with a minimum 1-year 
period of coverage subject to automatic renewal up to 5 years.

[76 FR 38558, July 1, 2011]



Sec. 250.1491  How will BOEMRE determine the amount of my bond or other surety instrument?

    (a) The BOEMRE 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 BOEMRE-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.
    (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.

[76 FR 38558, July 1, 2011]

                     Financial Solvency Requirements



Sec. 250.1495  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 
BOEMRE bond-approving officer, up to 3 years of tax returns to BOEMRE 
using the U.S. Postal Service, private delivery, courier, or overnight 
delivery at:
    (1) For Alaska OCS: Jeffrey Walker, RS/FO, BOEMRE Alaska OCS Region, 
3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503-5823, 
jeffrey,[email protected], (907) 334-5300.
    (2) For Gulf of Mexico and Atlantic OCS: Joshua Joyce, Regional FARM 
Program Coordinator, BOEMRE Gulf of Mexico OCS Region, 1201 Elmwood Park 
Boulevard New Orleans, LA 70123-

[[Page 239]]

2394, [email protected], (504) 736-2779
    (3) For Pacific OCS: Jaron Ming, Lead Leasing Specialist, BOEMRE 
Pacific OCS Region, 770 Paseo Camarillo, 2nd Floor, Camarillo, CA 93010, 
[email protected], (805) 389-7514
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date BOEMRE 
first determined that you demonstrated financial solvency as long as you 
have active appeals, or whenever BOEMRE 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 BOEMRE notifies you that you must 
redemonstrate financial solvency.

[76 FR 38558, July 1, 2011]



Sec. 250.1496  How will BOEMRE determine if I am financially solvent?

    (a) The BOEMRE 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 30 CFR 250.1490 and 250.1491 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 30 CFR 250.1490 and 250.1491 for all orders you have appealed is 
less than $300 million, you must submit the following to BOEMRE by one 
of the methods in Sec. 250.1495(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 250.126. 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 30 CFR 250.1490 and 250.1491;
    (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:
    (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 30 CFR 250.1490 and 250.1491;
    (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 30 CFR 250.1490 and 250.1491 or pay the obligation.

[76 FR 38558, July 1, 2011]



Sec. 250.1497  When will BOEMRE monitor my financial solvency?

    (a) If you are presumptively financially solvent under Sec. 
250.1496(b), BOEMRE will determine your net worth as described under 
Sec. Sec. 250.1496(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.

[[Page 240]]

    (b) If you ask us to consult a business-information or credit-
reporting service or program under Sec. 250.1496(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 BOEMRE-specified 
surety instrument under Sec. Sec. 250.1490 and 250.1491.

[76 FR 38558, July 1, 2011]



          Subpart O_Well Control and Production Safety Training

    Source: 65 FR 49490, Aug. 14, 2000, unless otherwise noted.



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 MMS-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 safety includes measures, practices, procedures, and 
equipment 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. Production 
operations include, but are not limited to, separation, dehydration, 
compression, sweetening, and metering operations.
    Well completion/well workover means those operations following the 
drilling of a well that are intended to establish or restore production.
    Well control means drilling, well completion, well workover, and 
well servicing operations. For purposes of this subpart, well 
completion/well workover means those operations following the drilling 
of a well that are intended to establish or restore production to a 
well. It includes small tubing operations but does not include well 
servicing. Well servicing means snubbing, coil tubing, and wireline 
operations.
    Well servicing means snubbing, coiled tubing, and wireline 
operations.

[65 FR 49490, Aug. 14, 2000, as amended at 74 FR 40073, Aug. 11, 2009; 
75 FR 63376, Oct. 14, 2010]

    Editorial Note: At 75 FR 63376, Oct. 14, 2010, Sec. 250.1500 was 
amended by adding a definition for ``Well control''; however, the 
amendment could not be incorporated due to inaccurate amendatory 
instruction.



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.

[65 FR 49490, Aug. 14, 2000, as amended at 75 FR 63376, Oct. 14, 2010]



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

[[Page 241]]

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.

[65 FR 49490, Aug. 14, 2000, as amended at 75 FR 63376, Oct. 14, 2010]



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:
    (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.

[65 FR 49490, Aug. 14, 2000, as amended at 75 FR 63376, Oct. 14, 2010]



Sec. 250.1507  How will MMS measure training results?

    MMS may periodically assess your training program, using one or more 
of the methods in this section.
    (a) Training system audit. MMS 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. MMS 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. MMS 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. MMS 
or its authorized representative may conduct

[[Page 242]]

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 MMS personnel.

[65 FR 49490, Aug. 14, 2000, as amended at 75 FR 63376, Oct. 14, 2010]



Sec. 250.1508  What must I do when MMS administers written or oral tests?

    MMS 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 MMS 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 MMS administers or requires hands-on, 

simulator, or other types of testing?

    If MMS 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 MMS 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 MMS personnel.



Sec. 250.1510  What will MMS do if my training program does not comply with this subpart?

    If MMS 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 MMS your training plan to 
address identified deficiencies;
    (c) Assess civil/criminal penalties; or
    (d) Initiate disqualification procedures.



                      Subpart P_Sulphur Operations

    Source: 56 FR 32100, July 15, 1991, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



Sec. 250.1600  Performance standard.

    Operations to discover, develop, and produce sulphur in the OCS 
shall be in accordance with an 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.

[[Page 243]]

    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.
    (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 where such provisions 
specifically are referenced in this subpart.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



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.
    (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 30 CFR 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. 250.109 through Sec. 
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

[[Page 244]]

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.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 67 FR 51760, Aug. 9, 2002; 68 FR 8435, Feb. 20, 
2003; 74 FR 46909, Sept. 14, 2009]



Sec. 250.1605  Drilling requirements.

    (a) 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 
MMS-123, Application for Permit to Drill (APD), in accordance with Sec. 
250.1617 of this subpart. After a drilling unit has been approved by an 
MMS 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 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 Sec. Sec. 250.211 through 250.228 
and 250.241 through 250.262 of this part 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.

[[Page 245]]

    (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.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 63 FR 
34597, June 25, 1998; 65 FR 15864, Mar. 24, 2000; 70 FR 51519, Aug. 30, 
2005; 74 FR 46909, Sept. 14, 2009]



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.



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),

[[Page 246]]

    (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 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

[[Page 247]]

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 timelapse 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.



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.
    (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.

[[Page 248]]

    (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.
    (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.

[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 74 FR 46909, Sept. 14, 2009]



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.

[[Page 249]]

    (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) Bind 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 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 MMS 
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 shall be conducted for each drilling crew in 
accordance with the requirements set forth in

[[Page 250]]

Sec. 250.462 of this part or as approved by the District Manager.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]



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.

[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 74 FR 46909, Sept. 14, 2009]



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. 
250.455 through Sec. 250.459 of this part, except that the installation 
of an operable degasser in the mud system as required in Sec. 
250.456(g) is not required for sulphur operations.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]



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.

[[Page 251]]

    (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 an approved Exploration Plan, 
Development and Production Plan, or Development Operations Coordination 
Document, you must file Form MMS-123, 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 an MMS 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 MMS-123 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 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

[[Page 252]]

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.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 71 FR 19646, Apr. 17, 2006; 71 FR 40913, July 19, 
2006]



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 MMS-124, 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 MMS-124 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 MMS-124 shall be submitted in 
accordance with Sec. 250.117 of this part.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 71 FR 40913, July 19, 2006]



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 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

[[Page 253]]

activities related to and conducted during the suspension or temporary 
prohibition on, or attached to, Form MMS-125, End of Operations Report, 
or Form MMS-124, 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.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 72 FR 25201, May 4, 2007]



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.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



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 MMS 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 MMS-124. 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 MMS-124 
(or with Form MMS-123):
    (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 MMS-125, including a 
schematic of the tubing and the results of any well tests, shall be 
submitted to the District Manager.

[[Page 254]]

    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124 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.

[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated at 63 FR 29479, May 29, 1998]



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 255]]

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.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



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.

[[Page 256]]

    (e) All personnel engaged in well-completion operations shall 
participate 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 MMS 
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.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 63 FR 34597, June 25, 1998]



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,

[[Page 257]]

compressor pumps, metering devices, and other sulphur-handling vessels;
    (2) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Recommended Practice for Design and Installation of Offshore Production 
Platform Piping Systems;
    (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 (incorporated by 
reference as specified 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 (incorporated by reference as specified 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, incorporated by 
reference as specified in Sec. 250.198) and the related Safety Analysis 
Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by 
reference as specified 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 lnstallation of Offshore Production Platform Piping Systems;
    (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 Divisions 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 (incorporated by reference as specified 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

[[Page 258]]

to be installed was 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; 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.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 219, Jan. 
4, 2000; 67 FR 51760, Aug. 9, 2002; 75 FR 22227, Apr. 28, 2010]



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 (incorporated by reference as specified in 30 CFR 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) (incorporated by reference as specified 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 (incorporated 
by reference as specified in 30 CFR 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) (incorporated by reference as specified 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 (incorporated by reference as specified 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

[[Page 259]]

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 
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 (incorporated by reference as 
specified in Sec. 205.198), 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. 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 incorporated by 
reference as specified 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.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 64 FR 72794, 
Dec. 28, 1999; 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 
43298, July 22, 2003; 70 FR 7403, Feb. 14, 2005; 72 FR 12096, Mar. 15, 
2007; 73 FR 20172, Apr. 15, 2008; 75 FR 22227, Apr. 28, 2010]



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 (incorporated by reference as specified in Sec. 
250.198). For safety system devices other than those listed in API RP 
14C, Appendix D, you must utilize the

[[Page 260]]

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 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 MMS 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.

[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 67 FR 51761, Aug. 9, 2002]



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 MMS 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

[[Page 261]]

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.



                  Subpart Q_Decommissioning Activities

    Authority: 43 U.S.C. 1331 et seq.

    Source: 67 FR 35406, May 17, 2002, unless otherwise noted.

                                 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 MMS and other agencies that 
have jurisdiction over decommissioning activities.
    (b) Obstructions means 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.

[67 FR 35406, May 17, 2002; 67 FR 66047, Oct. 30, 2002]



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:

[[Page 262]]

    (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;
    (c) Remove all platforms and other facilities, except as provided in 
sections 1725(a) and 1730.
    (d) Decommission all pipelines;
    (e) Clear the seafloor of all obstructions created by your lease and 
pipeline right-of-way operations; and
    (f) 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.

[67 FR 35406, May 17, 2002, as amended at 74 FR 19807, Apr. 29, 2009]



Sec. 250.1704  When must I submit decommissioning applications and reports?

    You must submit decommissioning applications and receive approval 
and submit subsequent reports according to the table in this section.

             Decommissioning Applications and Reports Table
------------------------------------------------------------------------
 Decommissioning applications
          and reports               When to submit        Instructions
------------------------------------------------------------------------
(a) Initial platform removal    In the Pacific OCS      Include
 application [not required in    Region or Alaska OCS    information
 the Gulf of Mexico OCS          Region, submit the      required under
 Region].                        application to the      Sec.
                                 Regional Supervisor     250.1726.
                                 at least 2 years
                                 before production is
                                 projected to cease.
(b) Final removal application   Before removing a       Include
 for a platform or other         platform or other       information
 facility.                       facility in the Gulf    required under
                                 of Mexico OCS Region,   Sec.
                                 or not more than 2      250.1727.
                                 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    Include
 platform or other facility.     you remove a platform   information
                                 or other facility.      required under
                                                         Sec.
                                                         250.1729.
(d) Pipeline decommissioning    Before you              Include
 application.                    decommission a          information
                                 pipeline.               required under
                                                         Sec.
                                                         250.1751(a) or
                                                         Sec.
                                                         250.1752(a), as
                                                         applicable.
(e) Post-pipeline               Within 30 days after    Include
 decommissioning report.         you decommission a      information
                                 pipeline.               required under
                                                         Sec.
                                                         250.1753.
(f) Site clearance report for   Within 30 days after    Include
 a platform or other facility.   you complete site       information
                                 clearance               required under
                                 verification            Sec.
                                 activities.             250.1743(b).
(g) Form MMS-124, Application   (1) Before you          Include
 for Permit to Modify (APM).     temporarily abandon     information
 The submission of your APM      or permanently plug a   required under
 must be accompanied by          well or zone.           Sec. Sec.
 payment of the service fee     (2) Within 30 days       250.1712 and
 listed in Sec.  250.125.       after you plug a well   250.1721.
                                 * * *.                 Include
                                                         information
                                                         required under
                                                         Sec.
                                                         250.1717.
                                (3) Before you install  Refer to Sec.
                                 a subsea protective     250.1722(a).
                                 device.
                                (4) Within 30 days      Include
                                 after you complete a    information
                                 protective device       required under
                                 trawl test.             Sec.
                                                         250.1722(d).
                                (5) Before you remove   Refer to Sec.
                                 any casing stub or      250.1723.
                                 mud line suspension
                                 equipment and any
                                 subsea protective
                                 device.
                                (6) Within 30 days      Include
                                 after you complete      information
                                 site clearance          required under
                                 verification            Sec.
                                 activities.             250.1743(a).
------------------------------------------------------------------------


[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66047, Oct. 
30, 2002, as amended at 71 FR 40913, July 19, 2006]

                       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 MMS order me to permanently plug a well?

    MMS will order you to permanently plug a well if that well:
    (a) Poses a hazard to safety or the environment; or

[[Page 263]]

    (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 
MMS-124, 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; that there will be at least two 
independent tested barriers, including one mechanical barrier, across 
each flow path during abandonment activities; and that the plug meets 
the requirements in the table in Sec. 250.1715. The Registered 
Professional Engineer must be registered in a State in the United 
States. You must submit this certification with your APM (Form MMS-124).

[67 FR 35406, May 17, 2002; 67 FR 66048, Oct. 30, 2002, as amended at 75 
FR 63376, Oct. 14, 2010]



Sec. 250.1713  Must I notify MMS 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.



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.



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.

[[Page 264]]

 
(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  (i) A method to squeeze cement to all
 currently open and not         perforations;
 previously squeezed or        (ii) A cement plug set by the
 isolated.                      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 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    (i) A cement plug set at least 100 feet
 stub end is within the         above and below the stub end;
 casing.                       (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    A plug as specified in paragraph (a)(1)
 stub end is below the casing.  or (a)(2) of this section, as
                                applicable.
(6) An annular space that      A cement plug at least 200 feet long set
 communicates with open hole    in the annular space. For a well
 and extends to the mud line.   completed above the ocean surface, you
                                must pressure test each casing annulus
                                to verify isolation.
(7) A subsea well with         A cutter to sever the casing, and you
 unsealed annulus.              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.
------------------------------------------------------------------------

    (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 percent in 15 minutes. The 
District Manager may require you to tests other plug(s).

[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66048, Oct. 
30, 2002]



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

[[Page 265]]

    (2) You determine, and MMS 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. 250.1717  After I permanently plug a well, what information must I submit?

    Within 30 days after you permanently plug a well, you must submit 
form MMS-124, Application for Permit to Modify (subsequent report), to 
the appropriate District Manager, and include the following information:
    (a) Information included in Sec. 250.1712 with a final well 
schematic;
    (b) Description of the plugging work;
    (c) Nature and quantities of material used in the plugs; and
    (d) If you cut and pulled any casing string, the following 
information:
    (1) A description of the methods used (including information on 
explosives, if used);
    (2) Size and amount of casing removed; and
    (3) Casing removal depth.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                        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 MMS-124, 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. MMS 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) Within 30 days after you temporarily plug a well, you must 
submit form MMS-124, Application for Permit to Modify (subsequent 
report), and include the following information:
    (1) Information included in Sec. 250.1712 with a well schematic;
    (2) Information required by Sec. 250.1717(b), (c), and (d); and
    (3) A description of any remaining subsea wellheads, casing stubs, 
mudline suspension equipment, or other obstructions that extend above 
the seafloor; and
    (h) Submit certification by a Registered Professional Engineer of 
the well abandonment design and procedures; that there will be at least 
two independent tested barriers, including one mechanical barrier, 
across each flow path during abandonment activities; and that the plug 
meets the requirements in the table in Sec. 250.1715. The Registered 
Professional Engineer must be registered in a State in the United 
States. You must submit this

[[Page 266]]

certification with your APM (Form MMS-124) required by Sec. 250.1712.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002, as amended at 75 
FR 63377, Oct. 14, 2010]



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 MMS-124, 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 MMS 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 MMS-124, 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.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

[[Page 267]]



Sec. 250.1723  What must I do when it is no longer necessary to maintain a

well in temporary abandoned status?

    If you or MMS 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 MMS-
124, Application for Permit to Modify; and
    (c) Clear the well site according to Sec. 250.1740 through Sec. 
250.1742.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                 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 MMS 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 MMS. 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.

[67 FR 35406, May 17, 2002, as amended at 74 FR 19807, Apr. 29, 2009]



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.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



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 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:

[[Page 268]]

    (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/MMS 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.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



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 processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and MMS 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).

[[Page 269]]



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 MMS 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.

[67 FR 35406, May 17, 2002, as amended at 74 FR 19807, Apr. 29, 2009]



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 part 285 of this 
subchapter 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 285, 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 
256 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 256 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.

[74 FR 19807, Apr. 29, 2009]

        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:
    (1) Drag a trawl over the site;
    (2) Scan across the site using sonar equipment; or

[[Page 270]]

    (3) Use another method approved by the Regional Supervisor if the 
particular site conditions warrant.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]



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:

------------------------------------------------------------------------
           For a--                 You must drag the trawl 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  600-foot-radius circle centered on the
 protector jacket, template,    structure location.
 or manifold.
------------------------------------------------------------------------

    (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           no closer than 100    Trawl parallel to
 pipelines that are 8 inches   feet to the either    the pipeline Do not
 in diameter or larger.        side of the           trawl across the
                               pipeline.             pipeline.
(3) Unburied smaller          no closer than 100    Trawl parallel to
 diameter active pipelines     feet to either side   the pipeline. Do
 in the trawl area that have   of the pipeline.      not trawl across
 obstructions (e.g.,                                 the pipeline.
 pipeline valves) present.
(4) Unburied active           parallel to the       ....................
 pipelines in the trawl area   pipeline.
 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.

[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002; 67 FR 66049, Oct. 
30, 2002]



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:

[[Page 271]]



------------------------------------------------------------------------
        If you use--               You must--          And you must--
------------------------------------------------------------------------
(a) Sonar...................  cover 100 percent of  Use a sonar signal
                               the appropriate       with a frequency of
                               grid area listed in   at least 500 kHz.
                               Sec.  250.1741(a).
(b) A diver.................  ensure that the       Ensure that the
                               diver visually        diver uses a search
                               inspects 100          pattern of
                               percent of the        concentric circles
                               appropriate grid      or parallel lines
                               area listed in Sec.  spaced no more than
                                 250.1741(a).        10 feet apart.
(c) An ROV (remotely          ensure that the ROV   Ensure that the ROV
 operated vehicle).            camera records        uses a pattern of
                               videotape over 100    concentric circles
                               percent of the        or parallel lines
                               appropriate grid      spaced no more than
                               area listed in Sec.  10 feet apart.
                                 250.1741(a).
------------------------------------------------------------------------


[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002]



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 MMS-124, 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 they 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.

[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

                        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;

[[Page 272]]

    (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.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



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.

[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]



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)

    Source: 75 FR 63649, Oct. 15, 2010, unless otherwise noted.



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) 
(incorporated by reference as specified in Sec. 250.198), and other 
requirements as identified in this subpart.
    (a) You must comply with the provisions of this subpart and have 
your SEMS program in effect on or before November 15, 2011, except for 
the submission of Form MMS-131 as required in Sec. 250.1929.
    (b) You must submit Form MMS-131 on an annual basis beginning March 
31, 2011.
    (c) If there are any conflicts between the requirements of this 
subpart and API RP 75 (incorporated by reference as specified in Sec. 
250.198), you must follow the requirements of this subpart.
    (d) Nothing in this subpart affects safety or other matters under 
the jurisdiction of the Coast Guard.

[[Page 273]]



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, 
inspection, and maintenance of all new and existing facilities, 
including mobile offshore drilling units (MODU) while under BOEMRE 
jurisdiction and Department of Interior (DOI) regulated pipelines.
    (b) All personnel involved with your SEMS program must be trained to 
have the skills and knowledge to perform their assigned duties.



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 BOEMRE 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. Sec. 250.1920)
    (13) Recordkeeping (Records and Documentation) and additional BOEMRE 
requirements (see Sec. 250.1928).
    (b) You must also include a job safety analysis (JSA) for OCS 
activities identified or discussed in your SEMS program (see Sec. 
250.1911(b)).
    (c) Your SEMS program must meet or exceed the standards of safety 
and environmental protection of API RP 75 (incorporated by reference as 
specified in Sec. 250.198).



Sec. 250.1903  Definitions.

    Definitions listed in this section apply to this subpart and 
supersede definitions in API RP 75, Appendices D and E (incorporated by 
reference as specified in Sec. 250.198).
    Designated and qualified personnel means employees (not contractors) 
that are knowledgeable of your program, and have actual work experience 
and training in implementing and auditing a SEMS or a similar program in 
an offshore oil and gas environment.
    Personnel means direct employee(s) of the operator and contracted 
workers who are involved with or affected by specific jobs or tasks.



Sec. 250.1904  Documents incorporated by reference.

    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 section provides otherwise. If any 
incorporated document uses the word ``should'', it means must for 
purposes of these regulations.



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 (incorporated by reference as specified 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,

[[Page 274]]

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);
    (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 criteria for hazards analyses must my SEMS program meet?

    You must ensure the development and implementation of a hazards 
analysis (facility level) and a job safety analysis (operations/task 
level) for all of your facilities. For this subpart, facilities include 
all types of offshore structures permanently or temporarily attached to 
the seabed (i.e., mobile offshore drilling units; floating production 
systems; floating production, storage and offloading facilities; 
tension-leg platforms; and spars) used for exploration, development, 
production, and transportation activities for oil, gas, or sulphur from 
areas leased in the

[[Page 275]]

OCS. Facilities also include DOI regulated pipelines. You must document 
and maintain current analyses for each operation covered by this section 
for the life of the operation at the facility. The analyses must be 
updated when an internal audit is conducted to ensure that it is 
consistent with the current operations on your facility. Hazards 
analysis requirements for simple and nearly identical facilities, such 
as well jackets and single well caissons, may be fulfilled by performing 
a single hazards analysis which you can apply to all such facilities 
after you verify that any site specific deviations are addressed in each 
of the elements of your SEMS program.
    (a) Hazards Analysis (facility level). For a hazards analysis 
(facility level), you must perform an initial hazards analysis on each 
facility on or before November 15, 2011. The hazards analysis must be 
appropriate to 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.
    (b) Job Safety Analysis (JSA). You must develop and implement a JSA 
for OCS activities identified or discussed in your SEMS program.
    (1) You must keep a copy of the most recent JSA (operations/task 
level) at the job site and it must be readily accessible to employees.
    (2) Your JSA must identify, analyze, and record:
    (i) The steps involved in performing a specific job;
    (ii) the existing or potential safety and health hazards associated 
with each step; and
    (iii) the recommended action(s)/procedure(s) that will eliminate or 
reduce these hazards and the risk of a workplace injury or illness.
    (3) The supervisor of the person in charge of the task must approve 
the JSA prior to the commencement of the work.



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

[[Page 276]]

    (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.
    (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 operating, maintenance, 
and 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 
and environmental performance. Operators must ensure that contractors 
have their own written safe work practices. Contractors may adopt 
appropriate sections of the operator's SEMS program. Operator and 
contractor must document their agreement on appropriate contractor 
safety and environmental policies and practices before the contractor 
begins work at the operator's facilities.
    (a) A contractor is anyone performing work for the lessee. However, 
these requirements do not apply to contractors providing domestic 
services to the lessee 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

[[Page 277]]

job and a copy of the contractor's safety policies and procedures must 
be made available to the operator and BOEMRE 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 BOEMRE 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 MMS-131.
    (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.



Sec. 250.1915  What criteria for training must be in my SEMS program?

    Your SEMS program must establish and implement a training program so 
that all personnel are trained to work safely and are aware of 
environmental considerations offshore, in accordance with their duties 
and responsibilities. Training must address the operating procedures 
(Sec. 250.1913), the safe work practices (Sec. 250.1914), and the 
emergency response and control measures (Sec. 250.1918). You must 
document the qualifications of your instructors. 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 whenever a change is 
made to operating procedures (Sec. 250.1913), the safe work practices 
(Sec. 250.1914), or the emergency response and control measures (Sec. 
250.1918), personnel will be trained in or otherwise informed of the 
change before they are expected to operate the facility.
    (d) How you will verify that the contractors are trained in the work 
practices necessary to perform their jobs in a safe and environmentally 
sound manner, including training on operating procedures (Sec. 
250.1913), the safe work practices (Sec. 250.1914), or the emergency 
response and control measures (Sec. 250.1918).



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

[[Page 278]]

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 BOEMRE 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.
    (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

[[Page 279]]

    (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 
BOEMRE 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
    (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) You must have your SEMS program audited by either an independent 
third-party or your designated and qualified personnel according to the 
requirements of this subpart and API RP 75, Section 12 (incorporated by 
reference as specified in Sec. 250.198) within 2 years of the initial 
implementation of the SEMS program and at least once every 3 years 
thereafter. The audit must be a comprehensive audit of all thirteen 
elements of your SEMS program to evaluate compliance with the 
requirements of this subpart and API RP 75 to identify areas in which 
safety and environmental performance needs to be improved.
    (b) Your audit plan and procedures must meet or exceed all of the 
recommendations included in API RP 75 section 12 (incorporated by 
reference 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 BOEMRE at least 30 days before the audit. BOEMRE reserves the right 
to modify the list of facilities that you propose to audit.
    (5) Section 12.5 Audit Frequency, except your audit interval must 
not exceed 3 years after the 2 year time period for the first audit.
    (6) Section 12.6 Audit Team. The audit that you submit to BOEMRE 
must be conducted by either an independent third party or your 
designated and qualified personnel. The independent third party or your 
designated and qualified personnel must meet the requirements in Sec. 
250.1926.
    (c) You must require your auditor (independent third party or your 
designated and qualified personnel) to submit an audit report of the 
findings and conclusions of the audit to BOEMRE within 30 days of the 
audit completion

[[Page 280]]

date. The report must outline the results of the audit, including 
deficiencies identified.
    (d) You must provide the BOEMRE a copy of your plan for addressing 
the deficiencies identified in your audit within 30 days of completion 
of the audit. Your plan must address the following:
    (1) A proposed schedule to correct the deficiencies identified in 
the audit. BOEMRE will notify you within 14 days of receipt of your plan 
if your proposed schedule is not acceptable.
    (2) The person responsible for correcting each identified 
deficiency, including their job title.
    (e) BOEMRE may verify that you undertook the corrective actions and 
that these actions effectively address the audit findings.



Sec. Sec. 250.1921-250.1923  [Reserved]



Sec. 250.1924  How will BOEMRE determine if my SEMS program is effective?

    (a) BOEMRE or its authorized representative may evaluate or visit 
your facility to determine whether your SEMS program is in place, 
addresses all required elements, and is effective in protecting the 
safety and health of workers, the environment, and preventing incidents. 
BOEMRE or its authorized representative may evaluate your SEMS program, 
including documentation of contractors, independent third parties, your 
designated and qualified personnel, and audit reports, to assess your 
SEMS program. These evaluations or visits may be random or based upon 
the OCS lease operator's or contractor's performance.
    (b) For the evaluations, you must make the following available to 
BOEMRE upon request:
    (1) Your SEMS program;
    (2) The qualifications of your independent third-party or your 
designated and qualified personnel;
    (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 BOEMRE 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.
    (d) Representatives from BOEMRE may observe or participate in your 
SEMS audit. You must notify the BOEMRE at least 30-days prior to 
conducting your audit as required in Sec. 250.1920, so that BOEMRE may 
make arrangements to observe or participate in the audit.



Sec. 250.1925  May BOEMRE direct me to conduct additional audits?

    (a) If BOEMRE identifies safety or non-compliance concerns based on 
the results of our inspections and evaluations, or as a result of an 
event, BOEMRE may direct you to have an independent third-party audit of 
your SEMS program, in addition to the regular audit required by Sec. 
250.1920, or BOEMRE may conduct an audit.
    (1) If BOEMRE direct you to have an independent third-party audit,
    (i) You are responsible for all of the costs associated with the 
audit, and
    (ii) The independent third-party audit must meet the requirements of 
Sec. 250.1920 of this part and you must ensure that the independent 
third party submits the findings and conclusions of a BOEMRE-directed 
audit according to the requirements in Sec. 250.1920 to BOEMRE within 
30 days after the audit is completed.
    (2) If BOEMRE conducts the audit, BOEMRE will provide a report of 
the findings and conclusions within 30 days of the audit.
    (b) Findings from these audits may result in enforcement actions as 
identified in Sec. 250.1927.
    (c) You must provide the BOEMRE a copy of your plan for addressing 
the deficiencies identified in the BOEMRE-directed audit within 30 days 
of completion of the audit as required in Sec. 250.1920.

[[Page 281]]



Sec. 250.1926  What qualifications must an independent third party or my 

designated and qualified personnel meet?

    (a) You must either choose an independent third-party or your 
designated and qualified personnel to audit your SEMS program. You must 
take into account the following qualifications when selecting the third-
party or your designated and qualified personnel:
    (1) Previous education and experience with SEMS, or similar 
management related programs.
    (2) Technical capabilities of the individual or organization for the 
specific project.
    (3) Ability to perform the independent third-party functions for the 
specific project considering current commitments.
    (4) Previous experience with BOEMRE regulatory requirements and 
procedures.
    (5) Previous education and experience to comprehend and evaluate how 
the company's offshore activities, raw materials, production methods and 
equipment, products, byproducts, and business management systems may 
impact health and safety performance in the workplace.
    (b) You must have procedures to avoid conflicts of interest related 
to the development of your SEMS program and the independent third party 
auditor and your designated and qualified personnel.
    (c) BOEMRE may evaluate the qualifications of the independent third 
parties or your designated and qualified personnel. This may include an 
audit of documents and procedures or interviews. BOEMRE may disallow 
audits by a specific independent third-party or your designated and 
qualified personnel if they do not meet the criteria of this section.



Sec. 250.1927  What happens if BOEMRE finds shortcomings in my SEMS program?

    If BOEMRE 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 BOEMRE 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 activity must document the 
results of the JSA in writing and must ensure that records are kept 
onsite for 30 days. You must retain these records for 2 years and make 
them available to BOEMRE 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 BOEMRE upon request.
    (d) You must keep your injury/illness log for 2 years and make them 
available to BOEMRE upon request.
    (e) You must keep all evaluations completed on contractor's safety 
policies and procedures for 2 years and make them available to BOEMRE 
upon request.
    (f) You must keep all records in an orderly manner, readily 
identifiable, retrievable and legible, and include the date of any and 
all revisions.



Sec. 250.1929  What are my responsibilities for submitting OCS performance measure data?

    You must submit Form MMS-131 on an annual basis by March 31st. The 
form must be broken down quarterly, reporting the previous calendar 
year's data.



PART 251_GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER 

CONTINENTAL SHELF--Table of Contents



Sec.
251.1 Definitions.

[[Page 282]]

251.2 Purpose of this part.
251.3 Authority and applicability of this part.
251.4 Types of G&G activities that require permits or Notices.
251.5 Applying for permits or filing Notices.
251.6 Obligations and rights under a permit or a Notice.
251.7 Test drilling activities under a permit.
251.8 Inspection and reporting requirements for activities under a 
          permit.
251.9 Temporarily stopping, canceling, or relinquishing activities 
          approved under a permit.
251.10 Penalties and appeals.
251.11 Submission, inspection, and selection of geological data and 
          information collected under a permit and processed by 
          permittees or third parties.
251.12 Submission, inspection, and selection of geophysical data and 
          information collected under a permit and processed by 
          permittees or third parties.
251.13 Reimbursement for the cost of reproducing data and information 
          and certain processing costs.
251.14 Protecting and disclosing data and information submitted to MMS 
          under a permit.
251.15 Authority for information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

    Source: 62 FR 67284, Dec. 24, 1997, 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 means 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 Minerals Management Service, 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

[[Page 283]]

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 MMS 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. 1301), and of 
which the subsoil and seabed appertain to the United States and

[[Page 284]]

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 
MMS 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.

[62 FR 67284, Dec. 24, 1997, as amended at 74 FR 40730, Aug. 13, 2009]



Sec. 251.2  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

[[Page 285]]

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, MMS.



Sec. 251.3  Authority and applicability of this part.

    MMS 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 280.



Sec. 251.4  Types of G&G activities that require permits or Notices.

    (a) Exploration. You must have an MMS-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 an 
MMS-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 MMS in 
writing when you conclude your work.



Sec. 251.5  Applying for permits or filing Notices.

    (a) Permits. You must submit a signed original and three copies of 
the MMS permit application form (Form MMS-327). 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 MMS 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 327.

[[Page 286]]

    (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, Minerals Management Service, Alaska OCS Region, 949 
East 36th Avenue, Anchorage, Alaska 99508-4302.
    (2) For the OCS off the Atlantic Coast and in the Gulf of Mexico--
the Regional Supervisor for Resource Evaluation, Minerals Management 
Service, 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, 
Minerals Management Service, Pacific OCS Region, 770 Paseo Camarillo, 
Camarillo, California 93010-6064.

[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 40913, July 19, 2006; 
73 FR 49948, Aug. 25, 2008]



Sec. 251.6  Obligations and rights under a permit or a Notice.

    While conducting G&G exploration or scientific research activities 
under MMS 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.
    (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. 251.7  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 (b)(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 
Regional Director, at the address in Sec. 251.5(d), a drilling plan, an 
environmental report, an Application for Permit to Drill (Form MMS-123), 
and a Supplemental APD Information Sheet (Form MMS-123S) 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

[[Page 287]]

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 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. MMS 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 MMS.
    (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 Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the 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. (The 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 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.

[[Page 288]]

    (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 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 Regional Director for review.
    (ii) If the 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 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 
Regional Director. If investigations determine that the resource is 
significant, the 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 
MMS-123 and MMS-123S) 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 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, MMS 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 
MMS 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 Regional Director at least 60 
days before the first day of the month in which MMS schedules the lease 
sale. However, the 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. MMS 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.

[[Page 289]]

    (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 MMS issues a permit authorizing the drilling of a deep 
stratigraphic test, you must either:
    (i) Furnish to MMS 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 MMS 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 Associate Director 
for Offshore Minerals Management.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25202, May 4, 2007]



Sec. 251.8  Inspection and reporting requirements for activities under a permit.

    (a) Inspection of permit activities. You must allow MMS 
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. MMS will reimburse you for food, 
quarters, and transportation that you provide for MMS 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

[[Page 290]]

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. 251.9  Temporarily stopping, canceling, or relinquishing activities approved under a permit.

    (a) MMS 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 MMS' 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. MMS 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 MMS 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.
    (3) After MMS cancels your permit or you relinquish it, you are 
still responsible for proper abandonment of any drill sites in 
accordance with the requirements of Sec. 251.7(b)(8). You must also 
comply with all other obligations specified in this part or in the 
permit.



Sec. 251.10  Penalties and appeals.

    (a) Penalties for noncompliance under a permit issued by MMS. 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 250, 
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 MMS issues. See 30 CFR 
part 290 for instructions on how to appeal any order or decision that we 
issue under this part.

[62 FR 67284, Dec. 24, 1997, as amended at 65 FR 3856, Jan. 25, 2000]



Sec. 251.11  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,

[[Page 291]]

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 MMS 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 MMS. 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 250, 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. 251.12  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

[[Page 292]]

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 MMS 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. MMS 
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 MMS 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 the notification 
provisions of paragraph (a)(1), and is subject to the penalty provisions 
of 30 CFR part 250, 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. 251.13  Reimbursement for the costs of reproducing data and information 

and certain processing costs.

    (a) MMS 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 MMS for the Regional 
Director to inspect or select and retain (according to Sec. Sec. 251.11 
or 251.12 );

[[Page 293]]

    (2) MMS 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) MMS 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 MMS 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) MMS 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. 251.14  Protecting and disclosing data and information submitted to MMS under a permit.

    (a) Disclosure of data and information to the public by MMS. (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 250 and 252.
    (2) Except as specified in this section or in 30 CFR parts 250 and 
252, if the Regional Director determines any data or information is 
exempt from public disclosure under paragraph (a) of this section, MMS 
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) MMS will keep confidential the identity of third party 
recipients of data and information collected under a permit. MMS 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.
    (b) Timetable for release of G&G data and information related to 
oil, gas, and sulphur that MMS acquires. Except for high-resolution data 
and information released under 30 CFR 250.197(b)(2), MMS will release or 
disclose acquired data and information in accordance with paragraphs 
(b)(1) through (b)(7) of this section.
    (1) If the data and information are not related to a deep 
stratigraphic test, MMS will release them to the public in accordance 
with the following table:

------------------------------------------------------------------------
                                             The Regional Director will
  If you or a third party submit and MMS    release them to the public *
               retains * * *                             * *
------------------------------------------------------------------------
(i) Geological data and information,......  10 years after MMS issued
                                             the permit.
(ii) Geophysical data,....................  50 years after MMS issued
                                             the permit.
(iii) Geophysical information processed or  25 years after MMS issued
 reprocessed less than 20 years after MMS    the permit.
 issued the germane permit,
(iv) Geophysical information processed or   25 years after MMS issued
 reprocessed 20 or more years after MMS      the permit; or, if you or a
 issued the germane permit,                  third party applied for an
                                             extension of the
                                             proprietary term, 5 years
                                             after MMS approved the
                                             application for an
                                             extension. In any case MMS
                                             will release the
                                             information no later than
                                             50 years after MMS issued
                                             the permit.
------------------------------------------------------------------------

    (2) Permittees and third parties may apply to MMS for an extension 
of the 25-year proprietary term for geophysical information reprocessed 
20 or more years after MMS issued the germane permit. You must submit 
the application to MMS 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. 
251.5(d). Your application must include:

[[Page 294]]

    (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 MMS issued the permit. Once 
the maximum term is reached, the MMS Regional Director will release the 
information to the public.
    (4) Geophysical information processed or reprocessed 20 or more 
years after MMS issued the germane permit and granted the extension will 
be subject to submission, inspection, and selection criteria under 30 
CFR 251.12 and reimbursement criteria identified under 30 CFR 251.13.
    (5) There will be a 1-year grace period, starting September 14, 
2009, to allow permittees and third parties sufficient time to meet the 
above requirements and to apply for all eligible extensions. During this 
time, MMS will not release geophysical information which was reprocessed 
20 or more years after the date that MMS issued the germane permit.
    (6) After September 14, 2010 MMS will resume releasing eligible 
reprocessed information. If an application for extension is not filed, 
not filed on time, or not approved by MMS, 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, MMS 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 MMS issues the first lease, any portion of which is 
located within 50 geographic miles (92.7 kilometers) of the test.
    (8) MMS may allow limited inspection, but only by persons with a 
direct interest in related MMS 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 MMS 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 MMS 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. Sec. 251.11 or 
251.12 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 MMS 
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 252.7 (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:

[[Page 295]]

    (i) All information on the geographical, geological, and ecological 
characteristics of the areas and regions MMS 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, 
MMS will carry out a tentative area identification according to 30 CFR 
part 256, 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 252.7(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 250, 251, and 252.

[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 16039, Mar. 30, 2006; 
71 FR 62050, Oct. 20, 2006; 72 FR 25202, May 4, 2007; 74 FR 40731, Aug. 
13, 2009]



Sec. 251.15  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 251, 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.
    (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. 251.14 and part 250 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[62 FR 67284, Dec. 24, 1997, as amended at 65 FR 2875, Jan. 19, 2000; 74 
FR 46909, Sept. 14, 2009]



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.

[[Page 296]]

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: 44 FR 46408, Aug. 7, 1979, 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 parts 250 and 251 of this chapter 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, 
Minerals Management Service. 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 meanings given below:
    (a) Act refers to the Outer Continental Shelf Lands Act, as amended 
(43 U.S.C. 1331 et seq.).
    (b) 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.
    (c) 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 
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.
    (d) 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.
    (e) 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.
    (f) Data means facts and statistics or samples which have not been 
analyzed or processed.

[[Page 297]]

    (g) 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.
    (h) Director means the Director of the Minerals Management Service 
of the U.S. Department of the Interior or a designee of the Director.
    (i) 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.
    (j) 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.
    (k) Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    (l) 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.
    (m) 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.
    (n) 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.
    (o) 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 250 of this chapter, 
including all parties holding such authority by or through the lessee.
    (p) 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.
    (q) Permittee means the party authorized by a permit issued pursuant 
to part 251 of this chapter to conduct activities on the OCS.
    (r) 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. 
Processsing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements.
    (s) 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.
    (t) Secretary means the Secretary of the Interior or a designee of 
the Secretary.

[44 FR 46408, Aug. 7, 1979, as amended at 49 FR 10670, Mar. 22, 1984; 51 
FR 10382, Mar. 26, 1986]



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

[[Page 298]]

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 provided in the contract. Contracts between 
the Minerals Management Service 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

[[Page 299]]

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.

[44 FR 46408, Aug. 7, 1979, as amended at 51 FR 17176, May 9, 1986]



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 the Minerals Management Service 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 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 Director shall prepare an index of OCS information (see 30 
CFR 256.10). 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 the Minerals 
Management Service, in

[[Page 300]]

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.

[44 FR 46408, Aug. 7, 1979, as amended at 54 FR 50617, Dec. 8, 1989]



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 part 250 (Oil and Gas and Sulphur 
Operations in the Outer Continental Shelf) and 30 CFR part 251 
(Geological and Geophysical Explorations of the Outer Continental 
Shelf).
    (b) Except as provided in Sec. 252.7 or in parts 250 and 251 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. 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 250.106 and 251.14, 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 250.106 and 251.14, 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 
part 250 (Oil and Gas and Sulphur Operations in the Outer Continental 
Shelf), the regulations contained in 30 CFR part 251 (Geological and 
Geophysical Explorations of the Outer Continental Shelf), and the 
regulations contained in this part 252 (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.

[[Page 301]]

    (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.

[44 FR 46408, Aug. 7, 1979, as amended at 64 FR 72794, Dec. 28, 1999]



PART 253_OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES--Table of Contents



                            Subpart A_General

Sec.
253.1 What is the purpose of this part?
253.3 How are the terms used in this regulation defined?
253.5 What is the authority for collecting Oil Spill Financial 
          Responsibility (OSFR) information?

               Subpart B_Applicability and Amount of OSFR

253.10 What facilities does this part cover?
253.11 Who must demonstrate OSFR?
253.12 May I ask MMS for a determination of whether I must demonstrate 
          OSFR?
253.13 How much OSFR must I demonstrate?
253.14 How do I determine the worst case oil-spill discharge volume?
253.15 What are my general OSFR compliance responsibilities?

                Subpart C_Methods for Demonstrating OSFR

253.20 What methods may I use to demonstrate OSFR?
253.21 How can I use self-insurance as OSFR evidence?
253.22 How do I apply to use self-insurance as OSFR evidence?
253.23 What information must I submit to support my net worth 
          demonstration?
253.24 When I submit audited annual financial statements to verify my 
          net worth, what standards must they meet?
253.25 What financial test procedures must I use to determine the amount 
          of self-insurance allowed as OSFR evidence based on net worth?
253.26 What information must I submit to support my unencumbered net 
          assets demonstration?
253.27 When I submit audited annual financial statements to verify my 
          unencumbered assets, what standards must they meet?
253.28 What financial test procedures must I use to evaluate the amount 
          of self-insurance allowed as OSFR evidence based on 
          unencumbered assets?
253.29 How can I use insurance as OSFR evidence?
253.30 How can I use an indemnity as OSFR evidence?
253.31 How can I use a surety bond as OSFR evidence?
253.32 Are there alternative methods to demonstrate OSFR?

         Subpart D_Requirements for Submitting OSFR Information

253.40 What OSFR evidence must I submit to MMS?
253.41 What terms must I include in my OSFR evidence?
253.42 How can I amend my list of COFs?

[[Page 302]]

253.43 When is my OSFR demonstration or the amendment to my OSFR 
          demonstration effective?
253.44 [Reserved]
253.45 Where do I send my OSFR evidence?

                   Subpart E_Revocation and Penalties

253.50 How can MMS refuse or invalidate my OSFR evidence?
253.51 What are the penalties for not complying with this part?

        Subpart F_Claims for Oil-Spill Removal Costs and Damages

253.60 To whom may I present a claim?
253.61 When is a guarantor subject to direct action for claims?
253.62 What are the designated applicant's notification obligations 
          regarding a claim?

Appendix to Part 253--List of U.S. Geological Survey Topographic Maps

    Authority: 33 U.S.C. 2716, 28 U.S.C. 2461.

    Effective Date Note: At 76 FR 38296, June 30, 2011, the authority 
citation for part 253 was revised, effective Aug. 1, 2011. For the 
convenience of the user, the revised text is set forth as follows:
    Authority: 28 U.S.C. 2461 note, 33 U.S.C. 2716.

    Source: 63 FR 42711, Aug. 11, 1998, unless otherwise noted.



                            Subpart A_General



Sec. 253.1  What is the purpose of this part?

    This part establishes the requirements for demonstrating OSFR for 
covered offshore facilities (COFs) under Title I of the Oil Pollution 
Act of 1990 (OPA), as amended, 33 U.S.C. 2701 et seq.



Sec. 253.3  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.
    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.
    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.
    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 Minerals Management Service.

[[Page 303]]

    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 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.
    Responsible party has the following meanings:
    (1) For a COF that is a pipeline, responsible party means any person 
owning or operating the pipeline;

[[Page 304]]

    (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.
    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 States Virgin Islands, the Commonwealth of the Northern Marianas, 
and any other territory or possession of the United States.



Sec. 253.5  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 253 under 44 U.S.C. 
3501 et seq. and assigned OMB control number 1010-0106.
    (b) MMS 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. 
MMS 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[63 FR 42711, Aug. 11, 1998, as amended at 65 FR 2876, Jan. 19, 2000; 74 
FR 46909, Sept. 14, 2009]



               Subpart B_Applicability and Amount of OSFR



Sec. 253.10  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. 253.11  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 MMS-1017 to select a designated applicant. The 
designated

[[Page 305]]

applicant must submit Form MMS-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 250.143 
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) MMS may require the designated applicant for a lease, permit, or 
RUE to be a person other than a person identified in paragraphs (b) 
through (d) of this section if MMS 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.

[63 FR 42711, Aug. 11, 1998, as amended at 64 FR 72794, Dec. 28, 1999]



Sec. 253.12  May I ask MMS for a determination of whether I must demonstrate OSFR?

    You may submit to MMS a request for a determination of OSFR 
applicability. Address the request to the office identified in Sec. 
253.45. You must include in your request any information that will 
assist MMS in making the determination. MMS may require you to submit 
other information before making a determination of OSFR applicability.



Sec. 253.13  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 (b)(2) for a facility with a 
potential worst case oil-spill discharge of 1,000 bbls or less if the 
Director notifies you

[[Page 306]]

in writing that the demonstration is justified by the risks of the 
potential oil-spill discharge.



Sec. 253.14  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. 253.13(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. 253.15  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 MMS 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 MMS.
    (e) You must notify MMS 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 MMS directs to 
ensure an acceptable OSFR demonstration.
    (f) If you deny payment of a claim presented to you under Sec. 
253.60, then you must give the claimant a written explanation for your 
denial.

[63 FR 42711, Aug. 11, 1998; 63 FR 48578, Sept. 11, 1998]



                Subpart C_Methods for Demonstrating OSFR



Sec. 253.20  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. 253.21 through 253.28;
    (b) Insurance under Sec. 253.29;
    (c) An indemnity under Sec. 253.30;
    (d) A surety bond under Sec. 253.31; or
    (e) An alternative method the Director approves under Sec. 253.32.



Sec. 253.21  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. 253.25 or an unencumbered net asset test under 
Sec. 253.28.
    (b) To establish the amount of self-insurance allowed, you must 
submit evidence of your net worth under Sec. 253.23 or evidence of your 
unencumbered assets under Sec. 253.26.
    (c) You must identify a U.S. agent for service of process.

[[Page 307]]



Sec. 253.22  How do I apply to use self-insurance as OSFR evidence?

    (a) You must submit a complete Form MMS-1018 with each application 
to demonstrate OSFR using self-insurance.
    (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 MMS your initial application to 
demonstrate OSFR using self-insurance at any time.



Sec. 253.23  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 MMS; 
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. 253.24  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 MMS 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. 253.25  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. 253.26  What information must I submit to support my unencumbered assets demonstration?

    You must support your unencumbered assets evaluation with the 
information required by Sec. 253.23(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;

[[Page 308]]

    (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;
    (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. 253.27  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. 253.24; 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. 253.28  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. 253.29  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 MMS.
    (b) You must submit information about your insurers to MMS on a 
completed and unaltered Form MMS-1019. The information you submit must:
    (1) Include all the information required by Sec. 253.41 and
    (2) Be executed on one original insurance certificate (i.e., Form 
MMS-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 MMS 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. 253.13;
    (2) No more than one insurance certificate may be used to cover each 
OSFR layer specified in Sec. 253.13(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;

[[Page 309]]

    (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 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 MMS. The agent may be different for 
each insurance certificate.
    (d) You may submit to MMS a temporary insurance confirmation (fax 
binder) for each insurance certificate you use as OSFR evidence. Submit 
your fax binder on Form MMS-1019, and each form must include the 
signature of an underwriter for at least one of the participating 
insurers. MMS 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. 253.30  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 MMS-1018 and provide an 
indemnity that:
    (1) Includes all the information required by Sec. 253.41; and
    (2) Does not exceed the amounts calculated using the net worth or 
unencumbered assets tests specified under Sec. Sec. 253.21 through 
253.28.
    (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 MMS 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. 253.31  How can I use a surety bond as OSFR evidence?

    (a) Each bonding company that issues a surety bond that you submit 
to MMS 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 MMS-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. 253.41.



Sec. 253.32  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. 
253.45. 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 
290 or 43 CFR part 4.



         Subpart D_Requirements for Submitting OSFR Information



Sec. 253.40  What OSFR evidence must I submit to MMS?

    (a) You must submit to MMS:
    (1) A single demonstration of OSFR that covers all the COFs for 
which you are the designated applicant;
    (2) A completed and unaltered Form MMS-1016;
    (3) MMS forms that identify your COFs (Form MMS-1021, Form MMS-
1022), and the methods you will use to demonstrate OSFR (Form MMS-1018, 
Form MMS-1019, Form MMS-1020). Forms are available from the address 
listed in Sec. 253.45;
    (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 MMS-1017 for each responsible party, unless you 
are

[[Page 310]]

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. 253.32.
    (b) Each MMS form you submit to MMS as part of your OSFR 
demonstration must be signed. You also must attach to Form MMS-1016 
proof of your authority to sign.



Sec. 253.41  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 MMS and the designated applicant 
receive from the instrument issuer a notification of intent to cancel; 
or
    (ii) MMS 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. 
253.60 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 an MMS form that you submit as part of your 
OSFR demonstration. If you attempt to do this, MMS will disregard the 
changes, omissions, additions, limitations, or exceptions and by 
operation of this rule MMS will consider the form to contain all the 
terms and conditions included on the original MMS form.



Sec. 253.42  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 MMS a completed Form MMS-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 MMS a completed Form MMS-1022. You 
must continue to demonstrate OSFR for the COF until MMS 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. 253.43  When is my OSFR demonstration or the amendment to my OSFR demonstration effective?

    (a) MMS 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, MMS 
acceptance of OSFR evidence is valid until the surety bond, insurance 
certificate, or

[[Page 311]]

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.



Sec. 253.44  [Reserved]



Sec. 253.45  Where do I send my OSFR evidence?

    Address all correspondence and required submissions related to this 
part to: U.S. Department of the Interior, Minerals Management Service, 
Gulf of Mexico Region, Oil Spill Financial Responsibility Program, 1201 
Elmwood Park Boulevard, New Orleans, Louisiana 70123.



                   Subpart E_Revocation and Penalties



Sec. 253.50  How can MMS refuse or invalidate my OSFR evidence?

    (a) If MMS 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. 253.51.
    (b) MMS 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 MMS 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 MMS specifies within 15 calendar days from the date you receive 
such a notice, we will invalidate your OSFR demonstration.



Sec. 253.51  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 $27,500 per 
COF per day of violation (that is, each day a COF is operated without 
acceptable evidence of OSFR).
    (b) MMS will determine the date of a noncompliance. MMS will assess 
penalties in accordance with an OSFR penalty schedule using the 
procedures found at 30 CFR part 250, subpart N. You may obtain a copy of 
the penalty schedule from MMS at the address in Sec. 253.45.
    (c) MMS 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.

[63 FR 42711, Aug. 11, 1998, as amended at 64 FR 72794, Dec. 28, 1999; 
72 FR 8899, Feb. 28, 2007]

    Effective Date Note: At 76 FR 38296, June 30, 2011, Sec. 253.51 was 
amended by revising paragraph (a), effective Aug. 1, 2011. For the 
convenience of the user, the revised text is set forth as follows:



Sec. 253.51  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 $30,000 per 
COF per day of violation (that is, each day a COF is operated without 
acceptable evidence of OSFR).

                                * * * * *

[[Page 312]]



        Subpart F_Claims for Oil-Spill Removal Costs and Damages



Sec. 253.60  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:

------------------------------------------------------------------------
 If the reason for denial or
        nonpayment is                    then you may elect to
------------------------------------------------------------------------
(1) Not an assertion of        (i) Present your claim to any of the
 insolvency or petition in      responsible parties for the COF; or
 bankruptcy under 11 U.S.C.    (ii) Initiate a lawsuit against the
 chapter 7 or 11.               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            (i) Pursue any of the remedies in items
 insolvency or petition in      (1)(i) through (iii) of this table; or
 bankruptcy under 11 U.S.C.    (ii) Present your claim to any of the
 chapter 7 or 11.               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 MMS 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. 253.45. You must include any information you 
have regarding the existence or identity of possible guarantors.



Sec. 253.61  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. 253.62  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.



 Sec. Appendix to Part 253--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.
    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

[[Page 313]]

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; 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

[[Page 314]]

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 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 a spill-response plan?
254.2 When must I submit a response plan?
254.3 May I cover more than one facility in my response plan?
254.4 May I reference other documents in my response plan?
254.5 General response plan requirements.
254.6 Definitions.
254.7 How do I submit my response plan to the MMS?
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 response plan?
254.22 What information must I include in the ``Introduction and plan 
          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 inventories'' 
          appendix?

[[Page 315]]

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?
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 response plan?

  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 response plan.
254.52 Following the format for an OCS response plan.
254.53 Submitting a response plan developed under State requirements.
254.54 Spill prevention for facilities located in State waters seaward 
          of the coast line.

    Authority: 33 U.S.C. 1321

    Source: 62 FR 13996, Mar. 25, 1997, unless otherwise noted.



                            Subpart A_General



Sec. 254.1  Who must submit a spill-response plan?

    (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 a spill-response plan to MMS for approval. Your spill-
response plan 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 response plan for an abandoned 
facility until you physically remove or dismantle the facility or until 
the Regional Supervisor 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 Regional 
Supervisor.
    (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 MMS, you may contact the Regional Supervisor, 
offer to accept MMS jurisdiction over your facility, and request that 
MMS seek from the agency with jurisdiction over your facility a 
relinquishment of that jurisdiction.



Sec. 254.2  When must I submit a response plan?

    (a) You must submit, and MMS must approve, a response plan that 
covers each facility located seaward of the coast line before you may 
use that facility. To continue operations, you must operate the facility 
in compliance with the plan.
    (b) Despite the provisions of paragraph (a) of this section, you may 
operate your facility after you submit your plan while MMS reviews it 
for approval. To operate a facility without an approved plan, you must 
certify in writing to the Regional Supervisor 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

[[Page 316]]

means approved by the Regional Supervisor, 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. MMS will not allow you to 
operate a facility for more than 2 years without an approved plan.
    (c) If you have a plan that MMS already approved, you are not 
required to immediately rewrite the plan to comply with this part. You 
must, however, submit the information this regulation requires when 
submitting your first plan revision (see Sec. 254.30) after the 
effective date of this rule. The Regional Supervisor may extend this 
deadline upon request.



Sec. 254.3  May I cover more than one facility in my response plan?

    (a) Your response plan 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 MMS Region (see definition of Regional Response Plan 
in Sec. 254.6).
    (b) Regional Response Plans must address all the elements required 
for a response plan in Subpart B, Oil Spill Response Plans for Outer 
Continental Shelf Facilities, or Subpart D, Oil Spill Response 
Requirements for Facilities Located in State Waters Seaward of the Coast 
Line, as appropriate.
    (c) When developing a Regional Response Plan, you may group leases 
or facilities subject to the approval of the Regional Supervisor 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 Regional Supervisor may specify how to address the elements 
of a Regional Response Plan. The Regional Supervisor also may require 
that Regional Response Plans contain additional information if necessary 
for compliance with appropriate laws and regulations.



Sec. 254.4  May I reference other documents in my response plan?

    You may reference information contained in other readily accessible 
documents in your response plan. Examples of documents that you may 
reference are the National Contingency Plan (NCP), Area Contingency Plan 
(ACP), MMS environmental documents, and Oil Spill Removal Organization 
(OSRO) documents that are readily accessible to the Regional Supervisor. 
You must ensure that the Regional Supervisor possesses or is provided 
with copies of all OSRO documents you reference. You should contact the 
Regional Supervisor if you want to know whether a reference is 
acceptable.



Sec. 254.5  General response plan requirements.

    (a) The response plan must provide for response to an oil spill from 
the facility. You must immediately carry out the provisions of the plan 
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 plan, 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 plan 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 Regional Supervisor requires for 
compliance with appropriate laws and regulations.



Sec. 254.6  Definitions.

    For the purposes of this part:
    Adverse weather conditions means 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 include, but

[[Page 317]]

are not limited to: Fog, inhospitable water and air temperatures, wind, 
sea ice, current, and sea states. It does not refer to conditions such 
as a hurricane, under which it would be dangerous or impossible to 
respond to a spill.
    Area Contingency Plan means an Area Contingency Plan prepared and 
published under section 311(j) of the Federal Water Pollution Control 
Act (FWPCA).
    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 MMS officer with authority and 
responsibility for a district within an MMS 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.
    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 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.
    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

[[Page 318]]

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 MMS Region.
    Regional Supervisor means the MMS official with responsibility and 
authority for operations or other designated program functions within an 
MMS 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 a 
response plan 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.

[62 FR 13996, Mar. 25, 1997, as amended at 71 FR 46400, Aug. 14, 2006]



Sec. 254.7  How do I submit my response plan to the MMS?

    You must submit the number of copies of your response plan that the 
appropriate MMS regional office requires. If you prefer to use improved 
information technology such as electronic filing to submit your plan, 
ask the Regional Supervisor for further guidance.
    (a) Send plans for facilities located seaward of the coast line of 
Alaska to: Minerals Management Service, Regional Supervisor, Field 
Operations, Alaska OCS Region, 949 East 36th Avenue, Anchorage, AK 
99508-4302.
    (b) Send plans for facilities in the Gulf of Mexico or Atlantic 
Ocean to: Minerals Management Service, Regional Supervisor, Field 
Operations, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New 
Orleans, LA 70123-2394.
    (c) Send plans for facilities in the Pacific Ocean (except seaward 
of the coast line of Alaska) to: Minerals Management Service, Regional 
Supervisor, Office of Development Operations and Safety, Pacific OCS 
Region, 770 Paseo Camarillo, Camarillo, CA 93010-6064.



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.

[65 FR 3857, Jan. 25, 2000]



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 1010-0091. The title of this 
information collection is ``30 CFR part 254, Oil Spill Response 
Requirements for Facilities Located Seaward of the Coast line.''
    (b) MMS collects this information to ensure that the owner or 
operator of an offshore facility is prepared to respond to an oil spill. 
MMS uses the information to verify compliance with the

[[Page 319]]

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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[62 FR 13996, Mar. 25, 1997, as amended at 62 FR 18041, Apr. 14, 1997; 
65 FR 2876, Jan. 19, 2000; 74 FR 46909, Sept. 14, 2009]



     Subpart B_Oil-Spill Response Plans for Outer Continental Shelf 
                               Facilities



Sec. 254.20  Purpose.

    This subpart describes the requirements for preparing spill-response 
plans for facilities located on the OCS.



Sec. 254.21  How must I format my response plan?

    (a) You must divide your response plan for OCS facilities into the 
sections specified in paragraph (b) and explained in the other sections 
of this subpart. The plan 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 Regional Supervisor 
that they provide for equal or greater levels of preparedness.
    (b) Your plan must include:
    (1) Introduction and plan 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.



Sec. 254.22  What information must I include in the ``Introduction and plan contents'' section?

    The ``Introduction and plan contents'' section must provide:
    (a) Identification of the facility the plan covers, including its 
location and type;
    (b) A table of contents;
    (c) A record of changes made to the plan; and
    (d) A cross-reference table, if needed, because you are using an 
alternate format for your plan.



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 
response plan. 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

[[Page 320]]

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
    (9) Your methods to implement your dispersant use plan and your in 
situ burning plan.



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 plan. 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.



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

[[Page 321]]

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;
    (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

[[Page 322]]

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.



Sec. 254.30  When must I revise my response plan?

    (a) You must review your response plan at least every 2 years and 
submit all resulting modifications 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.
    (b) You must submit revisions to your plan 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 plan; or
    (4) There is a significant change to the Area Contingency Plan(s).
    (c) The Regional Supervisor may require that you resubmit your plan 
if the plan has become outdated or if numerous revisions have made its 
use difficult.
    (d) The Regional Supervisor 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 plans.
    (e) The Regional Supervisor may require you to revise your plan 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 Regional Supervisor obtained.

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  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 MMS 
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 response plan for at least 2 
years. They must be made available to any authorized MMS representative 
upon request.



Sec. 254.42  Exercises for your response personnel and equipment.

    (a) You must exercise your entire response plan at least once every 
3 years (triennial exercise). You may satisfy this requirement by 
conducting separate exercises for individual parts of the plan over the 
3-year period; you do not have to exercise your entire response plan 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 
decisionmaking in managing a response. You must not reveal the spill 
scenario to team members before the exercise starts.
    (2) An annual deployment exercise of response equipment identified 
in your plan 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 MMS 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) MMS 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. MMS 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:

[[Page 324]]

    (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 plan. Records 
showing that OSRO's 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 Regional Supervisor 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 MMS 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 Regional Supervisor may require changes in the frequency or 
location of the required exercises, equipment to be deployed and 
operated, or deployment procedures or strategies. The Regional 
Supervisor 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 Regional 
Supervisor.



Sec. 254.43  Maintenance and periodic inspection of response equipment.

    (a) You must ensure that the response equipment listed in your 
response plan 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 MMS representative upon request.



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 response plan that you would use to contain and recover your 
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).



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 response plan 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 MMS.
    (b) You must conduct any required performance testing of booms in 
accordance with MMS-approved test criteria. You may use the document 
``Test Protocol for the Evaluation of Oil-Spill Containment Booms,'' 
available from MMS, for guidance. Performance testing of skimmers also 
must be conducted in accordance with MMS approved test criteria. You may 
use the document ``Suggested Test Protocol for the Evaluation of Oil 
Spill Skimmers for the OCS,'' available from MMS, for guidance.

[[Page 325]]

    (c) You are responsible for any required testing of equipment 
performance and for the accuracy of the information submitted.



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 followup report for any spill from your 
facility of 1 barrel or more. The Regional Supervisor 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.



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
    (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.

[[Page 326]]

    (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 Regional Supervisor for 
instructions on the calculation of the volume of your worst case 
discharge scenario.



  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 MMS 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 response plan.

    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 plan 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 MMS 
office if you have any questions on how to prepare this Regional 
Response Plan.



Sec. 254.52  Following the format for an OCS response plan.

    You may develop a response plan following the requirements for plans 
for OCS facilities found in subpart B of this part.



Sec. 254.53  Submitting a response plan developed under State requirements.

    (a) You may submit a response plan to MMS for approval that you 
developed in accordance with the laws or regulations of the appropriate 
State. The plan 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.



Sec. 254.54  Spill prevention for facilities located in State waters seaward of the coast line.

    In addition to your response plan, 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

[[Page 327]]

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 Regional Supervisor 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.



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.
256.0 Authority for information collection.
256.1 Purpose.
256.2 Policy.
256.4 Authority.
256.5 Definitions.
256.7 Cross references.
256.8 Leasing maps and diagrams.
256.10 Information to States.
256.11 Helium.
256.12 Supplemental sales.

                  Subpart B_Oil and Gas Leasing Program

256.16 Receipt and consideration of nominations; public notice and 
          participation.
256.17 Review by State and local governments and other persons.
256.19 Periodic consultation with interested parties.
256.20 Consideration of coastal zone management program.

                 Subpart C_Reports From Federal Agencies

256.22 General.

             Subpart D_Call for Information and Nominations

256.23 Information on areas.
256.25 Areas near coastal States.

              Subpart E_Area Identification and Tract Size

256.26 General.
256.28 Tract size.

                          Subpart F_Lease Sales

256.29 Proposed notice of sale.
256.31 State comments.
256.32 Notice of sale.

                      Subpart G_Issuance of Leases

256.35 Qualifications of lessees.
256.37 Lease term.
256.38 Joint bidding provisions.
256.40 Definitions.
256.41 Joint bidding requirements.
256.43 Chargeability for production.
256.44 Bids disqualified.
256.46 Submission of bids.
256.47 Award of leases.
256.49 Lease form.
256.50 Dating of leases.

Subpart H--Rentals and Royalties [Reserved]

                            Subpart I_Bonding

256.52 Bond requirements for an oil and gas or sulphur lease.
256.53 Additional bonds.
256.54 General requirements for bonds.
256.55 Lapse of bond.
256.56 Lease-specific abandonment accounts.
256.57 Using a third-party guarantee instead of a bond.
256.58 Termination of the period of liability and cancellation of a 
          bond.
256.59 Forfeiture of bonds and/or other securities.

            Subpart J_Assignments, Transfers, and Extensions

256.62 Assignment of lease or interest in lease.
256.63 Service fees.
256.64 How to file transfers.
256.65 Attorney General review.
256.67 Separate filings for assignments.
256.68 Effect of assignment of a particular tract.
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 K_Termination of Leases

256.76 Relinquishment of leases or parts of leases.
256.77 Cancellation of leases.

                       Subpart L_Section 6 Leases

256.79 Effect of regulations on lease.
256.80 Leases of other minerals.

[[Page 328]]

                            Subpart M_Studies

256.82 Environmental studies.

   Subpart N_Bonus or Royalty Credits for Exchange of Certain Leases 
                            Offshore Florida

256.90 Which leases may I exchange for a bonus or royalty credit?
256.91 How much bonus or royalty credit will MMS grant in exchange for a 
          lease?
256.92 What must I do to obtain a bonus or royalty credit?
256.93 How is the bonus or royalty credit allocated among multiple lease 
          owners?
256.94 How may I use the bonus or royalty credit?
256.95 How do I transfer a bonus or royalty credit to another person?

Appendix A to Part 256--Oil and Gas Cash Bonus Bid

    Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. L. 
109-432.

    Source: 44 FR 38276, June 29, 1979, unless otherwise noted. 
Redesignated at 47 FR 47006, Oct. 22, 1982.



  Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management, 
                                 General



Sec. 256.0  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 1010-0006. The title of this 
information collection is ``30 CFR part 256, Leasing of Sulphur or Oil 
and Gas in the Outer Continental Shelf.''
    (b) MMS collects this information to determine if the applicant 
filing for a lease on the Outer Continental Shelf is qualified to hold 
such a lease. Response is required to obtain a benefit according to 43 
U.S.C. 1331 et seq. MMS will protect proprietary information collected 
according to section 26 of the OCS Lands Act and 30 CFR 256.10.
    (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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[65 FR 2876, Jan. 19, 2000, as amended at 74 FR 46909, Sept. 14, 2009]



Sec. 256.1  Purpose.

    The purpose of the regulations in this part 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, rights-of-use 
and easements are addressed in other parts.

[64 FR 72795, Dec. 28, 1999]



Sec. 256.2  Policy.

    The management of Outer Continental Shelf 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 (43 U.S.C. 1332, 1801, 1802), and other Executive, legislative, 
judicial and Departmental guidance. The Secretary of the Interior shall 
consider available environmental information in making decisions 
affecting Outer Continental Shelf resources.



Sec. 256.4  Authority.

    The outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1331 et 
seq.) authorizes the Secretary of the Interior to issue, on a 
competitive basis, leases for oil and gas, and sulphur, in submerged 
lands of the outer Continental Shelf (OCS). The Act authorizes the 
Secretary to grant rights-of-way, rights-of-use and easements through 
the submerged lands of the OCS. The Energy Policy and Conservation Act 
of 1975 (42 U.S.C. 6213), prohibits joint bidding by major oil and gas 
producers.

[64 FR 72795, Dec. 28, 1999]



Sec. 256.5  Definitions.

    As used in this part, the term:
    (a) Act refers to the Outer Continental Shelf Lands Act of August 7, 
1953 (43 U.S.C. 1331 et seq.) as amended.

[[Page 329]]

    (b) Director means the Director, Minerals Management Service.
    (c) OCS means the Outer Continental Shelf, as that term is defined 
in 43 U.S.C. 1331(a).
    (d) Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    (e) MMS means the Minerals Management Service.
    (f) 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 includes 
islands, transition and intertidal areas, salt marshes, wetlands, and 
beaches, which 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 inward boundaries 
of which may be identified by the several coastal States, pursuant to 
the authority of section 305(b)(1) of the Coastal Zone Management Act of 
1972 (16 U.S.C. 1454(b)(1));
    (g) 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) of 
the Act, to be the law of the United States for the portion of the Outer 
Continental Shelf 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 structure referred 
to in section 4(a)(1) of the Act;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the Outer Continental Shelf 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 Outer Continental Shelf; 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 oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities;
    (h) Marine environment means the physical, atmospheric, and 
biological components, conditions, and factors which 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 Outer Continental Shelf;
    (i) Coastal environment means the physical, atmospheric, and 
biological components, conditions, and factors which interactively 
determine the productivity, state, conditions, and quality of the 
terrestrial ecosystem from the shoreline inward to the boundaries of the 
coastal zone;
    (j) 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 Outer Continental Shelf;
    (k) Mineral means oil, gas, and sulphur; it includes sand and gravel 
and salt used to facilitate the development and production of oil, gas, 
or sulphur.
    (l) Authorized officer means any person authorized by law or by 
delegation of authority to or within MMS to perform the duties described 
in this part.
    (m) Bonus or royalty credit means a legal instrument or other 
written documentation, 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--

[[Page 330]]

    (1) A bonus due for a lease on the Outer Continental Shelf; or
    (2) A royalty due on oil or gas production from any lease located on 
the Outer Continental Shelf.
    (n) Central planning area means the Central Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled ``Draft Proposed Program Outer Continental Shelf Oil and Gas 
Leasing Program 2007-2012,'' dated February 2006.
    (o) Coastline means the line of 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.
    (p) Desoto Canyon OPD means the official protraction diagram 
designated as Desoto Canyon which has a western edge located at the 
universal transverse mercator (UTM) X coordinate 1,346,400 in the North 
American Datum of 1927 (NAD 27).
    (q) Destin Dome OPD means the official protraction diagram 
designated as Destin Dome which has a western edge located at the 
universal transverse mercator (UTM) X coordinate 1,393,920 in the NAD 
27.
    (r) Eastern planning area means the Eastern Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled ``Draft Proposed Program Outer Continental Shelf Oil and Gas 
Leasing Program 2007-2012,'' dated February 2006.
    (s) Pensacola OPD means the official protraction diagram designated 
as Pensacola which has a western edge located at the universal 
transverse mercator (UTM) X coordinate 1,393,920 in the NAD 27.

[44 FR 38276, June 29, 1979. Redesignated and amended at 47 FR 47006, 
47007, Oct. 22, 1982; 54 FR 2049, Jan. 18, 1989; 73 FR 52920, Sept. 12, 
2008]



Sec. 256.7  Cross references.

    (a) For Minerals Management Service regulations governing 
exploration, development and production on leases, see 30 CFR parts 250 
and 270.
    (b) For MMS regulations governing the appeal of an order or decision 
issued under the regulations in this part, see 30 CFR part 290.
    (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.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
and amended at 54 FR 50617, Dec. 8, 1989; 55 FR 32908, Aug. 13, 1990; 62 
FR 27955, May 22, 1997]



Sec. 256.8  Leasing maps and diagrams.

    (a) Any area of the OCS which has been appropriately platted as 
provided in paragraph (b) of this section, is subject to lease for any 
mineral not included in a subsisting 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) The MMS shall prepare leasing maps and official protraction 
diagrams of areas of the OCS. The areas included in each mineral lease 
shall be in accordance with the appropriate leasing map or official 
protraction diagram.



Sec. 256.10  Information to States.

    (a) The information covered in this section is prepared by or 
directly obtained by the Director. Such information is typically not 
considered to be

[[Page 331]]

proprietary or privileged, with the primary exception of specific 
indications of interest in an area by industry received in response to a 
Call for Information issued by the Secretary. This information and all 
other proprietary and privileged information obtained by or under the 
control of the Minerals Management Service may be released only in 
accordance with the regulations in 30 CFR parts 250, 251, and 252.
    (b) The Director shall prepare an index to OCS information (see 30 
CFR 252.5). 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 by or directly obtained by the Director under 
the act. The index shall be sent on a regular basis to affected States 
and, upon request, it shall be sent to any affected local government. 
The public shall be informed of the availability of the index.
    (c) Upon request, the Director shall transmit to affected States, 
local governments or the public, a copy of any information listed in the 
index which is subject to the control of the MMS in accordance with the 
requirements and subject to the limitations of the Freedom of 
Information Act (5 U.S.C. 552) and regulations implementing said Act, 
and the regulations contained in 43 CFR part 2, except as provided in 
paragraph (d) of this section.
    (d) Upon request, the Director shall provide relative indications of 
interest in areas as well as any comments filed in response to a Call 
for Information for a proposed sale. However, no information transmitted 
shall 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.

[44 FR 38276, June 29, 1979, as amended at 47 FR 25970, June 16, 1982. 
Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982]



Sec. 256.11  Helium.

    (a) Each lease issued or continued under these regulations shall be 
subject to a reservation by the United States, under section 12(f) of 
the Act, of the ownership of and the right to extract helium from all 
gas produced from the leased area.
    (b) In case the United States elects to take the helium, the lessee 
shall deliver all gas containing helium, or the portion of gas desired, 
to the United States at any point on the leased area or at an onshore 
processing facility. Delivery shall be made in the manner required by 
the United States to such plants or reduction works as the United States 
may provide.
    (c) The extraction of helium shall not cause a reduction in the 
value of the lessee's gas or any other loss for which he is not 
reasonably compensated, except for the value of the helium extracted. 
The United States shall determine the amount of reasonable compensation. 
The United States shall have the right to erect, maintain and operate on 
the leased area any and all reduction works and other equipment 
necessary for the extraction of helium. The extraction of helium shall 
not cause substantial delays in the delivery of natural gas produced to 
the purchaser of that gas.



Sec. 256.12  Supplemental sales.

    (a) The Secretary may conduct a supplemental sale in accordance with 
the provisions of this section.
    (b) Supplemental sales shall be governed by the regulations in this 
part, except Sec. 256.22.
    (c) Supplemental sales shall be limited to blocks falling into one 
or more of the following categories:
    (1) Blocks for which bids were rejected during the calendar year 
preceding the year of the supplemental sale in which they are reoffered 
or blocks for which bids were rejected in the same calendar year as the 
supplemental sale in which they are reoffered, except that for the 
initial supplemental sale only blocks for which bids were rejected after 
October 1, 1987, may be reoffered. If, after the initial supplemental 
sale, a supplemental sale is not held annually for any reason, the 
relevant period for determining blocks eligible for a subsequent 
supplemental sale may be extended to include rejected bid blocks which 
were eligible for the supplemental sale not held.

[[Page 332]]

    (2) Blocks for which the high bid was forfeited during the calendar 
year preceding the year of the supplemental sale in which they are 
reoffered or blocks for which high bids were forfeited in the same 
calendar year as the supplemental sale in which they are reoffered, 
except that for the initial supplemental sale only blocks for which high 
bids were forfeited after October 1, 1987, may be reoffered. If, after 
the initial supplemental sale, a supplemental sale is not held annually 
for any reason, the relevant period for determining blocks eligible for 
a subsequent sale may be extended to include forfeited bid blocks which 
were eligible for the supplemental sale not held.
    (3) Development blocks. Development blocks (including blocks 
susceptible to drainage) are blocks which are located on the same 
general geologic structure as an existing lease having a well with 
indicated hydrocarbons; the reservoir may or may not be interpreted to 
extend on to the block.
    (d) Supplemental sales shall not include blocks in the Central or 
Western Gulf of Mexico Planning Areas.
    (e) The Director may disclose the classification of blocks in 
supplemental sales as development blocks.

[53 FR 29886, Aug. 9, 1988]



                  Subpart B_Oil and Gas Leasing Program



Sec. 256.16  Receipt and consideration of nominations; public notice and participation.

    (a) During preparation of a proposed 5-year leasing program, the 
Secretary shall invite and consider suggestions and relevant information 
for such program from Governors of affected States, local government, 
industry, other Federal agencies, including the Attorney General in 
consultation with the Federal Trade Commission, and all interested 
parties, including the general public. This request for information 
shall be issued as a notice in the Federal Register. Local governments 
wishing to respond to such request shall first submit their responses to 
the Governor of the State in which the local government is located.
    (b) The Secretary shall send letters to the Governors of the 
affected States requesting them to identify specific laws, goals, and 
policies which they believe should be considered by the Secretary in 
connection with the leasing program. The Secretary shall also request 
from the Secretary of Energy information on regional and national energy 
markets, on OCS production goals and on transportation networks.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 
47 FR 50684, Nov. 9, 1982]



Sec. 256.17  Review by State and local governments and other persons.

    (a)(1) The Secretary shall prepare a proposed leasing program. At 
least 60 days prior to publication of the proposed program in the 
Federal Register, a copy of the draft of the proposed program shall be 
forwarded to the Governor of each affected State for comment. The 
Governor may solicit comments from local governments in his or her State 
which the Governor determines will be affected by the proposed program.
    (2) The Secretary shall reply in writing to any comment on the draft 
of the proposed program from the Governor of an affected State which is 
received at least 15 days prior to the submission of the proposed 
program to the Congress and publication in the Federal Register. All 
such correspondence between the Secretary and Governor of such State 
shall accompany the proposed program when it is submitted to the 
Congress.
    (b) The proposed leasing program shall be submitted to the Governors 
of the affected States for review and comment at the time it is 
submitted to the Congress and the Attorney General and published in the 
Federal Register. The Governor of an affected State shall, upon request 
from any local government affected by the program, submit a copy of the 
proposed program to such local government. Comments and recommendations 
on any aspect of the proposed program may be submitted by a State or 
local government or other persons to the Secretary within 90 days after 
the date of its publication in the Federal Register. Comments and 
recommendations from local governments

[[Page 333]]

shall be submitted first to the Governor of the State in which the local 
government is located.
    (c) At least 60 days prior to approving the final leasing program 
and any later significant revision, the Secretary shall submit it to the 
President and the Congress, together with any comments. The Secretary 
shall indicate in such submission why any specific recommendation of the 
Attorney General or of a State or local government was not accepted.

[44 FR 38276, June 29, 1979, as amended at 47 FR 25970, June 16, 1982. 
Redesignated at 47 FR 47006, Oct. 22, 1982; 47 FR 50684, Nov. 9, 1982]



Sec. 256.19  Periodic consultation with interested parties.

    The Secretary shall provide for periodic consultation with State and 
local governments, existing and potential oil and gas lessees and 
permittees, and representatives of other individuals or organizations 
engaged in any activity in or on the OCS, including those involved in 
fish and shellfish recovery, and recreational activities. This 
consultation shall take place primarily through appropriate public 
notice as described in Sec. Sec. 256.16 and 256.17 and through the OCS 
Advisory Board and its committees, on a regional and national basis. 
Meetings of the OCS Advisory Board shall be held on specific issues as 
required by the Board's charter.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 
47 FR 50684, Nov. 9, 1982]



Sec. 256.20  Consideration of coastal zone management program.

    In the development of the leasing program, consideration shall be 
given to the coastal zone management program being developed or 
administered by an affected coastal State under section 305 or 306 of 
the Coastal Zone Management Act of 1972 as amended, (16 U.S.C. 1454, 
1455). Information concerning the relationship between a State's coastal 
zone management program and OCS oil and gas activity shall be requested 
from the Governors of the affected coastal States and from the Secretary 
of Commerce prior to the development of the proposed leasing program at 
the time information is requested under Sec. 256.16 of this part.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 
47 FR 50684, Nov. 9, 1982]



                 Subpart C_Reports From Federal Agencies



Sec. 256.22  General.

    For oil and gas lease sales shown in an approved leasing schedule 
and as the need arises for other mineral leasing, the Director shall 
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.

[51 FR 6107, Feb. 20, 1986]



             Subpart D_Call for Information and Nominations



Sec. 256.23  Information on areas.

    (a) The Director may receive and consider indications of interest in 
areas for mineral leasing.
    (b) In accordance with an approved program and schedule for the 
leasing of OCS lands which may contain oil and gas, the Director shall 
issue Calls for Information and Nominations on areas for leasing of such 
minerals in specified areas. The Call for Information and Nominations 
shall be published in the Federal Register and may be published in other 
publications as desirable. Information on areas shall be addressed to 
the appropriate regional Minerals Manager of the Minerals Management 
Service with a copy to any other office which may be specified in the 
Call. The Director shall also request comments on areas which should 
receive special concern and analysis. For an oil and gas lease sale Call 
Area, the Director may request comments concerning geological 
conditions, including bottom hazards; archaeological sites on the seabed 
or nearshore; multiple uses of the proposed leasing area,

[[Page 334]]

including navigation, recreation, and fisheries; and other 
socioeconomic, biological, and environmental information.

[47 FR 25970, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982 
and amended at 51 FR 21345, June 12, 1986; 59 FR 53094, Oct. 21, 1994]



Sec. 256.25  Areas near coastal States.

    (a) At the time information is solicited for leasing of areas within 
3 geographical miles seaward of the seaward boundary of any coastal 
State, the Secretary shall provide the Governor of that State 
information required under section 8(g)(1) of the Act. The Director 
shall furnish information identifying the areas for leasing as well as 
all relevant available environmental data for such areas (See 30 CFR 
251.14).
    (b) After receipt of information on areas within the area described 
in paragraph (a) of this section, the Secretary shall inform the 
Governor of those areas that are to be given further consideration for 
leasing. The Secretary shall enter into consultation with the Governor 
to determine whether the area may contain oil or gas pools or fields 
underlying both the OCS and lands subject to the jurisdiction of the 
State.
    (c) After selection for leasing of those tracts which may have oil 
or gas pools or fields underlying both the OCS and lands under State 
jurisdiction, the Secretary shall offer the Governor an opportunity to 
enter into an agreement for the equitable disposition of revenues from 
such tracts under section 8(g)(2) of the Act.
    (d) If no agreement can be reached within 90 days of the Secretary's 
offer, the tracts may be leased and all revenues deposited in a separate 
Treasury account pending equitable disposition of the revenues under 
sections 8(g) (3) and (4) of the Act.

[44 FR 38276, June 29, 1979, as amended at 47 FR 25971, June 16, 1982. 
Redesignated at 47 FR 47006, Oct. 22, 1982]



              Subpart E_Area Identification and Tract Size



Sec. 256.26  General.

    (a) The Director, in consultation with appropriate Federal Agencies, 
shall recommend to the Secretary areas identified for environmental 
analysis and consideration for leasing. 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 shall consider all available environmental information, 
multiple-use conflicts, resource potential, industry interest and other 
relevant information. Comments received from States and local 
governments and interested parties in response to calls for information 
and nominations shall be considered in making recommendations. For 
supplemental sales provided for by Sec. 256.12 of this part, the 
Director's recommendation shall be replaced by a statement describing 
the results of the Director's consideration of the factors specified 
above in this section.
    (b) The Director shall evaluate fully the potential effect of 
leasing on the human, marine and coastal environments, and develop 
measures to mitigate adverse impacts, including lease stipulations. The 
views and recommendations of Federal agencies, State agencies, local 
governments, organizations, industries and the general public shall be 
used as appropriate. The Director may hold public hearings on the 
environmental analysis after appropriate notice.
    (c) In general, the Director shall seek to inform the public as soon 
as possible of additions or deletions that occur after the 
identification of areas.

[47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982 
and amended at 51 FR 21345, June 12, 1986; 53 FR 29886, Aug. 9, 1988]



Sec. 256.28  Tract size.

    (a) A tract selected for oil and gas leasing shall consist of a 
compact area not exceeding 5,760 acres, unless the authorized officer 
finds that a larger area is necessary to comprise a reasonable economic 
production unit.
    (b) The tract size for the leasing of other minerals shall be 
specified in the notice of sale.

[47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]

[[Page 335]]



                          Subpart F_Lease Sales



Sec. 256.29  Proposed notice of sale.

    (a) The Director shall in consultation with appropriate Federal 
agencies develop measures, including lease stipulations and conditions, 
to mitigate adverse impacts on the environments. For oil and gas lease 
sales, appropriate proposed stipulations and conditions shall be 
contained or referenced in the proposed notice of lease sale.
    (b) A proposed notice of lease sale shall be submitted to the 
Secretary for approval. All comments and recommendations received and 
the Director's findings or actions thereon, shall also be forwarded to 
the Secretary.
    (c) Upon approval by the Secretary, the proposed Notice of Sale 
shall be sent to the Governor of any affected State and a notice of its 
availability shall be published in the Federal Register.

[44 FR 38276, June 29, 1979, as amended at 47 FR 25971, June 16, 1982. 
Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 51 FR 37178, 
Oct. 20, 1986]



Sec. 256.31  State comments.

    (a) Within 60 days after notice of a proposed lease sale, a Governor 
of any affected State or any affected local government in such State may 
submit recommendations to the Secretary regarding the size, timing or 
location of the proposed lease sale. Prior to submitting recommendations 
to the Secretary, any affected local government shall forward such 
recommendation to the Governor.
    (b) The Secretary shall accept such recommendations of the Governor 
and may accept recommendations of any affected local government if he 
determines, after having provided the opportunity for consultation, that 
they provide for a reasonable balance between the national interest and 
the well-being of the citizens of the affected State. A determination of 
the national interest shall be based on the findings, purposes and 
policies of the Act.
    (c) The Secretary shall communicate to the Governor, in writing, the 
reasons for his determination to accept or reject such Governor's 
recommendations, or to implement any alternative means identified in 
consultation with the Governor to provide for a reasonable balance 
between the national interest and the well-being of the citizens of the 
affected State.



Sec. 256.32  Notice of sale.

    (a) Upon approval of the Secretary, the Director shall publish the 
notice of lease sale in the Federal Register as the official 
publication, and may publish the notice in other publications. The 
publication in the Federal Register shall be at least 30 days prior to 
the date of the sale. The notice shall state the place and time at which 
bids shall be filed, and the place, date and hour at which bids shall be 
opened. The notice shall contain or reference a description of the areas 
to be offered for lease and any stipulations, terms and conditions of 
the sale.
    (b) Tracts shall be offered for lease by competitive sealed bidding 
under conditions specified in the notice of lease sale and in accordance 
with all applicable laws and regulations. A suggested format for bidder 
submissions appears in appendix A of this part.
    (c) The notice of lease sale shall contain a reference to the OCS 
lease form which shall be issued to successful bidders.
    (d) With the approval of the Secretary, the Director may defer any 
part of the payment of the cash bonus according to a schedule announced 
at the time of the notice of lease sale. Payment shall be made no later 
than 5 years after the date of the lease sale. The schedule shall 
contain provisions for guaranteed payment of a deferred bonus.
    (e) In order to obtain statistical information to determine which 
bidding alternatives best accomplish the purposes and policies of the 
Act, the Director may, until September 18, 1983, require each bidder to 
submit bids for any OCS area in accordance with more than one of the 
bidding systems described in section 8(a)(1) of the Act. No more than 10 
percent of the tracts offered each year shall contain such a 
requirement. Leases may be awarded using a bidding alternative selected 
at random for statistical purposes, if it is

[[Page 336]]

otherwise consistent with the purposes and policies of the Act.

[44 FR 38276, June 29, 1979. Redesignated and amended at 47 FR 25971, 
June 16, 1982. Further redesignated at 47 FR 47006, Oct. 22, 1982]



                      Subpart G_Issuance of Leases



Sec. 256.35  Qualifications of lessees.

    (a) In accordance with section 8 of the Act, leases shall be awarded 
only to the highest responsible qualified bidder.
    (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.
    (c) MMS may disqualify you from acquiring any new leaseholdings or 
lease assignments if your operating performance is unacceptable 
according to 30 CFR 250.135.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
as amended at 64 FR 72795, Dec. 28, 1999]



Sec. 256.37  Lease term.

    (a)(1) All oil and gas leases shall be issued for an initial period 
of 5 years, or not to exceed 10 years where the authorized officer finds 
that such longer period is necessary to encourage exploration and 
development in areas because of unusually deep water or other unusually 
adverse conditions.
    (2) If your oil and gas lease is in water depths between 400 and 800 
meters, it will have an initial lease term of 8 years unless MMS 
establishes a different lease term under paragraph (a)(1) of this 
section.
    (3) For leases issued with an initial term of 8 years, you must 
begin an exploratory well within the first 5 years of the term to avoid 
lease cancellation.
    (b) An oil and gas lease shall continue after such initial period 
for as long as oil or gas is produced from the lease in paying 
quantities, or drilling or well reworking operations as approved by the 
Secretary are conducted. The term of an oil and gas lease is subject to 
further extension as provided in Sec. 256.73 of this part.
    (c) Sulphur leases shall be issued for a term not to exceed 10 years 
and so long thereafter as sulphur is produced from the leasehold in 
paying quantities, or drilling, well reworking, plant construction, or 
other operations for the production of sulphur, as approved by the 
Secretary, are conducted thereon.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982 
and amended at 50 FR 49043, Nov. 29, 1985; 54 FR 2049, Jan. 18, 1989; 61 
FR 55889, Oct. 30, 1996]



Sec. 256.38  Joint bidding provisions.



Sec. 256.40  Definitions.

    The following definitions apply to Sec. Sec. 256.38 through 256.44 
of this part.
    (a) Single bid means a bid submitted by one person for an oil and 
gas lease under section 8(a) of the Act.
    (b) Joint bid means a bid submitted by two or more persons for an 
oil and gas lease under section 8(a) of the Act.
    (c) Average daily production is the total of all production in an 
applicable production period which is chargeable under Sec. 256.43 of 
this title divided by the exact number of calendar days in the 
applicable production period.
    (d) Barrel means 42 U.S. gallons.
    (e) 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.
    (f) An economic interest means any right to, or any right dependent 
upon, production of crude oil, natural gas, or liquefied petroleum 
products and shall include, but not be limited to, a royalty interest, 
or overriding royalty interest, whether payable in cash or in kind, a 
working interest, a net profits

[[Page 337]]

interest, a production payment, or a carried interest.
    (g) Liquefied petroleum products means natural gas liquid products 
including the following: ethane, propane, butane, pentane, natural 
gasoline, and other natural gas products recovered by a process of 
absorption, adsorption, compression, or refrigeration cycling, or a 
combination of such processes.
    (h) Natural gas means a mixture of hydrocarbons and varying 
quantities of nonhydrocarbons that exist in the gaseous phase.
    (i) Oil and gas lease means an oil and gas lease either offered or 
issued pursuant to the provisions of the Act.
    (j) Owned means:
    (1) With respect to crude oil--having either an economic interest in 
or a power of disposition over the production of crude oil;
    (2) With respect to natural gas--having either an economic interest 
in or a power of disposition over the production of natural gas; and
    (3) With respect to liquefied petroleum products--having either an 
economic interest in or a power of disposition over any liquefied 
petroleum product at the time of completion of the liquefaction process.
    (k) Prior production period means the continuous six month period of 
January 1 through June 30 preceding November 1 through April 30 for 
joint bids submitted during the six month bidding period from November 1 
through April 30, and means the continuous six month period of July 1 
through December 31 preceding May 1 through October 31 for joint bids 
submitted during the six month bidding period from May 1 through October 
31.
    (l) Production--(1) Of crude oil means the volume of crude oil 
produced worldwide from reservoirs during the prior production period. 
The amount of such crude oil production shall 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:
    (i) Net differences between opening and closing inventories, and
    (ii) Basic sediment and water;
    (2) Of natural gas means the volume of natural gas produced 
worldwide from natural oil and gas reservoirs during the prior 
production period, with adjustments, where applicable, to reflect
    (i) The volume of gas returned to natural reservoirs; and
    (ii) The reduction of volume resulting from the removal of natural 
gas liquids and nonhydrocarbon gases.
    (3) Of liquefied petroleum products means the volume of natural gas 
liquids produced from reservoir gas and liquefied at surface separators, 
field facilities, or gas processing plants worldwide during the prior 
production period; these liquefied petroleum products include the 
following:
    (i) Condensate--natural gas liquids recovered from gas well gas 
(associated and non-associated) in separators or field facilities;
    (ii) Gas plant products--natural gas liquids recovered from natural 
gas in gas processing plants and from field facilities. Gas plant 
products shall 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--C2 H6
    (B) Propane--C3 H8
    (C) Butane--C4 H10 including all products 
covered by NGPA specifications for commercial butane.
    (1) Isobutane,
    (2) Normal butane,
    (3) 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, which meet 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.).
    (m) Six month bidding period means the six month period of time

[[Page 338]]

    (1) From May 1 through October 31; or
    (2) From November 1 through April 30, respectively.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated 
at 47 FR 47006, Oct. 22, 1982, as amended at 66 FR 11518, Feb. 23, 2001]



Sec. 256.41  Joint bidding requirements.

    (a) Any person who submits a joint bid for any oil and gas lease 
during a 6-month bidding period, and who was chargeable for the prior 
production period with an average daily production in excess of 1.6 
million barrels of crude oil, natural gas and liquified petroleum 
products, shall have filed under oath with the Director, a Statement of 
Production of crude oil, natural gas and liquified petroleum products, 
hereinafter referred to as a Statement of Production, no later than 45 
days prior to the commencement of the applicable 6-month bidding period 
of May 1 through October 31, and November 1 through April 30. Statements 
of Production shall be submitted to the Director, MMS (Attention: 
Offshore Leasing Management Division), Washington, DC 20240. The 
Statement of Production shall indicate that the person was chargeable, 
in accordance with Sec. 256.43 of this part, with an average daily 
production in excess of 1.6 million barrels of crude oil, natural gas 
and liquified petroleum products for the prior production period. The 
Director shall publish semi-annually in the Federal Register a ``List of 
Restricted Joint Bidders'' to be effective immediately upon publication 
and to continue in force and effect until a subsequent list is 
published. The ``List of Restricted Joint Bidders'' shall consist of 
those persons, who in the judgment of the Director, based on information 
available to him, including, but not limited to, sworn Statements of 
Production, are chargeable under Sec. 256.43 of this part with an 
average daily production in excess of 1.6 million barrels of crude oil, 
natural gas and liquified petroleum products for the prior production 
period.
    (b) When a person is placed on the List of Restricted Joint Bidders 
the Director shall serve that person either personally or by certified 
mail, return receipt requested, with a copy of the Director's Order 
placing that person on the List of Restricted Joint Bidders. Any appeal 
from that Order or from an adverse effect of that Order shall be made in 
accordance with the provisions of 43 CFR part 4.
    (c) The submission of a Statement of Production or of a detailed 
Report of Production under Sec. 256.46(g) of this part which 
misrepresents the chargeable production of the reporting person shall 
constitute failure to comply with these regulations and any lease 
awarded in reliance on that Statement or Report of Production may be 
canceled, pursuant to section 8(o) of the Act and regulations issued 
thereunder as having been obtained by fraud or misrepresention.
    (d) The Secretary may exempt a person from the provisions of 
Sec. Sec. 256.41(a), 256.44, 256.46(g) and 256.62(b) of this part if it 
is found, on the record, after an opportunity for an agency hearing, 
that lands being offered have extremely high cost exploration and 
development problems and that exploration and development will not occur 
on such lands unless the exemption is granted.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 
45 FR 69174, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated and 
amended at 47 FR 47006, 47007, Oct. 22, 1982]



Sec. 256.43  Chargeability for production.

    (a) As used in this section the following definitions shall control:
    (1) Person means a natural person or company.
    (2) Company means a corporation, a partnership, an association, a 
joint-stock company, a trust, a fund, or any group of persons whether 
incorporated or not; it also means any receiver, trustee in bankruptcy, 
or similar official acting for such a company.
    (3) Subsidiary means a company 50 percent or more of whose stock or 
other interest having power to vote for the election of directors, 
trustees, or other similar controlling body of the company is directly 
or indirectly owned, controlled, or held with the power to vote by 
another company; a subsidiary shall be deemed a subsidiary

[[Page 339]]

of the other company owning, controlling, or holding 50 percent or more 
of the stock or other voting interest.
    (4) 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.
    (b) A person filing a Statement of Production under Sec. 256.41 of 
this part shall be charged with the following production during the 
applicable prior production period:
    (1) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products which it owned worldwide;
    (2) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by every 
subsidiary of the reporting person;
    (3) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by any person or 
persons of which the reporting person is a subsidiary; and
    (4) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by any subsidiary, 
other than the reporting person, of any person or persons of which the 
reporting person is a subsidiary.
    (c) A person filing a Statement of Production shall be charged with, 
in addition to the production chargeable under paragraph (b) of this 
section, but not in duplication thereof, its proportionate share of the 
average daily production in barrels of crude oil, natural gas, and 
liquefied petroleum products owned worldwide by every person:
    (1) Which has an interest in the reporting person, and
    (2) In which the reporting person has an interest, whether the 
interest referred to in paragraphs (c) (1) and (2) of this section is by 
virtue of ownership of securities or other evidence of ownership, or by 
participation in any contract, agreement, or understanding respecting 
the control of any person or of any person's production of crude oil, 
natural gas, or liquefied petroleum products, equal to said interest. As 
used in paragraph (c) of this section ``interest'' means an interest of 
at least 5 percent of the ownership or control of a person.
    (d) All measurements of crude oil and liquefied petroleum products 
under this section shall be at 60 [deg]F.
    (e)(1) For purposes of computing production of natural gas under 
Sec. 256.41 of this part, chargeability under this section, and 
reporting under Sec. 256.46(g) of this part, 5,626 cubic feet of 
natural gas at 14.73 pounds per square inch (msl) shall equal one 
barrel.
    (2) For purposes of computing production of liquefied petroleum 
products under Sec. 256.41 of this part, chargeability under Sec. 
256.46(g) of this part, 1.454 barrels of natural gas liquids at 60 
[deg]F shall equal one barrel of crude oil.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 
47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, 47007, Oct. 22, 
1982]



Sec. 256.44  Bids disqualified.

    The following bids for any oil and gas lease shall be disqualified 
and rejected in their entirety:
    (a) A joint bid submitted by 2 or more persons who are on the 
effective List of Restricted Joint Bidders; or
    (b)(1) A joint bid submitted by two or more persons when 1 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 liquified petroleum products and has not filed a 
Statement of Production as required by Sec. 256.41 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. 256.46(g) of 
this part, or
    (c) A single or joint bid submitted pursuant to an agreement 
(whether

[[Page 340]]

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) 
which 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 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 2 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 liquified petroleum products and has not filed a Statement of 
Production pursuant to Sec. 256.41 of this part for the applicable 6-
month bidding period. Assignments expressly required by law, regulation, 
lease or stipulation to lease shall 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.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 
45 FR 69175, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated at 
47 FR 47006, Oct. 22, 1982]



Sec. 256.46  Submission of bids.

    (a) A separate sealed bid shall be submitted for each tract unit bid 
upon as described in the notice of lease sale. A bid may not be 
submitted for less than an entire tract.
    (b) MMS requires a deposit for each bid. The notice of sale will 
specify the bid deposit amount and method of payment.
    (c) If the bidder is an individual a statement of citizenship shall 
accompany the bid.
    (d) 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 it is authorized to hold mineral 
leases on the OCS, or appropriate reference to statements or records 
previously submitted to an MMS OCS office (including material submitted 
in compliance with prior regulations).
    (e) If the bidder is a corporation, the following information shall 
be submitted with the bid:
    (1) 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 records previously 
submitted to an MMS 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 either a certified copy 
of 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 an MMS 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.
    (f) Bidders should be aware of the provisions of 18 U.S.C. 1860, 
prohibiting unlawful combination or intimidation of bidders.

[[Page 341]]

    (g) To verify the accuracy of any statement submitted pursuant to 
Sec. 256.41 of this part, the Director may require the person 
submitting such information to:
    (1) Submit no later than 30 days after receipt of the request by the 
Director, a detailed Report of Production which shall list, in barrels, 
the average daily production of crude oil, natural gas and liquefied 
petroleum products chargeable to the reporting person in accordance with 
Sec. 256.43 of this part for the prior production period, and
    (2) Permit the inspection and copying by an official of the 
Department of the Interior of such documents, records of production of 
crude oil, natural gas and liquified petroleum products, analyses and 
other material as are necessary to demonstrate the accuracy of any 
statement or information contained in any Report of Production.
    (h) No bid for a lease may be submitted if the Secretary finds, 
after notice and hearing, that the bidder is not meeting due diligence 
requirements on other OCS leases.

[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 
47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, 
as amended at 64 FR 40767, July 28, 1999]



Sec. 256.47  Award of leases.

    (a) Sealed bids received in response to the notice of lease sale 
shall be opened at the place, date and hour specified in the notice. The 
opening of bids is for the sole purpose of publicly announcing and 
recording the bids received and no bids shall be accepted or rejected at 
that time.
    (b) The United States reserves the right to reject any and all bids 
received for any tract, regardless of the amount offered.
    (c) In the event the highest bids are tie bids, the tie bidders 
(unless they would be disqualified under Sec. 256.35(b) of this part, 
or disqualified under Sec. 256.44 of this part if their bids had been 
joint bids) may file with the Director, within 15 days after 
notification, an agreement to accept the lease jointly; otherwise all 
bids shall be rejected.
    (d) Pursuant to section 8(c) of the Act, the Attorney General may 
review the results of the lease sale prior to the acceptance of bids and 
issuance of leases.
    (e)(1) The decision of the authorized officer on bids shall be the 
final action of the Department, subject only to reconsideration by the 
Secretary, pursuant to written request, of the rejection of the high 
bid. The delegation of review authority to the Office of Hearings and 
Appeals shall not be applicable to decisions on high bids for leases on 
the Outer Continental Shelf.
    (2) The authorized officer must accept or reject the bid within 90 
days. The authorized officer may extend the time period for acceptance 
or rejection of a bid for 15 working days or longer, if circumstances 
warrant. Any bid not accepted within the prescribed time period, 
including any extension thereof, is deemed rejected.
    (3) Any high bidder whose bid is rejected by the authorized officer 
may, within 15 days of such rejection, file with the Secretary, with a 
copy to the authorized officer, a written request for reconsideration 
accompanied by a statement of reasons. The Secretary shall respond in 
writing either affirming or reversing the decision of the authorized 
officer.
    (f) Written notice of the authorized officer's action 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 
to the successful bidder. As provided in Sec. 218.155, the bidder 
shall, not later than the 11th business day after receipt of the lease, 
execute the lease, pay the first-year's rental, and unless deferred, pay 
the balance of the bonus bid. The bidder must also file a bond as 
required in Sec. 256.52 of this title. Deposits and any interest 
accrued shall be refunded on high bids subsequently rejected.
    (g) If the successful bidder fails to execute the lease within the 
prescribed time or otherwise comply with the applicable regulations the 
deposit shall be forfeited and disposed of as other receipts under the 
Act.
    (h) 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, all deposits and any interest due shall be refunded.

[[Page 342]]

    (i) If the awarded lease is executed by an agent acting on behalf of 
the bidder, the lease shall be accompanied by evidence that the bidder 
authorized the agent to execute the lease. When three copies of the 
lease are executed and returned to the authorized officer, the lease 
shall be executed on behalf of the United States, and one fully executed 
copy shall be transmitted to the successful bidder.
    (j) No lease or permit shall be issued for any area within 15 
statute miles of the boundaries of the Point Reyes Wilderness in 
California unless the State of California allows exploration, 
development or production activities in the adjacent navigable waters of 
the State under section 11(h) of the Act.

[44 FR 38276, June 29, 1979, as amended at 47 FR 25972, June 16, 1982. 
Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 49 FR 8606, 
Mar. 8, 1984; 49 FR 10056, Mar. 16, 1984; 50 FR 47378, Nov. 18, 1985; 61 
FR 34732, July 3, 1996; 62 FR 27955, May 22, 1997]



Sec. 256.49  Lease form.

    Oil and gas leases and leases for sulphur shall be issued on forms 
approved by the Director. Other mineral leases shall be issued on such 
forms as may be prescribed by the Secretary.

[47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]



Sec. 256.50  Dating of leases.

    All 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. When prior written request is 
made, a lease may be dated and become effective as of the first day of 
the month within which it is so signed.

Subpart H--Rentals and Royalties [Reserved]



                            Subpart I_Bonding



Sec. 256.52  Bond requirements for an oil and gas or sulphur lease.

    This section establishes bond requirements for the lessee of an OCS 
oil and gas or sulphur lease.
    (a) Before MMS 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 areawide bond that guarantees compliance 
with all the terms and conditions of all your oil and gas and sulphur 
leases in the area where the lease is located; or
    (3) Maintain a lease or areawide bond in the amount required in 
Sec. 256.53(a) or (b) of this part.
    (b) For the purpose of this section, there are three areas. The area 
offshore the Atlantic Coast is included in the Gulf of Mexico. Areawide 
bonds issued in the Gulf of Mexico will cover oil and gas or sulphur 
operations offshore the Atlantic Coast. 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 
instruments) under paragraph (a)(1) of this section and Sec. 256.53 (a) 
and (b) is satisfied if your operator provides a lease bond in the 
required amount that guarantees compliance with all the terms and 
conditions of the lease. Your operator 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.

[[Page 343]]

    (f) You may pledge U.S. Department of the Treasury (Treasury) 
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 when 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 250, subpart N of this chapter;
    (2) Suspend production and other operations on your leases in 
accordance with Sec. 250.110 of this chapter; and
    (3) Initiate action to cancel your lease.

[62 FR 27955, May 22, 1997; 64 FR 9066, Feb. 24, 1999, as amended at 66 
FR 60150, Dec. 3, 2001]



Sec. 256.53  Additional bonds.

    (a) This paragraph explains what bonds the lessee 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;
    (B) The date you submit a request for approval of the assignment of 
a lease on which an EP has been approved; or
    (C) December 8, 1997, for any lease for 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 he/she approves 
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 sulphur leases held by 
the lease on the OCS for the area in which the lessee 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;
    (B) The date you submit a request for approval of the assignment of 
a lease on which a DPP or DOCD has been approved; or
    (C) December 8, 1997, for any lease for which a DPP or DOCD has been 
approved.
    (ii) The Regional Director may authorize you to submit the $500,000 
lease

[[Page 344]]

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.
    (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) The lessee need not submit and maintain a $500,000 lease 
development bond pursuant to paragraph (b)(1) of this section if the 
lessee furnishes and maintains 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 sulphur leases held by the 
lessee on the OCS for the area in which the lease is situated.
    (c) When a lessee can demonstrate to the satisfaction of the 
authorized officer that wells and platforms can be abandoned and removed 
and the drilling and platform sites cleared of obstructions 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 well abandonment, platform removal, and site 
clearance.
    (d) The Regional Director may determine that additional security 
(i.e., security above the amounts prescribed in Sec. Sec. 256.52(a) and 
256.53 (a) and (b) of this part) is necessary to ensure compliance with 
the obligations under your lease and the regulations in this chapter.
    (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 of future 
production;
    (iii) Business stability based on 5 years of continuous operation 
and production of oil and gas or sulphur in the OCS or in the onshore 
oil and gas industry;
    (iv) Reliability in meeting obligations based on:
    (A) Credit rating(s); 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 
a supplemental bond or bonds.
    (e) The Regional Director will determine the amount of supplemental 
bond required to guarantee compliance. The Regional Director will 
consider potential underpayment of royalty and cumulative obligations to 
abandon wells, remove platforms and facilities, and clear the seafloor 
of obstructions in the Regional Director's case-specific analysis.
    (f) If your cumulative potential obligations and liabilities either 
increase or decrease, the Regional Director may adjust the amount of 
supplemental 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 supplemental 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 lease abandonment and cleanup are less than 
the required bond amount. If the Regional Director finds that the 
evidence you submit is convincing, he/she may reduce the amount of 
supplemental bond required.

[58 FR 45262, Aug. 27, 1993. Redesignated and amended at 62 FR 27956, 
May 22, 1997]

[[Page 345]]



Sec. 256.54  General requirements for bonds.

    (a) Any bond or other security that you, as lessee 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 and regulations in this chapter; and
    (3) Guarantee compliance with the obligations of all lessees, 
operating 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 Associate Director for Offshore 
Minerals Management. 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 noncancellable, except as provided in Sec. 256.58 
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. 256.52(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 this, and if the 
document omits terms or conditions contained on the form approved by the 
Associate Director for Offshore Minerals Management the bond you submit 
will be deemed to contain the omitted terms and conditions.

[62 FR 27956, May 22, 1997]



Sec. 256.55  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. 256.52 and 256.53 of this 
part 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 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 MMS.

[62 FR 27957, May 22, 1997]



Sec. 256.56  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. 256.53(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 MMS and pledged to meet the lessee's obligations under 
Sec. 250.1703 of this chapter.
    (2) You must fully fund the lease-specific abandonment account to 
cover all the costs of lease abandonment and site clearance as estimated 
by MMS 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 MMS under paragraph (d) of this section.
    (b) Any interest paid on funds in a lease-specific abandonment 
account

[[Page 346]]

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 MMS under 
paragraph (c) 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 abandonment and clearance of a lease. 
The required obligation may be associated with oil and gas or sulphur 
production from a lease other than the lease bonded through the lease-
specific abandonment account.

[62 FR 27957, May 22, 1997; 64 FR 9066, Feb. 24, 1999, as amended at 67 
FR 35412, May 17, 2002]



Sec. 256.57  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. 256.53(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, abandonment, and clearance 
operations on your lease.
    (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;

[[Page 347]]

    (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 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 and the 
regulations in this chapter 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.

------------------------------------------------------------------------
       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 completed     Your guarantor's financial
 quarters in the current fiscal year.        officer certifies to be
                                             correct.
(iii) Additional information as requested   Your guarantor's financial
 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

[[Page 348]]

    (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. 256.59 of this part, 
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:
    (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.

[62 FR 27957, May 22, 1997]



Sec. 256.58  Termination of the period of liability and cancellation of a bond.

    This section defines the terms and conditions under which MMS 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 the surety under your bond requests termination:
    (1) The Regional Director will terminate the period of liability 
under your bond within 90 days after MMS receives the request; and
    (2) If you intend to continue operations, or have not met all end of 
lease 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. 256.52(a) or under Sec. 
256.53(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 supplemental bonds submitted under Sec. 256.53(d), the 
surety issuing the new supplemental bond agrees to assume that portion 
of the outstanding liabilities that accrued during the period of 
liability which 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:

[[Page 349]]



------------------------------------------------------------------------
                                  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.  256.52(a), Sec.         Director           termination of the
 256.53(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) Supplemental bonds          When the Regional  When you meet your
 submitted under Sec.           Director           bonded obligations,
 256.53(d).                      determines that    unless the Regional
                                 you have met all   Director:
                                 your obligations  (i) Determines that
                                 covered by the     the future potential
                                 supplemental       liability resulting
                                 bond.              from any undetected
                                                    problems 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).
------------------------------------------------------------------------

    (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 MMS that it has discharged 
its obligations under the lease, and the representation was materially 
false when the bond was canceled or released.

[66 FR 60150, Dec. 3, 2001]



Sec. 256.59  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 under 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 his/her 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 reasons 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 5 
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.

[[Page 350]]

    (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. In this 
case, the Regional Director will return the excess funds to the party 
from whom they were collected.

[62 FR 27958, May 22, 1997]



            Subpart J_Assignments, Transfers, and Extensions



Sec. 256.62  Assignment of lease or interest in lease.

    This section explains how to assign record title and other interests 
in OCS oil and gas or sulphur leases.
    (a) MMS may approve the assignment to you of the ownership of the 
record title to a lease or any undivided interest in a lease, or an 
officially designated subdivision of a lease, only if:
    (1) You qualify to hold a lease under Sec. 256.35(b);
    (2) You provide the bond coverage required under subpart I of this 
part; and
    (3) The Regional Director approves the assignment.
    (b) An assignment shall be void if it is made pursuant to any 
prelease agreement described in Sec. 256.44(c) of this part that would 
cause a bid to be disqualified.
    (c) Any approved assignment shall be deemed to be effective on the 
first day of the lease month following its filing in the appropriate 
office of the MMS, unless at the request of the parties, an earlier date 
is specified in the approval.
    (d) You, as assignor, are liable for all obligations that accrue 
under your lease before the date that the Regional Director approves 
your request for assignment of the record title in the lease. The 
Regional Director's approval of the assignment does not relieve you of 
accrued lease obligations that your assignee, or a subsequent assignee, 
fails to perform.
    (e) Your assignee and each subsequent assignee are liable for all 
obligations that accrue under the lease after the date that the Regional 
Director approves the governing assignment. They must:
    (1) Comply with all the terms and conditions of the lease and all 
regulations issued under the Act; and
    (2) Remedy all existing environmental problems on the tract, 
properly abandon all wells, and reclaim the lease site in accordance 
with part 250, subpart Q.
    (f) If your assignee, or a subsequent assignee, fails to perform any 
obligation under the lease or the regulations in this chapter, the 
Regional Director may require you to bring the lease into compliance to 
the extent that the obligation accrued before the Regional Director 
approved the assignment of your interest in the lease.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
and amended at 58 FR 45262, Aug. 27, 1993; 62 FR 27959, May 22, 1997; 67 
FR 35412, May 17, 2002]



Sec. 256.63  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to MMS 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.

[[Page 351]]



                            Service Fee Table
------------------------------------------------------------------------
                                                              30 CFR
                 Service                    Fee amount       citation
------------------------------------------------------------------------
(1) Record Title/Operating Rights                   $186   Sec.  256.64
 (Transfer).............................
(2) Non-required Document Filing........              27   Sec.  256.64
------------------------------------------------------------------------

    (b) 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 with the amended 
application.

[70 FR 49876, Aug. 25, 2005, as amended at 73 FR 49948, Aug. 25, 2008]



Sec. 256.64  How to file transfers.

    This section explains how to file instruments with MMS that create 
and/or transfer interests in OCS oil and gas or sulphur leases.
    (a) You must submit to the Regional Director for approval all 
instruments that create or transfer ownership of a lease interest.
    (1) You must submit two copies of the instruments that create or 
transfer an interest. Each instrument that creates or transfers an 
interest must describe by officially designated subdivision the interest 
you propose to create or transfer.
    (2) You must submit your proposal to create or transfer an interest, 
or create or transfer separate operating rights, subleases, and record 
title interests within 90 days of the last date that a party executes 
the transfer agreement.
    (3) The transferee must meet the citizenship and other qualification 
criteria specified in Sec. 256.35 of this part. When you submit an 
instrument to create or transfer an interest as an association, you must 
include a statement signed by the transferee about the transferee's 
citizenship and qualifications to own a lease.
    (4) Your instrument to create or transfer an interest must contain 
all of the terms and conditions to which you and the other parties 
agree.
    (5) You do not gain a release of any nonmonetary obligation under 
your lease or the regulations in this chapter by creating a sublease or 
transferring operating rights.
    (6) You do not gain a release from any accrued obligation under your 
lease or the regulations in this chapter by assigning your record title 
interest in the lease.
    (7) You may create or transfer carried working interests, overriding 
royalty interests, or payments out of production without obtaining the 
Regional Director's approval. However, you must file instruments 
creating or transferring carried working interests, overriding royalty 
interests, or payments out of production with the Regional Director for 
record purposes.
    (8) You must pay electronically through Pay.gov at: https://
www.pay.gov/paygov/ the service fee listed in Sec. 256.63 of this 
subpart and you must include a copy of the Pay.gov confirmation receipt 
page with your application for approval of any instrument of transfer 
you are required to file (Record Title/Operating Rights (Transfer) Fee). 
Where multiple transfers of interest are included in a single 
instrument, a separate fee applies to each individual transfer of 
interest. 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 the service fee listed in Sec. 256.63 
(Non-required Document Filing Fee) 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, in behalf of the holder of a lease, 
operating rights or sublease, shall furnish evidence of authority to 
execute the assignment or application for approval and the statement 
required by Sec. 256.46 of this part.
    (c) When you request approval for an assignment that assigns all 
your record title interest in a lease or that creates a segregated 
lease, your assignee must furnish a bond in the amount prescribed in 
Sec. Sec. 256.52 and 256.53 of this part.

[[Page 352]]

    (d) When you request approval for an assignment that assigns less 
than all the record title of a lease and that does not create a separate 
lease, the assignee may, with the surety's consent, become a joint 
principal on the surety instrument that guarantees compliance with all 
the terms and conditions of the lease.
    (e) 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 of the distribution of the estate or,
    (2) If no court action is necessary, the statements of two 
disinterested parties having knowledge of the facts or a certified copy 
of the will.
    (f) In addition to the requirements of paragraph (d) of this 
section, the heirs or devisees shall file statements that they are the 
persons named as successors to the estate with evidence of their 
qualifications as provided in Sec. 256.46 of this part.
    (g) 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 
of not to exceed 2 years from the date of death of the predecessor in 
interest.
    (h) Your heirs, executors, administrators, successors, and assigns 
are bound to comply with each obligation under any lease and under the 
regulations in this chapter.
    (1) You are jointly and severally liable for the performance of each 
nonmonetary obligation under the lease and under the regulations in this 
chapter with each prior lessee and with each operating rights owner 
holding an interest at the time the obligation accrued, unless this 
chapter provides otherwise.
    (2) Sublessees and operating rights owners are jointly and severally 
liable for the performance of each nonmonetary obligation under the 
lease and under the regulations in this chapter to the extent that:
    (i) The obligation relates to the area embraced by the sublease;
    (ii) Those owners held their respective interest at the time the 
obligation accrued; and
    (iii) This chapter does not provide otherwise.
    (i) 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 of the assignor or transferor, to a person or 
persons on the same List of Restricted Joint Bidders, the assignor or 
transferor shall file a copy, prior to approval of the assignment, of 
all agreements applicable to the acquisition of that lease or a 
fractional interest.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
as amended at 62 FR 27959, May 22, 1997; 62 FR 39775, July 24, 1997; 70 
FR 49877, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005; 73 FR 49948, Aug. 
25, 2008; 74 FR 46909, Sept. 14, 2009]



Sec. 256.65  Attorney General review.

    Prior to the approval of an assignment or transfer, the Secretary 
shall consult with and give due consideration to the views of the 
Attorney General. The Secretary may act on an assignment or transfer if 
the Attorney General has not responded to the request for consultation 
within 30 days of said request.



Sec. 256.67  Separate filings for assignments.

    A separate instrument of assignment shall be filed for each lease. 
When transfers to the same person, association or corporation, involving 
more than one lease are filed at the same time for approval, one request 
for approval and one showing as to the qualifications of the assignee 
shall be sufficient.



Sec. 256.68  Effect of assignment of a particular tract.

    (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 become 
segregated into separate and distinct leases. In such a case, the 
assignee becomes a lessee of

[[Page 353]]

the Government as to the segregated tract that is the subject of 
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 rental provisions of the original lease 
shall apply separately to each segregated portion.
    (b) For assignments of a portion of an oil and gas lease approved 
after the effective date of ths section, each segregated lease shall 
continue in full force and effect for the primary term of the original 
lease and so long thereafter as oil or gas is produced from that 
segregated portion of the leased area in paying quantities or drillng or 
well reworking operations as approved by the Secretary are conducted.
    (c) For those assignments approved prior to the effective date of 
this section, each segregated lease shall continue in full force and 
effect for the primary term of the original lease and so long thereafter 
as oil and gas may be produced from the original leased area in paying 
quantities or drilling or well reworking operations, as approved by the 
Secretary, are conducted.



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.

[44 FR 38276, June 29, 1979, as amended at 55 FR 32908, Aug. 13, 1990; 
64 FR 9066, Feb. 24, 1999; 64 FR 72795, Dec. 28, 1999]



Sec. 256.71  Directional drilling.

    In accordance with an 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, drillling 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.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, 
and amended at 54 FR 50617, Dec. 8, 1989]



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) MMS 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. MMS 
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.

[64 FR 72795, Dec. 28, 1999]



                     Subpart K_Termination of Leases



Sec. 256.76  Relinquishment of leases or parts of leases.

    A lease or any officially designated subdivision thereof may be 
surrendered by the record title holder by filing a written 
relinquishment, in triplicate,

[[Page 354]]

with the appropriate OCS office of the MMS. No filing fee is required. A 
relinquishment shall take effect on the date it is filed subject to the 
continued obligation of the lessee 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.



Sec. 256.77  Cancellation of leases.

    (a) Any nonproducing lease issued under the act may be cancelled by 
the 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 30 CFR 250.182 shall apply as appropriate.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated 
at 47 FR 47006, Oct. 22, 1982; 64 FR 13343, Mar. 18, 1999; 64 FR 72795, 
Dec. 28, 1999]



                       Subpart L_Section 6 Leases



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.

[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated 
at 47 FR 47006, Oct. 22, 1982]



Sec. 256.80  Leases of other minerals.

    The existence of a lease that meets the requirements of section 6(a) 
of the Act shall not preclude the issuance of other leases of the same 
area for deposits of other minerals. However, no other lease of minerals 
shall authorize or permit the lessee thereunder unreasonably to 
interfere with or endanger operations under the existing lease. No 
sulphur leases shall be granted by the United States on any area while 
such area is included in a lease covering sulphur under section 6(b) of 
the Act.

[[Page 355]]



                            Subpart M_Studies



Sec. 256.82  Environmental studies.

    (a) The Director shall conduct a study of any area or region 
included in any lease sale 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 activities in such 
area or region. Any study shall, to the extent practicable, be designed 
to predict environmental impacts of pollutants introduced into the 
environments and of the impacts of offshore activities on the seabed and 
affected coastal areas.
    (b) Studies shall be planned and carried out in cooperation with the 
affected States and interested parties and, to the extent possible, 
shall not duplicate studies done under other laws. Where appropriate, 
the Director shall, to the maximum extent practicable, enter into 
agreements with the National Oceanic and Atmospheric Administration in 
executing the environmental studies responsibilities. By agreement, the 
Director may also utilize services, personnel or facilities of any 
Federal, State or local government agency in the conduct of such study.
    (c) Any study of an area or region required by paragraph (a) of this 
section for a lease sale shall be commenced not later than six months 
prior to holding a lease sale for that area. The Director may utilize 
information collected in any prior study. The Director may initiate 
studies for areas or regions not identified in the leasing program.
    (d) After the leasing and developing of any area or region, the 
Director shall conduct such studies as are deemed necessary to establish 
additional information and shall 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 shall be done to identify any 
significant changes in the quality and productivity of such 
environments, to establish trends in the areas studies, and to design 
experiments identifying the causes of such changes. Findings from such 
studies shall be used to recommend modifications in practices which 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 shall, 
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.



   Subpart N_Bonus or Royalty Credits for Exchange of Certain Leases 
                            Offshore Florida

    Source: 73 FR 52920, Sept. 12, 2008, unless otherwise noted.



Sec. 256.90  Which leases may I exchange for a bonus or royalty credit?

    You may exchange a lease for a bonus or royalty credit if it:
    (a) Was in effect on December 20, 2006, and
    (b) Is 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.



Sec. 256.91  How much bonus or royalty credit will MMS grant in exchange for a lease?

    The amount of the bonus or royalty credit for an exchanged lease 
equals the sum of:
    (a) The amount of the bonus payment; and
    (b) All rent paid for the lease as of the date the lessee submits 
the request to exchange the lease under Sec. 256.92 to MMS.



Sec. 256.92  What must I do to obtain a bonus or royalty credit?

    (a) To obtain the bonus or royalty credit, all of the record title 
interest owners in the lease must submit the following to the MMS 
Regional Supervisor for Leasing and Environment for

[[Page 356]]

the Gulf of Mexico on or before October 14, 2010.
    (1) A written request to exchange the lease for the bonus or royalty 
credit, signed by all record title interest owners in the lease.
    (2) The name and contact information for a person who will act as a 
contact for each record title interest owner.
    (3) Documentation of each record title interest owner's percentage 
share in the lease.
    (4) A list of all bonus and rental payments for that lease made by, 
or on behalf of, each of the current record title owners.
    (5) A written relinquishment of the lease as described in Sec. 
256.76. Notwithstanding Sec. 256.76, the relinquishment will become 
effective when the credit becomes effective under paragraph (b) of this 
section.
    (b) The credit becomes effective when MMS issues a certification to 
the record title interest owners that the lease has qualified for the 
credit.



Sec. 256.93  How is the bonus or royalty credit allocated among multiple lease owners?

    The MMS will allocate the bonus or royalty credit for an exchanged 
lease to the current record title interest owners in the same percentage 
share as each owner has in the lease as of the date of the request to 
exchange the lease.



Sec. 256.94  How may I use the bonus or royalty credit?

    (a) You may use a credit issued under this part in lieu of a 
monetary payment due under any lease in the Gulf of Mexico not subject 
to the revenue distribution provisions of section 8(g)(2) of the OCSLA 
(43 U.S.C. 1337(g)(2)) for either:
    (1) A bonus for acquisition of an interest in a new lease; or
    (2) Royalty due on oil and gas production after October 14, 2008.
    (b) You may not use a bonus or royalty credit in lieu of delivering 
oil or gas taken as royalty-in-kind.
    (c) If you have any credit that remains unused after 5 years from 
the date MMS issued the credit, MMS reserves the right to apply the 
remaining credit to any of your obligations.



Sec. 256.95  How do I transfer a bonus or royalty credit to another person?

    (a) You may transfer your bonus or royalty credit to any other 
person by submitting to the MMS Adjudication Unit for the Gulf of Mexico 
two originally executed transfer letters of agreement.
    (b) Authorized officers indicated on the qualification card filed 
with MMS of all companies involved in transferring and receiving the 
credit must sign the transfer letters of agreement.
    (c) A transfer letter of agreement must include:
    (1) The effective date of the transfer,
    (2) The OCS-G number for the lease that originally qualified for the 
credit,
    (3) The amount of the credit being transferred,
    (4) Company names punctuated exactly as filed on the qualification 
card at MMS, and
    (5) A corporate seal, if you used a corporate seal in your initial 
qualification to hold OCS leases.
    (d) The transferee of a credit transferred under this section may 
use it in accordance with Sec. 256.94 as soon as MMS sends a 
confirmation of the transfer to the transferee.



         Sec. Appendix A to Part 256--Oil and Gas Cash Bonus Bid

    The following bid is submitted for an oil and gas lease on the area 
of the Outer Continental Shelf specified below:

------------------------------------------------------------------------
                                                         Amount of cash
   Tract No.*     Total amount bid   Amount per acre     submitted with
                                     (or per hectare)         bid
------------------------------------------------------------------------
 
 
------------------------------------------------------------------------
 *Or, if tract numbers are not used, Protraction Diagram or Leasing Map
  and block number.


------------------------------------------------------------------------
                                    Proportionate
                                     interest of
     Bidder qualification No.         company(s)    Name and address of
                                      submitting      bidding company
                                         bid
------------------------------------------------------------------------
---- Misc. No.....................  .............  .....................
------------------------------------------------------------------------

------------------------,
Authorized signatory's name and title.

[47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]

[[Page 357]]



PART 259_MINERAL LEASING: DEFINITIONS--Table of Contents



Sec.
259.001 Purpose and scope.
259.002 Definitions.

    Authority: Pub. L. 83-212, 67 Stat. 462, 43 U.S.C. 1331 et seq., as 
amended by Pub. L. 95-372, 92 Stat. 629.



Sec. 259.001  Purpose and scope.

    The purpose of this part 259 is to define various terms appearing in 
parts 260, 261 and 262 of this chapter.

[48 FR 1182, Jan. 11, 1983]



Sec. 259.002  Definitions.

    For purposes of parts 260, 261, and 262 of this chapter:
    Area or region means the geographic area or region over which the 
MMS designated official has jurisdiction, unless the context in which 
those words are used indicates that a different meaning is intended.
    Designated official means a representative of DOI subject to the 
direction and supervisory authority of the Director, MMS, and the 
appropriate Regional Manager of the MMS authorized and empowered to 
supervise and direct all oil and gas operations and to perform other 
duties prescribed in 30 CFR part 250 (offshore).
    Director means Director, MMS, 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 any consideration, 
including, but not limited to, bonuses, rents or royalties conferred, 
and convenants 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 goethermal resources on lands or interests in 
lands under Federal jurisdiction.
    Gas means natural gas as defined by the Federal Energy Regulatory 
Commission.
    MMS means Minerals Management Service.
    OCS means the Outer Continental Shelf, which includes all submerged 
lands (1) that lie seaward outside of the area of lands beneath 
navigable waters as defined in the Submerged Lands Act (Pub. L. 31-35, 
67 Stat. 29, (43 U.S.C. 1301)) and (2) of which the subsoil and seabed 
appertain to the United States 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 et seq., as 
amended by Pub. L. 95-372, 92 Stat. 629).
    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.

[48 FR 1182, Jan. 11, 1983]



PART 260_OUTER CONTINENTAL SHELF OIL AND GAS LEASING--Table of Contents



                      Subpart A_General Provisions

Sec.
260.1 What is the purpose of this part?
260.2 What definitions apply to this part?
260.3 What is MMS's authority to collect information?

                        Subpart B_Bidding Systems

                           General Provisions

260.101 What is the purpose of this subpart?
260.102 What definitions apply to this subpart?
260.110 What bidding systems may MMS use?
260.111 What conditions apply to the bidding systems that MMS uses?

                             Eligible Leases

260.112 How do royalty suspension volumes apply to eligible leases?
260.113 When does an eligible lease qualify for a royalty suspension 
          volume?
260.114 How does MMS assign and monitor royalty suspension volumes for 
          eligible leases?
260.115 How long will a royalty suspension volume for an eligible lease 
          be effective?
260.116 How do I measure natural gas production on my eligible lease?

                     Royalty Suspension (RS) Leases

260.120 How does royalty suspension apply to leases issued in a sale 
          held after November 2000?

[[Page 358]]

260.121 When does a lease issued in a sale held after November 2000 get 
          a royalty suspension?
260.122 How long will a royalty suspension volume be effective for a 
          lease issued in a sale held after November 2000?
260.123 How do I measure natural gas production for a lease issued in a 
          sale held after November 2000?
260.124 How will royalty suspension apply if MMS assigns a lease issued 
          in a sale held after November 2000 to a field that has a pre-
          Act lease?

                    Bidding System Selection Criteria

260.130 What criteria does MMS use for selecting bidding systems and 
          bidding system components?

Subpart C [Reserved]

                         Subpart D_Joint Bidding

260.301 What is the purpose of this subpart?
260.302 What definitions apply to this subpart?
260.303 What are the joint bidding requirements?

    Authority: 43 U.S.C. 1331 et seq.

    Source: 66 FR 11518, Feb. 23, 2001, unless otherwise noted.



                      Subpart A_General Provisions



Sec. 260.1  What is the purpose of this part?

    Part 260 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.



Sec. 260.2  What definitions apply to this part?

    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 
et seq.), as amended.
    Person includes, in addition to a natural person, an association, a 
State, or a private, public, or municipal corporation.
    We means the Minerals Management Service (MMS).
    You means the lessee or operating rights holder.



Sec. 260.3  What is MMS'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 
260 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers to 
requirements covered under 30 CFR parts 203 and 256.
    (b) You may send comments regarding any aspect of the collection of 
information under this part to the Information Collection Clearance 
Officer, Minerals Management Service, Mail Stop 5438, 1849 C Street, 
NW., Washington, DC 20240.

[73 FR 58472, Oct. 7, 2008]



                        Subpart B_Bidding Systems

                           General Provisions



Sec. 260.101  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.



Sec. 260.102  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

[[Page 359]]

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 256, subpart G of this title, 
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 
part 203 of this title.)
    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 256, subpart G of this title.
    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 part 206 of this title.

[66 FR 11518, Feb. 23, 2001, as amended at 72 FR 25202, May 4, 2007]



Sec. 260.110  What bidding systems may MMS 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 the--         And the characteristics are--
----------------------------------------------------------------------------------------------------------------
(a) Cash bonus bid with a fixed royalty   Cash bonus..........................  The highest responsible
 rate of not less than 12.5 percent.                                             qualified bidder will pay a
                                                                                 royalty rate of 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 with fixed cash      Royalty rate........................  We will specify the fixed amount
 bonus.                                                                          of cash bonus the highest
                                                                                 responsible qualified bidder
                                                                                 must pay in the Notice of OCS
                                                                                 Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------

[[Page 360]]

 
(c) Cash bonus bid with a sliding         Cash bonus..........................  (1) We will calculate the
 royalty rate of not less than 12.5                                              royalty rate the highest
 percent at the beginning of the lease                                           responsible qualified bidder
 period.                                                                         must pay using either:
                                                                                (i) A sliding-scale 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 with fixed share of    Cash bonus..........................  (1) If we award you a lease as
 the net profits of no less than 30                                              the highest responsible
 percent.                                                                        qualified 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 Sec.
                                                                                 220.022. You will calculate the
                                                                                 net profit share base according
                                                                                 to Sec.  220.021.
                                                                                (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 Sec.  220.020, 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 variable royalty      Cash bonus..........................  (1) We may suspend or defer
 rate(s) during one or more periods of                                           royalty for a period, volume,
 production.                                                                     or value of 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 royalty rate(s)       Cash bonus..........................  We will base the royalty rate on
 based on formula(s) or schedule(s)                                              formula(s) or schedule(s)
 during one or more periods of                                                   specified in the Notice of OCS
 production.                                                                     Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(g) Cash bonus with a fixed royalty rate  Cash bonus..........................  Except for periods of royalty
 of not less than 12.5 percent, at the                                           suspension, you will pay a
 beginning of the lease period,                                                  fixed royalty rate of not less
 suspension of royalties for a period,                                           than 12.5 percent. If we award
 volume, or value of production, or                                              to you a lease under this
 depending upon selected characteristics                                         system, you must calculate the
 of extraction, and with suspensions                                             royalty due during the
 that may vary based on the price of                                             designated period using the
 production.                                                                     rate, formula, or schedule
                                                                                 specified in the lease. We will
                                                                                 specify the royalty rate,
                                                                                 formula, or schedule in the
                                                                                 Notice of OCS Lease Sale
                                                                                 published in the Federal
                                                                                 Register.
----------------------------------------------------------------------------------------------------------------



Sec. 260.111  What conditions apply to the bidding systems that MMS uses?

    (a) For each of the bidding systems in Sec. 260.110, 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.

[[Page 361]]

    (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. 260.110, 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.

                             Eligible Leases



Sec. 260.112  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. 260.113. For 
purposes of this section and Sec. Sec. 260.113 through 260.117:
    (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.



Sec. 260.113  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. 260.110(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.

[73 FR 58473, Oct. 7, 2008]



Sec. 260.114  How does MMS 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 MMS 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):

------------------------------------------------------------------------
                                           Minimum  royalty  suspension
               Water depth                            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.
------------------------------------------------------------------------


[73 FR 58473, Oct. 7, 2008]



Sec. 260.115  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 entitled to share the royalty suspension volume 
reaches that volume or the lease period ends.



Sec. 260.116  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 part 250, subpart L of this 
title, equals one barrel of oil equivalent.

                     Royalty Suspension (RS) Leases



Sec. 260.120  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. 260.121 through 260.124:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel

[[Page 362]]

gas) do not count against royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.



Sec. 260.121  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 part 203 of this title, 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.

[66 FR 11518, Feb. 23, 2001, as amended at 73 FR 69517, Nov. 18, 2008]



Sec. 260.122  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 Sec. 218.54 of this title, no 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. 260.120 through 260.124.
    (c) If you must pay royalty on any product (either oil or natural 
gas) for any period under paragraph (b), 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.

[66 FR 11518, Feb. 23, 2001, as amended at 73 FR 69517, Nov. 18, 2008]



Sec. 260.123  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,

[[Page 363]]

measured according to part 250, subpart L of this title, equals one 
barrel of oil equivalent.



Sec. 260.124  How will royalty suspension apply if MMS 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 part 
250, subpart A of this title) 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 part 290 of this title 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 part 203 of this chapter, then:
    (1) Royalty-free production from your RS lease shares from and 
counts as part of any royalty suspension volume under Sec. 260.114(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 part 203 of this title. To share in any larger royalty suspension 
volume, you must file an application described in 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.

[66 FR 11518, Feb. 23, 2001, as amended at 67 FR 57739, Sept. 12, 2002; 
73 FR 58473, Oct. 7, 2008]

                    Bidding System Selection Criteria



Sec. 260.130  What criteria does MMS use for selecting bidding systems and bidding system components?

    In analyzing the application of one of the bidding systems listed in 
Sec. 260.110 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;
    (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 [Reserved]



                         Subpart D_Joint Bidding



Sec. 260.301  What is the purpose of this subpart?

    The purpose of this subpart is to encourage participation in OCS oil 
and gas lease sales by limiting the requirement for filing ``Statements 
of Production'' to certain joint bidders.

[[Page 364]]



Sec. 260.302  What definitions apply to this subpart?

    For the purposes of this subpart, all terms used are defined as in 
Sec. 256.40 of this title.



Sec. 260.303  What are the joint bidding requirements?

    (a) You must file a Statement of Production with the Director, 
according to the requirements of Sec. Sec. 256.38 through 256.44 of 
this title if:
    (1) You submit a joint bid for any OCS oil and gas lease during a 6-
month bidding period; and
    (2) You were chargeable for the prior production period with an 
average daily production from all sources in excess of 1.6 million 
barrels of crude oil, natural gas equivalents, and liquefied petroleum 
products.
    (b) The Statement of Production that you file under paragraph (a) of 
this section must state that you are chargeable for the prior production 
period with an average daily production in excess of the quantities 
listed in paragraph (a) of this section.
    (c) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not submit a joint bid for any OCS oil and gas lease 
during the applicable 6-month bidding period with any other person 
similarly chargeable. We will disqualify and reject these bids.
    (d) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not enter into an agreement prior to a lease sale that 
would result in two or more persons, similarly chargeable, acquiring or 
holding any interest in the tract for which the bid is submitted. We 
will disqualify and reject these bids.



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: 50 FR 21048, May 22, 1985, 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 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 meanings 
given below:
    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

[[Page 365]]

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 title, 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.

[50 FR 21048, May 22, 1985; 64 FR 9066, Feb. 24, 1999, as amended at 73 
FR 20172, Apr. 15, 2008]



Sec. 270.7  Remedies.

    In addition to the penalties available under 30 CFR part 250, 
subpart N of this title, 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.

[50 FR 21048, May 22, 1985; 64 FR 9066, Feb. 24, 1999]



PART 280_PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR ON THE 

OUTER CONTINENTAL SHELF--Table of Contents



                      Subpart A_General Information

Sec.
280.1 What definitions apply to this part?
280.2 What is the purpose of this part?
280.3 What requirements must I follow when I conduct prospecting or 
          research activities?
280.4 What activities are not covered by this part?

          Subpart B_How To Apply for a Permit or File a Notice

280.10 What must I do before I may conduct prospecting activities?
280.11 What must I do before I may conduct scientific research?
280.12 What must I include in my application or notification?
280.13 Where must I send my application or notification?

[[Page 366]]

                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements

280.20 What must I not do in conducting Geological and Geophysical (G&G) 
          prospecting or scientific research?
280.21 What must I do in conducting G&G prospecting or scientific 
          research?
280.22 What must I do when seeking approval for modifications?
280.23 How must I cooperate with inspection activities?
280.24 What reports must I file?

                         Interrupted Activities

280.25 When may MMS require me to stop activities under this part?
280.26 When may I resume activities?
280.27 When may MMS cancel my permit?
280.28 May I relinquish my permit?

                          Environmental Issues

280.29 Will MMS monitor the environmental effects of my activity?
280.30 What activities will not require environmental analysis?
280.31 Whom will MMS notify about environmental issues?

                          Penalties and Appeals

280.32 What penalties may I be subject to?
280.33 How can I appeal a penalty?
280.34 How can I appeal an order or decision?

                       Subpart D_Data Requirements

                     Geological Data and Information

280.40 When do I notify MMS that geological data and information are 
          available for submission, inspection, and selection?
280.41 What types of geological data and information must I submit to 
          MMS?
280.42 When geological data and information are obtained by a third 
          party, what must we both do?

                    Geophysical Data and Information

280.50 When do I notify MMS that geophysical data and information are 
          available for submission, inspection, and selection?
280.51 What types of geophysical data and information must I submit to 
          MMS?
280.52 When geophysical data and information are obtained by a third 
          party, what must we both do?

                              Reimbursement

280.60 Which of my costs will be reimbursed?
280.61 Which of my costs will not be reimbursed?

                               Protections

280.70 What data and information will be protected from public 
          disclosure?
280.71 What is the timetable for release of data and information?
280.72 What procedure will MMS follow to disclose acquired data and 
          information to a contractor for reproduction, processing, and 
          interpretation?
280.73 Will MMS share data and information with coastal States?

                    Subpart E_Information Collection

280.80 Paperwork Reduction Act statement--information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

    Source: 67 FR 46858, July 17, 2002, unless otherwise noted.



                      Subpart A_General Information



Sec. 280.1  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):
    (l) 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.

[[Page 367]]

    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 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 Minerals Management Service, U.S. 
Department of the Interior, or an official authorized to act on the 
Director's behalf.
    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 and geophysical (G&G) prospecting activities means 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 
means 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 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 means 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

[[Page 368]]

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 means 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:
    (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

[[Page 369]]

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. 280.2  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 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. 280.3  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. 280.4  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 part 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 part 251.



          Subpart B_How To Apply for a Permit or File a Notice



Sec. 280.10  What must I do before I may conduct prospecting activities?

    You must have an MMS-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. 280.11  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 an MMS-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 MMS in writing when you conclude your work.

[[Page 370]]



Sec. 280.12  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 MMS-134) 
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;
    (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 MMS-134. (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.)

[67 FR 46858, July 17, 2002, as amended at 71 FR 40914, July 19, 2006; 
73 FR 49948, Aug. 25, 2008]



Sec. 280.13  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, Minerals Management Service,
                                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, Minerals Management Service,
 territories in the Caribbean   Gulf of Mexico OCS Region, 1201 Elmwood
 Sea.                           Park Boulevard, New Orleans, LA 70123.
(c) States of California,      Regional Supervisor for Resource
 Oregon, Washington, Hawaii,    Evaluation, Minerals Management Service,
 or U.S. territories in the     Pacific OCS Region, 770 Paseo Camarillo,
 Pacific Ocean.                 Camarillo, CA 93010.
------------------------------------------------------------------------


[67 FR 46858, July 17, 2002, as amended at 74 FR 46909, Sept. 14, 2009]

[[Page 371]]



                  Subpart C_Obligations Under This Part

                      Prohibitions and Requirements



Sec. 280.20  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. 280.21  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 RD 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 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 RD considers economically feasible.



Sec. 280.22  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 RD's oral or 
written approval. If circumstances preclude a written request, you must 
make an oral request and follow up in writing.



Sec. 280.23  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) MMS 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. 280.24  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 RD, 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:

[[Page 372]]

    (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 RD.

                         Interrupted Activities



Sec. 280.25  When may MMS require me to stop activities under this part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the RD 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 RD 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.



Sec. 280.26  When may I resume activities?

    The RD will advise you when you may start your permit activities 
again.



Sec. 280.27  When may MMS cancel my permit?

    The RD may cancel a permit at any time.
    (a) If we cancel your permit, the RD 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 RD 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. 280.29  Will MMS 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. 280.30  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;

[[Page 373]]

    (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. 280.31  Whom will MMS 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. 280.32  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 U.S.C. 1350) and the 
procedures contained in 30 CFR part 250, 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. 280.33  How can I appeal a penalty?

    See 30 CFR Sec. 250.1409 and 30 CFR part 290, subpart A, for 
instructions on how to appeal any decision assessing a civil penalty 
under 43 U.S.C. 1350 and 30 CFR part 250, subpart A.



Sec. 280.34  How can I appeal an order or decision?

    See 30 CFR part 290, subpart A, for instructions on how to appeal an 
order or decision.



                       Subpart D_Data Requirements

                     Geological Data and Information



Sec. 280.40  When do I notify MMS that geological data

and information are available for submission, inspection, and selection?

    (a) You must notify the RD, 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 RD 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 RD 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. 280.41  What types of geological data and information must I submit to MMS?

    Unless the RD 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

[[Page 374]]

collected, including the reference datum to which paleontological sample 
depths are related and, if the RD 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. 280.42  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. 280.40(a) and is subject to the penalty provisions of Sec. 
280.32(a)(1) and 30 CFR part 250, 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, trades, or otherwise provides data and information to a third 
party must advise the RD 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 RD, advise the RD, in writing, of the license agreement, 
including the identity of the recipient of the data and information.

                    Geophysical Data and Information



Sec. 280.50  When do I notify MMS that geophysical data and

information are available for submission, inspection, and selection?

    (a) You must notify the RD 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 RD 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 RD 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 RD 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 RD extends the delivery time.
    (e) At any time before final selection, the RD 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. 280.51  What types of geophysical data and information must I submit to MMS?

    Unless the RD 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;

[[Page 375]]

    (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. 280.52  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. 280.50(a) and is subject to the penalty provisions of Sec. 
280.32(a)(1) and 30 CFR 250, 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, trades, or otherwise provides data and information to a third 
party must advise the RD, 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 RD, advise the RD, in writing, of the license agreement, 
including the identity of the recipient of the data and information.

                              Reimbursement



Sec. 280.60  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 RD requests if:
    (1) You deliver G&G data and information to us for the RD to inspect 
or select and retain (according to Sec. Sec. 280.40 and 280.50);
    (2) We receive your request for reimbursement and the RD 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 RD, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business.



Sec. 280.61  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. 280.70  What data and information will be protected from public disclosure?

    In making data and information available to the public, the RD 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 250 and 252.
    (1) If the RD determines that any data or information is exempt from

[[Page 376]]

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 250 and 252 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 
RD will immediately issue a public announcement. The announcement must 
further the national interest without unduly damaging your competitive 
position.



Sec. 280.71  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:

------------------------------------------------------------------------
   If you or a third party      The Regional Director will disclose them
 submits and we retain * * *              to the public * * *
------------------------------------------------------------------------
(1) Geological data and        10 years after issuing the permit.
 information.
(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       25 years after you complete the test,
 related to a deep              unless the provisions of paragraph (b)
 stratigraphic test.            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. 280.72  What procedure will MMS follow to disclose acquired data and information

to a contractor for reproduction, processing, and interpretation?

    (a) When practical, the RD will advise the person who submitted data 
and information under Sec. Sec. 280.40 or 280.50 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 RD 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 RD's consent.



Sec. 280.73  Will MMS 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

[[Page 377]]

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.
    (iii) 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.
    (iv) 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
    (2) The regulations at 30 CFR parts 280, 281, and 282.



                    Subpart E_Information Collection



Sec. 280.80  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 280, 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. 280.70 and 30 CFR part 281.
    (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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[67 FR 46858, July 17, 2002, as amended at 74 FR 46910, Sept. 14, 2009]



PART 281_LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN THE OUTER 

CONTINENTAL SHELF--Table of Contents



                            Subpart A_General

Sec.
281.0 Authority for information collection.
281.1 Purpose and applicability.
281.2 Authority.
281.3 Definitions.
281.4 Qualifications of lessees.
281.5 False statements.
281.6 Appeals.
281.7 Disclosure of information to the public.
281.8 Rights to minerals.
281.9 Jurisdictional controversies.

                      Subpart B_Leasing Procedures

281.11 Unsolicited request for a lease sale.
281.12 Request for OCS mineral information and interest.
281.13 Joint State/Federal coordination.
281.14 OCS mining area identification.

[[Page 378]]

281.15 Tract size.
281.16 Proposed leasing notice.
281.17 Leasing notice.
281.18 Bidding system.
281.19 Lease term.
281.20 Submission of bids.
281.21 Award of leases.
281.22 Lease form.
281.23 Effective date of leases.

                   Subpart C_Financial Considerations

281.26 Payments.
281.27 Annual rental.
281.28 Royalty.
281.29 Royalty valuation.
281.30 Minimum royalty.
281.31 Overriding royalties.
281.32 Waiver, suspension, or reduction of rental, minimum royalty, or 
          production royalty.
281.33 Bonds and bonding requirements.

               Subpart D_Assignments and Lease Extensions

281.40 Assignment of leases or interests therein.
281.41 Requirements for filing for transfers.
281.42 Effect of assignment on particular lease.
281.43 Effect of suspensions on lease term.

                     Subpart E_Termination of Leases

281.46 Relinquishment of leases or parts of leases.
281.47 Cancellation of leases.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

    Source: 54 FR 2049, Jan. 18, 1989, unless otherwise noted.



                            Subpart A_General



Sec. 281.0  Authority for information collection.

    The information collection requirements contained in part 281 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.

[54 FR 2049, Jan. 18, 1989, as amended at 73 FR 20172, Apr. 15, 2008]



Sec. 281.1  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. 281.2  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. 281.3  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 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 Minerals Management Service (MMS) 
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

[[Page 379]]

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.
    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. 281.4  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. 281.5  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. 281.6  Appeals.

    Any party adversely affected by a decision of an MMS official made 
pursuant to the provisions of this part shall have the right of appeal 
pursuant to part 290 of this title, except as provided otherwise in 
Sec. 281.21 of this part.



Sec. 281.7  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 280 and 282 and 43 CFR 
part 2).

[[Page 380]]



Sec. 281.8  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 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. 281.9  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. 281.11  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. 281.12  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. 281.11, 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

[[Page 381]]

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, recreation and fisheries; and other socioeconomic, 
biological, and environmental information relating to the area proposed 
for leasing.

[54 FR 2049, Jan. 18, 1989, as amended at 59 FR 53094, Oct. 21, 1994]



Sec. 281.13  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 arrangement 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. 281.14  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. 281.13 of this 
part, and the comments received from interested parties, shall select 
the tracts to be considered for offering for lease. The selected

[[Page 382]]

tracts will be considered in the environmental analysis conducted for 
the proposed lease offering.



Sec. 281.15  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. 281.16  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 
pursuant to Sec. 281.13 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. 281.17  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. 281.18  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.

[[Page 383]]

    (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 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. 281.33.



Sec. 281.19  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. 281.20  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 an MMS 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 an MMS 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 an MMS 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,

[[Page 384]]

shall be presented to MMS at the lease sale prior to the offering of an 
oral bid.



Sec. 281.21  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 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. 281.26 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. 281.33. 
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. 281.22  Lease form.

    The OCS mineral leases shall be issued on the lease form prescribed 
by the Secretary in the leasing notice.



Sec. 281.23  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. 281.26  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, commerical check, bank draft, money order, certified 
check, or cashier's check made payable to ``Department of the Interior--
MMS.'' 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 shall 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

[[Page 385]]

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) (MMS-4430) in accordance with Sec. 210.201 of this 
title. The designated person shall be responsible 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. 281.28(b) on this 
part) of OCS minerals produced (sold, transferred, used, or otherwise 
disposed of) from the leasehold.
    (h) Unless stated otherwise in the lease, product valuation will be 
in accordance with the regulations of this chapter. The value used in 
the computation of royalty shall be determined by the Director. 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: (1) The price received by the lessee; (2) 
commodity and spot market transactions; (3) any other valuation method 
proposed by the lessee and approved by the Director; and (4) value or 
cost netback. 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 II, Subchapter A--
Minerals Revenue Management.

[54 FR 2049, Jan. 18, 1989, as amended at 73 FR 20172, Apr. 15, 2008]



Sec. 281.27  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. 281.28.
    (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. 281.28  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

[[Page 386]]

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.
    (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. 281.29  Royalty valuation.

    The method of valuing the product from a leasehold shall be in 
accordance with regulations of this chapter and procedures prescribed in 
the leasing notice and subsequently issued lease.



Sec. 281.30  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. 
281.28(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. 281.31  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. 281.30 of this part, paragraph (a) of this section, and Sec. 
281.32 of this part.



Sec. 281.32  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

[[Page 387]]

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
    (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. 281.33  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 Associate Director for Offshore Minerals 
Management. 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. 
282.40 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.

[54 FR 2049, Jan. 18, 1989, as amended at 62 FR 27960, May 22, 1997]



               Subpart D_Assignments and Lease Extensions



Sec. 281.40  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. 281.41  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

[[Page 388]]

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 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. 281.20 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. 282.40 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.

[54 FR 2049, Jan. 18, 1989, as amended at 73 FR 49948, Aug. 25, 2008]



Sec. 281.42  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. 281.43  Effect of suspensions on lease term.

    (a) If the 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 Director orders or approves the suspension of either 
operations or

[[Page 389]]

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.



                     Subpart E_Termination of Leases



Sec. 281.46  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. 281.47  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

[[Page 390]]

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 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 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 Opportunities for review and comment.
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 Cancellation of leases.

          Subpart C_Obligations and Responsibilities of Lessees

282.20 Obligations and responsibilities of lessees.
282.21 Plans, general.
282.22 Delineation Plan.
282.23 Testing Plan.
282.24 Mining Plan.
282.25 Plan Modification.
282.26 Contingency Plan.
282.27 Conduct of operations.
282.28 Environmental protection measures.
282.29 Reports and records.
282.30 Right of use and easement.
282.31 Suspension of production or other operations.

                           Subpart D_Payments

282.40 Bonds.
282.41 Methods of royalty calculation.
282.42 Payments.

                            Subpart E_Appeals

282.50 Appeals.

    Authority: 43 U.S.C 1334.

    Source: 54 FR 2067, Jan. 18, 1989, unless otherwise noted.



                            Subpart A_General



Sec. 282.0  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 Minerals Management Service (MMS) of general mining 
operations in the Outer Continental Shalf (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. 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

[[Page 391]]

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 the MMS.



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.



Sec. 282.3  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 MMS 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 overylying 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

[[Page 392]]

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 includes 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. 282.4  Opportunities for review and comment.

    (a) In carrying out MMS'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

[[Page 393]]

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 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. 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 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

[[Page 394]]

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 MMS 
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. 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 part 281 of this chapter, 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. 282.11  Director's authority.

    (a) In the exercise of jurisdiction under Sec. 282.10, 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

[[Page 395]]

and easement and may require a lessee or holder to obtain additional 
environmental data when deemed necessary to 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. 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)(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. 282.4(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);

[[Page 396]]

to property; to natural resources of the OCS including mineral deposits 
(in areas leased or not leased); or to the 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. 282.4(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. 282.4(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 397]]

    (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) 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) 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. 
281.26(i) of this chapter.
    (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 398]]

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 for approval in accordance with the requirements for the 
approval of such plans in this part.
    (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 shall 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. When deemed appropriate by the Director, the lessee shall submit 
a revised Delineation, Testing, or Mining Plan to incorporate the 
mitigation measures required by the Director. In choosing between 
alternative mitigation measures, the Director shall 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.
    (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 other operations on the entire

[[Page 399]]

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 
Sec. 281.28(b) of this subchapter 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 Sec. 
281.28(b) of this subchapter, 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.



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 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

[[Page 400]]

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 part 250 of this 
title 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. 282.15  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;
    (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),

[[Page 401]]

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.



          Subpart C_Obligations and Responsibilities of Lessees



Sec. 282.20  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 part 281 of this title. 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

[[Page 402]]

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. 282.29 of this part.
    (h) When an oral approval is given by MMS 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 MMS or other Agencies needed to carry out exploration, 
testing, development, and production activities under a lease issued 
under part 281 of this title.



Sec. 282.21  Plans, general.

    (a) No exploration, testing, development, or production activities, 
except 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.

[[Page 403]]



Sec. 282.22  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.
    (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 sample 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. 282.28(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. 282.23  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

[[Page 404]]

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 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. 282.28(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.

[[Page 405]]



Sec. 282.24  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.
    (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. 282.28(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.

[[Page 406]]

    (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.



Sec. 282.25  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. 282.21, 282.22, 282.23, and 282.24 of this part.



Sec. 282.26  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. 282.28(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. 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

[[Page 407]]

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 transportation for MMS representatives to inspect its 
facilities. Upon request, the lessee will be reimbursed by the United 
States for the actual costs which it incurs as a result of its providing 
food, quarters, and transportation for an MMS representative's stay of 
more than 10 hours. Request for reimbursement must be submitted within 
60 days following the cost being incurred.
    (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 
liklihood 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;

[[Page 408]]

    (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
    (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 (h)(3)(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 part 250, subpart I, 
of this title.
    (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 Sec. 282.29 of this title.
    (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.



Sec. 282.28  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 
Sec. Sec. 250.194, 250.218, 250.249, and 250.303 of this title.
    (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) 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

[[Page 409]]

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) 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:
    (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) 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.

[54 FR 2067, Jan. 18, 1989; 64 FR 9066, Feb. 24, 1999, as amended at 64 
FR 72795, Dec. 28, 1999; 70 FR 51519, Aug. 30, 2005]



Sec. 282.29  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.

[[Page 410]]

    (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.
    (d) The lessee shall report the results of environmental monitoring 
activities required in Sec. 282.28 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

[[Page 411]]

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. 282.30  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.



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  Bonds.

    (a) Pursuant to the requirements for a bond in Sec. 281.33 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 Associate Director for Offshore Minerals Management. 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. 
256.58(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

[[Page 412]]

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.

[54 FR 2067, Jan. 18, 1989, as amended at 62 FR 27960, May 22, 1997; 73 
FR 20172, Apr. 15, 2008]



Sec. 282.41  Method of royalty calculation.

    In the event that the provisions of royalty management regulations 
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  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. 281.26 of this title.



                            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.

[65 FR 3857, Jan. 25, 2000]



PART 285_RENEWABLE ENERGY ALTERNATE USES OF EXISTING FACILITIES ON THE

OUTER CONTINENTAL SHELF--Table of Contents



                      Subpart A_General Provisions

Sec.
285.100 Authority.
285.101 What is the purpose of this part?
285.102 What are MMS's responsibilities under this part?
285.103 When may MMS prescribe or approve departures from these 
          regulations?
285.104 Do I need an MMS lease or other authorization to produce or 
          support the production of electricity or other energy product 
          from a renewable energy resource on the OCS?
285.105 What are my responsibilities under this part?
285.106 Who can hold a lease or grant under this part?
285.107 How do I show that I am qualified to be a lessee or grant 
          holder?
285.108 When must I notify MMS if an action has been filed alleging that 
          I am insolvent or bankrupt?
285.109 When must I notify MMS of mergers, name changes, or changes of 
          business form?
285.110 How do I submit plans, applications, reports, or notices 
          required by this part?
285.111 When and how does MMS charge me processing fees on a case-by-
          case basis?
285.112 Definitions.
285.113 How will data and information obtained by MMS under this part be 
          disclosed to the public?
285.114 Paperwork Reduction Act statements--information collection.
285.115 Documents incorporated by reference.
285.116 Requests for information on the state of the offshore renewable 
          energy industry.
285.117 [Reserved]
285.118 What are my appeal rights?

[[Page 413]]

            Subpart B_Issuance of OCS Renewable Energy Leases

                        General Lease Information

285.200 What rights are granted with a lease issued under this part?
285.201 How will MMS issue leases?
285.202 What types of leases will MMS issue?
285.203 With whom will MMS consult before issuance of a lease?
285.204 What areas are available for leasing consideration?
285.205 How will leases be mapped?
285.206 What is the lease size?
285.207-285.209 [Reserved]

                        Competitive Lease Process

285.210 How does MMS initiate the competitive leasing process?
285.211 What is the process for competitive issuance of leases?
285.212 What is the process MMS will follow if there is reason to 
          believe that competitors have withdrawn before the Final Sale 
          Notice is issued?
285.213 What must I submit in response to a Request for Interest or a 
          Call for Information and Nominations?
285.214 What will MMS do with information from the Requests for 
          Information or Calls for Information and Nominations?
285.215 What areas will MMS offer in a lease sale?
285.216 What information will MMS publish in the Proposed Sale Notice 
          and Final Sale Notice?
285.217-285.219 [Reserved]

                     Competitive Lease Award Process

285.220 What auction format may MMS use in a lease sale?
285.221 What bidding systems may MMS use for commercial leases and 
          limited leases?
285.222 What does MMS do with my bid?
285.223 What does MMS do if there is a tie for the highest bid?
285.224 What happens if MMS accepts my bid?
285.225 What happens if my bid is rejected, and what are my appeal 
          rights?
285.226-285.229 [Reserved]

                   Noncompetitive Lease Award Process

285.230 May I request a lease if there is no Call?
285.231 How will BOEMRE process my unsolicited request for a 
          noncompetitive lease?
285.232 May I acquire a lease noncompetitively after responding to a 
          Request for Interest or Call for Information and Nominations 
          under Sec. 285.213?
285.233-285.234 [Reserved]

                   Commercial and Limited Lease Terms

285.235 If I have a commercial lease, how long will my lease remain in 
          effect?
285.236 If I have a limited lease, how long will my lease remain in 
          effect?
285.237 What is the effective date of a lease?
285.238 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

285.300 What types of activities are authorized by ROW grants and RUE 
          grants issued under this part?
285.301 What do ROW grants and RUE grants include?
285.302 What are the general requirements for ROW grant and RUE grant 
          holders?
285.303 How long will my ROW grant or RUE grant remain in effect?
285.304 [Reserved]

                   Obtaining ROW Grants and RUE Grants

285.305 How do I request an ROW grant or RUE grant?
285.306 What action will MMS take on my request?
285.307 How will MMS determine whether competitive interest exists for 
          ROW grants and RUE grants?
285.308 How will MMS conduct an auction for ROW grants and RUE grants?
285.309 When will MMS issue a noncompetitive ROW grant or RUE grant?
285.310 What is the effective date of an ROW grant or RUE grant?
285.311-285.314 [Reserved]

          Financial Requirements for ROW Grants and RUE Grants

285.315 What deposits are required for a competitive ROW grant or RUE 
          grant?
285.316 What payments are required for ROW grants or RUE grants?

                Subpart D_Lease and Grant Administration

                   Noncompliance and Cessation Orders

285.400 What happens if I fail to comply with this part?
285.401 When may MMS issue a cessation order?
285.402 What is the effect of a cessation order?
285.403-285.404 [Reserved]

                         Designation of Operator

285.405 How do I designate an operator?
285.406 Who is responsible for fulfilling lease and grant obligations?

[[Page 414]]

285.407 [Reserved]

                        Lease or Grant Assignment

285.408 May I assign my lease or grant interest?
285.409 How do I request approval of a lease or grant assignment?
285.410 How does an assignment affect the assignor's liability?
285.411 How does an assignment affect the assignee's liability?
285.412-285.414 [Reserved]

                        Lease or Grant Suspension

285.415 What is a lease or grant suspension?
285.416 How do I request a lease or grant suspension?
285.417 When may MMS order a suspension?
285.418 How will MMS issue a suspension?
285.419 What are my immediate responsibilities if I receive a suspension 
          order?
285.420 What effect does a suspension order have on my payments?
285.421 How long will a suspension be in effect?
285.422-285.424 [Reserved]

                         Lease or Grant Renewal

285.425 May I obtain a renewal of my lease or grant before it 
          terminates?
285.426 When must I submit my request for renewal?
285.427 How long is a renewal?
285.428 What effect does applying for a renewal have on my activities 
          and payments?
285.429 What criteria will MMS consider in deciding whether to renew a 
          lease or grant?
285.430-285.431 [Reserved]

                       Lease or Grant Termination

285.432 When does my lease or grant terminate?
285.433 What must I do after my lease or grant terminates?
285.434 [Reserved]

                      Lease or Grant Relinquishment

285.435 How can I relinquish a lease or a grant or parts of a lease or 
          grant?

                       Lease or Grant Contraction

285.436 Can MMS require lease or grant contraction?

                       Lease or Grant Cancellation

285.437 When can my lease or grant be canceled?

         Subpart E_Payments and Financial Assurance Requirements

                                Payments

285.500 How do I make payments under this part?
285.501 What deposits must I submit for a competitively issued lease, 
          ROW grant, or RUE grant?
285.502 What initial payment requirements must I meet to obtain a 
          noncompetitive lease, ROW grant, or RUE grant?
285.503 What are the rent and operating fee requirements for a 
          commercial lease?
285.504 How are my payments affected if I develop my lease in phases?
285.505 What are the rent and operating fee requirements for a limited 
          lease?
285.506 What operating fees must I pay on a commercial lease?
285.507 What rent payments must I pay on a project easement?
285.508 What rent payments must I pay on ROW grants or RUE grants 
          associated with renewable energy projects?
285.509 Who is responsible for submitting lease or grant payments to 
          MMS?
285.510 May MMS reduce or waive my lease or grant payments?
285.511-285.514 [Reserved]

         Financial Assurance Requirements for Commercial Leases

285.515 What financial assurance must I provide when I obtain my 
          commercial lease?
285.516 What are the financial assurance requirements for each stage of 
          my commercial lease?
285.517 How will MMS determine the amounts of the supplemental and 
          decommissioning financial assurance requirements associated 
          with commercial leases?
285.518-285.519 [Reserved]

   Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

285.520 What financial assurance must I provide when I obtain my limited 
          lease, ROW grant, or RUE grant?
285.521 Do my financial assurance requirements change as activities 
          progress on my limited lease or grant?
285.522-285.524 [Reserved]

            Requirements for Financial Assurance Instruments

285.525 What general requirements must a financial assurance instrument 
          meet?
285.526 What instruments other than a surety bond may I use to meet the 
          financial assurance requirement?
285.527 May I demonstrate financial strength and reliability to meet the 
          financial assurance requirement for lease or grant activities?

[[Page 415]]

285.528 May I use a third-party guaranty to meet the financial assurance 
          requirement for lease or grant activities?
285.529 Can I use a lease- or grant-specific decommissioning account to 
          meet the financial assurance requirements related to 
          decommissioning?

                     Changes in Financial Assurance

285.530 What must I do if my financial assurance lapses?
285.531 What happens if the value of my financial assurance is reduced?
285.532 What happens if my surety wants to terminate the period of 
          liability of my bond?
285.533 How does my surety obtain cancellation of my bond?
285.534 When may MMS cancel my bond?
285.535 Why might MMS call for forfeiture of my bond?
285.536 How will I be notified of a call for forfeiture?
285.537 How will MMS proceed once my bond or other security is 
          forfeited?
285.538-285.539 [Reserved]

                       Revenue Sharing With States

285.540 How will MMS equitably distribute revenues to States?
285.541 What is a qualified project for revenue sharing purposes?
285.542 What makes a State eligible for payment of revenues?
285.543 Example of how the inverse distance formula works.

              Subpart F_Plans and Information Requirements

285.600 What plans and information must I submit to MMS before I conduct 
          activities on my lease or grant?
285.601 When am I required to submit my plans to MMS?
285.602 What records must I maintain?
285.603-285.604 [Reserved]

 Site Assessment Plan and Information Requirements for Commercial Leases

285.605 What is a Site Assessment Plan (SAP)?
285.606 What must I demonstrate in my SAP?
285.607 How do I submit my SAP?
285.608-285.609 [Reserved]

                  Contents of the Site Assessment Plan

285.610 What must I include in my SAP?
285.611 What information must I submit with my SAP to assist MMS in 
          complying with NEPA and other relevant laws?
285.612 How will my SAP be processed for Federal consistency under the 
          Coastal Zone Management Act?
285.613 How will MMS process my SAP?

                    Activities Under an Approved SAP

285.614 When may I begin conducting activities under my approved SAP?
285.615 What other reports or notices must I submit to MMS under my 
          approved SAP?
285.616 [Reserved]
285.617 What activities require a revision to my SAP, and when will MMS 
          approve the revision?
285.618 What must I do upon completion of approved site assessment 
          activities?
285.619 [Reserved]

         Construction and Operations Plan for Commercial Leases

285.620 What is a Construction and Operations Plan (COP)?
285.621 What must I demonstrate in my COP?
285.622 How do I submit my COP?
285.623-285.625 [Reserved]

            Contents of the Construction and Operations Plan

285.626 What must I include in my COP?
285.627 What information and certifications must I submit with my COP to 
          assist the MMS in complying with NEPA and other relevant laws?
285.628 How will MMS process my COP?
285.629 May I develop my lease in phases?
285.630 [Reserved]

                    Activities Under an Approved COP

285.631 When must I initiate activities under an approved COP?
285.632 What documents must I submit before I may construct and install 
          facilities under my approved COP?
285.633 How do I comply with my COP?
285.634 What activities require a revision to my COP, and when will MMS 
          approve the revision?
285.635 What must I do if I cease activities approved in my COP before 
          the end of my commercial lease?
285.636 What notices must I provide MMS following approval of my COP?
285.637 When may I commence commercial operations on my commercial 
          lease?
285.638 What must I do upon completion of my commercial operations as 
          approved in my COP or FERC license?
285.639 [Reserved]

General Activities Plan Requirements for Limited Leases, ROW Grants, and 
                               RUE Grants

285.640 What is a General Activities Plan (GAP)?
285.641 What must I demonstrate in my GAP?
285.642 How do I submit my GAP?
285.643-285.644 [Reserved]

[[Page 416]]

                 Contents of the General Activities Plan

285.645 What must I include in my GAP?
285.646 What information and certifications must I submit with my GAP to 
          assist MMS in complying with NEPA and other relevant laws?
285.647 How will my GAP be processed for Federal consistency under the 
          Coastal Zone Management Act?
285.648 How will MMS process my GAP?
285.649 [Reserved]

                    Activities Under an Approved GAP

285.650 When may I begin conducting activities under my GAP?
285.651 When may I construct complex or significant OCS facilities on my 
          limited lease or any facilities on my project easement 
          proposed under my GAP?
285.652 How long do I have to conduct activities under an approved GAP?
285.653 What other reports or notices must I submit to MMS under my 
          approved GAP?
285.654 [Reserved]
285.655 What activities require a revision to my GAP, and when will MMS 
          approve the revision?
285.656 What must I do if I cease activities approved in my GAP before 
          the end of my term?
285.657 What must I do upon completion of approved activities under my 
          GAP?

                      Cable and Pipeline Deviations

285.658 Can my cable or pipeline construction deviate from my approved 
          COP or GAP?
285.659 What requirements must I include in my SAP, COP, or GAP 
          regarding air quality?

        Subpart G_Facility Design, Fabrication, and Installation

                                 Reports

285.700 What reports must I submit to MMS before installing facilities 
          described in my approved SAP, COP, or GAP?
285.701 What must I include in my Facility Design Report?
285.702 What must I include in my Fabrication and Installation Report?
285.703 What reports must I submit for project modifications and 
          repairs?
285.704 [Reserved]

                      Certified Verification Agent

285.705 When must I use a Certified Verification Agent (CVA)?
285.706 How do I nominate a CVA for MMS approval?
285.707 What are the CVA's primary duties for facility design review?
285.708 What are the CVA's or project engineer's primary duties for 
          fabrication and installation review?
285.709 When conducting onsite fabrication inspections, what must the 
          CVA or project engineer verify?
285.710 When conducting onsite installation inspections, what must the 
          CVA or project engineer do?
285.711 [Reserved]
285.712 What are the CVA's or project engineer's reporting requirements?
285.713 What must I do after the CVA or project engineer confirms 
          conformance with the Fabrication and Installation Report on my 
          commercial lease?
285.714 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

285.800 How must I conduct my activities to comply with safety and 
          environmental requirements?
285.801 How must I conduct my approved activities to protect marine 
          mammals, threatened and endangered species, and designated 
          critical habitat?
285.802 What must I do if I discover a potential archaeological resource 
          while conducting my approved activities?
285.803 How must I conduct my approved activities to protect essential 
          fish habitats identified and described under the Magnuson-
          Stevens Fishery Conservation and Management Act?
285.804-285.809 [Reserved]

                        Safety Management Systems

285.810 What must I include in my Safety Management System?
285.811 When must I follow my Safety Management System?
285.812 [Reserved]

                        Maintenance and Shutdowns

285.813 When do I have to report removing equipment from service?
285.814 [Reserved]

           Equipment Failure and Adverse Environmental Effects

285.815 What must I do if I have facility damage or an equipment 
          failure?
285.816 What must I do if environmental or other conditions adversely 
          affect a cable, pipeline, or facility?
285.817-285.819 [Reserved]

                       Inspections and Assessments

285.820 Will MMS conduct inspections?
285.821 Will MMS conduct scheduled and unscheduled inspections?

[[Page 417]]

285.822 What must I do when MMS conducts an inspection?
285.823 Will MMS reimburse me for my expenses related to inspections?
285.824 How must I conduct self-inspections?
285.825 When must I assess my facilities?
285.826-285.829 [Reserved]

                  Incident Reporting and Investigation

285.830 What are my incident reporting requirements?
285.831 What incidents must I report, and when must I report them?
285.832 How do I report incidents requiring immediate notification?
285.833 What are the reporting requirements for incidents requiring 
          written notification?

                        Subpart I_Decommissioning

              Decommissioning Obligations and Requirements

285.900 Who must meet the decommissioning obligations in this subpart?
285.901 When do I accrue decommissioning obligations?
285.902 What are the general requirements for decommissioning for 
          facilities authorized under my SAP, COP, or GAP?
285.903 What are the requirements for decommissioning FERC-licensed 
          hydrokinetic facilities?
285.904 Can I request a departure from the decommissioning requirements?

                      Decommissioning Applications

285.905 When must I submit my decommissioning application?
285.906 What must my decommissioning application include?
285.907 How will MMS process my decommissioning application?
285.908 What must I include in my decommissioning notice?

                            Facility Removal

285.909 When may MMS authorize facilities to remain in place following 
          termination of a lease or grant?
285.910 What must I do when I remove my facility?
285.911 [Reserved]

                         Decommissioning Report

285.912 After I remove a facility, cable, or pipeline, what information 
          must I submit?

         Compliance With an Approved Decommissioning Application

285.913 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

285.1000 What activities does this subpart regulate?
285.1001-285.1003 [Reserved]

                     Requesting an Alternate Use RUE

285.1004 What must I do before I request an Alternate Use RUE?
285.1005 How do I request an Alternate Use RUE?
285.1006 How will MMS decide whether to issue an Alternate Use RUE?
285.1007 What process will MMS use for competitively offering an 
          Alternate Use RUE?
285.1008-285.1009 [Reserved]

                    Alternate Use RUE Administration

285.1010 How long may I conduct activities under an Alternate Use RUE?
285.1011 What payments are required for an Alternate Use RUE?
285.1012 What financial assurance is required for an Alternate Use RUE?
285.1013 Is an Alternate Use RUE assignable?
285.1014 When will MMS suspend an Alternate Use RUE?
285.1015 How do I relinquish an Alternate Use RUE?
285.1016 When will an Alternate Use RUE be cancelled?
285.1017 [Reserved]

                  Decommissioning an Alternate Use RUE

285.1018 Who is responsible for decommissioning an OCS facility subject 
          to an Alternate Use RUE?
285.1019 What are the decommissioning requirements for an Alternate Use 
          RUE?

    Authority: 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

    Source: 74 FR 19807, Apr. 29, 2009, unless otherwise noted.



                      Subpart A_General Provisions



Sec. 285.100  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

[[Page 418]]

Policy Act of 2005 (EPAct) (Pub. L. 109-58). The Secretary of the 
Interior delegated to the Minerals Management Service (MMS) 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. 285.101  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
    (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. 285.102  What are MMS's responsibilities under this part?

    (a) The MMS 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) The MMS will require compliance with all applicable laws, 
regulations, other requirements, and the terms of your lease or grant 
under this part and approved plans. The MMS will approve, disapprove, or 
approve with conditions any plans, applications, or other documents 
submitted to MMS for approval under the provisions of this part.
    (c) Unless otherwise provided in this part, MMS may give oral 
directives or decisions whenever prior MMS approval is required under 
this part. The MMS will document in writing any such oral directives 
within 10 business days.
    (d) The MMS 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. 
The MMS will do this in accordance with the terms of this part, the 
leasing notice, the lease or grant under this part, and applicable 
Minerals Revenue Management regulations or guidance.
    (e) The MMS will provide for coordination and consultation with the 
Governor of any State or the executive of any local government or Indian 
tribe

[[Page 419]]

that may be affected by a lease, easement, or ROW under this subsection. 
The MMS 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.



Sec. 285.103  When may MMS prescribe or approve departures from these regulations?

    (a) The MMS 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;
    (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. 285.104  Do I need an MMS 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. 285.105  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 MMS 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 MMS, and of all plans, revisions, and other MMS 
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 MMS representatives, 
within the time specified by MMS, 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. 285.106  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;

[[Page 420]]

    (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 MMS explicitly 
has approved an exception for this transaction;
    (2) The MMS determines or has previously determined after notice and 
opportunity for a hearing that you or your principals have failed to 
meet or exercise due diligence under any OCS lease or grant; or
    (3) The MMS 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 MMS allowed for compliance) after MMS 
directed you to comply; and
    (ii) You took no action to correct the noncompliance within that 
time period.



Sec. 285.107  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 MMS 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 MMS.
    (d) Acceptable evidence under paragraph (c) of this section 
includes, but is not limited to the following:

[[Page 421]]

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[[Page 422]]


[GRAPHIC] [TIFF OMITTED] TR29AP09.101

    (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) The MMS may require you to submit additional information at any 
time considering your bid or request for a noncompetitive lease.



Sec. 285.108  When must I notify MMS if an action has been filed alleging 

that I am insolvent or bankrupt?

    You must notify MMS within 3 business days after you learn of any 
action filed alleging that you are insolvent or bankrupt.



Sec. 285.109  When must I notify MMS of mergers, name changes, or changes of business form?

    You must notify MMS in writing of any merger, name change, or change 
of business form. You must notify MMS 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. 285.110  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 MMS at the following address: Associate 
Director, OEMM, Minerals Management Service, MS-4001, 381 Elden Street, 
Herndon, VA 20170.
    (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.



Sec. 285.111  When and how does MMS charge me processing fees on a case-by-case basis?

    (a) The MMS 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 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 MMS.
    (2) We may apply a standard overhead rate to direct processing 
costs.

[[Page 423]]

    (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 MMS-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), (b)(2), (b)(3), and 
(b)(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. 285.112  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 
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.

[[Page 424]]

    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 MMS 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.
    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 MMS-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 MMS 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. The 
MMS 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) 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

[[Page 425]]

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, an MMS-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.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    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 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

[[Page 426]]

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 280. 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 
MMS 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 MMS 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 refer to an applicant, lessee, the operator, a 
designated agent of the lessee(s) or designated operator, ROW grant 
holder, RUE grant holder, or Alternate Use RUE grant holder under this 
part, or the possessive of each, depending on the context.
    We, us, and our refer to the Minerals Management Service of the 
Department of the Interior, or its possessive, depending on the context.



Sec. 285.113  How will data and information obtained by MMS under this

part be disclosed to the public?

    (a) The MMS 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) The MMS 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.
[GRAPHIC] [TIFF OMITTED] TR29AP09.102


[[Page 427]]


    (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. 285.114  Paperwork Reduction Act statements--information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in 30 CFR part 285 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 MMS 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.
    (e) The MMS is collecting this information for the reasons given in 
the following table:

[[Page 428]]

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[[Page 429]]





Sec. 285.115  Documents incorporated by reference.

    (a) The MMS 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) The MMS will publish, as a rule, any changes in the documents 
incorporated by reference in the Federal Register.
    (2) The MMS may amend by rule the list of industry standards 
incorporated by reference of the document effective without prior 
opportunity for public comment when MMS 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) The MMS 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) The MMS 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 MMS official.
    (d) You may inspect these documents at the Minerals Management 
Service, 381 Elden Street, Room 3313, Herndon, Virginia, 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:
[GRAPHIC] [TIFF OMITTED] TR29AP09.104

    (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.
[GRAPHIC] [TIFF OMITTED] TR29AP09.105


[[Page 430]]





Sec. 285.116  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) The MMS may make such requests for information on a regional 
basis, and may tailor the requests to specific types of renewable energy 
technologies.
    (c) The MMS will publish such requests for information by the 
Director in the Federal Register.



Sec. 285.117  [Reserved]



Sec. 285.118  What are my appeal rights?

    (a) Any party adversely affected by an MMS 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 290 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. 285.200  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
    (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) The MMS 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 MMS approval as provided in Sec. 285.629.

[[Page 431]]



Sec. 285.201  How will MMS issue leases?

    The MMS will issue leases on a competitive basis, as provided under 
Sec. Sec. 285.210 through 285.225. 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. 
285.230 and 285.232. We will issue leases on forms approved by MMS and 
will include terms, conditions, and stipulations identified and 
developed through the process set forth in Sec. Sec. 285.211 and 
285.231.



Sec. 285.202  What types of leases will MMS issue?

    The MMS 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. 285.203  With whom will MMS consult before issuance of a lease?

    For leases issued under this part, through either the competitive or 
noncompetitive process, MMS 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 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 us to consult with or respond to findings 
include the Endangered Species Act (ESA), and the Magnuson-Stevens 
Fishery Conservation and Management Act (MSA).



Sec. 285.204  What areas are available for leasing consideration?

    The MMS may offer any appropriately platted area of the OCS, as 
provided in Sec. 285.205, 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. 285.205  How will leases be mapped?

    The MMS 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. 285.206  What is the lease size?

    (a) The MMS 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.



Sec. Sec. 285.207--285.209  [Reserved]

                        Competitive Lease Process



Sec. 285.210  How does MMS initiate the competitive leasing process?

    The MMS 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. The MMS 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. 285.211  What is the process for competitive issuance of leases?

    The MMS 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

[[Page 432]]

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). The MMS 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. The MMS 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 
MMS 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. The MMS will publish the Proposed Sale 
Notice in the Federal Register and send it to the Governor of any 
affected State 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. The MMS will publish the Final Sale Notice in 
the Federal Register at least 30 days before the date of the sale.



Sec. 285.212  What is the process MMS will follow if there is reason to 

believe that competitors have withdrawn before the Final Sale Notice is issued?

    The MMS 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, MMS 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. 285.231(d) through (i). Under 
the noncompetitive process, the acquisition fee specified in Sec. 
285.502(a) must be submitted with the Site Assessment Plan (SAP) or GAP.
    (b) If, after reviewing comments in response to the notice of 
Request for Interest, MMS determines that competitive interest in the 
lease area continues to exist, we will continue with the competitive 
process set forth in Sec. 285.211 through 285.225.



Sec. 285.213  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. The

[[Page 433]]

MMS 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. 285.113.
    (e) Documentation showing that you are qualified to hold a lease, as 
specified in Sec. 285.107.
    (f) Any other information requested by MMS in the Federal Register 
notice.



Sec. 285.214  What will MMS do with information from the Requests for 

Information or Calls for Information and Nominations?

    The MMS 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 MSA.



Sec. 285.215  What areas will MMS offer in a lease sale?

    The MMS will offer the areas for leasing determined through the 
process set forth in Sec. 285.211 of this part. We will not accept 
nominations after the Call for Information and Nominations closes.



Sec. 285.216  What information will MMS publish in the Proposed Sale Notice and Final Sale Notice?

    For each competitive lease sale, MMS 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 MMS lease form to be used or a reference to that 
form.
    (e) Criteria MMS 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 MMS will award leases 
and how MMS will handle unsuccessful bids or applications.
    (g) Procedures for appealing the lease issuance decision.
    (h) Execution of the lease instrument.



Sec. Sec. 285.217-285.219  [Reserved]

                     Competitive Lease Award Process



Sec. 285.220  What auction format may MMS use in a lease sale?

    (a) Except as provided in Sec. 285.231, 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:

[[Page 434]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.106

    (b) You must submit your bid and a deposit as specified in 
Sec. Sec. 285.500 and 285.501 to cover the bid for each lease area, 
according to the terms specified in the Final Sale Notice.



Sec. 285.221  What bidding systems may MMS 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:
[GRAPHIC] [TIFF OMITTED] TR29AP09.107


[[Page 435]]


    (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. 285.222  What does MMS 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. 285.107).
    (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 MMS. 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. 285.223  What does MMS 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. 285.224  What happens if MMS 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. 285.515 
through 285.537; 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 6 months rent as required in Sec. 285.503.
    (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 MMS 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) The MMS will consider the highest submitted qualified bid to be 
the winning bid when bidding occurs under the systems described in 
Sec. Sec. 285.221(a)(1) through (5). We will determine the winning bid 
for proposals submitted under

[[Page 436]]

the multiple-factor bidding format on the basis of selection by the 
panel as specified in Sec. 285.222(d) when the bidding system under 
Sec. 285.221(a)(6) is used. We will refund the deposit on all other 
bids.



Sec. 285.225  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 MMS Director for reconsideration, in writing, 
within 15 business days of bid rejection, under Sec. 285.118(c)(1). We 
will send you a written response either affirming or reversing the 
rejection.



Sec. Sec. 285.226-285.229  [Reserved]

                   Noncompetitive Lease Award Process



Sec. 285.230  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. The MMS 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. 
285.113.
    (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. 285.107.
    (g) An acquisition fee, as specified in Sec. 285.502(a).



Sec. 285.231  How will BOEMRE process my unsolicited request for a noncompetitive lease?

    (a) The MMS 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) The MMS 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 MMS determines that competitive interest exists in the lease 
area:
    (1) The MMS will proceed with the competitive process set forth in 
Sec. Sec. 285.210 through 285.225;
    (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, MMS will not refund your acquisition fee.
    (d) If MMS determines that there is no competitive interest in a 
lease:
    (1) We will publish in the Federal Register a notice that there is 
no competitive interest; and
    (2) You must submit within 60 days of the date of the notice to MMS:
    (i) For a commercial lease, a SAP, as described in Sec. Sec. 
285.605 through 285.613; or
    (ii) For a limited lease, a GAP, as described in Sec. Sec. 285.640 
through 285.648.
    (e) The MMS will coordinate and consult with affected Federal 
agencies, State, and local governments, and affected Indian tribes in 
the review of noncompetitive lease requests and associated plans.
    (f) If we approve or approve with conditions your SAP or GAP, we may 
offer you a noncompetitive lease.
    (g) If you accept the terms and conditions of the lease, then we 
will issue the lease, and you must comply with all terms and conditions 
of your lease and all applicable provisions of this

[[Page 437]]

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. 285.515 
through 285.537; and
    (2) Within 45 days after you receive the lease copies, you must pay 
the first 6-months rent, as required in Sec. 285.503.
    (h) The MMS will publish in the Federal Register a notice announcing 
the issuance of your lease.
    (i) If you do not accept the terms and conditions, MMS will not 
issue a lease, and we will not refund your acquisition fee.

[74 FR 19807, Apr. 29, 2009, as amended at 76 FR 28180, May 16, 2011]



Sec. 285.232  May I acquire a lease noncompetitively after responding to a

Request for Interest or Call for Information and Nominations under Sec. 285.213?

    (a) If you submit an area of interest for a possible lease and MMS 
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. 285.502(a).
    (c) After receiving the acquisition fee, BOEMRE will follow the 
process outlined in Sec. 285.231(d) through (i).

[74 FR 19807, Apr. 29, 2009, as amended at 76 FR 28180, May 16, 2011]



Sec. Sec. 285.233-285.234  [Reserved]

                   Commercial and Limited Lease Terms



Sec. 285.235  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:

[[Page 438]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.108

    (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.



Sec. 285.236  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:

[[Page 439]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.109

    (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.



Sec. 285.237  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 MMS approves, a 
lease may be dated and become effective the first day of the month in 
which it is signed by the lessor.



Sec. 285.238  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, MMS will coordinate and consult with other 
relevant Federal agencies, any other affected State(s), affected local 
government executives, and affected Indian tribes.
    (c) The MMS may issue leases, RUEs, and ROWs for research activities 
managed by a Federal agency or a State only in areas for which the 
Director 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 MMS and a Federal agency or a State. 
The MOA must include the agreement of the head of the Federal agency or

[[Page 440]]

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 MMS 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) The MMS 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) The MMS 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. 285.300  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. 285.200(b) to serve your lease.



Sec. 285.301  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 MMS on a case-by-case basis 
and set forth in each RUE grant.



Sec. 285.302  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. 285.107.
    (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 MMS in the 
area of a previously issued ROW grant or RUE grant may not unreasonably 
interfere 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. 285.303  How long will my ROW grant or RUE grant remain in effect?

    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.

[[Page 441]]



Sec. 285.304  [Reserved]

                   Obtaining ROW Grants and RUE Grants



Sec. 285.305  How do I request an ROW grant or RUE grant?

    You must submit to MMS 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. 285.306  What action will MMS take on my request?

    The MMS 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. 285.308, or noncompetitively if we determine after public notice 
that there is no competitive interest. The MMS 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 MMS will first determine if there is competitive interest, as 
provided in Sec. 285.307.
    (b) If MMS determines that there is no competitive interest in a ROW 
grant or RUE grant, we will:
    (1) In consultation with you, establish the terms and conditions for 
the grant;
    (2) Require you to submit a GAP, as described in Sec. Sec. 285.640 
through 285.648, within 60 days of the determination of no competitive 
interest; and
    (3) Evaluate your request for a noncompetitive grant and GAP 
simultaneously.
    (c) If we award your ROW grant or RUE grant competitively, you must 
submit and receive MMS approval of your GAP, as provided in Sec. Sec. 
285.640 through 285.648.



Sec. 285.307  How will MMS 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. 285.308  How will MMS conduct an auction for ROW grants and RUE grants?

    (a) If MMS determines that there is competitive interest, we will:
    (1) Publish a notice of each grant auction in the Federal Register 
describing auction procedures, allowing 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. 
285.211 through 285.225.
    (b) If you are the successful bidder in an auction, you must pay the 
first year's rent, as provided in Sec. 285.316.



Sec. 285.309  When will MMS issue a noncompetitive ROW grant or RUE grant?

    If we approve or approve with conditions your GAP, we 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, MMS will not 
issue a grant.



Sec. 285.310  What is the effective date of an ROW grant or RUE grant?

    Your ROW grant or RUE grant becomes effective on the date 
established

[[Page 442]]

by MMS on the ROW grant or RUE grant instrument.



Sec. Sec. 285.311-285.314  [Reserved]

          Financial Requirements for ROW Grants and RUE Grants



Sec. 285.315  What deposits are required for a competitive ROW grant or RUE grant?

    (a) You must make a deposit, as required in Sec. 285.501(a), 
regardless of whether the auction is a sealed-bid, oral, electronic, or 
other auction format. The MMS 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. 285.316  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 MMS, as provided in the 
sale notice.
    (b) An annual rent for the first year of the grant, as specified in 
Sec. 285.508.



                Subpart D_Lease and Grant Administration

                   Noncompliance and Cessation Orders



Sec. 285.400  What happens if I fail to comply with this part?

    (a) The MMS 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) The MMS 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, MMS 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 MMS to issue a cessation 
order as provided in Sec. 285.401, and/or a cancellation of the lease 
or grant as provided in Sec. 285.437.
    (e) If the MMS 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 
historical or archaeological significance, MMS 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 MMS 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 250, subpart N.
    (g) You may be subject to criminal penalties as authorized by 
section 24 of the OCS Lands Act.



Sec. 285.401  When may MMS issue a cessation order?

    (a) The MMS 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 MMS 
approval under this part. Except as provided in Sec. 285.400(e), MMS

[[Page 443]]

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 
MMS, to receive approval to resume activities on your lease or grant.



Sec. 285.402  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. The MMS 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 MMS. If MMS 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. 285.437.
    (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. 285.403-285.404  [Reserved]

                         Designation of Operator



Sec. 285.405  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. 285.610(a)(3)), COP (under Sec. 285.626(b)(2)), or GAP (under 
Sec. 285.645(b)(3)), as applicable. If no operator is designated in a 
SAP, COP, or GAP, MMS 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 MMS 
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 MMS and identify the new designated operator 
within 72 hours on a form approved by MMS. The lessee(s) or grantee(s) 
is the operator and responsible for compliance until MMS 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.



Sec. 285.406  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, MMS 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.

[[Page 444]]



Sec. 285.407  [Reserved]

                        Lease or Grant Assignment



Sec. 285.408  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 MMS 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 MMS. The 
assignment application must include:
    (1) The MMS-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. 285.107; and
    (8) A statement on how the assignee will comply with the financial 
assurance requirements of Sec. Sec. 285.515 through 285.537. 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 MMS approves the assignment.
    (d) The assignment takes effect on the date MMS approves your 
application.
    (e) You do not need to request an assignment for mergers, name 
changes, or changes of business form. You must notify MMS of these 
events under Sec. 285.109.



Sec. 285.409  How do I request approval of a lease or grant assignment?

    (a) You must request approval of each assignment on a form approved 
by MMS, 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. 285.515 through 
285.537.
    (c) The assignee must submit proof of eligibility and other 
qualifications specified in Sec. 285.107.
    (d) Persons executing on behalf of the assignor and assignee must 
furnish evidence of authority to execute the assignment.



Sec. 285.410  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 MMS approves 
your assignment. Our approval of the assignment does not relieve you of 
these accrued obligations. The MMS 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. 285.411  How does an assignment affect the assignee's liability?

    (a) As assignee, you are liable for all lease or grant obligations 
that accrue after MMS 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

[[Page 445]]

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. 285.412-285.414  [Reserved]

                        Lease or Grant Suspension



Sec. 285.415  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 MMS at your request, as provided in Sec. 
285.416; or
    (2) As ordered by MMS, as provided in Sec. 285.417.
    (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 MMS under 
the terms of the suspension.



Sec. 285.416  How do I request a lease or grant suspension?

    You must submit a written request to MMS 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 MMS may require.



Sec. 285.417  When may MMS order a suspension?

    (a) The MMS 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 MMS 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
    (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. 285.418  How will MMS issue a suspension?

    (a) The MMS will issue a suspension order orally or in writing.
    (b) The MMS 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

[[Page 446]]

activities. The MMS may authorize certain activities during the period 
of the suspension, as set forth in the suspension order.



Sec. 285.419  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. 285.420  What effect does a suspension order have on my payments?

    (a) While MMS evaluates your request for a suspension under Sec. 
285.416, 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 MMS to complete its evaluation of your request, but you will not be 
required to make payments during the time of the extension.
    (b) If MMS approves your request for a suspension, as provided in 
Sec. 285.416, we may suspend your payment obligation, as appropriate 
for the term that is suspended, depending on the reasons for the 
requested suspension.
    (c) If MMS orders a suspension, as provided in Sec. 285.417, your 
payments, as appropriate for the term that is suspended, will be waived 
during the suspension period.



Sec. 285.421  How long will a suspension be in effect?

    A suspension will be in effect for the period specified by MMS.
    (a) The MMS will not approve a suspension request pursuant to Sec. 
285.416 for a period longer than 2 years.
    (b) If MMS determines that the circumstances giving rise to a 
suspension ordered under Sec. 285.417 cannot be resolved within 5 
years, the Secretary may initiate cancellation of the lease or grant, as 
provided in Sec. 285.437.



Sec. Sec. 285.422-285.424  [Reserved]

                         Lease or Grant Renewal



Sec. 285.425  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. The MMS, at its discretion, may 
approve a renewal request to conduct substantially similar activities as 
were originally authorized under the lease or grant. The MMS will not 
approve a renewal request that involves development of a type of 
renewable energy not originally authorized in the lease or grant. The 
MMS may revise or adjust payment terms of the original lease, as a 
condition of lease renewal.



Sec. 285.426  When must I submit my request for renewal?

    (a) You must request a renewal from MMS:
    (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 MMS all information we request pertaining to 
your lease or grant and your renewal request.



Sec. 285.427  How long is a renewal?

    The MMS will set the term of a renewal at the time of renewal on a 
case-by-case basis.
    (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. 285.428  What effect does applying for a renewal have on my activities and payments?

    If you timely request a renewal:

[[Page 447]]

    (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 MMS.
    (b) You may request a suspension of your lease or grant, as provided 
in Sec. 285.416, while we consider your request.
    (c) For the period MMS 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. 285.429  What criteria will MMS consider in deciding whether to renew a lease or grant?

    The MMS 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. 285.430-285.431  [Reserved]

                       Lease or Grant Termination



Sec. 285.432  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. Sec. 285.235 or 
285.236, a request for renewal of your lease or grant is pending a 
decision by MMS, or your lease or grant is suspended or renewed as 
provided in this subpart;
    (b) A cancellation, as set forth in Sec. 285.437; or
    (c) Relinquishment, as set forth in Sec. 285.435.



Sec. 285.433  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 MMS under subpart I of 
this part.
    (c) If you fail to comply with your approved decommissioning plan or 
application:
    (1) The MMS 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. 285.434  [Reserved]

                      Lease or Grant Relinquishment



Sec. 285.435  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 copy and one 
electronic copy of a relinquishment application with MMS. 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 MMS; 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;

[[Page 448]]

    (6) The MMS-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 MMS 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. 285.436  Can MMS require lease or grant contraction?

    At an interval no more frequent than every 5 years, the MMS 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. The MMS 
will notify you of our proposal to contract the lease or grant area.
    (a) The MMS 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, MMS 
will issue a decision addressing your contentions that the area is 
needed.
    (c) You may appeal this decision under Sec. 285.118 of this part.

                       Lease or Grant Cancellation



Sec. 285.437  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 MMS 
specifies) after you receive notice from MMS. 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. 285.635, or other approved activities under your 
GAP, as provided in Sec. 285.656;
    (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
    (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. 285.500  How do I make payments under this part?

    (a) For acquisition fees or the initial 6-months rent paid for the 
preliminary term of your lease, you must make credit card or automated 
clearing house payments through the Pay.gov

[[Page 449]]

Web site, and you must include one copy of the Pay.gov confirmation 
receipt page with your unsolicited request or signed lease instrument. 
You may access the Pay.gov Web site through links on the MMS Offshore 
Web site at: http://www.mms.gov/offshore or directly through Pay.gov at: 
https://www.pay.gov/paygov/.
    (b) For rent during the preliminary term, subsequent to the first 6-
months rent, or the site assessment term; or operating fees during the 
operations term, you must make your payments as required in Sec. 218.51 
of this chapter.
    (c) This table summarizes payments you must make for leases and 
grants, unless otherwise specified in the Final Sale Notice:
[GRAPHIC] [TIFF OMITTED] TR29AP09.110



Sec. 285.501  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.

[[Page 450]]

    (b) For a competitive lease that we offer through ascending bidding, 
you must submit a deposit as established in the Final Sale Notice.
    (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. 285.502  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. 285.500.
    (b) If MMS 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. 285.503  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 the first 6-months rent, as provided in Sec. 
285.500, 45 days after we issue your lease.
    (2) You must pay rent at the beginning of each subsequent 1-year 
period in accordance with the regulations at Sec. 218.51 of this 
chapter for the entire lease area until the facility begins to generate 
commercially, as specified in Sec. 285.506 or as otherwise specified in 
the Final Sale Notice or lease instrument:
    (i) For leases issued competitively, the MMS 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 MMS 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 the rent for a project easement in addition to the 
lease rent, as provided in Sec. 285.507. 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 MMS, you must pay operating fees in the amount 
specified in Sec. 285.506:
    (1) For leases issued competitively, MMS will specify in the Final 
Sale Notice and lease the date when operating fees commence; and
    (2) For leases issued noncompetitively, MMS will specify in the 
lease the date when operating fee commences.



Sec. 285.504  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. 285.629, you must pay:
    (a) Rent on the portion of the lease that is not authorized for 
commercial operations.
    (b) Operating fees on the portion of the lease that is authorized 
for commercial operations, in the amount specified in Sec. 285.506 and 
as described in Sec. 285.503(b).

[[Page 451]]

    (c) Rent for a project easement in addition to lease rent, as 
provided in Sec. 285.507. You must commence rent payments for your 
project easement upon our approval of your COP.



Sec. 285.505  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 the first 6-months rent when MMS issues your 
limited lease, as provided in Sec. 285.500.
    (c) You must pay 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 Sec. 218.51 of this chapter.
    (d) The MMS will not charge an operating fee for the authorized sale 
of power from a limited lease.



Sec. 285.506  What operating fees must I pay on a commercial lease?

    If you are generating electricity, you must pay operating fees on 
your commercial lease when you begin commercial generation, as described 
in Sec. 285.503.
    (a) The MMS 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) The MMS 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 MMS 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. 285.510.
    (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. The MMS:
    (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.
    (3) The MMS 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.

[[Page 452]]

    (i) Upon the completion of the first year of commercial operations 
on the lease, MMS 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, MMS 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 MMS adjusts the capacity factor.
    (iii) The process by which MMS 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. 285.510.
    (4) Ten days after the anniversary date of when you began to 
commercially generate electricity, you must submit to MMS 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), MMS 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 MMS in accordance 
with the provisions under Sec. 218.51 of this chapter.
    (e) The MMS 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. 285.507  What rent payments must I pay on a project easement?

    (a) You must pay MMS 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. 285.500;
    (2) You must submit all subsequent rent payments in accordance with 
the regulations at Sec. 218.51 of this chapter; and
    (3) You must continue to pay annual rent for your project easement 
until your lease is terminated.



Sec. 285.508  What rent payments must I pay on ROW grants or RUE grants 

associated with renewable energy projects?

    (a) For each ROW grant MMS approves under subpart C of this part, 
you must pay 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 MMS approves under subpart C of this part, 
you must pay a rent of:
    (1) $5 per acre per year; or
    (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.

[[Page 453]]

    (d) You must make the first annual rent payment upon approval of 
your ROW grant or RUE grant request, as provided in Sec. 285.500, and 
all subsequent rent payments to MMS in accordance with the regulations 
at Sec. 218.51 of this chapter.



Sec. 285.509  Who is responsible for submitting lease or grant payments to MMS?

    (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 Sec. 218.52 of this 
chapter.
    (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. 285.510  May MMS reduce or waive my lease or grant payments?

    (a) The MMS 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. 285.511-285.514  [Reserved]

         Financial Assurance Requirements for Commercial Leases



Sec. 285.515  What financial assurance must I provide when I obtain my commercial lease?

    (a) Before MMS 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. 285.526 through 
285.529.
    (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. 285.516  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 454]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.111

    (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 MMS before FERC 
issues a license.



Sec. 285.517  How will MMS determine the amounts of the supplemental and

decommissioning financial assurance requirements associated with commercial leases?

    (a) The MMS 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 455]]



Sec. 285.518-285.519  [Reserved]

   Financial Assurance for Limited Leases, ROW Grants, and RUE Grants



Sec. 285.520  What financial assurance must I provide when I obtain my 

limited lease, ROW grant, or RUE grant?

    (a) Before MMS 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. 285.526 through 285.529.
    (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. 285.521  Do my financial assurance requirements change as activities 

progress on my limited lease or grant?

    (a) The MMS 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) The MMS 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. 285.525 
through 285.529.
    (2) The MMS will allow you to provide your financial assurance for 
decommissioning in accordance with the number of facilities installed or 
being installed. The MMS must approve the schedule for providing the 
appropriate financial assurance coverage.



Sec. Sec. 285.522-285.524  [Reserved]

            Requirements for Financial Assurance Instruments



Sec. 285.525  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 MMS 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 MMS. 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 MMS-
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 456]]

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 MMS 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. 285.526  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 MMS 
determines that such security protects MMS to the same extent as the 
surety bond. The MMS 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 MMS;
    (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 MMS;
    (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 MMS; 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 MMS 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 457]]



Sec. 285.527  May I demonstrate financial strength and reliability to 

meet the financial assurance requirement for lease or grant activities?

    The MMS 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 MMS has reason to believe that you are unable to meet 
the financial assurance requirements of this section, after notice and 
opportunity for a hearing, MMS 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. 285.528  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) The MMS 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 458]]

to be updated annually within 90 days of the end of the fiscal year (FY) 
or as otherwise prescribed.
[GRAPHIC] [TIFF OMITTED] TR29AP09.112

    (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. 285.107.
    (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 MMS 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 MMS 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 MMS 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. 285.529  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, MMS 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 MMS and pledged to meet your lease 
or

[[Page 459]]

grant decommissioning and site clearance obligations; and
    (2) You must fully fund the account within the time MMS prescribes 
to cover all costs of decommissioning including site clearance. The MMS 
will estimate the cost of decommissioning, including site clearance.
    (b) Any interest paid on the account will be treated as account 
funds unless we authorize in writing that any interest be paid to the 
depositor.
    (c) We may allow you to pledge Treasury securities, payable to MMS 
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. 285.530  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 MMS within 3 business days about the financial assurance 
lapse; and
    (2) Provide new financial assurance in the amount set by MMS, as 
provided in this subpart.
    (b) You must notify MMS 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. 285.531  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 MMS.



Sec. 285.532  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 MMS 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 MMS 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. The MMS will 
terminate that period of liability within 90 days after MMS receives the 
request.



Sec. 285.533  How does my surety obtain cancellation of my bond?

    (a) The MMS will release a bond or allow a surety to cancel a bond, 
and will relieve the surety from accrued obligations only if:
    (1) The MMS determines that there are no outstanding obligations 
covered by the bond; or
    (2) The following occurs:
    (i) The MMS 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

[[Page 460]]

during the terminated period of liability that exceeds the coverage of 
the bond prescribed under Sec. Sec. 285.515, 285.516, 285.520, or 
285.521, and of which you were notified.
    (b) When your lease or grant ends, your surety(ies) remain(s) 
responsible, and MMS will retain any financial assurance as follows:
    (1) The period of liability ends when you cease all operations and 
activities 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 MMS to determine that all of your obligations 
under the lease or grant have been satisfied; and
    (3) The MMS 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. 285.534  When may MMS cancel my bond?

    When your lease or grant ends, your surety(ies) remain(s) 
responsible, and MMS will retain any pledged security as shown in the 
following table:
[GRAPHIC] [TIFF OMITTED] TR29AP09.113



Sec. 285.535  Why might MMS call for forfeiture of my bond?

    (a) The MMS 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 MMS, 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.

[[Page 461]]

    (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. 285.536  How will I be notified of a call for forfeiture?

    (a) The MMS 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 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 MMS 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. 285.537  How will MMS proceed once my bond or other security is forfeited?

    (a) If MMS 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, MMS 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. 285.538-285.539  [Reserved]

                       Revenue Sharing With States



Sec. 285.540  How will MMS equitably distribute revenues to States?

    (a) The MMS 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. 
285.541 and an eligible State is determined in Sec. 285.542, with each 
term defined in Sec. 285.112. 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, MMS 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. 285.435 or 285.436, MMS will re-evaluate the project area 
to determine whether the geographic center has changed. If it has, MMS 
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, MMS 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)).

[[Page 462]]



Sec. 285.541  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. 285.542. The entire area within a lease or grant for the 
qualified project, excluding project easements, is considered the 
qualified project area.



Sec. 285.542  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. 285.543  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. The MMS 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. 285.600  What plans and information must I submit to MMS 

before I conduct activities on my lease or grant?

    You must submit a SAP, COP, or GAP and receive MMS approval as set 
forth in the following table:
[GRAPHIC] [TIFF OMITTED] TR29AP09.114


[[Page 463]]





Sec. 285.601  When am I required to submit my plans to MMS?

    Your plan submission requirements depend on whether your lease or 
grant was issued competitively or noncompetitively under subpart B or 
subpart C of this part.
    (a) If your lease or grant is issued competitively, you must submit 
your SAP or your GAP within 6 months of issuance.
    (b) If you request that a lease or grant be issued noncompetitively, 
you must submit your SAP or your GAP within 60 days after the Director 
issues a determination that there is no competitive interest.
    (c) 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.
    (d) You may submit your COP or FERC license application with your 
SAP.
    (1) You must provide sufficient data and information with your COP 
for MMS to complete the needed reviews and NEPA analysis; and
    (2) The MMS may need to conduct additional reviews, including NEPA 
analysis, if significant new information becomes available after you 
complete your site assessment activities or you revise your COP. As a 
result of the additional reviews, we may require modification of your 
COP.



Sec. 285.602  What records must I maintain?

    Until MMS releases your financial assurance under Sec. 285.534, you 
must maintain and provide to MMS, upon request, all data and information 
related to compliance with required terms and conditions of your SAP, 
COP, or GAP.



Sec. Sec. 285.603-285.604  [Reserved]

 Site Assessment Plan and Information Requirements for Commercial Leases



Sec. 285.605  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) The MMS 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. 285.113.
    (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 MMS approval of your SAP before you can begin 
any of the approved activities on your lease, as provided in Sec. 
285.613.
    (d) If you propose to construct a facility or combination of 
facilities deemed by MMS to be complex or significant, as provided in 
Sec. 285.613(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. 285.810.



Sec. 285.606  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. 285.105(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;

[[Page 464]]

    (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. 285.626(a).



Sec. 285.607  How do I submit my SAP?

    You must submit one paper copy and one electronic version of your 
SAP to MMS at the address listed in Sec. 285.110(a).



Sec. Sec. 285.608-285.609  [Reserved]

                  Contents of the Site Assessment Plan



Sec. 285.610  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 465]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.115

    (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:

[[Page 466]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.116

    (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 MMS and/or FERC to complete the needed 
reviews and NEPA analysis.
    (2) You may need to revise your COP or FERC license application and 
MMS

[[Page 467]]

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. 285.611  What information must I submit with my SAP to assist 

MMS in complying with NEPA and other relevant laws?

    (a) You must submit with your SAP detailed information to assist MMS 
in complying with NEPA and other relevant laws, as appropriate. For a 
noncompetitive commercial lease, 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.
    (b) For competitively issued commercial leases, MMS will have 
prepared a NEPA document and consistency determination for the lease 
sale and site assessment activities. However, if you submit a SAP that 
shows changes in impacts from those identified in the NEPA document or 
consistency determination prepared for the lease, MMS may determine that 
your SAP is subject to a new NEPA/CZMA and other relevant Federal 
reviews. In that case, MMS will notify you of the 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:

[[Page 468]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.117



Sec. 285.612  How will my SAP be processed for Federal consistency 

under the Coastal Zone Management Act?

    Your SAP will be processed based on how your commercial lease was 
issued:

[[Page 469]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.118



Sec. 285.613  How will MMS process my SAP?

    (a) The MMS will review your submitted SAP, and additional 
information provided pursuant to Sec. 285.611, 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) The MMS 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, MMS may disapprove your SAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal laws (e.g., CZMA), MMS 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 and conditions required under Sec. 285.615(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. 285.614  When may I begin conducting activities under my approved SAP?

    (a) You may begin conducting the activities approved in your SAP 
following MMS approval of your SAP.
    (b) If you are installing a facility or a combination of facilities 
deemed by MMS to be complex or significant, as provided in Sec. 
285.613(a)(1), you must comply with the requirements of subpart G of 
this part and submit your Safety Management System required by Sec. 
285.810 before construction may begin.



Sec. 285.615  What other reports or notices must I submit to MMS under my approved SAP?

    (a) You must notify MMS in writing within 30 days of completing 
installation activities approved in your SAP.

[[Page 470]]

    (b) You must prepare and submit to MMS a report annually on November 
1 of each year that summarizes your site assessment activities and the 
results of those activities. The MMS 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. 285.113.
    (c) You must submit a certification of compliance annually (or other 
frequency as determined by MMS) with certain terms and conditions of 
your SAP that MMS identifies under Sec. 285.613(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. 285.616  [Reserved]



Sec. 285.617  What activities require a revision to my SAP, and when will MMS approve the revision?

    (a) You must notify MMS 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) The MMS 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 MMS.
    (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. 285.618  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

[[Page 471]]

continued use of existing facilities approved in your SAP, you may keep 
such facilities in place on your lease during the time that MMS 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, MMS 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. 285.619  [Reserved]

         Construction and Operations Plan for Commercial Leases



Sec. 285.620  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. The MMS 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. 285.113.
    (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 MMS approval of your COP before you can begin 
any of the approved activities on your lease.



Sec. 285.621  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. 285.105(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;
    (e) Uses best available and safest technology;
    (f) Uses best management practices; and
    (g) Uses properly trained personnel.



Sec. 285.622  How do I submit my COP?

    (a) You must submit one paper copy and one electronic version of 
your COP to MMS at the address listed in Sec. 285.110(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. 285.623-285.625  [Reserved]

            Contents of the Construction and Operations Plan



Sec. 285.626  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:

[[Page 472]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.119


[[Page 473]]


[GRAPHIC] [TIFF OMITTED] TR29AP09.120

    (b) Your COP must include the following project-specific 
information, as applicable.

[[Page 474]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.121


[[Page 475]]


[GRAPHIC] [TIFF OMITTED] TR29AP09.122



Sec. 285.627  What information and certifications must I submit with 

my COP to assist the MMS in complying with NEPA and other relevant laws?

    (a) You must submit with your COP detailed information to assist MMS 
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:

[[Page 476]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.123

    (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 subsection 
307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 930.76 
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) ``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).
    (c) You must submit your oil spill response plan, as required by 
part 254 of this subchapter.
    (d) You must submit your Safety Management System as required by 
Sec. 285.810.



Sec. 285.628  How will MMS process my COP?

    (a) The MMS will review your submitted COP, and the information 
provided pursuant to Sec. 285.627, 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.
    (b) The MMS will prepare an appropriate NEPA analysis.

[[Page 477]]

    (c) The MMS will forward one copy of your COP, consistency 
certification, and associated data and information under the CZMA to the 
State's CZM agency after all information requirements for the COP are 
met.
    (d) As appropriate, MMS 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, MMS may disapprove your COP.
    (f) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), MMS 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. 285.633(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 MMS approves your project easement, MMS 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.



Sec. 285.629  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. 285.630  [Reserved]

                    Activities Under an Approved COP



Sec. 285.631  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. 
285.626(b)(21), and included as a part of your approved COP, unless MMS 
approves a deviation from your schedule.



Sec. 285.632  What documents must I submit before I may construct and 

install facilities under my approved COP?

    (a) You must submit to MMS the documents listed in the following 
table: 
[GRAPHIC] [TIFF OMITTED] TR29AP09.124

    (b) You must submit your Safety Management System, as required by 
Sec. 285.810 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. 285.634, for 
MMS approval before commencing the activity.

[[Page 478]]



Sec. 285.633  How do I comply with my COP?

    (a) Based on MMS's environmental and technical reviews, we will 
specify terms and conditions to be incorporated into your COP.
    (b) You must submit a certification of compliance annually (or other 
frequency as determined by MMS) with certain terms and conditions of 
your COP that MMS 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. 285.105(i), MMS may require you to submit 
any supporting data and information.



Sec. 285.634  What activities require a revision to my COP, and when will 

MMS approve the revision?

    (a) You must notify MMS 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) The MMS 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 MMS.
    (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. 285.635  What must I do if I cease activities approved in my COP before the end of my commercial lease?

    You must notify the MMS, 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

[[Page 479]]

Sec. 285.437, and you must initiate the decommissioning process, as set 
forth in subpart I of this part.



Sec. 285.636  What notices must I provide MMS following approval of my COP?

    You must notify MMS 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. 285.637  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 MMS the final Fabrication and Installation Report for 
the fabrication and installation review, as provided in Sec. 285.708.
    (b) Require a FERC license or exemption, then you may commence 
commercial operations when permitted by the terms of your license or 
exemption.



Sec. 285.638  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. 285.905 and 285.906.
    (b) Upon completion of your approved activities under your FERC 
license, the terms of your FERC license will govern your decommissioning 
activities.



Sec. 285.639  [Reserved]

General Activities Plan Requirements for Limited Leases, ROW Grants, and 
                               RUE Grants



Sec. 285.640  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 MMS approval of your GAP before you can begin 
any of the approved activities on your lease or grant. For a ROW grant 
or RUE grant issued competitively, you must submit your GAP within 6 
months of issuance.



Sec. 285.641  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. 285.642  How do I submit my GAP?

    (a) You must submit one paper copy and one electronic version of 
your GAP to MMS at the address listed in Sec. 285.110(a).

[[Page 480]]

    (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. 285.643-285.644  [Reserved]

                 Contents of the General Activities Plan



Sec. 285.645  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:

[[Page 481]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.125

    (b) For all activities you propose to conduct under your GAP, you 
must provide the following information:

[[Page 482]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.126

    (c) If you are applying for a project easement or constructing a 
facility, or a combination of facilities deemed by MMS 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:

[[Page 483]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.127

    (d) The MMS will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure in 
accordance with the terms of Sec. 285.113.



Sec. 285.646  What information and certifications must I submit

with my GAP to assist MMS in complying with NEPA and other relevant laws?

    You must submit with your GAP detailed information to assist MMS in 
complying with NEPA and other relevant laws. Your GAP 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, including:

[[Page 484]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.128



Sec. 285.647  How will my GAP be processed for Federal consistency under the Coastal Zone Management Act?

    Your GAP will be processed based on how your limited lease, ROW 
grant, or RUE grant was issued: 
[GRAPHIC] [TIFF OMITTED] TR29AP09.129


[[Page 485]]





Sec. 285.648  How will MMS process my GAP?

    (a) The MMS will review your submitted GAP, along with the 
information and certifications provided pursuant to Sec. 285.646, 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) The MMS 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, MMS may disapprove your GAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), MMS 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. 285.653(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. 285.649  [Reserved]

                    Activities Under an Approved GAP



Sec. 285.650  When may I begin conducting activities under my GAP?

    After MMS 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 MMS has deemed to be complex or significant.



Sec. 285.651  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 MMS to be 
complex or significant, as provided in Sec. 285.648(a)(1), you also 
must comply with the requirements of subpart G of this part and submit 
your Safety Management System required by Sec. 285.810 before 
construction may begin.



Sec. 285.652  How long do I have to conduct activities under an approved GAP?

    After MMS 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. 285.425 through 
285.429.
    (b) For a ROW grant or RUE grant, the time provided in the terms of 
the grant.



Sec. 285.653  What other reports or notices must I submit to MMS under my approved GAP?

    (a) You must notify MMS in writing within 30 days after completing 
installation activities approved in your GAP.
    (b) You must prepare and submit to MMS 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. 285.113.
    (c) You must annually (or other frequency as determined by MMS) 
submit a certification of compliance with those terms and conditions of 
your GAP that MMS identifies under

[[Page 486]]

Sec. 285.648(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. 285.654  [Reserved]



Sec. 285.655  What activities require a revision to my GAP, and when will MMS approve the revision?

    (a) You must notify MMS 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) The MMS 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 MMS.
    (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. 285.656  What must I do if I cease activities approved in my GAP before the end of my term?

    You must notify the MMS 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, MMS may cancel your lease or 
grant under Sec. 285.437, as applicable, and you must initiate the 
decommissioning process, as set forth in subpart I of this part.



Sec. 285.657  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 487]]

You must submit your decommissioning application as provided in 
Sec. Sec. 285.905 and 285.906.

                      Cable and Pipeline Deviations



Sec. 285.658  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 MMS 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, MMS 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 MMS with evidence of 
such notification;
    (2) Relinquish any unused portion of your lease or grant; and
    (3) Submit a revised plan for MMS 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. 285.659  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. 
[GRAPHIC] [TIFF OMITTED] TR29AP09.130

    (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 MMS 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. 285.700  What reports must I submit to MMS before installing 

facilities described in my approved SAP, COP, or GAP?

    (a) You must submit the following reports to MMS before installing 
facilities described in your approved COP (Sec. 285.632(a)) and, when 
required by this part, your SAP (Sec. 285.614(b)) or GAP (Sec. 
285.651):
    (1) A Facility Design Report; and
    (2) A Fabrication and Installation Report.
    (b) You may begin to fabricate and install the approved facilities 
after MMS notifies you that it has received your reports and has no 
objections. If

[[Page 488]]

MMS receives the reports, but does 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, MMS is deemed not to have 
objections to the reports, and you may commence fabrication and 
installation of your facility or facilities.
    (c) If MMS has any objections, we will notify you verbally or in 
writing within 60 days of receipt of the report. Following initial 
notification of objections, MMS 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 
MMS's satisfaction.



Sec. 285.701  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. 285.105(a). You must include the following items in your 
Facility Design Report:

[[Page 489]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.132


[[Page 490]]


[GRAPHIC] [TIFF OMITTED] TR29AP09.133

    (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. 
285.714(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 MMS 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) The MMS 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. 
285.113.



Sec. 285.702  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. 285.105(a). You must 
include the following items in your Fabrication and Installation Report:

[[Page 491]]

[GRAPHIC] [TIFF OMITTED] TR29AP09.134

    (b) You must provide the location of records, as required in Sec. 
285.714(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 MMS 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) The MMS 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. 
285.113.



Sec. 285.703  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. 285.714(c).
    (c) The MMS may require you to use a CVA for project modifications 
and repairs.

[[Page 492]]



Sec. 285.704  [Reserved]

                      Certified Verification Agent



Sec. 285.705  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 MMS immediate reports of all incidents that affect the 
design, fabrication, and installation of the project and its components.
    (b) The MMS may waive the requirement that you use a CVA if you can 
demonstrate the following: 
[GRAPHIC] [TIFF OMITTED] TR29AP09.135

    (c) You must submit a request to waive the requirement to use a CVA 
to MMS in writing, along with your SAP under Sec. 285.610(a)(9), COP 
under Sec. 285.626(b)(20), or GAP under Sec. 285.645(c)(5).
    (1) The MMS 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 MMS does not waive the requirement for a CVA, you may file an 
appeal under Sec. 285.118.
    (3) If MMS 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. 285.706  How do I nominate a CVA for MMS approval?

    (a) As part of your COP (as provided in Sec. 285.626(b)(20) and, 
when required by this part, your SAP (Sec. 285.610(a)(9)) or GAP (Sec. 
285.645(c)(5)), you must nominate a CVA for MMS 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 MMS 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;

[[Page 493]]

    (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 MMS 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) The MMS 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 MMS 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. 285.707  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 MMS that the facility 
is designed to withstand the environmental 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. 285.708  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. 285.709;
    (4) Make periodic onsite inspections while installation is in 
progress and satisfy the requirements of Sec. 295.710; 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. 
285.714(c); and
    (ii) You may commence commercial operations or other approved 
activities 30 days after MMS receives that certification report, unless 
MMS 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

[[Page 494]]

CVA or project engineer must inform you; and
    (2) If you accept the modifications, then you must also inform MMS.



Sec. 285.709  When conducting onsite fabrication inspections, what must 

the CVA or project engineer verify?

    (a) To comply with Sec. 285.708(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
    (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. 285.710  When conducting onsite installation inspections, what must 

the CVA or project engineer do?

    To comply with Sec. 285.708(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,

[[Page 495]]

and recordkeeping as necessary to determine compliance with the 
applicable documents incorporated by reference and the regulations under 
this part.



Sec. 285.711  [Reserved]



Sec. 285.712  What are the CVA's or project engineer's reporting requirements?

    (a) The CVA or project engineer must prepare and submit to you and 
MMS all reports required by this subpart. The CVA or project engineer 
must also submit interim reports to you and MMS, as requested by the 
MMS.
    (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 MMS. 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. 285.713  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 MMS within 10 business days after commencing commercial 
operations.



Sec. 285.714  What records relating to SAPs, COPs, and GAPs must I keep?

    (a) Until MMS releases your financial assurance under Sec. 285.534, 
you must compile, retain, and make available to MMS representatives, 
within the time specified by MMS, 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. 285.820 through 285.825; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec. 285.824(b)(3).
    (b) You must record and retain the original material test results of 
all primary structural materials during all stages of construction until 
MMS releases your financial assurance under Sec. 285.534. 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 MMS with the location of these records in the 
certification statement, as required in Sec. Sec. 285.701(c), 
285.703(b), and 285.708(a)(5)(i).



Subpart H_Environmental and Safety Management, Inspections, and Facility 
     Assessments for Activities Conducted Under SAPs, COPs and GAPs



Sec. 285.800  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. 
285.105(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. Sec. 285.615(c), 285.633(b), or 285.653(c).



Sec. 285.801  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

[[Page 496]]

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 MMS 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 MMS 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.
    (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 unmitigable 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 MMS 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. 285.802  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 MMS 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

[[Page 497]]

    (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. 285.803  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, MMS finds 
that essential fish habitat or habitat areas of particular concern may 
be adversely affected by your activities, MMS must consult with National 
Marine Fisheries Service.
    (b) Any conservation recommendations adopted by MMS 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. The MMS may require additional surveys to define boundaries 
and avoidance distances.
    (c) If required, MMS will specify the survey methods and 
instrumentations for conducting the biological survey and will specify 
the contents of the biological report.



Sec. Sec. 285.804-285.809  [Reserved]

                        Safety Management Systems



Sec. 285.810  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. 285.627(d)) and, when 
required by this part, your SAP (as provided in Sec. 285.614(b)) or GAP 
(as provided in Sec. 285.651). 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. 285.811  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. 285.810.



Sec. 285.812  [Reserved]

                        Maintenance and Shutdowns



Sec. 285.813  When do I have to report removing equipment from service?

    (a) The removal of any equipment from service may result in MMS 
applying remedies, as provided in this part, when such equipment is 
necessary for implementing your approved plan. Such remedies may include 
an order from MMS 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. 
285.105(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 MMS when you return the equipment to service.

[[Page 498]]



Sec. 285.814  [Reserved]

           Equipment Failure and Adverse Environmental Effects



Sec. 285.815  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 MMS, as required in 
Sec. 285.711.
    (b) If you are required to report any facility damage or failure 
under Sec. 285.831, MMS 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. 285.634 (COP), Sec. 285.617 (SAP), Sec. 285.655 
(GAP). You must submit a report of the repairs to MMS, as required in 
Sec. 285.703.
    (c) The MMS may require that you analyze cable, pipeline, or 
facility damage or failure to determine the cause. If requested by MMS, 
you must submit a comprehensive written report of the failure or damage 
to MMS as soon as available.



Sec. 285.816  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 MMS 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 MMS a report of the remedial action taken within 
30 days after completion.



Sec. Sec. 285.817-285.819  [Reserved]

                       Inspections and Assessments



Sec. 285.820  Will MMS conduct inspections?

    The MMS 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. 285.810.



Sec. 285.821  Will MMS conduct scheduled and unscheduled inspections?

    The MMS will conduct both scheduled and unscheduled inspections.



Sec. 285.822  What must I do when MMS conducts an inspection?

    (a) When MMS 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 MMS 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 MMS releases your financial assurance under Sec. 285.534 
and provide them to MMS upon request, within the time period specified 
by MMS.
    (c) You must demonstrate to the inspector how you are in compliance 
with your Safety Management System.



Sec. 285.823  Will MMS reimburse me for my expenses related to inspections?

    Upon request, MMS 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.

[[Page 499]]



Sec. 285.824  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 MMS 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. 285.825  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 
(incorporated by reference, as specified in Sec. 285.115).
    (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 MMS.



Sec. Sec. 285.826-285.829  [Reserved]

                  Incident Reporting and Investigation



Sec. 285.830  What are my incident reporting requirements?

    (a) You must report all incidents listed in Sec. 285.831 to MMS, 
according to the reporting requirements for these incidents in 
Sec. Sec. 285.832 and 285.833.
    (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. 285.831  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);

[[Page 500]]

    (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. 285.832  How do I report incidents requiring immediate notification?

    For an incident requiring immediate notification under Sec. 
285.831(a), you must notify MMS 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. 285.833  What are the reporting requirements for incidents requiring written notification?

    (a) For any incident covered under Sec. 285.831, you must submit a 
written report within 15 days after the incident to MMS. The report must 
contain the following information:
    (1) Date and time of occurrence;
    (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) The MMS may require you to submit additional information about 
an incident on a case-by-case basis.



                        Subpart I_Decommissioning

              Decommissioning Obligations and Requirements



Sec. 285.900  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. 285.901  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 
an MMS-approved assignment a facility, cable, or pipeline, or you create 
an obstruction to other uses of the OCS.

[[Page 501]]



Sec. 285.902  What are the general requirements for decommissioning for 

facilities authorized under my SAP, COP, or GAP?

    (a) Except as otherwise authorized by MMS under Sec. 285.909, 
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 MMS.
    (b) Before decommissioning the facilities under your SAP, COP, or 
GAP, you must submit a decommissioning application and receive approval 
from the MMS.
    (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. 285.908 to MMS 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 MMS with documentation of any coordination efforts you 
have made with the affected States, local, and tribal governments.



Sec. 285.903  What are the requirements for decommissioning FERC-licensed hydrokinetic facilities?

    You must comply with the decommissioning requirements in your MMS-
issued lease. If you fail to comply with the decommissioning 
requirements of your lease then:
    (a) The MMS 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) The MMS may take enforcement action under Sec. 285.400 of this 
part.



Sec. 285.904  Can I request a departure from the decommissioning requirements?

    You may request a departure from the decommissioning requirements 
under Sec. 285.103.

                      Decommissioning Applications



Sec. 285.905  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. 285.906  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.

[[Page 502]]

    (b) Identification and description of the facilities, cables, or 
pipelines you plan to remove or propose to leave in place, as provided 
in Sec. 285.909.
    (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 
MMS 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. 285.907  How will MMS process my decommissioning application?

    (a) Based upon your inclusion of all the information required by 
Sec. 285.906, MMS 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 MMS 
will begin the appropriate NEPA analysis and other regulatory reviews as 
required, if MMS 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 MMS disapproves your decommissioning application, you must 
resubmit your application to address the concerns identified by MMS.



Sec. 285.908  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. 285.905 through 
285.907. 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 MMS 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

[[Page 503]]

    (3) Propose activities not previously identified and evaluated.

                            Facility Removal



Sec. 285.909  When may MMS 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) The MMS 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 MMS 
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 MMS 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. The MMS will evaluate all 
such requests, as provided in Sec. 250.1730 of this subchapter.



Sec. 285.910  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 MMS.
    (b) Within 60 days after you remove a facility, you must verify to 
MMS that you have cleared the site.



Sec. 285.911  [Reserved]

                         Decommissioning Report



Sec. 285.912  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 MMS 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. 285.913  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) The MMS 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) The MMS may take enforcement action under Sec. 285.400.



  Subpart J_Rights of Use and Easement for Energy- and Marine-Related 
                Activities Using Existing OCS Facilities

                          Regulated Activities



Sec. 285.1000  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

[[Page 504]]

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) The MMS 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. 285.1001--285.1003  [Reserved]

                     Requesting an Alternate Use RUE



Sec. 285.1004  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. 285.1005  How do I request an Alternate Use RUE?

    To request an Alternate Use RUE, you must submit to MMS 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;
    (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. 285.106, as 
required by Sec. 285.107.
    (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. 285.1006  How will MMS 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) MMS can effectively regulate.

[[Page 505]]

    (b) Based on the evaluation that we perform under paragraph (a) of 
this section, the MMS may authorize or reject, or authorize with 
modifications or stipulations, the proposed activity.



Sec. 285.1007  What process will MMS use for competitively offering an Alternate Use RUE?

    (a) An Alternate Use RUE must be issued on a competitive basis 
unless MMS 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. The MMS 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. 
285.106 and 285.107, 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 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. 285.1008--285.1009  [Reserved]

                    Alternate Use RUE Administration



Sec. 285.1010  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, MMS will consider the size and scale 
of the proposed alternate use activities, the type of alternate use 
activities, and any other relevant considerations.
    (c) The MMS may authorize renewal of Alternate Use RUEs at its 
discretion.



Sec. 285.1011  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. 285.1012  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 MMS 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 MMS.
    (b) We may revise financial assurance amounts, as necessary, to 
ensure that there is sufficient financial assurance

[[Page 506]]

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. 285.1013  Is an Alternate Use RUE assignable?

    (a) The MMS 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) The MMS-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. 285.107 that the assignee satisfies 
the requirements of Sec. 285.106; 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 MMS does not relieve the assignor of liability 
for accrued obligations that the assignee, or a subsequent assignee, 
fail 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.



Sec. 285.1014  When will MMS suspend an Alternate Use RUE?

    (a) The MMS 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. 285.1015  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) The MMS-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 MMS 
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

[[Page 507]]

all outstanding rentals (or other payments) and fines.
    (c) The relinquishment takes effect on the date we approve your 
request.



Sec. 285.1016  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 MMS, 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. 285.1017  [Reserved]

                  Decommissioning an Alternate Use RUE



Sec. 285.1018  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 part 250 of 
this chapter 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 other parts of this subchapter.



Sec. 285.1019  What are the decommissioning requirements for an Alternate Use RUE?

    (a) Decommissioning requirements will be determined by MMS 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 508]]



                          SUBCHAPTER C_APPEALS


PART 290_APPEAL PROCEDURES--Table of Contents



        Subpart A_Offshore Minerals Management 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. 301 et seq.; 43 U.S.C. 1331

    Source: 64 FR 26257, May 13, 1999, unless otherwise noted.



        Subpart A_Offshore Minerals Management 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 Minerals Management Service (MMS) Offshore Minerals Management (OMM) 
decisions and orders issued under subchapter B.



Sec. 290.2  Who may appeal?

    If you are adversely affected by an OMM official's final decision or 
order issued under 30 CFR chapter II, subchapter B, 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 an MMS decision 
concerning a lease bid, authorized in 30 CFR 256.47(e)(3), 281.21(a)(1), 
or 285.118(c), is not subject to the procedures found in this part.

[64 FR 26257, May 13, 1999, as amended at 74 FR 19871, Apr. 29, 2009]



Sec. 290.3  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. 290.4  How do I file an appeal?

    For your appeal to be filed, MMS 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 OMM 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 Pay.gov at: https://
www.pay.gov/paygov/, 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.

[64 FR 26257, May 13, 1999, as amended at 73 FR 49948, Aug. 25, 2008]



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.

[[Page 509]]



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) 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 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 
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. 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 MMS'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 MMS Hotline to informally resolve an allegation 
          that open and nondiscriminatory access was denied?
291.103 May I use alternative dispute resolution to informally resolve 
          an allegation that open 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 MMS require to produce information?
291.111 How does MMS treat the confidential information that I provide?
291.112 What process will MMS follow in rendering a decision on whether 
          a grantee or transporter has provided open and 
          nondiscriminatory access?
291.113 What actions may MMS 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: 73 FR 34640, June 18, 2008, unless otherwise noted.



Sec. 291.1  What is MMS'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 1010-0172.
    (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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[73 FR 34640, June 18, 2008, as amended at 74 FR 46910, Sept. 14, 2009]

[[Page 510]]



Sec. 291.100  What is the purpose of this part?

    This part:
    (a) Explains the procedures for filing a complaint with the 
Director, Minerals Management Service (MMS) alleging that a grantee or 
transporter has denied a shipper of production from the OCS open and 
nondiscriminatory access to a pipeline;
    (b) Explains the procedures MMS 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 MMS 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 MMS 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 MMS.
    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 MMS 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 MMS Hotline at 1-888-232-1713.
    (a) MMS Hotline staff will informally seek information needed to 
resolve the

[[Page 511]]

dispute. MMS 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 MMS or FERC in docketed 
proceedings.
    (b) MMS Hotline staff may provide information to you and give 
informal oral advice. The advice given is not binding on MMS, the 
Department of the Interior (DOI), or any other person.
    (c) To the extent permitted by law, the MMS Hotline staff will treat 
all information it obtains as non-public and confidential.
    (d) You may call the MMS Hotline anonymously.
    (e) If you contact the MMS Hotline, you may file a complaint under 
this part if discussions assisted by MMS Hotline staff are unsuccessful 
at resolving the matter.
    (f) You may terminate use of the MMS Hotline procedure at any time.



Sec. 291.103  May I use alternative dispute resolution 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 MMS at 1-888-232-1713 or write to us at the 
following address: Associate Director, Policy and Management 
Improvement, Minerals Management Service, 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) MMS 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, MMS is not a party in an ADR proceeding.

[73 FR 34640, June 18, 2008, as amended at 74 FR 46910, Sept. 14, 2009]



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 MMS. The brief must be served following the procedure 
set out in 30 CFR 291.107. After considering the brief, it is within 
MMS's discretion as to whether MMS 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, Minerals Management 
Service

[[Page 512]]

at the following address: Director, Minerals Management Service, 
Attention: Policy and Management Improvement, 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 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 two (2) years from the 
time of the alleged access denial. If the complaint is filed later than 
two (2) years from the time of the alleged access denial, the MMS 
Director will not consider the complaint and the case will be closed.

[73 FR 34640, June 18, 2008, as amended at 74 FR 46910, Sept. 14, 2009]



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, MMS may disregard your answer. We consider your 
answer to be filed when the MMS Director receives it at the following 
address: Director, Minerals Management Service, Attention: Policy and 
Management Improvement, 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 MMS docket number (you may obtain the docket number by calling 
the Policy and Management Improvement Office at (202) 208-2622);
    (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.

[73 FR 34640, June 18, 2008, as amended at 74 FR 46910, Sept. 14, 2009]



Sec. 291.108  How do I pay the processing fee?

    (a) You must pay the processing fee electronically through Pay.Gov. 
The Pay.Gov Web site may be accessed through links on the MMS Offshore 
Web site at: http://www.mms.gov/offshore/homepage (on drop-down topic 
list) or directly through Pay.Gov at: https://www.pay.gov/paygov/.
    (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.



Sec. 291.109  Can I ask for a fee waiver or a reduced processing fee?

    (a) MMS 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 MMS Policy and Management 
Improvement Office 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 MMS Policy and Management Improvement Office 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.

[[Page 513]]

    (2) If we deny your request, you must pay the entire processing fee 
within 30 days of the date you receive the decision.
    (3) MMS's decision granting or denying a fee waiver or reduction is 
final for the Department.



Sec. 291.110  Who may MMS require to produce information?

    (a) MMS may require any lessee, operator of a lease or unit, 
shipper, grantee, or transporter to provide information that MMS 
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 MMS requires 
under paragraph (a) of this section, MMS 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 MMS requires under paragraph (a) of this section, MMS may 
assess civil penalties under 30 CFR part 250, subpart N.



Sec. 291.111  How does MMS treat the confidential information I provide?

    (a) Any person who provides documents under this part in response to 
a request by MMS 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 MMS 
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 MMS 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, MMS 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, MMS 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) MMS retains the right to make the determination with regard to 
any claim of confidentiality. MMS 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 MMS follow in rendering a decision on whether 

a grantee or transporter has provided open and nondiscriminatory access?

    MMS will begin processing a complaint upon receipt of a processing 
fee or granting a waiver of the fee. The MMS 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 MMS take to remedy denial of open and nondiscriminatory access?

    If the MMS 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 
MMS will take to require the grantee or transporter to remedy the denial 
of open access or nondiscriminatory access. The remedies MMS would 
require

[[Page 514]]

must be consistent with MMS's statutory authority, regulations, and any 
limits thereon due to Congressional delegations to other agencies. 
Actions MMS may take include, but are not limited to:
    (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 an MMS 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 MMS 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 MMS 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 MMS 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 MMS 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 MMS Director; or
    (2) The Assistant Secretary for Land and Minerals Management.

[[Page 515]]



        CHAPTER IV--GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------
Part                                                                Page
401             State Water Research Institute Program......         517
402             Water-Resources Research Program and the 
                    Water-Resources Technology Development 
                    Program.................................         522


PART 401_STATE WATER RESEARCH INSTITUTE PROGRAM--Table of Contents



[[Page 517]]

                            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 the 
grant programs. Response is mandatory in accordance with 30 CFR 401.11 
and 401.19.

[[Page 518]]

    (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;
    (4) Conservation and best use of available supplies of water and 
methods of increasing such supplies;
    (5) Water reuse;

[[Page 519]]

    (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 the times at which there 
will be need for specified amounts of Federal funds; and

[[Page 520]]

    (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 521]]

    (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 522]]

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 523]]

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 524]]

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 525]]

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.

[[Page 527]]



                              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 529]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2011)

                      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--500)

                    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 100--
                199)
        II  Office of Management and Budget Circulars and Guidance 
                (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)
        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 
                1880--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  Housing and Urban Development (Parts 2400--2499)
       XXV  National Science Foundation (Parts 2500--2599)
      XXVI  National Archives and Records Administration (Parts 
                2600--2699)
     XXVII  Small Business Administration (Parts 2700--2799)
    XXVIII  Department of Justice (Parts 2800--2899)

[[Page 530]]

       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)
      XXXV  Export-Import Bank of the United States (Parts 3500--
                3599)
    XXXVII  Peace Corps (Parts 3700--3799)
     LVIII  Election Assistance Commission (Parts 5800--5899)

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--99)
        II  Recovery Accountability and Transparency Board (Parts 
                200--299)

                   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)
         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)
        XV  Office of Administration, Executive Office of the 
                President (Parts 2500--2599)
       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)
    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)

[[Page 531]]

     XXXIV  Securities and Exchange Commission (Parts 4400--4499)
      XXXV  Office of Personnel Management (Parts 4500--4599)
        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)
     LXXII  Special Inspector General for Iraq Reconstruction 
                (Parts 8200--8299)
    LXXIII  Department of Agriculture (Parts 8300--8399)
     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 8700--8799)
    LXXXII  Special Inspector General for Iraq Reconstruction 
                (Parts 9200--9299)

[[Page 532]]

     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Parts 
                9700--9799)
      XCIX  Department of Defense Human Resources Management and 
                Labor Relations Systems (Department of Defense--
                Office of Personnel Management) (Parts 9900--9999)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 0--99)

                         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)
        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)

[[Page 533]]

     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)
      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)
         L  Rural Business-Cooperative Service, Rurual Housing 
                Service, and Rural Utilities Service, Department 
                of Agriculture (Parts 5000--5099)

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Immigration and 
                Naturalization) (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)

[[Page 534]]

       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 1303--
                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  Office of Thrift Supervision, Department of the 
                Treasury (Parts 500--599)
        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)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XII  Federal Housing Finance Agency (Parts 1200--1299)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
      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)

[[Page 535]]

        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--499)
         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  Technology Administration, Department of Commerce 
                (Parts 1100--1199)
      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)

[[Page 536]]

                    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)

                     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)
        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)

[[Page 537]]

                       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  Millenium 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)
        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)

[[Page 538]]

        II  Office of Assistant Secretary for Housing-Federal 
                HousingCommissioner, 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)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799)
       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)
        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)
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

                           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--799)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900)

[[Page 539]]

        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--899)

           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)
        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)

[[Page 540]]

      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 Ocean Energy Management, Regulation, and 
                Enforcement, Department of the Interior (Parts 
                200--299)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
       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)
      VIII  Office of International Investment, 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, Departmnent 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)

[[Page 541]]

       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 (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)
        IV  Office of Vocational and Adult Education, Department 
                of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599)
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
       VII  Office of Educational Research and Improvmeent, 
                Department of Education [Reserved]
        XI  National Institute for Literacy (Parts 1100--1199)
            Subtitle C--Regulations Relating to Education
       XII  National Council on Disability (Parts 1200--1299)

[[Page 542]]

                          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  Copyright Office, Library of Congress (Parts 200--299)
       III  Copyright Royalty Board, Library of Congress (Parts 
                301--399)
        IV  Assistant Secretary for Technology Policy, Department 
                of Commerce (Parts 400--499)
         V  Under Secretary for Technology, Department of Commerce 
                (Parts 500--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--99)
        II  Armed Forces Retirement Home

                       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)

[[Page 543]]

        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)

          Title 41--Public Contracts and Property Management

            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)
       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)
        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--499)

[[Page 544]]

         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1999)

                   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 200--499)
        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)
         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) 
                [Reserved]
         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  Office of Human Development Services, Department of 
                Health and Human Services (Parts 1300--1399)

[[Page 545]]

       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 on Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Part 2301)
      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)

           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  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)

[[Page 546]]

        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 [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)
        63  Department of Transportation Board of Contract Appeals 
                (Parts 6300--6399)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

                       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)

[[Page 547]]

         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, Department of 
                Transportation (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation [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)

                      CFR Index and Finding Aids

            Subject/Agency Index
            List of Agency Prepared Indexes
            Parallel Tables of Statutory Authorities and Rules
            List of CFR Titles, Chapters, Subchapters, and Parts
            Alphabetical List of Agencies Appearing in the CFR

[[Page 549]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2011)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Administrative Conference of the United States    1, III
Advanced Research Projects Agency                 32, I
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture Department                            2, IV; 5, LXXIII
  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, L
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII, XXXV, L
  Rural Telephone Bank                            7, XVI
  Rural Utilities Service                         7, XVII, XVIII, XLII, L
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force Department                              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
Appalachian Regional Commission                   5, IX

[[Page 550]]

Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI
Army Department                                   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
Bureau of Ocean Energy Management, Regulation,    30, II
     and Enforcement
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X
Civil Rights, Commission on                       5, LXVIII; 45, VII
Civil Rights, Office for                          34, I
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                               44, IV; 50, VI
  Census Bureau                                   15, I
  Economic Affairs, Under Secretary               37, V
  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
  National Marine Fisheries Service               50, II, IV
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III, IV
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office, United States      37, I
  Productivity, Technology and Innovation,        37, IV
       Assistant Secretary for
  Secretary of Commerce, Office of                15, Subtitle A
  Technology, Under Secretary for                 37, V
  Technology Administration                       15, XI
  Technology Policy, Assistant Secretary for      37, IV
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 Product Safety Commission                5, LXXI; 16, II
Copyright Office                                  37, 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    28, VIII
     for the District of Columbia
Customs and Border Protection Bureau              19, I
Defense Contract Audit Agency                     32, I
Defense Department                                5, XXVI; 32, Subtitle A; 
                                                  40, VII

[[Page 551]]

  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  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
  Human Resources Management and Labor Relations  5, XCIX
       Systems
  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
District of Columbia, Court Services and          28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Affairs, Under Secretary                 37, V
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office 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
  Vocational and Adult Education, Office of       34, IV
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 Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             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
  Administration, Office of                       5, XV
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                5, III, LXXVII; 14, VI; 
                                                  48, 99

[[Page 552]]

  National Drug Control Policy, Office of         21, III
  National Security Council                       32, XXI; 47, 2
  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                       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
Fine Arts, Commission on                          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 553]]

  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
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
  Community Services, Office of                   45, X
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Human Development Services, Office of           45, XIII
  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; 6, I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection Bureau            19, I
  Federal Emergency Management Agency             44, I
  Human Resources Management and Labor Relations  5, XCVII
       Systems
  Immigration and Customs Enforcement Bureau      19, IV
  Immigration and Naturalization                  8, I
  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
Human Development Services, Office of             45, XIII
Immigration and Customs Enforcement Bureau        19, IV
Immigration and Naturalization                    8, I
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
Indian Affairs, Bureau of                         25, I, V

[[Page 554]]

Indian Affairs, Office of the Assistant           25, VI
     Secretary
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
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Interior Department
  American Indians, Office of the Special         25, VII
       Trustee
  MBureau of Ocean Energy Management,             30, II
       Regulation, and Enforcement
  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
  Reclamation, Bureau of                          43, I
  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                                2, XXVII; 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
  Offices of Independent Counsel                  28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department                                  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

[[Page 555]]

  Federal Contract Compliance Programs, Office    41, 60
       of
  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
  Office of Workers' Compensation Programs        20, VII
  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
Labor-Management Standards, Office of             29, II, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Library of Congress                               36, VII
  Copyright Office                                37, II
  Copyright Royalty Board                         37, III
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
Millenium 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   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
National Commission for Employment Policy         1, IV
National Commission on Libraries and Information  45, XVII
     Science
National Council on Disability                    34, XII
National Counterintelligence Center               32, XVIII
National Credit Union Administration              12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           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 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 for Literacy                   34, XI
National Institute of Food and Agriculture.       7, XXXIV
National Institute of Standards and Technology    15, II
National Intelligence, Office of Director of      32, XVII
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV
National Mediation Board                          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

[[Page 556]]

  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI
National Security Council and Office of Science   47, II
     and Technology Policy
National Telecommunications and Information       15, XXIII; 47, III, IV
     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                                   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
Offices of Independent Counsel                    28, VI
Office of Workers' Compensation Programs          20, VII
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                                       22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 45, VIII
  Human Resources Management and Labor Relations  5, XCIX
       Systems, Department of Defense
  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
Procurement and Property Management, Office of    7, XXXII
Productivity, Technology and Innovation,          37, IV
     Assistant Secretary
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
Recovery Accountability and Transparency Board    4, II
Refugee Resettlement, Office of                   45, IV
Relocation Allowances                             41, 302
Research and Innovative Technology                49, XI
     Administration
Rural Business-Cooperative Service                7, XVIII, XLII, L
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII, XXXV, L
Rural Telephone Bank                              7, XVI
Rural Utilities Service                           7, XVII, XVIII, XLII, L
Saint Lawrence Seaway Development Corporation     33, IV
Science and Technology Policy, Office of          32, XXIV

[[Page 557]]

Science and Technology Policy, Office of, and     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                5, XXXIV; 17, II
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
Special Inspector General for Iraq                5, LXXXVII
     Reconstruction
State Department                                  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
Technology Administration                         15, XI
Technology Policy, Assistant Secretary for        37, IV
Technology, Under Secretary for                   37, V
Tennessee Valley Authority                        5, LXIX; 18, XIII
Thrift Supervision Office, Department of the      12, V
     Treasury
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     2, XII; 5, L
  Commercial Space Transportation                 14, III
  Contract Appeals, Board of                      48, 63
  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
  Surface Transportation Board                    49, X
  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                               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 Bureau            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
  Thrift Supervision, Office of                   12, V
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
[[Page 558]]

Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs Department                       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
Vocational and Adult Education, Office of         34, IV
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I
World Agricultural Outlook Board                  7, XXXVIII

[[Page 559]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations that were 
made by documents published in the Federal Register since January 1, 
2001, 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 and parts as well as 
sections for revisions.
For the period before January 1, 2001, see the ``List of Sections 
Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000,'' published in 
11 separate volumes.

                                  2001

30 CFR
                                                                   66 FR
                                                                    Page
Chapter II
206.251 Amended....................................................45769
206.254 (a) removed; (b) designation removed and amended...........45769
206.257 (d)(3) amended.............................................45769
206.259 (a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) 
        amended....................................................45769
206.262 (a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) 
        amended....................................................45769
206.263 Removed....................................................45769
206.453 (a) removed; (b) designation removed and amended...........45769
206.456 (d)(3) amended.............................................45769
206.458 (c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended.....45769
206.461 (c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended.....45769
206.462 Removed....................................................45769
208.4 (b)(4) removed...............................................28657
210.10 Nomenclature change; (a) and (d) revised; (b)(2) and (3) 
        amended; (b)(6), (c)(4), (11) and (12) removed; (c)(5) 
        through (10) and (13) through through (20) redesignated as 
        new (c)(4) through (9) and (10) through (17); (b)(6), (7), 
        (8) and new (c)(18) through (21) added.....................45769
210.200--210.204 (Subpart E) Removed; new 210.200--210.206 
        (Subpart E) added..........................................45771
210.201 (c)(3)(i) corrected........................................50827
216.2 Amended......................................................45773
216.6 Amended......................................................45773
216.20 Amended.....................................................45773
216.40 (d) removed; (e), (f) and (g) redesignated as (d), (e) and 
        (f)........................................................45773
216.200--216.204 (Subpart E) removed...............................45773
218 Authority citation revised.....................................45773
218.40 (c) revised.................................................45773
218.51 (d)(2), (3) and (e) amended.................................45773
218.151 Heading, (a) and (b) revised; introductory text added; (c) 
        and (d) removed; (e) redesignated as new (c)...............11518
218.201 Revised....................................................45773
218.203 (a) and (b) amended........................................45773
    (b) corrected..................................................50827
256.14 Removed.....................................................32904
256.40 Introductory text revised...................................11518
256.52 (b)(1) revised; (d), (e), (g) introductory text, (1) and 
        (2) amended................................................60150
256.58 Revised.....................................................60150
260 Revised........................................................11518

                                  2002

30 CFR
                                                                   67 FR
                                                                    Page
Chapter II
201.100 Heading amended............................................19111
203.0 Amended.......................................................1872
203.2 Revised.......................................................1872
203.4 Revised.......................................................1873
203.60 Revised......................................................1875
203.62 Introductory text and (c) revised............................1875

[[Page 560]]

203.63 Introductory text, (a), (b) and (c) redesignated as (a), 
        (1), (2) and (3); new (b) added.............................1875
203.64 Heading revised; introductory text amended...................1875
203.65 (b) revised..................................................1875
203.66 Revised......................................................1875
203.67 Revised......................................................1876
203.68 (b) revised..................................................1876
203.69 Introductory text and (b) through (e) revised; (f) added.....1876
203.70 Revised......................................................1876
203.71 Introductory text, (a), (b) and (c) revised..................1877
203.74 (b) and (c) redesignated as (c) and (d); introductory text, 
        new (c) and (d) revised; new (b) added......................1878
203.76 (a), (b) and (c) revised.....................................1878
203.77 Revised......................................................1878
203.78 Introductory text, (a)(1), (b)(1) and (f) revised............1878
203.80 Added........................................................1879
203.81 (a) and (c) revised..........................................1879
203.83 (c) revised..................................................1879
203.86 (b)(6), (7), (d)(6) and (7) amended; (b)(8) and (d)(8) 
        added; (c)(4) revised.......................................1879
203.87 (a)(1) and (d) revised.......................................1880
203.89 (a) revised..................................................1880
203.91 Amended......................................................1880
206.52 (e)(2) amended..............................................19111
206.103 (b)(2)(iii) amended........................................19111
206.152 (e)(3) amended.............................................19111
206.153 (e)(3) amended.............................................19111
206.250 (c) amended................................................19111
206.352 (e)(3) amended.............................................19111
206.355 (e)(3) amended.............................................19111
206.356 (d)(3) amended.............................................19111
212 Authority citation revised.....................................19111
212.51 (a) amended.................................................19111
212.351 (a) and (c) amended........................................19111
216.6 Amended......................................................19111
216.15 (a) and (b) amended.........................................19111
216.16 (a) and (b) amended.........................................19111
216.21 Amended.....................................................19111
216.30 Amended.....................................................19112
217.200 Amended....................................................19112
218.51 (g)(1) and (h)(2) amended...................................19112
218.53 (b) amended.................................................19112
218.102 (b) amended................................................19112
218.150 (c) amended................................................19112
218.151 (c) amended................................................19112
218.155 (a) and (d)(3) amended.....................................19112
218.202 (b) amended................................................19112
218.302 (b) amended................................................19112
219.102 Amended....................................................19112
220.011 (c)(1) amended.............................................19112
227.103 Amended....................................................19112
227.110 (b) amended................................................19112
227.401 (f) amended................................................19112
227.501 (c) amended................................................19112
228.6 Amended......................................................19112
230 Removed........................................................19112
241 Authority citation revised.....................................19112
241.54 Amended.....................................................19112
241.56 (b) amended.................................................19113
241.62 Amended.....................................................19113
241.64 (b) amended.................................................19113
243 Heading revised................................................19113
243.3 Amended......................................................19113
250.102 (b) table amended; eff. 7-16-02............................35405
250.175 Existing text designated as (a); (b) added.................44360
250.198 (d) table and (e) table amended............................51759
250.199 (e) table amended; eff. 7-16-02............................35405
250.700--250.704 (Subpart G) Removed; eff. 7-16-02.................35405
250.802 (b) and (e)(2) revised.....................................51759
250.803 (a), (b)(4) introductory text, (5)(i), (7), (9)(v) and 
        (c)(2) introductory text revised; (b)(2)(i), (10) and (d) 
        amended....................................................51759
250.804 (a)(3) introductory text revised; (a)(4) through (11) 
        redesignated as (a)(5) through (12); new (a)(4) added; (a) 
        introductory text, new (a)(5) and (10) amended.............51760
250.913 Removed; eff. 7-16-02......................................35405
250.1001 Amended; eff. 7-16-02.....................................35405
250.1002 (d) amended...............................................51760
250.1004 (b)(9) amended............................................51760
250.1006 Revised; eff. 7-16-02.....................................35405
250.1007 (c) removed; eff. 7-16-02.................................35406
250.1014 Amended; eff. 7-16-02.....................................35406
250.1604 (c) and (d) amended.......................................51760
250.1628 (c) and (d)(2) revised....................................51760
250.1629 (b)(2) and (4)(v) revised.................................51760
250.1630 (a) introductory text and (2) introductory text revised; 
        (a)(3), (4) and (5) redesignated as (a)(4), (5) and (6); 
        new (a)(3) added...........................................51761
250.1700--250.1754 (Subpart Q) Added; eff. 7-16-02.................35406

[[Page 561]]

    250.1700 (c) corrected.........................................66047
250.1704 Table correctly added.....................................44265
    (f) correctly designated as (g); new (f) correctly added; 
table corrected; new (g) correctly revised.........................66047
250.1712 Introductory text corrected; (e) and (f)(14) correctly 
        revised....................................................66048
250.1715 Table correctly added.....................................44265
    (a)(1) through (4) correctly revised; (a)(10) correctly added 
                                                                   66048
250.1717 Introductory text correctly revised.......................66049
250.1721 Undesignated center heading, heading and introductory 
        text corrected; (a) and (g) introductory text amended......66049
250.1722 Introductory text, (c) and (g) introductory text 
        corrected; (a) and (d) introductory text amended...........66049
250.1723 Introductory text corrected; (b) amended..................66049
250.1726 Introductory text correctly revised.......................66049
250.1740 (a) correctly removed; (b) correctly redesignated as (a); 
        new (b) correctly added; (a) introductory text and (c) 
        introductory text correctly revised; (c)(3) corrected......66049
250.1741 (g) table correctly added.................................44266
    (b) correctly revised; (g) table corrected.....................66049
250.1742 Table correctly added.....................................44266
250.1743 (a) amended; (b) corrected................................66049
256.56 (a)(1) amended; eff. 7-16-02................................35412
256.62 (e)(2) amended; eff. 7-16-02................................35412
260.114 (d) revised................................................57739
260.124 (b)(1) revised.............................................57739
280 Revised........................................................46858
Chapter VI
Chapter VI Removed.................................................30803

                                  2003

30 CFR
                                                                   68 FR
                                                                    Page
Chapter II
250.102 (b)(1) revised..............................................8422
250.105 Amended.....................................................8422
250.108 Revised.....................................................7426
250.114 (c) revised................................................43298
250.160 (f) through (i) added......................................69311
250.198 (e) table corrected...........................................46
    (e) table amended...........................7427, 8422, 19355, 43298
250.199 (e) table amended...........................................8422
250.203 (b)(5)(i), (ii) and (p) amended.............................8422
250.204 (b)(2)(i), (ii) and (t) amended.............................8422
250.400 Revised.....................................................8423
250.401 Revised.....................................................8423
250.402 Revised.....................................................8423
250.403 Revised.....................................................8423
250.404 Revised.....................................................8423
250.405 Revised.....................................................8423
250.406 Revised.....................................................8423
250.407 Revised.....................................................8423
250.408 Revised.....................................................8423
250.409 Revised.....................................................8423
250.410 Revised.....................................................8423
250.411 Revised.....................................................8423
250.412 Revised.....................................................8423
250.413 Revised.....................................................8423
250.414 Revised.....................................................8423
250.415 Revised.....................................................8423
250.416 Revised.....................................................8423
250.417 Redesignated as 250.490; new 250.417 added..................8423
250.418 Added.......................................................8423
250.420 Added.......................................................8423
250.421 Added.......................................................8423
250.422 Added.......................................................8423
250.423 Added.......................................................8423
250.424 Added.......................................................8423
250.425 Added.......................................................8423
250.426 Added.......................................................8423
250.427 Added.......................................................8423
250.428 Added.......................................................8423
250.430 Added.......................................................8423
250.431 Added.......................................................8423
250.432 Added.......................................................8423
250.433 Added.......................................................8423
250.434 Added.......................................................8423
250.440 Added.......................................................8423
250.441 Added.......................................................8423
250.442 Added.......................................................8423
250.443 Added.......................................................8423
250.444 Added.......................................................8423
250.445 Added.......................................................8423
250.446 Added.......................................................8423
250.447 Added.......................................................8423
250.448 Added.......................................................8423
250.449 Added.......................................................8423

[[Page 562]]

250.450 Added.......................................................8423
250.451 Added.......................................................8423
250.455 Added.......................................................8423
250.456 Added.......................................................8423
    (i) corrected..................................................14274
250.457 Added.......................................................8423
250.458 Added.......................................................8423
250.459 Added.......................................................8423
250.460 Added.......................................................8423
250.461 Added.......................................................8423
250.462 Added.......................................................8423
250.463 Added.......................................................8423
250.465 Added.......................................................8423
250.466 Added.......................................................8423
250.467 Added.......................................................8423
250.468 Added.......................................................8423
250.469 Added.......................................................8423
250.490 Redesignated from 250.417; undesignated center heading 
        added.......................................................8423
    (g)(4)(iv), (j)(13)(ii) and (p)(2) revised......................8434
250.504 Amended.....................................................8434
250.513 (a) and (b)(4) amended......................................8434
250.515 (b) revised.................................................8434
250.604 Amended.....................................................8435
250.613 (b)(3) amended..............................................8435
250.615 (b) revised.................................................8435
250.803 (b)(9)(v) revised..........................................43298
    (b)(7) revised.................................................65172
250.804 (a)(5) and (6) corrected......................................46
250.807 Amended.....................................................8435
250.900 (g) revised................................................19355
250.912 (a) amended................................................19355
    (a) amended....................................................41078
    Correctly amended..............................................41861
250.1009 (a)(1), (2), (b)(1) introductory text, (i), (ii), (2) 
        introductory text, (i), (ii), (iii), (3), (4), (c) 
        introductory text, (1) through (6), (7)(i), (ii) 
        introductory text, (A), (B), (8), (9), (d) and (e) 
        redesignated as (a), (b), 250.1011 (a) introductory text, 
        (1), (2), (b) introductory text, (1), (2), (3), (c), (d), 
        250.1010 introductory text, (a), 250.1012, 250.1010 (b) 
        through (e), (f)(1), (2) introductory text, (i), (ii), 
        (g), (h), 250.1013 and 250.1014............................69311
250.1010 Redesignated as 250.1015; new 250.1010 introductory text, 
        (a) through (e), (f)(1), (2) introductory text, (i), (ii), 
        (g) and (h) redesignated from 250.1009 (c) introductory 
        text, (1), (3) through (6), (7)(i), (ii) introductory 
        text, (A), (B), (8) and (9)................................69312
250.1011 Redesignated as 250.1016; new 250.1011 (a) introductory 
        text, (1), (2), (b) introductory text, (1), (2), (3), (c) 
        and (d) redesignated from 250.1009(b)(1) introductory 
        text, (i)(ii), (2) introductory text, (i), (ii), (iii), 
        (3) and (4)................................................69311
    Heading for new 250.1011 revised...............................69312
250.1012 Redesignated as 250.1017; new 250.1012 redesignated from 
        250.1009(c)(2).............................................69311
    New 250.1012 revised...........................................69312
250.1013 Redesignated as 250.1018; new 250.1013 redesignated from 
        250.1009(d)................................................69311
    Heading for new 250.1013 revised...............................69312
250.1014 Redesignated as 250.1019; new 250.1014 redesignated from 
        250.1009(e)................................................69311
    Heading for new 250.1014 revised...............................69312
250.1015 Redesignated from 250.1010................................69311
    Heading revised................................................69312
250.1016 Redesignated from 250.1011................................69311
    Heading revised................................................69312
250.1017 Redesignated from 250.1012................................69311
    Heading revised................................................69312
250.1018 Redesignated from 250.1013................................69311
    Heading revised................................................69313
250.1019 Redesignated from 250.1014; heading revised...............69312
250.1105 (f)(1)(i) amended..........................................8435
250.1403 Revised...................................................61624
250.1604 (b) amended................................................8435
250.1612 Amended....................................................8435
250.1614 (b) amended................................................8435
250.1629 (b)(4)(v) revised.........................................43298

[[Page 563]]

                                  2004

30 CFR
                                                                   69 FR
                                                                    Page
Chapter II
203.0 Amended................................................3509, 24053
    Regulation at 69 FR 3509 eff. date corrected to 5-3-04.........24052
    Regulation at 69 FR 24053 eff. date corrected to 5-3-04........25500
203.4 Introductory text revised.....................................3509
203.5 Added.........................................................3509
    Regulation at 69 FR 3509 eff. date corrected to 5-3-04.........24052
203.40 Section and undesignated center heading added................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.41 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (b) and (d) amended............................................24053
    Regulation at 69 FR 24053 eff. date corrected to 5-3-04........25500
203.42 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (a)(1) and (b) introductory text revised.......................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.43 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (d) and (e) introductory text revised..........................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.44 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (b) amended; (e) introductory text revised.....................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.45 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.46 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
    (c) revised....................................................24054
    Regulation at 69 FR 24054 eff. date corrected to 5-3-04........25500
203.47 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
203.48 Added........................................................3510
    Regulation at 69 FR 3510 eff. date corrected to 5-3-04.........24052
204 Added..........................................................55088
    Notice of decision by States...................................68805
206.101 Amended; eff. 7-6-04.......................................24975
    Regulation at 69 FR 24975 eff. date corrected to 8-1-04........29432
206.103 (b), (c), (d), (e) introductory text, (1)(ii) and (iii) 
        revised; eff. 7-6-04.......................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.104 Heading, (a) introductory text, (3), (c) and (d) revised; 
        eff. 7-6-04................................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.109 (b) revised; eff. 7-6-04...................................24976
    Regulation at 69 FR 24976 eff. date corrected to 8-1-04........29432
206.110 (a) revised; (b) through (e) redesignated as (d) through 
        (g); new (b) and (c) added; eff. 7-6-04....................24977
    Regulation at 69 FR 24977 eff. date corrected to 8-1-04........29432
206.111 Heading, (a), (b) introductory text, (h)(5) and (i)(2) 
        revised; (b)(6) and (7) added; eff. 7-6-04.................24977
    Regulation at 69 FR 24977 eff. date corrected to 8-1-04........29432
206.112 Revised; eff. 7-6-04.......................................24978
    Regulation at 69 FR 24978 eff. date corrected to 8-1-04........29432
206.118 Removed; eff. 7-6-04.......................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
206.119 (c) revised; eff. 7-6-04...................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
206.121 Removed; eff. 7-6-04.......................................24979
    Regulation at 69 FR 24979 eff. date corrected to 8-1-04........29432
250.160 (i) revised................................................29433
250.198 Nomenclature change........................................18803
250.1012 (e) revised...............................................29433

                                  2005

30 CFR
                                                                   70 FR
                                                                    Page
Chapter II
203.40 Introductory text and (a) revised...........................22252
204 Policy statement...............................................72381
206.150 (b) revised................................................11877
206.151 Amended....................................................11878

[[Page 564]]

206.157 (b)(2)(v), (5), (c), (f) introductory text, (1), (7) and 
        (g)(5) revised; (f)(10), (g)(6), (7) and (8) added; (g)(4) 
        amended....................................................11878
216.53 (e) and (f) added...........................................56852
218.50 (d) and (e) added...........................................56853
250 Authority citation revised.....................................49875
    Regulation at 70 FR 49875 eff. date delayed....................56119
250.102 (b) table amended..........................................51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.105 Amended.............................................41573, 51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.125 Undesignated center heading and section added..............49875
    Regulation at 70 FR 49875 eff. date delayed....................56119
250.143 (d) added..................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.171 Revised....................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.175 (c) added..................................................74663
250.198 (e) table amended....................................7403, 41573
250.199 (e) table amended...................................41574, 51500
    Regulation at 70 FR 51500 eff. date delayed....................56853
250.200--250.299 (Subpart B) Revised...............................51501
    Regulation at 70 FR 51501 eff. date delayed....................56853
250.303 (b)(2) and (d) amended.....................................51518
    Regulation at 70 FR 51518 eff. date delayed....................56853
250.304 (a)(6) and (b) amended.....................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853
250.800 Existing text designated as (a); (b) added.................41574
250.803 (b)(1) introductory text revised............................7403
    (a) revised; (b)(2)(iii) added.................................41575
250.900--250.921 (Subpart I) Revised...............................41575
250.1002 (b)(4) and (5) added......................................41583
250.1007 (a)(4) revised............................................41583
250.1015 (a) revised...............................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
    (e) added......................................................61893
250.1018 (b) revised...............................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
    (c) added......................................................61893
250.1101 (f) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1106 (d) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1303 (d) added.................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
250.1605 (d) amended...............................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853
250.1629 (b)(1) introductory text revised...........................7403
256 Authority citation revised.....................................49876
256.63 Added.......................................................49876
    Regulation at 70 FR 49876 eff. date delayed....................56119
256.64 (a)(8) revised..............................................49877
    Regulation at 70 FR 49877 eff. date delayed....................56119
    (a)(9) added...................................................61893
282.28 (a) amended.................................................51519
    Regulation at 70 FR 51519 eff. date delayed....................56853

                                  2006

30 CFR
                                                                   71 FR
                                                                    Page
Chapter II
201--243 (Subchapter A) Heading revised............................51751
218.500--218.580 (Subpart H) Added.................................51751
241.51 (c) removed; (b) revised....................................51752
241.61 Revised.....................................................51752
250 Nomenclature change.....................................46399, 46400
250.105 Amended....................................................23862
250.125 (a) table and (b) revised; (c) added.......................40909
250.126 Added......................................................40911
250.186 Redesignated from 250.190; eff. 7-17-06....................19644
250.187 Added; eff. 7-17-06........................................19644
250.188 Added; eff. 7-17-06........................................19644
250.189 Added; eff. 7-17-06........................................19644
250.190 Redesignated as 250.186; new 250.190 added; eff. 7-17-06 
                                                                   19644
250.191 Revised; eff. 7-17-06......................................19645
250.194 Heading and (a) introductory text revised..................23862
250.195 Redesignated as 250.196; new 250.195 added.................23862

[[Page 565]]

250.196 (b)(1) removed; (b)(2) through (10) redesignated as (b)(1) 
        through (9); heading, introductory text, (b) introductory 
        text and new (9) revised...................................16039
    Redesignated as 250.197; new 250.196 redesignated from 250.195
                                                                   23862
250.197 Redesignated from 250.196; (a) and (b)(7) revised; (b) 
        table amended..............................................23862
250.198 (e) table amended..........................................40911
250.199 (e) revised................................................23863
250.211 (d) added..................................................40911
250.235 Second (a) correctly designated as (c).....................12438
250.241 (e) added..................................................40911
250.292 (n) and (o) revised; (p) added.............................40911
250.296 (a) amended................................................40911
250.410 Introductory text and (d) revised..........................40911
250.465 (b)(1) revised.............................................40911
250.490 (l) revised; eff. 7-17-06..................................19645
250.513 (d) amended; eff. 7-17-06..................................19646
    (a) amended; (b) introductory text, (3) and (4) revised; 
(b)(5) added.......................................................40911
250.601 Amended....................................................11313
250.613 (a) amended; (b) introductory text, (2) and (3) revised; 
        (b)(4) added...............................................40912
250.615 (e) revised................................................11313
    (e)(1) table corrected.........................................29710
250.616 (d) and (e) redesignated as (f) and (g); new (d) and (e) 
        added; (a) and new (f) revised.............................11313
250.802 (e)(7) added...............................................40912
250.900 (b)(2) corrected...........................................16859
250.910 (b)(2)(i) corrected........................................28080
250.905 Introductory text revised; table amended; (k) added........40912
250.1000 (b) revised...............................................40912
250.1008 (e) revised...............................................40912
250.1102 (a)(9), (b)(8) and (9) amended; eff. 7-17-06..............19646
250.1202 (a)(1) revised............................................40912
250.1203 (b)(1) revised............................................40912
250.1204 (a)(1) revised............................................40913
250.1402 Amended...................................................23864
250.1617 (d) amended; eff. 7-17-06.................................19646
    (a) revised....................................................40913
250.1618 Heading and (a) revised...................................40913
250.1704 (g) revised...............................................40913
250.1727 Introductory text revised.................................40913
250.1751 (a) introductory text revised.............................40913
250.1752 (a) introductory text revised.............................40913
251 Authority citation revised.....................................40913
251.5 (a) revised..................................................40913
251.14 (b) introductory text and (1) table revised; (b)(3) added 
                                                                   16039
    (b)(1) table corrected.........................................62050
254 Nomenclature change............................................46400
280 Authority citation revised.....................................40914
280.12 (a) revised.................................................40914
290 Authority citation revised.....................................51752
290.100--290.111 (Subpart B) Heading revised.......................51752
290.100 Revised....................................................51752
290.102 Amended....................................................51752
290.111 Removed....................................................51752

                                  2007

30 CFR
                                                                   72 FR
                                                                    Page
Chapter II
202.351 Revised....................................................24458
202.353 Revised....................................................24458
203.44 (a) amended.................................................25198
206.50 Revised.....................................................71241
206.51 Revised.....................................................71241
206.52 Revised.....................................................71241
206.53 Revised.....................................................71241
206.54 Redesignated as 206.56; new 206.54 added....................71241
206.55 Redesignated as 206.57; new 206.55 added....................71241
206.56 Redesignated from 206.54; (a), (b)(1) and (c) amended.......71241
206.57 Redesignated from 206.55....................................71241
206.58 Added.......................................................71244
206.59 Added.......................................................71244
206.60 Added.......................................................71244
206.61 Added.......................................................71244
206.62 Added.......................................................71244
206.350--206.366 (Subpart H) Revised...............................24459
210.352 Removed; new 210.352 redesignated from 210.353.............24467
210.353 Redesignated as 210.352; redesignated from 210.354.........24467

[[Page 566]]

210.354 Redesignated as 210.353; redesignated from 210.355 and 
        revised....................................................24467
210.355 Redesignated as 210.354....................................24467
217.300--217.302 (Subpart G) Added.................................24468
218 Heading revised................................................24468
218.303 Added......................................................24468
218.304 Added......................................................24468
218.305 Added......................................................24468
218.306 Added......................................................24468
218.307 Added......................................................24468
250.102 (b) table revised..........................................25198
250.108 (c) revised................................................12092
250.125 (a) table revised..........................................25199
250.143 (a) amended................................................25200
250.160 (f) and (g) amended........................................25200
250.165 (a) and (b) amended........................................25200
250.169 (a) amended................................................25200
250.175 (b)(3) amended.............................................25200
250.186 (b)(2) amended.............................................25200
250.194 (c) amended................................................25200
250.197 (a)(8) and (b)(7) amended..................................25200
250.198 (e) table amended...........................................8902
    (e) table revised..............................................12092
    (d) table revised..............................................25200
250.199 (b) and (e) table amended..................................25200
250.201 (a)(3) amended.............................................25200
250.210 (a) and (b) amended........................................25200
250.216 (a) revised................................................18584
250.221 (b) redesignated as (c); new (b) added.....................18584
250.223 Revised....................................................18585
250.227 (a)(3) and (c)(1) revised..................................18585
250.232 (a)(2) amended.............................................25200
250.247 (a) revised................................................18585
250.252 (b) redesignated as (c); new (b) added.....................18585
250.254 Revised....................................................18585
250.261 (a)(3) and (c)(1) revised..................................18585
250.270 (a)(1)(i) revised..........................................18585
    (a)(1)(i) amended..............................................25200
250.281 (a)(3) amended.............................................25200
250.282 Introductory text revised..................................18585
250.285 (c) amended................................................25201
250.408 Amended....................................................25201
250.410 (d)(2) amended.............................................25201
250.415 (e) added...................................................8903
250.417 (c)(1) amended.............................................25201
250.466 Introductory text amended..................................25201
250.490 (p)(2) revised.............................................12096
    (o)(3) amended.................................................25201
250.513 (a), (c) and (d) revised...................................25201
250.613 (d) amended................................................25201
250.801 (e)(4) revised.............................................12096
    (h)(1) amended.................................................25201
250.802 (d) amended................................................12096
    (e)(3) and (4)(i) amended......................................25201
250.803 (b)(1) amended.............................................12096
250.806 (a)(2)(ii) revised.........................................12096
250.901 (a)(3) revised.............................................12096
250.1001 Amended...................................................25201
250.1002 (a) and (b)(2) amended....................................12096
    (c)(2) amended.................................................25201
250.1003 (b)(1) amended............................................25201
250.1004 (b)(2) amended............................................25201
250.1005 (b) amended...............................................25201
250.1007 (a)(4) amended............................................25201
250.1010 (c) and (h) amended.......................................25201
250.1011 (b)(1) revised; (b)(2) amended............................25201
250.1016 (c)(1) amended............................................25201
250.1019 Amended...................................................25201
250.1102 (a)(1) amended............................................25201
250.1103 (a) amended...............................................25201
250.1202 (f)(1) amended............................................25201
250.1403 Revised....................................................8899
250.1602 (b) amended...............................................25201
250.1619 (b) amended...............................................25201
250.1629 (b)(1) introductory text amended..........................12096
251.7 (b) introductory text revised; (b)(6) amended................25201
251.14 (b) introductory text amended...............................25202
253 Authority citation revised......................................8899
253.51 (a) revised..................................................8899
260.102 Amended....................................................25202

                                  2008

30 CFR
                                                                   73 FR
                                                                    Page
Chapter II
203 Authority citation revised..............................49946, 69504
203.0 Amended......................................................69504
203.1 Introductory text and (b) revised; (d) added.................69506
203.2 Heading, (b), (d) and (e) revised; (f), (g) and (h) added....69506
203.3 Revised......................................................49946
203.30 Undesignated center heading and section added...............69506
203.31 Added.......................................................69506
203.32 Added.......................................................69506
203.33 Added.......................................................69506
203.34 Added.......................................................69506
203.35 Added.......................................................69506

[[Page 567]]

203.36 Added.......................................................69506
203.40 Revised.....................................................69510
203.41 (b) introductory text and (d) introductory text revised.....15889
    Revised........................................................69510
203.42 Redesignated as 203.43; new 203.42 added....................69512
203.43 Redesignated as 203.44; new 203.43 redesignated from 203.42 
        and revised................................................69512
203.44 (b) introductory text revised...............................15890
    Redesignated as 203.45; new 203.44 redesignated from 203.43....69512
    (a), (d) and (e) revised.......................................69513
203.45 Redesignated as 203.46; new 203.45 redesignated from 203.44
                                                                   69512
    (a), (b) and (e) revised.......................................69513
203.46 Redesignated as 203.47; new 203.46 redesignated from 203.45
                                                                   69512
    (a) introductory text, (1), (c) and (e) revised................69514
203.47 Redesignated as 203.48; new 203.47 redesignated from 203.46
                                                                   69512
    (c) revised....................................................69514
203.48 Redesignated as 203.49; new 203.48 redesignated from 203.47
                                                                   69512
    Revised........................................................69514
203.49 Redesignated from 203.48....................................69512
    (a) introductory text and (c) revised..........................69515
203.60 Undesignated center heading and section revised.............69515
203.62 Revised.....................................................69515
203.69 (c) revised.................................................58472
    Regulation at 73 FR 58472 eff. date delayed to 12-8-08.........64205
    (b) revised; (c) through (f) redesignated as (f) through (i); 
new (c), (d) and (e) added.........................................69515
203.70 Introductory text and (b) revised...........................69515
203.71 (a)(1), (3) and (5) revised; (b) removed; (c) and (d) 
        redesignated as new (b) and (c)............................58472
    Regulation at 73 FR 58472 eff. date delayed to 12-8-08.........64205
203.77 Revised.....................................................69516
203.78 Revised.....................................................69516
203.79 Heading revised.............................................69516
203.80 Heading and introductory text revised.......................69516
203.81 (b) revised.................................................69516
203.89 Heading revised.............................................69516
203.90 (b) revised.................................................69516
206.51 Amended.....................................................15890
206.56 (b)(1), (2) and (d) revised.................................15890
206.57 (c)(4) and (e)(1) revised...................................15890
206.116 Revised....................................................15890
206.151 Amended....................................................15890
206.156 (c) and (d) revised........................................15890
206.157 (a)(1)(i) and (b)(1) amended; (d)(1) removed; (d)(2), (3) 
        and (4) redesignated as new (d)(1), (2) and (3)............15891
206.158 (e) revised................................................15891
206.159 (a)(1)(i), (b)(1), (c)(1)(i), (2)(i), (d) heading and 
        (e)(1) amended; (d)(1) removed; (d)(2), (3) and (4) 
        redesignated as new (d)(1), (2) and (3)....................15891
206.171 Amended....................................................15891
206.177 (c)(1) and (2) amended.....................................15891
206.178 (d)(2) amended.............................................15891
206.180 (c)(2) amended.............................................15891
206.251 Amended....................................................15891
206.252 Revised....................................................15891
206.254 Amended....................................................15891
206.259 (d)(1) amended.............................................15891
206.262 (d)(1) amended.............................................15891
206.451 Amended....................................................15891
206.453 Amended....................................................15892
210.01--210.40 (Subpart A) Revised.................................15892
210.10 Table correctly amended.....................................58875
210.50--210.60 (Subpart B) Revised.................................15892
210.100--210.106 (Subpart C) Added.................................15892
210.150--210.158 (Subpart D) Added.................................15892
210.200--210.206 (Subpart E) Heading revised.......................15897
210.205 Redesignated as 210.206; new 210.205 added.................15897
210.206 Redesignated as 210.207; new 210.206 redesignated from 
        210.205....................................................15897
210.207 Redesignated from 210.206..................................15897
216 Removed........................................................15897
218 Heading revised................................................15897
218.40 (a), (b) and (c) revised....................................15897
218.41 (a) through (e) revised.....................................15897
218.50 (b) revised.................................................15898

[[Page 568]]

218.51 (a) amended; (f)(1) and (2) revised.........................15898
218.52 (a) introductory text, (1), (4)(i) and (c) introductory 
        text revised...............................................15898
218.57 Removed.....................................................15898
218.154 (c) amended................................................15898
218.155 (b)(2) amended.............................................15898
219 Authority citation revised.....................................78629
219.410--219.418 (Subpart D) Added.................................78629
227.401 (f) revised................................................15898
250 Authority citation revised..............................20168, 20171
250.107 (a)(2) amended.............................................20171
250.125 (a) table revised..........................................49946
250.126 Revised....................................................49947
250.160 (h) revised................................................49948
250.192 Revised....................................................64545
250.198 (e) table amended...................................20168, 64545
250.199 (e)(1) revised.............................................64546
250.260 (a) amended................................................20171
250.803 (b)(8) and (9)(i) amended..................................20171
250.806 (c) amended................................................20171
250.900 (a) amended................................................20171
    (c) and (e) revised............................................64546
250.901 (a)(4) through (20) redesignated as (a)(7) through (23); 
        new (a)(4), (5) and (6) added; new (a)(7), (23) and (d) 
        revised....................................................20169
    (a)(9) through (23) redesignated as (a)(10) through (24); new 
(a)(9) and (d)(23) added; (d)(22) revised..........................64546
250.905 Introductory text amended; (i), (j) and (k) redesignated 
        as (j), (k) and (l); new (i) added.........................64546
250.911 (d) through (g) redesignated as (e) through (h); new (d) 
        added......................................................64547
250.916 (c) revised................................................64547
250.917 (c) revised................................................64547
250.918 (c) revised................................................64547
250.919 Revised....................................................64547
250.920 Revised....................................................64548
250.1007 (a)(4) revised............................................64548
250.1201 Amended...................................................20171
250.1202 (k)(3) and (4) amended....................................20171
250.1204 (b)(1) amended............................................20171
250.1301 (b) and (c) revised.......................................20172
250.1502 Removed...................................................20172
250.1629 (b)(1) introductory text and (i) amended..................20172
251 Authority citation revised.....................................49948
251.5 (a) revised..................................................49948
256 Authority citation revised..............................49948, 52920
256.5 (m) through (s) added........................................52920
256.63 (a) table revised...........................................49948
256.64 (a)(8) revised..............................................49948
256.90--256.95 (Subpart N) Added...................................52920
260.3 Revised......................................................58472
    Regulation at 73 FR 58472 eff. date delayed to 12-8-08.........64205
260.113 Revised....................................................58473
    Regulation at 73 FR 58473 eff. date delayed to 12-8-08.........64205
260.114 Revised....................................................58473
    Regulation at 73 FR 58473 eff. date delayed to 12-8-08.........64205
260.117 Removed....................................................58473
    Regulation at 73 FR 58473 eff. date delayed to 12-8-08.........64205
260.121 (b) revised................................................69517
260.122 (b)(1) revised; (d) removed................................69517
260.124 Heading and (b) introductory text revised..................58473
    Regulation at 73 FR 58473 eff. date delayed to 12-8-08.........64205
270 Authority citation revised.....................................20172
270.6 Amended......................................................20172
280 Authority citation revised.....................................49948
280.12 (a) revised.................................................49948
281 Authority citation revised..............................20172, 49948
281.0 Amended......................................................20172
281.26 (e) amended; (i) revised....................................20172
281.41 (a)(2) revised..............................................49948
282 Authority citation revised.....................................20172
282.40 (f) revised.................................................20172
290 Authority citation revised.....................................49948
290.4 (b) revised..................................................49948
291 Added; eff. 8-18-08............................................34640

                                  2009

30 CFR
                                                                   74 FR
                                                                    Page
Chapter II
203.5 Revised......................................................46907
203.45 (e) introductory text revised...............................46907
203.82 (d) amended.................................................46907
210.20 Amended.....................................................46907
250.108 (b) revised................................................46907
250.199 (d) amended................................................46908
250.233 (b)(2) amended.............................................46908
250.441 (b) revised................................................46908
250.510 Revised....................................................46908

[[Page 569]]

250.511 Revised....................................................46908
250.515 (b) table, (c) introductory text and (1) revised...........46908
250.615 (b) table, (c) introductory text and (1) revised...........46908
250.803 (b)(5)(ii) revised.........................................46909
250.1201 Amended...................................................40073
250.1202 (d)(3), (k)(3) and (4) revised............................40073
250.1203 (c)(1) revised............................................40073
250.1204 (b)(1) revised............................................40073
250.1500 Amended...................................................40073
250.1604 (f) revised...............................................46909
250.1605 (h) revised...............................................46909
250.1610 (d)(1) revised............................................46909
250.1613 (b) and following undesignated text removed; (c), (d) and 
        (e) redesignated as new (b), (c) and (d)...................46909
250.1703 (c) revised...............................................19807
250.1725 (a) introductory text amended; (a)(1) and (2) added.......19807
250.1730 Introductory text amended.................................19807
250.1731 Added.....................................................19807
251.1 Amended......................................................40730
251.14 (b) introductory text and (1) table revised; (b)(2) and (3) 
        redesignated as (b)(7) and (8); new (b)(2) through (6) 
        added......................................................40731
251.15 (e) amended.................................................46909
253 Authority citation revised.....................................46909
253.5 (d) amended..................................................46909
253.44 Removed.....................................................46909
254.9 (d) amended..................................................46909
256.0 (d) amended..................................................46909
256.64 (a)(9) removed..............................................46909
260.122 (b)(2) and (3) reinstated; CFR correction..................66574
280.13 Table revised...............................................46909
280.80 (e) amended.................................................46910
285 Added..........................................................19807
290 Authority citation revised.....................................19871
290.2 Amended......................................................19871
291 Authority citation revised.....................................46910
291.1 (e) amended..................................................46910
291.103 Introductory text amended..................................46910
291.106 (a) amended................................................46910
291.107 (a) amended................................................46910

                                  2010

30 CFR
                                                                   75 FR
                                                                    Page
Chapter II
Chapter II Heading revised.........................................61066
200 Removed........................................................61066
201 Redesignated as Part 1201......................................61066
202 Redesignated as Part 1202......................................61066
203.250--203.251 (Subpart F) Redesignated as Part 1203.............61067
204 Redesignated as Part 1204......................................61067
206 Redesignated as Part 1206......................................61069
207 Redesignated as Part 1207......................................61080
208 Redesignated as Part 1208......................................61080
210 Redesignated as Part 1210......................................61081
212 Redesignated as Part 1212......................................61084
215 Removed........................................................61084
217 Redesignated as Part 1217......................................61084
218 Redesignated as Part 1218......................................61084
219.100--219.105 (Subpart C) Redesignated as Part 1219; new 
        Subpart C added............................................61086
220 Redesignated as Part 1220......................................61087
227 Redesignated as Part 1227......................................61088
228 Redesignated as Part 1228......................................61090
229 Redesignated as Part 1229......................................61091
230 Removed........................................................61091
231 Removed........................................................61091
232 Removed........................................................61091
233 Removed........................................................61091
234 Removed........................................................61091
241 Redesignated as Part 1241......................................61091
242 Removed........................................................61092
243 Redesignated as Part 1243......................................61092
250 Policy statement...............................................80717
250.105 Amended....................................................20288
250.125 (a)(27), (28) and (29) revised.............................20288
250.198 (e) table amended...........................................1279
    Revised........................................................22222
    (h)(78) added..................................................23584
    (a)(3) and (h)(79) added; (h)(63) revised; interim.............63372
    (h)(80) added..................................................63649
250.199 (e)(10) revised............................................20289
    (e)(17) revised................................................63649
250.415 (c), (d) and (e)(2) revised; (f) added; interim............63372
    (d) correctly revised; interim.................................76632
250.416 (d) and (e) revised; (f) and (g) added; interim............63372
250.418 (g) revised; (h) redesignated as (j); new (h) and (i) 
        added; interim.............................................63372
250.420 (a)(4) and (5) revised; (a)(6) and (b)(3) added; interim 
                                                                   63373
250.423 Revised; interim...........................................63373
250.442 Revised; interim...........................................63373

[[Page 570]]

250.446 (a) revised; interim.......................................63374
250.449 (h) and (i) revised; (j) and (k) added; interim............63374
250.451 (i) added; interim.........................................63374
250.456 (i) amended; (j) redesignated as (k); new (j) added; 
        interim....................................................63374
250.490 (o)(3) amended.............................................20289
250.515 (b)(5) and (e) added; interim..............................63375
250.516 (d)(6), (g) and (h) revised; (d)(8) and (9) added; interim
                                                                   63375
250.517 (c) revised................................................23584
250.518 Undesignated center heading and section added..............23584
250.519 Added......................................................23584
250.520 Added......................................................23584
250.521 Added......................................................23584
250.522 Added......................................................23584
250.523 Added......................................................23584
250.524 Added......................................................23584
250.525 Added......................................................23584
250.526 Added......................................................23584
250.527 Added......................................................23584
250.528 Added......................................................23584
250.529 Added......................................................23584
250.530 Added......................................................23584
250.615 (e), (f) and (g) redesignated as (f), (g) and (h); (b)(5) 
        and new (e) added; interim.................................63375
250.616 (h) added; interim.........................................63376
250.617 (c) revised................................................23586
    Redesignated as 250.618; new 250.617 added; interim............63376
250.618 Redesignated as 250.619; new 250.618 redesignated from 
        250.617; interim...........................................63376
250.619 Redesignated from 250.618; interim.........................63376
250.803 (b)(1) introductory text amended...........................22226
250.806 (a)(3) amended..............................................1279
    (a)(2)(i) revised..............................................22226
250.807 Redesignated as 250.808; new 250.807 added..................1280
250.808 Redesignated from 250.807...................................1280
250.901 (a)(1), (2), (15) through (19), (d)(1), (7) through (11) 
        and (16) revised...........................................22226
250.1150--250.1167 (Subpart K) Revised.............................20289
250.1500 Amended; interim..........................................63376
250.1501 Amended; interim..........................................63376
250.1503 (b) and (c) redesignated as (c) and (d); (a), new (c)(1), 
        new (3) and new (d)(1) amended; new (b) added; interim.....63376
250.1506 (a), (b) and (c) amended; interim.........................63376
250.1507 (c) and (d) amended; interim..............................63376
250.1628 (b)(3) and (d)(4)(i) revised..............................22227
250.1629 (b)(1) introductory text and (4)(i) amended; (b)(3) 
        introductory text revised..................................22227
250.1712 (e) and (f)(14) revised; (g) added; interim...............63376
250.1721 (e) and (g)(3) revised; (h) added; interim................63377
250.1900--250.1929 (Subpart S) Added...............................63649
285.231 Heading and (d)(1) revised.................................72682
285.232 (c) revised................................................72682
290.100--290.110 (Subpart B) Redesignated as Part 1290.............61093
Chapter III
Chapter III Removed................................................64663

                                  2011

    (Regulations published from January 1, 2011 through July 1, 2011)

30 CFR
                                                                   76 FR
                                                                    Page
Chapter II
250 Workshop.......................................................11079
250 Authority citation revised.....................................38557
250.1400--250.1409 (Subpart N) Heading revised.....................38557
250.1400 Undesignated center heading added.........................38557
250.1403 Revised; eff. 8-1-11......................................38296
250.1450 Undesignated center heading and section added.............38558
250.1451 Undesignated center heading and section added.............38558
250.1452 Added.....................................................38558
250.1453 Added.....................................................38558
250.1454 Added.....................................................38558
250.1455 Added.....................................................38558
250.1456 Added.....................................................38558
250.1460 Undesignated center heading and section added.............38558
250.1461 Added.....................................................38558
250.1462 Added.....................................................38558
250.1463 Added.....................................................38558
250.1464 Added.....................................................38558

[[Page 571]]

250.1470 Undesignated center heading and section added.............38558
250.1471 Added.....................................................38558
250.1472 Added.....................................................38558
250.1473 Added.....................................................38558
250.1474 Added.....................................................38558
250.1475 Added.....................................................38558
250.1476 Added.....................................................38558
250.1477 Added.....................................................38558
250.1480 Undesignated center heading and section added.............38558
250.1490 Undesignated center heading and section added.............38558
250.1491 Added.....................................................38558
250.1495 Undesignated center heading and section added.............38558
250.2496 Added.....................................................38558
250.2497 Added.....................................................38558
253 Authority citation revised; eff. 8-1-11........................38296
253.51 (a) revised; eff. 8-1-11....................................38296
285.231 Regulation at 75 FR 72682 withdrawn.........................4244
    Heading and (d)(1) revised.....................................28180
285.232 Regulation at 75 FR 72682 withdrawn.........................4244
    (c) revised....................................................28180


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