[Federal Register Volume 71, Number 116 (Friday, June 16, 2006)]
[Rules and Regulations]
[Pages 35006-35046]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-5218]



[[Page 35005]]

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Part II





Environmental Protection Agency





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40 CFR Parts 9, 122, 123, et al.



National Pollutant Discharge Elimination System; Establishing 
Requirements for Cooling Water Intake Structures at Phase III 
Facilities; Final Rule

  Federal Register / Vol. 71, No. 116 / Friday, June 16, 2006 / Rules 
and Regulations  

[[Page 35006]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9, 122, 123, 124, and 125

[OW-2004-0002, FRL-8181-5]
RIN 2040-AD70


National Pollutant Discharge Elimination System--Final 
Regulations To Establish Requirements for Cooling Water Intake 
Structures at Phase III Facilities

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: On November 1, 2004, EPA published a proposal that contained 
several options for the control of cooling water intake structures at 
existing Phase III facilities and at new offshore oil and gas 
extraction facilities. This rule establishes categorical section 316(b) 
requirements for intake structures at new offshore oil and gas 
extraction facilities that have a design intake flow threshold of 
greater than 2 million gallons per day and that withdraw at least 25 
percent of the water exclusively for cooling purposes. For existing 
Phase III facilities, EPA determined that uniform national standards 
are not the most effective way at this time to address cooling water 
intake structures at these facilities. Instead, EPA believes that it is 
better to continue to rely upon the existing National Pollutant 
Discharge Elimination System (NPDES) program, which implements section 
316(b) for existing facilities not covered under the Phase II rule on a 
case-by-case, best professional judgment basis. This final action 
constitutes Phase III of EPA's section 316(b) regulation development. 
This rule does not alter the regulatory requirements for facilities 
subject to the Phase I or Phase II regulations.

DATES: This regulation is effective July 17, 2006. For judicial review 
purposes, this final rule is promulgated as of 1 p.m. Eastern Daylight 
Time (EDT) on June 30, 2006 as provided in 40 CFR 23.2.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-OW-2004-0002. All documents in the docket are listed on the 
www.regulations.gov web site. Although listed in the index, some 
information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically through www.regulations.gov or in hard copy at the Water 
Docket in the EPA Docket Center, EPA/DC, EPA West, Room B102, 1301 
Constitution Ave., NW, Washington, DC. The Public Reading Room is open 
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 
holidays. The telephone number for the Public Reading Room is (202) 
566-1744, and the telephone number for the Water Docket is (202) 566-
2426.

FOR FURTHER INFORMATION CONTACT: For additional technical information 
contact Paul Shriner, OW/OST at (202) 566-1076. For additional 
biological information contact Ashley Allen, OW/OST at (202) 566-1012. 
The address for the above contacts is: Office of Science and 
Technology, Engineering Analysis Division (Mailcode 4303T), 
Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 
Washington, DC 20460; fax number: (202) 566-1053; e-mail address: 
[email protected].

SUPPLEMENTARY INFORMATION:

I. General Information

A. What Entities Are Regulated By This Action?

    This final rule applies to new offshore and coastal oil and gas 
extraction facilities, which were specifically excluded from the Phase 
I new facility rule. New offshore and coastal oil and gas extraction 
facilities with a design intake flow threshold of greater than 2 
million gallons per day (MGD) are subject to requirements similar to 
those under the Phase I rule. A new offshore or coastal oil and gas 
extraction facility is defined as any building, structure, facility, or 
installation that (1) meets the definition of a ``new facility'' in 40 
CFR 125.83; (2) is regulated by either the Offshore or Coastal 
subcategories of the Oil and Gas Extraction Point Source Category 
Effluent Guidelines in 40 CFR part 435, Subpart A or Subpart D; and (3) 
commences construction after July 17, 2006. Any offshore or coastal oil 
and gas extraction facility that does not meet these three criteria is 
subject to section 316(b) requirements established by the permit writer 
on a case-by-case basis. Exhibit I-1 provides examples of other 
industrial facility types potentially interested in this final action.

               Exhibit I-1.--Industrial Facility Types Potentially Interested in This Final Action
----------------------------------------------------------------------------------------------------------------
                                       Examples of potentially      Standard industrial       North American
              Category                   interested entities       classification codes    industry codes (NAIC)
----------------------------------------------------------------------------------------------------------------
Federal, State and local government  Operators of steam electric  4911 and 493..........  221111, 221112,
                                      generating point source                              221113, 221119,
                                      dischargers that employ                              221121, 221122
                                      cooling water intake
                                      structures.
Industry...........................  Operators of industrial      See below.............  See below
                                      point source dischargers
                                      that employ cooling water
                                      intake structures.
                                     Agricultural production....  0133..................  111991, 11193
                                     Metal mining...............  1011..................  21221
                                     Oil and gas extraction.....  1311, 1321............  211111, 211112
                                     Mining and quarrying of      1474..................  212391
                                      nonmetallic minerals.
                                     Food and kindred products..  2046, 2061, 2062,       311221, 311311,
                                                                   2063, 2075, 2085.       311312, 311313,
                                                                                           311222, 311225, 31214
                                     Tobacco products...........  2141..................  312229, 31221
                                     Textile mill products......  2211..................  31321
                                     Lumber and wood products,    2415, 2421, 2436, 2493  321912, 321113,
                                      except furniture.                                    321918, 321999,
                                                                                           321212, 321219
                                     Paper and allied products..  2611, 2621, 2631, 2676  3221, 322121, 32213,
                                                                                           322121, 322122,
                                                                                           32213, 322291
                                     Chemical and allied          28 (except 2895, 2893,  325 (except 325182,
                                      products.                    2851, and 2879).        32591, 32551, 32532)

[[Page 35007]]

 
                                     Petroleum refining and       2911, 2999............  32411, 324199
                                      related industries.
                                     Rubber and miscellaneous     3011, 3069............  326211, 31332, 326192,
                                      plastics.                                            326299
                                     Stone, clay, glass, and      3241..................  32731
                                      concrete products.
                                     Primary metal industries...  3312, 3313, 3315,       324199, 331111,
                                                                   3316, 3317, 3334,       331112, 331492,
                                                                   3339, 3353, 3363,       331222, 332618,
                                                                   3365, 3366.             331221, 22121,
                                                                                           331312, 331419,
                                                                                           331315, 331521,
                                                                                           331524, 331525
                                     Fabricated metal products,   3421, 3499............  332211, 337215,
                                      except machinery and                                 332117, 332439,
                                      transportation equipment.                            33251, 332919,
                                                                                           339914, 332999
                                     Industrial and commercial    3523, 3531............  333111, 332323,
                                      machinery and computer                               332212, 333922,
                                      equipment.                                           22651, 333923, 33312
                                     Transportation equipment...  3724, 3743, 3764......  336412, 333911, 33651,
                                                                                           336416
                                     Measuring, analyzing, and    3861..................  333315, 325992
                                      controlling instruments,
                                      photographic, medical, and
                                      optical goods, watches and
                                      clocks.
                                     Electric, gas, and sanitary  4911, 4931, 4939, 4961  221111, 221112,
                                      services.                                            221113, 221119,
                                                                                           221121, 221122,
                                                                                           22121, 22133
                                     Educational services.......  8221..................  61131
                                     Engineering, accounting,     8731..................  54171
                                      research, management and
                                      related services.
----------------------------------------------------------------------------------------------------------------

    This exhibit is not intended to be exhaustive, but rather provides 
a guide for readers regarding entities likely to be interested in this 
action. This exhibit also lists the types of entities that EPA is now 
aware could potentially be regulated by this action. Other types of 
entities not listed in the exhibit could also be regulated. To 
determine whether your facility is regulated by this action, you should 
carefully examine the applicability criteria in Sec.  125.131 of this 
rule. If you have questions regarding the applicability of this action 
to a particular entity, consult the persons listed for technical 
information in the FOR FURTHER INFORMATION CONTACT section.

B. Supporting Documentation

    The final regulation is supported by three major documents:
    1. Economic and Benefits Analysis for the Final Section 316(b) 
Phase III Existing Facilities Rule (EPA-821-R-06-001), hereafter 
referred to as the Economic and Benefits Analysis or EA. This document 
presents the methodology employed to assess economic impacts of the 
options we considered for this action and the results of the analysis.
    2. Regional Analysis for the Final Section 316(b) Phase III 
Existing Facilities Rule (EPA-821-R-06-002), hereafter referred to as 
the Regional Analysis Document. This document examines cooling water 
intake structure impacts and the environmental benefits of the national 
categorical regulatory options we considered for this action at the 
regional level.
    3. Technical Development Document for the Final Section 316(b) 
Phase III Existing Facilities Rule (EPA-821-R-06-003), hereafter 
referred to as the Technical Development Document. This document 
presents the technical information that formed the basis for our 
decisions in this action, including information on the costs and 
performance of the impingement and entrainment reduction technologies 
we considered.

Table of Contents

I. General Information
II. Scope and Applicability of the Final Rule
III. Legal Authority, Purpose, and Background of This Regulation
IV. Environmental Impacts Associated with Cooling Water Intake 
Structures
V. Description of the Rule
VI. Basis for the Final Rule Decision
VII. Response to Major Comments on the Proposed Rule and Notice of 
Data Availability (NODA)
VIII. Implementation
IX. Economic Impact Analysis
X. Benefits Analysis
XI. Comparison of Benefits and Costs
XII. Statutory and Executive Order Reviews

II. Scope and Applicability of the Final Rule

    The national categorical requirements in this rule apply to new 
offshore oil and gas extraction facilities, which were specifically 
excluded from the Phase I new facility rule. (40 CFR part 125, Subpart 
I). This rule defines the term ``new offshore oil and gas extraction 
facility'' to encompass facilities in both the offshore and the coastal 
subcategories of EPA's Oil and Gas Extraction Point Source Category for 
which effluent limitations are established at 40 CFR part 435. Although 
the term ``offshore'' denotes only one of these two subcategories for 
purposes of the effluent guidelines, EPA is using the term ``offshore'' 
here to denote facilities in either subcategory because the 
requirements in this rule are the same for both offshore and coastal 
facilities and the term ``offshore'' is commonly understood to include 
any facilities not located on land. In order to be covered by this 
rule, these facilities would need to use cooling water intake 
structures to withdraw water from waters of the U.S. and meet all other 
applicability criteria, as described in this section.
    New offshore oil and gas facilities that meet all of the following 
criteria are subject to this rule:
     The facility is a point source;
     The facility uses or proposes to use cooling water intake 
structures,

[[Page 35008]]

including a cooling water intake structure operated by one or more 
independent suppliers (other than a public water system), with a total 
design intake flow equal to or greater than 2 million gallons per day 
(MGD) to withdraw cooling water from waters of the United States;
     The facility is expected to use at least 25 percent of 
water withdrawn exclusively for cooling purposes, based on the new 
facility's design and measured as a monthly average, during at least 
one month over the course of a year.
    For the purposes of this rule, a new facility is a point source if 
it has, or is required to have, an NPDES permit. If a new facility is a 
point source that uses a cooling water intake structure, but does not 
meet the applicable design intake flow/source waterbody threshold or 
the 25 percent cooling water use threshold, it would continue to be 
subject to permit conditions implementing CWA section 316(b) set by the 
permit director on a case-by-case, best professional judgment basis. 
Section II.A of the preamble discusses what constitutes a ``new'' 
offshore oil and gas extraction facility for purposes of the section 
316(b) Phase III rule. Requirements for new offshore oil and gas 
extraction facilities are specified in 40 CFR Subpart N.
    Existing Phase III facilities, including manufacturing facilities, 
electric power producers with a design intake flow (DIF) less than 50 
MGD, and existing offshore oil and gas extraction facilities, are not 
subject to the national categorical requirements of this final rule. 
These facilities will continue to be regulated on a case-by-case basis 
using a permit director's best professional judgment.
    Finally, this rule does not establish national categorical 
requirements for seafood processing vessels or offshore liquefied 
natural gas import terminals. Those facilities would be subject to 
permit conditions implementing CWA section 316(b) set by the permit 
director on a case-by-case, best professional judgment basis where the 
facility is a point source and uses a cooling water intake structure.

A. What Is a ``New'' Offshore Oil and Gas Extraction Facility for 
Purposes of the Section 316(b) Phase III Rule?

    For purposes of this rule, new offshore oil and gas extraction 
facilities are those facilities that (1) are subject to the Offshore or 
Coastal subcategories of the Oil and Gas Extraction Point Source 
Category Effluent Guidelines (i.e., 40 CFR part 435 Subpart A (Offshore 
Subcategory) or 40 CFR part 435 Subpart D (Coastal Subcategory)); (2) 
commence construction after July 17, 2006; and (3) meet the definition 
of a ``new facility'' in 40 CFR 125.83. For a discussion of the 
definition of new facility, see 66 FR 65256, 65258-59, 65785-87 
(December 18, 2001) and 69 FR 41576, 41578-80 (July 9, 2004). New 
offshore oil and gas extraction facilities were not subject to the 
Phase I new facility rule.
    The determination of whether a facility is ``new'' or ``existing'' 
is focused on the point source discharger--not on the cooling water 
intake structure. In other words, modifications or additions to the 
cooling water intake structure (or even the total replacement of an 
existing cooling water intake structure with a new one) does not 
convert an otherwise unchanged existing facility into a new facility, 
regardless of the purpose of such changes. Rather, the determination as 
to whether a facility is new or existing focuses on the point source 
itself.

B. What Is ``Cooling Water'' and What Is a ``Cooling Water Intake 
Structure?''

    This rule adopts the same definition of a ``cooling water intake 
structure'' that applies to new facilities under the final Phase I rule 
and existing facilities under the final Phase II rule. Under this final 
rule, a cooling water intake structure is defined as the total physical 
structure and any associated constructed waterways used to withdraw 
cooling water from waters of the United States. Under this definition, 
the cooling water intake structure extends from the point at which 
water is withdrawn from the surface water source up to and including 
the intake pumps. This rule also adopts the definition of ``cooling 
water'' used in the Phase I and Phase II rules: water used for contact 
or noncontact cooling, including water used for equipment cooling, 
evaporative cooling tower makeup, and dilution of effluent heat 
content. The definition specifies that the intended use of cooling 
water is to absorb waste heat rejected from the processes used or 
auxiliary operations on the facility's premises. As is the case with 
the Phase I and Phase II rules, only the water used exclusively for 
cooling purposes is to be counted when determining whether the 25 
percent threshold in Sec.  125.131(a)(2) is met.

C. Would My Facility Be Covered if It Is a Point Source Discharger?

    This rule applies only to facilities that have an NPDES permit or 
are required to obtain one. This is the same requirement EPA included 
in the Phase I and Phase II final rules (see 40 CFR 125.81(a)(1) and 40 
CFR 125.91(a)(1), respectively). Requirements for complying with 
section 316(b) will continue to be applied through NPDES permits.
    The Agency recognizes that some facilities that have or are 
required to have an NPDES permit might not own and operate the intake 
structure that supplies their facility with cooling water. For example, 
facilities operated by separate entities might be located on the same, 
adjacent, or nearby property(ies); one of these facilities might take 
in cooling water and then transfer it to other facilities prior to 
discharge of the cooling water to a water of the United States. Section 
125.92(c) of this rule addresses such a situation. It provides that use 
of a cooling water intake structure includes obtaining cooling water by 
any sort of contract or arrangement with one or more independent 
suppliers of cooling water if the supplier withdraws water from waters 
of the United States. This provision is intended to prevent new Phase 
III facilities from circumventing the requirements of this rule by 
creating arrangements to receive cooling water from an entity that is 
not itself subject to the requirements of Phase III. EPA expects that a 
facility that is otherwise subject to the requirements of Phase I and 
that is an independent supplier to a Phase III facility would still be 
subject to the requirements of Phase I.

D. When Would a New Offshore Oil and Gas Extraction Facility Be 
Required To Comply With Any New 316(b) Requirements?

    This final rule will become effective July 17, 2006. After that 
date, new offshore oil and gas extraction Phase III facilities will 
need to comply when an NPDES permit containing requirements consistent 
with this rule is issued to the facility (see Sec.  125.132). Under 
current NPDES program regulations, this will occur when a new NPDES 
permit is issued or when an existing NPDES permit is issued, reissued, 
or modified or revoked and reissued.
    Most offshore oil and gas extraction facilities are covered by 
general permits issued by EPA. New offshore oil and gas extraction 
facilities that meet the applicability criteria for the Phase III rule 
may obtain permit coverage under these general permits until they 
expire. When EPA reissues these general permits, EPA will incorporate 
requirements based on today's rule. Facilities that are new offshore 
oil and gas extraction facilities, as defined in today's rule, will be 
subject to those Phase III section 316(b) new facility

[[Page 35009]]

requirements should they seek permit coverage under those reissued 
general permits.

III. Legal Authority, Purpose, and Background of This Final Regulation

A. Legal Authority

    This action is issued under the authority of sections 101, 301, 
308, 316, 401, 402, 501, and 510 of the Clean Water Act (CWA), 33 
U.S.C. 1251, 1311, 1318, 1326, 1341, 1342, 1361, and 1370. Publication 
of this action fulfills the final obligation of the U.S. Environmental 
Protection Agency (EPA) under a consent decree in Riverkeeper, Inc. v. 
Johnson, No. 93 Civ. 0314, (S.D.N.Y).

B. Purpose of This Regulation

    Section 316(b) of the CWA provides that any standard established 
pursuant to section 301 or 306 of the CWA and applicable to a point 
source must require that the location, design, construction, and 
capacity of cooling water intake structures reflect the best technology 
available for minimizing adverse environmental impact. This rule 
establishes requirements that apply to new offshore oil and gas 
extraction facilities that have a design intake flow threshold of 
greater than 2 MGD. This is the same design intake flow threshold as 
for new facilities in the Phase I rule. To be covered, a facility would 
need to use at least 25 percent of the water withdrawn exclusively for 
cooling purposes and meet other specified criteria in order to be 
within the scope of the rule (see section II--Scope and Applicability 
of Final Rule). In this action, EPA is not promulgating any new section 
316(b) requirements for existing facilities. Therefore, existing 
facilities that are not covered by the Phase II rule (Phase II is 
described in section III.C.5 of this preamble) must continue to meet 
requirements under Section 316(b) of the CWA determined by the 
permitting authority on a case-by-case, best professional judgment 
(BPJ) basis. See 40 CFR 125.90(b).

C. Background

1. The Clean Water Act
    The Federal Water Pollution Control Act, also known as the Clean 
Water Act (CWA), 33 U.S.C. 1251 et seq., seeks to ``restore and 
maintain the chemical, physical, and biological integrity of the 
nation's waters.'' 33 U.S.C. 1251(a). The CWA establishes a 
comprehensive regulatory program, key elements of which are (1) a 
prohibition on the discharge of pollutants from point sources to waters 
of the United States, except as authorized by the statute; (2) 
authority for EPA or authorized States or Tribes to issue National 
Pollutant Discharge Elimination System (NPDES) permits that regulate 
the discharge of pollutants; and (3) requirements for limitations in 
NPDES permits based on effluent limitations guidelines and standards 
and water quality standards.
    Section 316(b) addresses the adverse environmental impact caused by 
the intake of cooling water, not discharges into water. Despite this 
special focus, the requirements of section 316(b) are closely linked to 
several of the core elements of the NPDES permit program established 
under section 402 of the CWA to control discharges of pollutants into 
navigable waters. For example, while effluent limitations apply to the 
discharge of pollutants by NPDES-permitted point sources to waters of 
the United States, section 316(b) applies to facilities subject to 
NPDES requirements that withdraw water from waters of the United States 
for cooling and that use a cooling water intake structure to do so.
    Section 301 of the CWA prohibits the discharge of any pollutant by 
any person, except in compliance with specified statutory requirements, 
including section 402. Section 402 of the CWA provides authority for 
EPA or an authorized State or Tribe to issue an NPDES permit to any 
person discharging any pollutant or combination of pollutants from a 
point source into waters of the United States. Forty-five States and 
one U.S. territory are currently authorized under section 402(b) to 
administer the NPDES permitting program. NPDES permits restrict the 
types and amounts of pollutants, including heat, that may be discharged 
from various industrial, commercial, and other sources of wastewater. 
These permits control the discharge of pollutants primarily by 
requiring dischargers to meet effluent limitations established pursuant 
to section 301 or section 306. Effluent limitations are based on 
Federal effluent limitations guidelines and new source performance 
standards, or in cases where there are no applicable effluent 
guidelines or standards, on the best professional judgment of the 
permit writer. Limitations based on these guidelines, standards, or 
best professional judgment are known as technology-based effluent 
limits. Where technology-based effluent limits are inadequate to ensure 
attainment of water quality standards applicable to the receiving 
water, section 301(b)(1)(C) of the CWA requires permits to include more 
stringent limits based on applicable water quality standards. NPDES 
permits also routinely include monitoring and reporting requirements, 
and other conditions, including conditions to implement the 
requirements of section 316(b).
    Section 510 of the CWA provides that, except as provided in the 
CWA, nothing in the Act shall preclude or deny the right of any State 
or political subdivision thereof to adopt or enforce any requirement 
respecting control or abatement of pollution; except that if a 
limitation, prohibition or standard of performance is in effect under 
the CWA, such State or political subdivision may not adopt or enforce 
any other limitation, prohibition or standard of performance which is 
less stringent than the limitation, prohibition or standard of 
performance under the Act. EPA interprets this to reserve for the 
States authority to implement requirements that are more stringent than 
the Federal requirements under State law. PUD No. 1 of Jefferson County 
v. Washington Dep't of Ecology, 511 U.S. 700, 705 (1994).
    Under sections 301, 304, and 306 of the CWA, EPA issues effluent 
limitations guidelines and new source performance standards for 
categories of industrial dischargers based on the pollutants of concern 
discharged by the industry, the degree of control that can be attained 
using various levels of pollution control technology, consideration of 
economics, as appropriate to each level of control, and other factors 
identified in sections 304 and 306 of the CWA. EPA has promulgated 
regulations setting effluent limitations guidelines and standards under 
sections 301, 304, and 306 of the CWA for more than 50 industries. See 
40 CFR parts 405 through 471. EPA has established effluent limitations 
guidelines and standards that apply to most of the industry categories 
that use cooling water intake structures (e.g., steam electric power 
generation, iron and steel manufacturing, pulp and paper manufacturing, 
petroleum refining, and chemical manufacturing).
    Section 316(b) states that any standard established pursuant to 
section 301 or section 306 of [the Clean Water] Act and applicable to a 
point source shall require that the location, design, construction, and 
capacity of cooling water intake structures reflect the best technology 
available for minimizing adverse environmental impact.
    The phrase ``best technology available'' in CWA section 316(b) is 
not defined in the statute, but its meaning can be understood in light 
of similar phrases used elsewhere in the CWA. See Riverkeeper, Inc. v. 
EPA, 358 F.3d 174, 186 (2nd Cir. 2004) (noting that the cross-reference 
in CWA section 316(b) to CWA section 306 ``is an invitation to

[[Page 35010]]

look to section 306 for guidance in discerning what factors Congress 
intended the EPA to consider in determining ``best technology 
available'' for new sources).
    In sections 301 and 306, Congress directed EPA to set effluent 
discharge standards for new sources based on the ``best available 
demonstrated control technology'' and for existing sources based on the 
``best available technology economically achievable.'' For new sources, 
section 306(b)(1)(B) directs EPA to establish ``standards of 
performance.'' The phrase ``standards of performance'' under section 
306(a)(1) is defined as being the effluent reduction that is 
``achievable through application of the best available demonstrated 
control technology, processes, operating methods or other alternatives 
* * * .'' This is commonly referred to as ``best available demonstrated 
technology'' or ``BADT.'' For existing dischargers, section 
301(b)(1)(A) requires the establishment of effluent limitations based 
on ``the application of best practicable control technology currently 
available.'' This is commonly referred to as ``best practicable 
technology'' or ``BPT.'' Further, section 301(b)(2)(A) directs EPA to 
establish effluent limitations for certain classes of pollutants 
``which shall require the application of the best available technology 
economically achievable.'' This is commonly referred to as ``best 
available technology'' or ``BAT.'' Section 301 specifies that both BPT 
and BAT limitations must reflect determinations made by EPA under CWA 
section 304. Under these provisions, the limitations on the discharge 
of pollutants from point sources are based upon the capabilities of the 
equipment or ``control technologies'' available to control those 
discharges.
    The phrases ``best available demonstrated technology'' and ``best 
available technology''--like ``best technology available'' in CWA 
section 316(b)--are not defined in the statute. However, section 304 of 
the CWA specifies factors to be considered in establishing the best 
practicable control technology currently available and best available 
technology.
    For best practicable control technology currently available, the 
CWA directs EPA to consider the total cost of application of technology 
in relation to the effluent reduction benefits to be achieved from such 
application, and shall also take into account the age of the equipment 
and facilities involved, the process employed, the engineering aspects 
of the application of various types of control techniques, process 
changes, non-water quality environmental impact (including energy 
requirements), and such other factors as [EPA] deems appropriate. (33 
U.S.C. 1314(b)(1)(B)).
    For ``best available technology,'' the CWA directs EPA to consider 
the age of equipment and facilities involved, the process employed, the 
engineering aspects * * * of various types of control techniques, 
process changes, the cost of achieving such effluent reduction, non-
water quality environmental impacts (including energy requirements), 
and such other factors as [EPA] deems appropriate. (33 U.S.C. 
1314(b)(2)(B)).
    Section 316(b) expressly refers to section 301, and the phrase 
``best technology available'' is very similar to ``best available 
technology'' in that section. These facts, coupled with the brevity of 
section 316(b) itself, prompted EPA to look to section 301 and, 
ultimately, section 304 for guidance in determining the ``best 
technology available to minimize adverse environmental impact'' of 
cooling water intake structures for Phase III existing facilities.
    By the same token, however, there are significant differences 
between section 316(b) and sections 301 and 304. See Riverkeeper, 358 
F.3d at 186 (``not every statutory directive contained [in sections 301 
and 306] is applicable'' to a section 316(b) rulemaking). Section 
316(b) requires that cooling water intake structures reflect ``the best 
technology available for minimizing adverse environmental impact.'' In 
contrast to the effluent limitations provisions, the object of the 
``best technology available'' is explicitly articulated by reference to 
the receiving water: To minimize adverse environmental impact in the 
waters from which cooling water is withdrawn. In other words, EPA must 
consider the receiving water effects of the candidate technologies.
    Because section 316(b) is silent as to the factors EPA should 
consider in deciding whether a candidate technology minimizes adverse 
environmental impact, EPA has broad discretion to identify the 
appropriate criteria. See Riverkeeper, 358 F.3d at 187, n.12 (brevity 
of section 316(b) reflects an intention to delegate significant 
rulemaking authority to EPA); see id. at 195 (appellate courts give EPA 
``considerable discretion to weigh and balance the various factors'' 
where the statute does not state what weight should be accorded) 
(citation omitted).
    For this Phase III rulemaking, EPA therefore interprets the phrase 
``best available technology for minimizing adverse environmental 
impacts'' as authorizing EPA to consider the relationship of the costs 
of the technologies to the benefits associated with them. EPA has 
previously considered the costs of technologies in relation to the 
benefits of minimizing adverse environmental impact in establishing 
section 316(b) limits, which historically have been done on a case-by-
case basis. In Re Public Service Co. of New Hampshire, 10 ERC 1257 
(June 17, 1977); In Re Public Service Co. of New Hampshire, 1 EAD 455 
(Aug. 4, 1978); Seacoast Anti-Pollution League v. Costle, 597 F.2d 306 
(1st Cir. 1979).
    In addition to helping EPA determine the effects of candidate 
technologies on the receiving water, considering the relationship of 
costs and benefits also helps EPA determine whether the technologies 
are economically practicable. EPA has long recognized, with the support 
of legislative history, that section 316(b) does not require adverse 
environmental impact to be minimized beyond that which can be achieved 
at an economically practicable cost. See 118 Cong. Rec. 33762 (1972) 
reprinted in 1 Legislative History of the Water Pollution Control Act 
Amendments of 1972, at 264 (1973) (Statement of Representative Don H. 
Clausen). EPA therefore may consider costs and benefits in deciding 
whether any of the technology options for Phase III existing facilities 
actually do minimize adverse environmental impact--or whether the 
choice of technologies should be left to BPJ decision-making. When the 
costs of establishing a national categorical rule substantially 
outweigh the benefits of such a rule, a national categorical section 
316(b) rule may not be economically practicable, and therefore not the 
``best technology available for minimizing adverse environmental 
impact.''
    Nothing in section 316(b) requires EPA to promulgate a regulation 
to implement the requirements for cooling water intake structures. 
Section 316(b) of the CWA grants EPA broad authority to establish 
performance standards for cooling water intake structures based on the 
``best technology available to minimize adverse environmental impact.'' 
Although EPA has chosen under section 316(b) to promulgate national 
categorical performance standards applicable to certain classes of 
point sources using cooling water intake structures, see 40 CFR part 
125, Subpart I (new facilities), Subpart J (existing power generating 
facilities), and Subpart N (new offshore oil and gas facilities), the 
statute does not preclude EPA from determining BTA on a site-specific 
basis. Indeed, the U.S. Court of

[[Page 35011]]

Appeals for the Second Circuit, in upholding virtually the entire 
316(b) Phase I rule for new facilities, specifically noted that section 
316(b) does not compel EPA to regulate cooling water intake structures 
using any particular format, e.g. overarching regulation, different 
regulations for different categories of sources, or individually on a 
case-by-case basis. Riverkeeper, 358 F.3d at 203. In fact, EPA and 
state permitting authorities have been implementing Section 316(b) on a 
case-by-case basis for over 25 years (see Section III.C.3 below), and 
courts have recognized this practice as consistent with the statute. 
See Hudson Riverkeeper Fund v. Orange & Rockland Utils., Inc., 835 F. 
Supp. 160, 165 (S.D.N.Y. 1993) (``This leaves to the Permit Writer an 
opportunity to impose conditions on a case-by-case basis, consistent 
with the statute * * * ''). Moreover, in both the Phase I and II rules, 
EPA uses a case-by-case, BPJ permitting regime for facilities that do 
not meet the applicability criteria for EPA's national categorical 
rules. See 40 CFR 125.81(a), 125.90(b). In Riverkeeper, this provision 
of the Phase I rule was upheld by the Second Circuit. 358 F.3d at 203 
(``[w]e see no textual bar in sections 306 or 316(b) to regulating 
below-threshold structures on a case-by-case basis.'').
2. Consent Decree
    This final action fulfills EPA's obligation to comply with the 
Second Amended Consent Decree, which was filed on November 25, 2002, in 
the United States District Court, Southern District of New York, in 
Riverkeeper, Inc. v. Johnson, No. 93 Civ 0314 (AGS). That case was 
brought against EPA by a coalition of individuals and environmental 
groups. The original Consent Decree, filed on October 10, 1995, 
provided that EPA was to propose regulations implementing section 
316(b) by July 2, 1999, and take final action with respect to those 
regulations by August 13, 2001. Under subsequent interim orders, the 
Amended Consent Decree filed on November 22, 2000, and the Second 
Amended Consent Decree, EPA divided the rulemaking into three phases. 
EPA took final action promulgating a rule governing cooling water 
intake structures used by new facilities (Phase I) on November 9, 2001 
(66 FR 65255, December 18, 2001). EPA took final action promulgating a 
rule governing cooling water intake structures used by large existing 
power producers (Phase II) on February 16, 2004 (69 FR 41576, July 9, 
2004). The consent decree further requires that EPA propose by November 
1, 2004, and take final action on by June 1, 2006 regulations 
applicable to the following categories: Utility and non-utility power 
producers not covered by the Phase II regulations, pulp and paper 
manufacturing, petroleum and coal products manufacturing, chemical and 
allied products manufacturing, and primary metals manufacturing (Phase 
III). EPA proposed Phase III regulations on November 1, 2004 (69 FR 
68444) and this final action fulfills EPA's obligations for Phase III.
3. What Other EPA Rulemakings and Guidance Address Cooling Water Intake 
Structures?
    In April 1976, EPA published a final rule under section 316(b) that 
addressed cooling water intake structures. 41 FR 17387 (April 26, 
1976), see also the proposed rule at 38 FR 34410 (December 13, 1973). 
The rule added a new Sec.  401.14 to 40 CFR Chapter I that reiterated 
the requirements of CWA section 316(b). It also added a new part 402, 
which included three sections: (1) Sec.  402.10 (Applicability), (2) 
Sec.  402.11 (Specialized definitions), and (3) Sec.  402.12 (Best 
technology available for cooling water intake structures). Section 
402.10 stated that the provisions of part 402 applied to ``cooling 
water intake structures for point sources for which effluent 
limitations are established pursuant to section 301 or standards of 
performance are established pursuant to section 306 of the Act.'' 
Section 402.11 defined the terms ``cooling water intake structure,'' 
``location,'' ``design,'' ``construction,'' ``capacity,'' and 
``Development Document.'' Section 402.12 included the following 
language:

    The information contained in the Development Document shall be 
considered in determining whether the location, design, 
construction, and capacity of a cooling water intake structure of a 
point source subject to standards established under section 301 or 
306 reflect the best technology available for minimizing adverse 
environmental impact.

    In 1977, fifty-eight electric utility companies challenged those 
regulations, arguing that EPA had failed to comply with the 
requirements of the Administrative Procedure Act (APA) in promulgating 
the rule. Specifically, the utilities argued that EPA had neither 
published the Development Document in the Federal Register nor properly 
incorporated the document into the rule by reference. The United States 
Court of Appeals for the Fourth Circuit agreed and, without reaching 
the merits of the regulations themselves, remanded the rule. 
Appalachian Power Co. v. Train, 566 F.2d 451 (4th Cir. 1977). EPA later 
withdrew part 402.44 FR 32956 (June 7, 1979). The regulation at 40 CFR 
401.14, which reiterates the statutory requirement, remains in effect.
    Since the Fourth Circuit remanded EPA's section 316(b) regulations 
in 1977, NPDES permit authorities have made decisions implementing 
section 316(b) on a case-by-case, site-specific basis. EPA published 
draft guidance addressing section 316(b) implementation in 1977. See 
Draft Guidance for Evaluating the Adverse Impact of Cooling Water 
Intake Structures on the Aquatic Environment: Section 316(b) P.L. 92-
500 (U.S. EPA, 1977). This draft guidance described the studies 
recommended for evaluating the impact of cooling water intake 
structures on the aquatic environment and recommended a basis for 
determining the best technology available for minimizing adverse 
environmental impact. The 1977 section 316(b) draft guidance states, 
``The environmental-intake interactions in question are highly site-
specific and the decision as to best technology available for intake 
design, location, construction, and capacity must be made on a case-by-
case basis.'' (Section 316(b) Draft Guidance, U.S. EPA, 1977, p. 4). 
This case-by-case approach was also consistent with the approach 
described in the 1976 Development Document referenced in the remanded 
regulation.
    The 1977 section 316(b) draft guidance suggested a general process 
for developing information needed to support section 316(b) decisions 
and presenting that information to the permitting authority. The 
process involved the development of a site-specific study of the 
environmental effects associated with each facility that uses one or 
more cooling water intake structures, as well as consideration of that 
study by the permitting authority in determining whether the facility 
must make any changes for minimizing adverse environmental impact. 
Where adverse environmental impact is present, the 1977 draft guidance 
suggested a stepwise approach that considers size, location, capacity, 
available technology, and other factors.
    The draft guidance left the decisions on the appropriate location, 
design, capacity, and construction of cooling water intake structures 
to the permitting authority. Under this framework, the Director 
determined whether appropriate studies have been performed, whether a 
given facility has minimized adverse environmental impact, and what, if 
any, technologies may be required.
4. Phase I New Facility Rule
    On November 9, 2001, EPA took final action on Phase I regulations 
governing

[[Page 35012]]

cooling water intake structures at new facilities. 66 FR 65255 
(December 18, 2001). On December 26, 2002, EPA made minor changes to 
the Phase I regulations. 67 FR 78947. The final Phase I new facility 
rule (40 CFR part 125, Subpart I) establishes requirements applicable 
to the location, design, construction, and capacity of cooling water 
intake structures at new facilities that withdraw greater than two (2) 
MGD and use at least twenty-five (25) percent of the water they 
withdraw solely for cooling purposes.
    With the new facility rule, EPA promulgated national minimum 
requirements for the location, design, capacity, and construction of 
cooling water intake structures at new facilities. The final new 
facility rule establishes a reasonable framework that creates certainty 
for permitting of new facilities, while providing significant 
flexibility to take site-specific factors into account.
    EPA specifically excluded new offshore oil and gas extraction 
facilities from the Phase I new facility rule, but committed to 
consider establishing requirements for such facilities in the Phase III 
rulemaking. 66 FR 65338 (December 18, 2001).
5. Phase II Existing Facility Rule
    On February 16, 2004, EPA took final action on regulations 
governing cooling water intake structures at certain existing power 
producing facilities. 69 FR 41576 (July 9, 2004). The final Phase II 
rule applies to existing facilities that are point sources; that, as 
their primary activity, both generate and transmit electric power or 
generate electric power for sale to another entity for transmission; 
that use or propose to use cooling water intake structures with a total 
design intake flow of 50 MGD or more to withdraw cooling water from 
waters of the United States; and that use at least 25 percent of the 
withdrawn water exclusively for cooling purposes.
    Under the Phase II rule, EPA established performance standards for 
the reduction of impingement mortality and entrainment (see 40 CFR 
125.94). The performance standards consist of ranges of reductions in 
impingement mortality and/or entrainment. These performance standards 
reflect the best technology available for minimizing adverse 
environmental impacts at facilities covered by the Phase II rule. The 
type of performance standard applicable to a particular facility (i.e., 
reductions in impingement mortality only or impingement mortality and 
entrainment) is based on several factors, including the facility's 
location (i.e., source waterbody), rate of use (capacity utilization 
rate), and the proportion of the waterbody withdrawn. The Phase II 
regulations address more than 90 percent of total cooling water intake 
flows in the United States.
6. Public Participation
    EPA worked extensively with stakeholders from industry, public 
interest groups, State agencies, and other Federal agencies in the 
development of this rule. EPA included industry groups, environmental 
groups, and other government entities in the development, testing, 
refinement, and completion of the section 316(b) survey, which was used 
as a primary source of data for Phase III. As discussed in section III 
of this preamble, the survey, ``Information Collection Request, 
Detailed Industry Questionnaires: Phase II Cooling Water Intake 
Structures & Watershed Case Study Short Questionnaire,'' was initiated 
in 1997, and was used to collect data during 2000.
    EPA sponsored a Symposium on Cooling Water Intake Technologies to 
Protect Aquatic Organisms, on May 6-7, 2003. This symposium brought 
together professionals from Federal, State, and Tribal regulatory 
agencies; industry; environmental organizations; engineering consulting 
firms; science and research organizations; academia; and others 
concerned with mitigating harm to the aquatic environment by cooling 
water intake structures. Efficacy and costs of various technologies to 
mitigate impacts to aquatic organisms from cooling water intake 
structures, as well as research and other future needs, were discussed.
    During the development of this regulation, EPA met several times 
with trade associations whose members would be subject to Phase III 
requirements. EPA also conducted Phase III-specific data collection 
activities, including a study of entrainment at Phase III facilities, 
contacting Phase III facilities to request biological studies and 
conducting an industry survey of offshore oil and gas extraction 
facilities and seafood processing vessels.
    In developing requirements for new offshore oil and gas extraction 
facilities, EPA drew on its experience from the offshore oil and gas, 
the coastal oil and gas, and the synthetic drilling fluids effluent 
limitations guidelines, which included extensive public outreach, 
meetings, public comment periods, industry surveys, and economic 
analysis and modeling of representative oil and gas operations as 
detailed in 61 FR 66086-66130 and 66 FR 6849-6919.
    Finally, EPA convened a Small Business Advocacy Review (SBAR) panel 
(in accordance with the Regulatory Flexibility Act section 609(b) as 
amended by the Small Business Regulatory and Enforcement Fairness Act) 
to provide information to small entities and receive feedback during 
the Phase III rulemaking process. EPA hosted a pre-panel outreach 
meeting for small entities potentially subject to Phase III on January 
22, 2004. The SBAR panel held an outreach meeting with small entity 
representatives (SERs) on March 16, 2004. Based on the information 
gathered from the participating small entities during these outreach 
meetings and subsequent correspondence, the SBAR panel produced a final 
report to the EPA Administrator on April 27, 2004. Results of the final 
report were considered in the development of the Phase III rule.
    These coordination efforts and all of the meetings described in 
this section, as well as the comments submitted on the Phase I and II 
section 316(b) rules and EPA's response to these comments, are 
documented or summarized in the dockets for these three rules. The 
Administrative Record for this rule includes all materials from the 
Phase I, Phase II, and Phase III section 316(b) rule dockets.

IV. Environmental Impacts Associated With Cooling Water Intake 
Structures

    EPA has identified a variety of environmental impacts that may be 
associated with cooling water intake structures at Phase III 
facilities, depending on conditions at an individual facility's site. 
These impacts include organism entrainment and impingement, which can 
contribute to impacts to threatened and endangered species; reductions 
in ecologically critical aquatic organisms, including important 
elements of an ecosystem's food chain; diminishment of population 
compensatory reserves; losses to populations, including reductions of 
commercial and recreational fisheries; and stresses to overall 
communities and ecosystems as evidenced by reductions in diversity, 
changes in species composition, or other changes in ecosystem structure 
or function. (See discussion at 69 FR 68461-66.)
    The withdrawal of water affects a variety of aquatic organisms 
including phytoplankton (tiny, free-floating photosynthetic organisms 
suspended in the water column), zooplankton (small aquatic animals, 
including fish eggs and larvae, which may consume phytoplankton and 
other zooplankton), macroinvertebrates, shellfish, and fish. Other 
organisms, including reptiles,

[[Page 35013]]

birds, and mammals can also be impinged or entrained.
    Impingement takes place when organisms are trapped against a 
cooling water intake structure, particularly screening materials, by 
the force of water being drawn through the intake structure. The 
velocity of the water intake by the structure can remove fish scales or 
other organism structures, prevent proper gill function, or otherwise 
physically harm or cause the death of impinged organisms through 
exhaustion, starvation, asphyxiation, and descaling or other injury. 
Death from impingement (``impingement mortality'') can take place while 
organisms are impinged on an intake structure or it can take place 
after organisms have escaped impingement and have returned to a 
waterbody. An organism can die despite escaping impingement because of 
injuries it receives during the impingement process.
    Entrainment occurs when organisms are drawn through a cooling water 
intake structure into a facility's cooling system. Organisms that 
become entrained are typically relatively small aquatic organisms, 
including many early life stages of fish and shellfish. As entrained 
organisms pass through a facility's cooling system they can be subject 
to mechanical, thermal, and/or, chemical stress. Sources of stress 
include physical impacts in the pumps and condenser tubing, pressure 
changes caused by diversion of the cooling water into the plant or by 
the hydraulic effects of the condensers, shear stress, thermal shock in 
the condenser and discharge tunnel, and chemical toxic effects from 
cooling system antifouling agents such as chlorine. Similar to 
impingement mortality, death from entrainment can occur during 
entrainment or at some time after the entrainment and return of 
entrained organisms to a waterbody.

Environmental Impacts from New Offshore Oil and Gas Extraction Facility 
Cooling Water Intake Structures

    Offshore oil and gas extraction facilities currently operate off 
the coasts of California and Alaska and throughout the Gulf of Mexico. 
Most activity currently takes place in the Gulf of Mexico. EPA expects 
that most new facility activity will also take place in this region. 
(See Phase III TDD; DCN [9-0004], Chapter 3.)
    While EPA is not aware of any studies that directly examine or 
document impingement mortality and entrainment by offshore oil and gas 
extraction facilities, numerous studies show that offshore marine 
environments provide habitat for a number of species of fish, 
shellfish, and other aquatic organisms. Many of these species have life 
stages that are small and planktonic or have limited swimming ability. 
These life stages are potentially vulnerable to entrainment by cooling 
water intake structures. Larger life stages are potentially vulnerable 
to impingement. The introduction of cooling water intake structures 
into the offshore habitat in which these organisms live creates the 
potential for impingement and entrainment of these organisms.
    The densities of organisms in the immediate vicinity of offshore 
oil and gas extraction facilities relative to densities in estuaries 
and other nearshore coastal waters is not well characterized. In the 
Phase III Notice of Data Availability (NODA) (70 FR 71059), EPA 
presented an analysis of additional data from the general regions in 
which existing offshore oil and gas extraction facilities operate and 
where new facilities might operate in the future in order to better 
characterize the potential for impingement and entrainment by these 
facilities.
    EPA obtained data on densities of ichthyoplankton (planktonic fish 
eggs and larvae) in the Gulf of Mexico from the Southeast Area 
Monitoring and Assessment Program (SEAMAP).12 
This long-term sampling program collects information on the density of 
fish eggs and larvae throughout the Gulf of Mexico. EPA analyzed the 
SEAMAP data to determine average ichthyoplankton densities in the Gulf 
of Mexico for the period of time for which sampling data was available 
(1982-2003). Actual conditions at any one location and at any one point 
in time may vary from the calculated averages.
---------------------------------------------------------------------------

    \1\ Adam Rettig and Blaine Snyder, Tetra Tech, Inc. Memorandum 
to Ashley Allen, EPA. A summary of ichthyoplankton presence and 
abundance in the Gulf of Mexico, as part of an assessment of the 
potential for entrainment by offshore oil and gas facilities. 2005. 
DCN 8-5220. Document ID OW-2004-0002-951.
    \2\ Adam Rettig and Blaine Snyder, Tetra Tech, Inc. Memorandum 
to Ashley Allen, EPA. A Summary of Fish Egg Presence and Abundance 
in the Gulf of Mexico, as Part of an Assessment of the Potential for 
Entrainment by Offshore Oil and Gas Facilities. DCN 9-5200.
---------------------------------------------------------------------------

    EPA's analysis of the SEAMAP data indicates that ichthyoplankton 
occur throughout the Gulf of Mexico. On average, densities are highest 
at sampling stations in the shallower regions of the Gulf of Mexico and 
lowest at sampling stations in the deepest regions. The overall range 
of average larval fish densities was calculated to be 25-450+organisms/
100m \3\ The wide range of ichthyoplankton densities seen in the 
offshore Gulf of Mexico region falls within the range of larval fish 
densities documented in freshwater and coastal water bodies in various 
coastal and inland regions of the United States.\4\ Over 600 different 
fish taxa were identified in the SEAMAP samples, including species of 
commercial and recreational utility.
---------------------------------------------------------------------------

    \3\ Average larval fish densities are greater than 450 
organisms/100 m3 at sampling stations in waters less than 50 meters 
deep. Average larval fish densities gradually decrease to 100 
organisms/100 m3 as sampling station depth-at-location increases to 
150 meters. At stations in waters greater than 150 meters deep, 
larval fish densities are relatively uniform and fall between 25 
organisms/100 m3 and 100 organisms/100 m3. See Document ID OW-2004-
0002-951.
    \4\ A. L. Allen (EPA). Memorandum to EPA Docket OW-2004-0002. 
Summary of Information on Ichthyoplankton Densities in Various 
Aquatic Ecosystems in the United States. DCN 8-5240.
---------------------------------------------------------------------------

    In the area surrounding existing offshore oil and gas extraction 
facilities off the California coast, the California Cooperative Oceanic 
Fisheries Investigations (CalCOFI) program has gathered data on 
densities of ichthyoplankton and other organisms. According to the 
CalCOFI and other research programs, a number of fish and shellfish 
species, including species of commercial and recreational value, are 
known to live and spawn in this region. EPA does not know of similarly 
extensive sampling programs for the Alaska offshore region. However, a 
number of fish and shellfish species, including species of commercial 
and recreational value, are known from various research programs to 
live and spawn in the offshore regions of Alaska where oil and gas 
extraction activities currently take place or may take place in the 
future.\5\ The eggs and larvae of many species found in the offshore 
regions of California and Alaska are planktonic and could therefore be 
vulnerable to entrainment by a facility's cooling water intake 
structure operating in these regions. Larger life stages (e.g., 
juveniles and adults) could be vulnerable to impingement.
---------------------------------------------------------------------------

    \5\ A.L. Allen (EPA). Memorandum to EPA Docket OW-2004-0002. 
Summary of Information on Fish Species that Live and Spawn off the 
Coasts of Alaska and California in the Vicinity of Offshore Oil and 
Gas Production Areas. DCN 8-5260.
---------------------------------------------------------------------------

    The densities of organisms in the immediate vicinity of offshore 
oil and gas extraction facilities may differ from those suggested by 
analysis of SEAMAP and other collections of data that characterize 
typical organism densities in marine waters. Offshore oil and gas 
extraction facilities have been shown to attract and concentrate 
aquatic organisms in the immediate vicinity of the underwater portions 
of their structures. A variety of species of pelagic fish have been 
found to gather around the underwater portions of

[[Page 35014]]

offshore oil and gas extraction facilities within short time periods 
after the facilities' appearance in the water column. If a facility 
remains in one place for a sufficient length of time, some aquatic 
organism species take up residence directly upon the underwater 
structure and form reef-like communities. The increased number of 
organisms living near the underwater portion of facilities where 
cooling water intake structures are located increases the potential for 
impingement mortality and entrainment of those organisms. The extent to 
which the increased numbers of aquatic organisms represents an overall 
increase in organism populations, rather than a concentration of 
organisms from surrounding areas, is not known. (For additional 
information, see DCN 7-0013.)
    EPA believes the data it has gathered on organisms that inhabit 
offshore environments indicate the potential for their entrainment and 
impingement by cooling water intake structures associated with new 
offshore oil and gas extraction facilities. Given this potential for 
impingement and entrainment, EPA believes that these new facilities 
have the potential to create multiple types of undesirable and 
unacceptable impacts.

V. Description of the Rule

    In this rule, EPA is promulgating requirements for new offshore and 
coastal oil and gas extraction facilities that are designed to withdraw 
at least 2 MGD. New offshore oil and gas extraction facilities were 
specifically excluded from the scope of the Phase I new facility rule 
so that EPA could gather additional data on these facilities (see 66 FR 
65311). This final action also announces EPA's decision not to 
promulgate a national rule for existing Phase III facilities.

A. Final Rule for New Offshore Oil and Gas Extraction Facilities

    This rule establishes national requirements for new offshore and 
coastal oil and gas extraction facilities that have a design intake 
flow of 2 MGD or greater and that withdraw at least 25 percent of the 
water exclusively for cooling purposes and meet other applicability 
criteria (see Sec.  125.131). This rule imposes requirements for the 
reduction of impingement mortality on all facilities subject to the 
rule; a subset of these facilities must comply with requirements for 
the reduction of entrainment. Specifically, fixed \6\ facilities 
without sea chests are required to comply with entrainment standards. 
EPA has established a two-track approach to offer maximum flexibility. 
Fixed facilities may choose to comply under Track I or Track II, but 
non-fixed facilities must comply under Track I. Track I establishes 
uniform requirements based on facility type (i.e., fixed or non-fixed) 
and, for fixed facilities the types of intake structures used (i.e., 
sea chest or non-sea chest). Under Track I, facilities are required to 
design their cooling water intake structures to meet a through-screen 
velocity of 0.5 feet per second or less. If they are a fixed facility 
and are located in estuaries or tidal rivers, they would also be 
required to meet proportional flow requirements. All facilities would 
need to implement technologies and/or operational measures for 
minimizing impingement if the permitting authority determines that 
there are protected species or critical habitat for those species, or 
species of impingement concern within the hydrologic zone of influence 
of the cooling water intake structure, or (based on available 
information, including information from fishery management agencies) 
that the proposed facility, after meeting the technology-based 
performance requirements, would still contribute unacceptable stress to 
protected species or critical habitat of those species, or species of 
concern. Fixed facilities that do not employ sea chests (openings in 
the hull of a vessel for withdrawing cooling water) are required to use 
fish protection technologies and/or operational measures to minimize 
entrainment.
---------------------------------------------------------------------------

    \6\ A fixed facility is defined as a bottom founded offshore oil 
and gas extraction facility permanently attached to the seabed or 
subsoil of the outer continental shelf (e.g., platforms, guyed 
towers, articulated gravity platforms) or a buoyant facility 
securely and substantially moored so that it cannot be moved without 
a special effort (e.g., tension leg platforms, permanently moored 
semi-submersibles) and which is not intended to be moved during the 
production life of the well.
---------------------------------------------------------------------------

    As with other new facilities covered by the Phase I rule, fixed 
facilities could comply under Track II, which allows the facility to 
employ alternative technologies that the facility demonstrates provide 
comparable performance to meeting the 0.5 ft/s velocity standard, and 
for fixed facilities without sea chests, the requirement to minimize 
entrainment. EPA did not extend this provision to mobile facilities, as 
EPA does not believe that there were alternatives to the low-velocity 
standard for mobile facilities. Further, a Track II demonstration 
generally requires consideration of site-specific factors. Since mobile 
facilities are designed to operate at multiple locations over their use 
life, it is generally not possible for them to provide in advance the 
information that would be necessary for a Track II demonstration.
    As described in Sec.  125.135, facilities have the opportunity to 
conduct a cost-cost test and provide data to show that compliance with 
the requirements of Sec.  125.134 would result in compliance costs 
wholly out of proportion to those EPA considered in establishing the 
requirements, or would result in significant adverse impacts on local 
water resources other than impingement or entrainment, or significant 
adverse impacts on energy markets. In this case, alternative 
requirements may be imposed in the permit. See the Phase I final 
preamble for a more detailed explanation of this cost-cost test at 66 
FR 65322, which is different than the cost-cost test for Phase II 
facilities.
    These final requirements for new offshore oil and gas extraction 
facilities are essentially unchanged from the Phase III proposal. In 
response to comments, however, EPA is not promulgating national 
entrainment controls for fixed facilities with sea chests or mobile 
facilities in this final rule. EPA's data suggest that the only 
physical technology controls for entrainment at facilities with sea 
chests and non-fixed (i.e., mobile) facilities would entail 
installation of equipment projecting beyond the hull of the vessel or 
facility. Such controls may not be practical or feasible since the 
configuration may alter fluid dynamics and impede safe seaworthy 
travel, even for new facilities that could avoid the challenges of 
retrofitting control technologies.
    EPA also proposed national categorical requirements for Phase III 
existing facilities that use or propose to use a cooling water intake 
structure to withdraw cooling water from waters of the United States 
and that are point sources and use at least 25 percent of the water 
withdrawn exclusively for cooling purposes. As proposed, Phase III 
would have included either existing facilities on all waterbody types 
that had a design intake flow of 50 MGD or greater, existing facilities 
on all waterbody types that has a design intake flow of 200 MGD or 
greater, or those existing facilities with a design intake flow of 100 
MGD or greater which were located on sensitive waterbodies (i.e., 
estuaries, tidal rivers, coastal waters, or the Great Lakes). 
Facilities not meeting these applicability criteria would have 
continued to be subject to 316(b) requirements set by the Director on a 
case-by-case basis. EPA also proposed the option of not promulgating 
national categorical requirements for existing

[[Page 35015]]

facilities potentially covered by Phase III in which case all Phase III 
existing facilities would have continued to be subject to 316(b) 
requirements set by the Director on a case-by-case basis.
    For existing Phase III facilities meeting the selected threshold, 
the proposed rule would have established national performance standards 
for the reduction of impingement mortality and in some cases 
entrainment at land-based Phase III existing facilities (i.e., non-
offshore facilities). The performance standards applicable to a 
particular facility (i.e., reductions in impingement only or 
impingement and entrainment) were based on several factors, including 
the facility's location (i.e., source waterbody) and the proportion of 
the waterbody withdrawn. Under the proposed rule, the performance 
standards could have been met, in whole or in part, by using design and 
construction technologies, operational measures, or restoration 
measures.
    EPA rejected the proposed requirements for existing Phase III 
facilities for the reasons set forth in Section VI.B below. This 
section discusses EPA's reasoning in detail as applied to the lead 
option (the 50 MGD option). EPA's reasons for rejecting the 100 MGD and 
200 MGD option were similar. In particular, the cost-benefit ratios 
were still unacceptable and there would have been even fewer facilities 
that would ultimately have been regulated by the rule and even smaller 
incremental environmental improvements that the regulation would have 
realized when compared to the significant environmental gains 
attributed to the Phase II rule.

B. Existing Facilities With Cooling Water Intake Structures

    For existing Phase III facilities, EPA determined that uniform 
national technology-based standards are not the most effective way to 
address their cooling water intake structures because the monetized 
costs of such standards would have been wholly disproportionate to 
their monetized use benefits. Accordingly, EPA believes that it is 
better at this time to utilize the existing National Pollutant 
Discharge Elimination System (NPDES) program for existing Phase III 
facilities, which provides that any NPDES permitted facility not 
subject to the national categorical requirements in Phase I, Phase II, 
or Phase III of EPA's 316(b) regulation development is subject to 
section 316(b) requirements set by the Director on a case-by-case best 
professional judgment basis. Examples of such facilities include 
existing power generators with a design intake flow of less than 50 
MGD, and new seafood processing vessels, and existing manufacturers.
    These requirements must ensure that the location, design, 
construction and capacity of any cooling water intake structure reflect 
the best technology available for minimizing adverse environmental 
impact. Because the factors that EPA considered in evaluating candidate 
options for a national categorical determination of BTA vary 
considerably from site to site, including technology costs and 
feasibility, potential for adverse environmental impacts, and 
relationship of costs to benefits, EPA believes that for Phase III 
facilities a BPJ-based site specific approach is the best way to ensure 
that each Phase III existing facility adopts BTA appropriate to its 
site. The basis for this determination is further discussed in Section 
VI.B. below.
    This rule does not alter the regulatory requirements for facilities 
subject to the Phase I or Phase II regulations.

VI. Basis for the Final Rule Decision

    This section discusses EPA's basis for final requirements 
applicable to new offshore oil and gas extraction facilities and EPA's 
decision to continue to rely on case-by-case, best professional 
judgment permit conditions implementing CWA section 316(b) at existing 
Phase III facilities.

A. Why Is EPA Promulgating National Requirements for New Offshore and 
Coastal Oil and Gas Extraction Facilities?

    After EPA proposed the Phase I rule for new facilities (65 FR 
49060, August 10, 2000), the Agency received adverse comment from 
operators of offshore and coastal (collectively ``offshore'') drilling 
facilities concerning the limited information about their cooling water 
intakes, associated impingement mortality and entrainment, costs of 
technologies, or achievability of the controls proposed by EPA for new 
facilities. On May 25, 2001, EPA published a Notice of Data 
Availability (NODA) for Phase I that, in part, sought additional data 
and information about mobile offshore and coastal drilling facilities 
(see 66 FR 28857). EPA was not able to fully consider this additional 
information in time to address new offshore oil and gas facilities in 
the final Phase I rule. Accordingly, in the Phase I final rule, EPA 
committed to ``propose and take final action on regulations for new 
offshore oil and gas extraction facilities, as defined at 40 CFR 435.10 
and 40 CFR 435.40, in the Phase III section 316(b) rule.'' See 66 FR 
65256. This regulation fulfills that commitment and establishes 
national requirements for new offshore oil and gas extraction 
facilities that meet the applicability requirements in Sec.  125.131.
    Requirements for new offshore oil and gas extraction facilities are 
specified in a new Subpart N of Part 125. New onshore oil and gas 
extraction facilities are currently regulated by section 316(b) Phase I 
requirements if these facilities meet the applicability criteria of the 
316(b) Phase I regulations. As described in more detail below, the 
requirements for the offshore facilities are similar to some, but not 
all, of the requirements contained in the Phase I rule applicable to 
other new facilities. For example, the Phase I requirement to reduce 
intake flow commensurate with a closed-cycle, recirculating cooling 
system does not apply to these offshore facilities.
    This rule distinguishes between new offshore oil and gas facilities 
that are ``fixed,'' and those that are not fixed. For ``fixed'' 
facilities, the rule further distinguishes between those with sea 
chests and those without. Under this rule, new offshore oil and gas 
extraction facilities that meet the applicability criteria in Sec.  
125.131 and that employ sea chests as cooling water intake structures 
and are fixed facilities would have to comply with the requirements in 
Sec.  125.134(b)(1)(ii). These requirements address intake flow 
velocity, percentage of the source waterbody withdrawn (if applicable), 
specific impact concerns (e.g., threatened or endangered species, 
critical habitat, migratory or sport or commercial species), required 
information submission, monitoring, and recordkeeping. Under this rule, 
new offshore oil and gas extraction facilities that meet the 
applicability criteria in Sec.  125.131, that do not employ sea chests 
as cooling water intake structures, and that are fixed facilities would 
have to comply with the requirements in Sec.  125.134(b)(1)(i). The one 
additional requirement for these facilities is Sec.  125.134(b)(5), 
which requires the selection and implementation of design and 
construction technologies or operational measures to minimize 
entrainment of entrainable life stages of fish or shellfish. Fixed 
facilities, whether they employ sea chests or not, can also choose to 
comply through Track II, which allows a site-specific demonstration 
that alternative requirements would produce comparable levels of 
impingement mortality and entrainment reduction.
    New offshore oil and gas facilities that are not fixed facilities 
would have to comply with the regulations at Sec.  125.134(b)(1)(iii), 
which address intake flow velocity, specific impact

[[Page 35016]]

concerns (e.g., threatened or endangered species, critical habitat, 
migratory or sport or commercial species), required information 
submission, monitoring, and recordkeeping. Track II is not available to 
non-fixed (mobile) facilities because non-fixed facilities, which are 
expected to operate at multiple locations, would not be able to perform 
a site-specific demonstration. For this same reason, EPA has dropped 
some of the other site-dependent requirements for non-fixed facilities 
(e.g., provision of source waterbody flow information).
    EPA has limited information on specific environmental impacts 
associated with the use of cooling water intake structures at new 
offshore oil and gas extraction facilities but believes the potential 
for such impacts is sufficient to warrant including requirements for 
new offshore oil and gas extraction facilities in this rule (see 
section IV for more detailed discussion). SEAMAP data for the Gulf of 
Mexico identified over 600 different fish taxa and indicate that 
ichthyoplankton occurs throughout the Gulf of Mexico, with densities 
highest (e.g., average densities greater than 450 organisms/100 
m3) at sampling stations in the shallower regions (less than 
50 meters deep) of the Gulf, and lower in deeper waters. (70 FR 71,059-
71,060). Most offshore oil and gas facilities, if they employ cooling 
water intake structures, operate them in near-surface (e.g., 20-100 
feet deep) waters, rather than in deeper waters. (TDD, Chap. 3, Sec. 
III). As stated earlier in this preamble, offshore oil and gas 
extraction facilities have been shown to attract and concentrate 
aquatic organisms in the immediate vicinity of the underwater portions 
of their structures. Data also indicate the presence of aquatic 
organisms identified off the California and Alaska coasts, both 
additional areas of offshore oil and gas production. In addition, 
although such technologies are not generally in use at all existing 
offshore oil and gas extraction facilities, technologies are in use and 
are available to new facilities in this subcategory to meet the 
requirements as described below.
    Some offshore oil and gas extraction facilities employ an 
underwater compartment within the facility or vessel hull or pontoon 
through which sea water is drawn in or discharged, often called a ``sea 
chest.'' A passive screen (strainer) is often set along the flush line 
of the sea chest. Pumps draw seawater from open pipes in the sea chest 
cavity for a variety of purposes (e.g., cooling water, fire water, and 
ballast water). These intakes are normally the only source of cooling 
water for the facility; therefore, it is crucial to the operation of 
these facilities that the intake structures be kept clean and clear of 
fish, jellyfish, plastic bags, and other debris. To accomplish this, 
these intake structures can be, and have been, designed for low intake 
velocity (i.e., less than 0.5 feet per second) and/or include fish 
protection equipment. See the Technical Development Document for 
details.
    As outlined in Alaska's oil and gas leasing requirements, oil and 
gas extraction facilities in Alaskan State waters are currently subject 
to an impingement control velocity limit of 0.1 feet per second (i.e., 
more stringent than EPA's design requirement of 0.5 feet per second in 
this rule). These State regulations suggest that impingement controls 
that would meet the velocity requirements of this rule are demonstrated 
as available for offshore oil and gas extraction facilities in Alaskan 
or similar waters.
    However, facilities using sea chests may have few, if any, 
opportunities to meet the entrainment control requirements applicable 
to facilities subject to the Phase I rule. A 2003 literature survey by 
Mineral Management Services (DCN 7-0012) identified no evidence of 
entrainment controls successfully fitted to offshore oil and gas 
extraction vessels with sea chests such as drill ships, jack-ups, 
MODUs, and barges. EPA's data suggests that the only physical 
technology controls available for reducing entrainment at facilities 
with sea chests would entail installation of equipment projecting 
beyond the hull of the vessel. This outward projection has been shown 
to create problems with respect to fluid dynamics, vessel shapes and 
safe seaworthy profile. Therefore, EPA does not believe entrainment 
controls are feasible at such facilities, even for new facilities that 
could avoid the challenges of retrofitting control technologies.
    EPA also considered whether all new offshore vessels could be 
constructed without employing sea chests. A technology must prove to be 
practicable to be a viable alternative to current technology. In this 
case, a viable alternative to a sea chest is any alternative 
configuration/technology successfully implemented at existing 
facilities, including those in other manufacturing industries, with 
similar seawater intake structures. EPA data suggest the only 
demonstrated design for drill ships and semi-submersible MODUs is to 
use sea chests because they allow the vessel to maintain appropriate 
fluid dynamics, overall optimal vessel shape, and a safe seaworthy 
profile. Therefore, EPA has concluded that building new offshore oil 
and gas facilities without sea chests has not been shown to be 
practicable for the category as a whole.
    In contrast to facilities with sea chests, fixed offshore oil and 
gas extraction facilities with intake structures other than sea chests 
can feasibly install both impingement and entrainment controls. For 
example, technologies to reduce impingement mortality and entrainment 
of marine life at a caisson intake structure \7\ include passive intake 
screens or velocity caps. Other technologies such as acoustic barriers, 
electro barriers, or intake relocation may also be used to reduce 
impingement and entrainment at intake structures. Air sparges and 
copper nickel alloys can also be used to control biofouling. EPA has 
concluded that these are all ``available'' technologies for these 
facilities and therefore justify impingement and entrainment 
requirements.
---------------------------------------------------------------------------

    \7\ A caisson intake (a steel pipe attached to a fixed structure 
that extends from an operating area down some distance into the 
water) is used to provide a protective shroud around another process 
pipe or pump that is lowered into the caisson from the operating 
area.
---------------------------------------------------------------------------

    In summary, EPA is establishing requirements that are similar to 
some--but not all--of the Phase I provisions. The differences in 
requirements between this rule and the Phase I rule reflect the 
differences in technology availability between offshore oil and gas 
extraction facilities and those facilities covered in the Phase I rule.
    Impingement and entrainment requirements for new offshore oil and 
gas facilities are not based on closed-cycle recirculating cooling 
because available information indicates that it is not feasible for all 
new offshore oil and gas extraction facilities to employ closed-cycle 
recirculating cooling systems. The rest of the requirements are similar 
to those in Phase I (e.g., velocity information and design and 
construction technology plan for Track I facilities, comprehensive 
demonstration study for Track II facilities).

B. Why Is EPA Implementing CWA Section 316(b) at Existing Phase III 
Facilities Through Case-By-Case, Best Professional Judgment Permit 
Conditions?

    After considering available data, analyses and comments, EPA has 
decided not to promulgate a national categorical rule today for Phase 
III existing facilities. This means that section 316(b) requirements 
for Phase III existing facilities will continue to be

[[Page 35017]]

imposed on a case-by-case, best professional judgment basis.
    EPA bases this decision on its judgment that the monetized costs 
associated with the primary option under consideration are wholly 
disproportionate to the monetized environmental benefits to be derived 
from that option. EPA has long considered the wholly disproportionate 
cost test to be appropriate for section 316(b) decision-making for 
existing facilities. Here, EPA is using the wholly disproportionate 
cost test to determine whether the national categorical rule options 
proposed by EPA are the best way to minimize adverse environmental 
impact. As the Administrator observed in In Re Public Service Company 
of New Hampshire when reviewing contested 316(b) requirements for an 
existing facility, costs may be considered ``in determining the degree 
of minimization to be required.'' 10 ERC 1257, 1261 (June 10, 1977). 
Otherwise, the Administrator noted, ``the effect would be to require 
cooling towers at every place that could afford to install them, 
regardless of whether or not any significant degree of entrainment or 
entrapment was anticipated. I do not believe that it is reasonable to 
interpret Section 316(b) as requiring use of technology whose cost is 
wholly disproportionate to the environmental benefit to be gained.'' 
Id.
    The primary option EPA considered in today's final action was a 
rule that would have regulated Phase III existing facilities with a 
design intake flow of 50 MGD or greater. EPA also solicited comment on 
variations that would have narrowed the scope of the proposed rule. As 
discussed in more detail in section X of this preamble, EPA estimated 
that the total pre-tax costs of the 50 MGD option would be $38.3 to $39 
million and the monetized benefits for commercial and recreational uses 
would be $1.8 to $2.3 million ($2004, 7 percent and 3 percent discount 
rates). This yields a cost to benefit ratio ranging from a low of 17 to 
1 to a high of 22 to 1. EPA has concluded that the costs associated 
with the 50 MGD option are wholly disproportionate to the anticipated 
monetized benefits; therefore, EPA has concluded that this regulatory 
option does not constitute the ``best technology available for 
minimizing adverse environmental impacts.''
    Making a decision on the grounds that the costs here are wholly 
disproportionate to the benefits is also consistent with Executive 
Order 12866, entitled ``Regulatory Planning and Review'' (Oct. 1993). 
That Executive Order directs agencies to ``assess both the costs and 
the benefits of the intended regulation and, recognizing that some 
costs and benefits are difficult to quantify, propose or adopt a 
regulation only upon a reasoned determination that the benefits of the 
intended regulation justify its costs.'' E.O. 12866, Sec. 1(b)(6). This 
Executive Order has been in effect for over a decade under two 
Presidents, representing each major political party, and is now widely 
accepted as reflecting general principles of sound government 
regulation. It does not supersede any of the decision factors specified 
in the Clean Water Act and, in fact, says explicitly that it applies 
only ``to the extent permitted by law and where applicable,'' E.O. 
12866, Sec. 1(b). EPA believes that in this case the directive of the 
Executive Order is fully consistent with the requirements of the Clean 
Water Act.
    EPA considered non-use benefits as well as monetized use benefits 
in reaching its final decision. Non-use benefits may arise from reduced 
impacts to ecological resources that the public considers important. 
These include reduced impacts to species without direct commercial or 
recreational fishing value, such as forage fish, which play a role in 
the functioning of an aquatic ecosystem. In this rulemaking, EPA fully 
considered all benefits, but was able to assign a monetized value only 
to benefits associated with commercial and recreational uses. Non-use 
benefits can generally only be monetized when two steps have been 
completed: (1) Environmental impacts are quantified; and (2) a monetary 
value is available to be assigned to those impacts. EPA was unable to 
assign a monetary value that fully captured the value of avoiding the 
environmental impacts that EPA had identified because the necessary 
information was not available. EPA did attempt in the Phase III rule to 
monetize the loss of forage fish indirectly through its impact on 
reducing commercial and recreational harvests, and found these impacts 
to be generally small. However, this approach does not capture the 
value that society may place on these fish for their own sake. 
Therefore, EPA considered non-use benefits qualitatively. Doing so is 
consistent with accepted practices of benefits assessment and with 
EPA's past practice of fully evaluating benefits for purposes of 
section 316(b).
    Ultimately, in reaching today's decision, EPA took into account the 
uncertainty inherent in qualitative benefits assessment, the size of 
the ratio of monetized costs to monetized benefits, qualitative 
information about the likely ecosystem impacts of cooling water 
withdrawals from Phase III existing facilities, and other policy 
concerns outlined in this preamble. When fully considering these non-
monetized benefits in light of all of these factors, EPA determined 
that they were not likely to be of sufficient magnitude to alter EPA's 
decision to continue to use a case-by-case, best professional judgment 
approach for Phase III existing facilities. In the context of this 
rulemaking, EPA believes that a case-by-case approach is a reasonable 
way of identifying, for a particular Phase III existing facility, the 
best technology available for minimizing adverse environmental impact. 
This approach allows the permit writer to assess site-specific 
information regarding the impacts of the facility's cooling water 
impact structure and to decide how best to minimize them.
    In reaching today's decision, EPA has taken note that the vast 
majority of environmental benefits from regulating cooling water intake 
structures have already been realized by the Phase II rule. As a result 
of the Phase II rule, approximately 90 percent of the total volume of 
cooling water withdrawn nationally is already subject to national 
categorical requirements. The 543 facilities covered by the Phase II 
rule withdraw on average more than 214 billion gallons of cooling water 
every day from the nation's waters and, in the process, more than 3.4 
billion fish and shellfish were killed annually by impingement and 
entrainment prior to rule implementation. Compliance with the rule will 
reduce this loss by 1.4 billion fish and shellfish. 69 FR at 41586 & 
41656-57. The 146 existing facilities that would have been covered by 
the broadest of the Phase III proposed options (the 50 MGD proposal), 
in contrast, withdraw 31 billion gallons of cooling water every day and 
kill about 265 million fish and shellfish annually. The proposed rule 
would have reduced this loss by about 98 million fish and shellfish. 
Had EPA codified national categorical rules for those facilities, EPA 
thus would have saved only an additional 7 percent of the fish and 
shellfish from impingement and entrainment while expanding the universe 
subject to national categorical regulations by 27 percent. Also 
illuminating is the fact that, of the 146 Phase III existing 
facilities, only ten have intake structures designed to take in more 
than 500 MGD. In contrast, 257 Phase II facilities use cooling water 
intake structures designed to take in more than 500 MGD. This 
information indicates that the majority of large-flow facilities and 
cooling water intake flows

[[Page 35018]]

are already regulated by the Phase II rule. Most of the reductions in 
fish impinged and entrained at existing facilities, and therefore most 
of the benefits, are also already obtained through implementation of 
the Phase II regulations. The other options EPA considered--involving 
200 MGD and 100 MGD facilities--involved even less flow and fewer 
regulated facilities than the 50 MGD option.
    A comparison of the cost-benefit ratio for Phase II to the cost-
benefit ratio for the primary Phase III option supports EPA's decision 
here. The ratio of costs to monetized benefits for the Phase II 50MGD 
rule was approximately 5 to 1. In contrast, the ratio of monetized 
costs to monetized benefits for the proposed Phase III 50 MGD rule 
ranges from 17 to 1 to 22 to 1. Moreover, due to the ten-fold greater 
impingement and entrainment losses at Phase II facilities, EPA was not 
able to determine for Phase II, as it has for Phase III, that non-
quantified benefits, including non-use benefits, would not be 
sufficient to justify the costs. In light of the much smaller aggregate 
quantity of water withdrawals associated with Phase III and likely 
correspondingly smaller non-use benefits, EPA has determined that, at 
this time, a national categorical rule is not a reasonable approach for 
minimizing adverse environmental impacts for Phase III existing 
facilities.
    Instead, EPA will continue to rely on case-by-case decision-making 
to regulate cooling water intake structures at Phase III existing 
facilities. In some situations, as was the case when EPA's Region 1 
established section 316(b) requirements for the Brayton Point power 
station, a site-specific inquiry can produce performance standards that 
are more stringent than the categorical rules would have established. 
In other situations, the permit writer may determine that fewer 
controls need to be imposed. In both cases, however, the permitting 
authority is in a good position to perform the careful balancing 
contemplated by section 316(b) in order to select the best technology 
available for minimizing adverse environmental impact.
    In reaching today's decision, EPA has given special consideration 
to the fact that existing manufacturers were the rule's primary focus. 
According to the study published by the U.S. Department of Commerce 
entitled ``Manufacturing in America: A Comprehensive Strategy to 
Address the Challenges to U.S. Manufacturers'' (Jan. 2004), 
manufacturers have ``focused on reducing costs to improve productivity 
and ensure their competitiveness.'' Id. at 33. At the same time, some 
manufacturers have found these efforts ``eroded by costs they cannot 
control--costs that result in part from government policy.'' Id. at 33. 
A study by the U.S. Office of Management and Budget (OMB) found that 
regulatory costs in 1997 comprised 3.7 percent of gross domestic 
product (GDP) (``Report to Congress on the Costs and Benefits of 
Federal Regulations,'' September 1997). These costs have risen 
significantly over time and U.S. manufacturers face considerably higher 
compliance costs than do many of the U.S.'s trading partners. Since 
U.S. manufacturers compete with other firms from both developed and 
developing countries in a global economy, any additional regulatory 
costs should be carefully evaluated in order to ensure U.S. firms' 
continued competitiveness in the global marketplace. In a second report 
entitled ``Regulatory Reform of the U.S. Manufacturing Sector'' (2005), 
OMB stated that ``[s]treamlining regulation is a key plank in the 
President's economic program.'' Id. at 1. This report suggests that any 
unnecessary regulatory burdens, especially on small and medium-sized 
manufacturers, should be removed. To address these concerns for U.S. 
manufacturers, benefits justifying costs is of paramount importance.
    Today's decision, while based on statutory factors in the Clean 
Water Act, does also address the concerns in these reports. As 
proposed, the Phase III rule would have required most facilities to 
submit a number of highly detailed studies and reports to the permit 
writer, with additional studies required for facilities seeking 
alternative standards based on site-specific considerations. Today's 
final action for Phase III adopts a more flexible approach under which 
the permit writer can tailor the data and information request more 
specifically to the location, technology constraints, and potential 
adverse environmental impacts of a particular facility. Today's 
decision provides manufacturing facilities the opportunity to provide 
information to the permit writer relating to the site specific 
environmental impacts attributable to their cooling water intake 
structures and the technological feasibility and economic burdens 
associated with various levels of control. This tailored regulatory 
approach not only meets the Clean Water Act requirement to adopt the 
best technology available to minimize adverse environmental impacts, 
but it also advances EPA's policy of avoiding imposing unnecessary 
burdens on manufacturers.
    Continuing a regime of BPJ decision-making for Phase III existing 
facilities does not mean that EPA is merely preserving the status quo. 
To the contrary, EPA believes that the rulemaking record contains 
important factual data that can help permit writers when reissuing 
NPDES permits for the Phase III existing facilities. The numeric 
performance standards that EPA had proposed, for example, reflect EPA's 
judgment regarding the level of reduction in impingement mortality and 
entrainment that available technologies can achieve. Similarly, the 
regulatory support documents describe a variety of control devices, 
analyze their effectiveness and present their costs. The record also 
contains information regarding environmental impacts associated with 
cooling water intake structures. EPA expects permit writers and 
permittees to fully consider this information and other useful guidance 
contained in the record as they develop site-specific section 316(b) 
requirements.
    For the foregoing reasons, EPA has decided, based on its assessment 
of costs and benefits in this rulemaking, to continue to rely on permit 
writers' use of their best professional judgment to establish the 
statutorily mandated section 316(b) requirements on a case-by-case 
basis for existing Phase III facilities.

VII. Response to Major Comments on the Proposed Rule and Notice of Data 
Availability (NODA)

    Fifty-one organizations and individuals submitted comments on a 
range of issues in the proposed rule. An additional six comments were 
received on the NODA. Detailed responses to all comments, including 
those summarized here, can be found in the Response to Comments 
document in the official public docket.

A. Offshore Oil and Gas Extraction Facilities

    Commenters raised many issues concerning the regulation of offshore 
oil and gas extraction facilities. One commenter requested that EPA 
exclude mobile offshore drilling units (MODUs) from the rule. A few 
commenters also claimed that EPA did not demonstrate a need to regulate 
offshore oil and gas extraction facilities. Another commenter asserted 
that new offshore oil and gas extraction facilities should be included 
under the new facility definition promulgated under Phase I.
    One commenter suggested that EPA exempt offshore oil and gas 
extraction facilities employing sea chests in order to facilitate 
international movement of MODUs. This commenter and others also 
requested that EPA establish a higher minimum flow threshold (of at

[[Page 35019]]

least 25 MGD) for offshore oil and gas units in shallow waters, and 
exempt units in unproductive deep waters (over 100 meters deep).
    One commenter added that the ichthyoplankton density data (SEAMAP 
data) provided in the NODA supports the assertion that location alone 
should be used to regulate requirements for offshore oil and gas 
extraction facilities and supports the exemption of units in 
unproductive waters offshore. The commenter stated that the SEAMAP data 
shows that these waters have significantly reduced levels of biological 
life. Several commenters expressed concern that intake technologies 
from other industries may not be appropriate for offshore oil and gas 
extraction facilities.
    As presented in the NODA, EPA collected biological data from the 
Gulf of Mexico and other locations demonstrating that there is a 
potential for adverse environmental impacts due to the operation of 
cooling water intake structures at new offshore oil and gas extraction 
facilities. While the data did show spatial and temporal variations, as 
well as variability at different depths, the range of ichthyoplankton 
densities found were within the same range seen in coastal and inland 
waterbodies addressed by the Phase I final rule. As discussed in 
section IX, there is no economic barrier for new offshore oil and gas 
facilities to meet the performance standards as proposed. Based in part 
on these results, EPA is addressing new offshore oil and gas extraction 
facilities in this final rule. EPA proposed to set a regulatory 
threshold of 2 MGD for new offshore oil and gas facilities. EPA has not 
identified nor have commenters provided a basis for selecting an 
alternative regulatory threshold. Therefore, consistent with the Phase 
I rule, new offshore oil and gas extraction facilities with a design 
intake flow greater than 2 MGD are subject to this rule.
    EPA recognizes the inherent differences in the design and operation 
of land-based and offshore facilities (as well as the differences 
between the several types of offshore facilities) and has adopted a 
regulatory approach that allows new offshore oil and gas extraction 
facilities ample flexibility in complying with the rule. EPA's record 
shows the technologies evaluated for use by new facilities are already 
in use at some existing offshore facilities. Furthermore, EPA does not 
have any (and commenters did not provide) data to suggest that MODUs 
with sea chests would be inhibited from international movement by the 
proposed requirements. Commenters did not submit any information that 
would lead EPA to believe that the intake technologies already used and 
demonstrated at existing facilities are inadequate or inappropriate for 
use at new offshore facilities. However, EPA recognizes that 
differences in types of offshore facilities may limit the technologies 
available, and is therefore requiring different performance standards 
for these classes of facilities. For this reason, new offshore oil and 
gas extraction facilities are subject to a new Subpart N rather than 
being included under the new facility definition promulgated under 
Phase I. As discussed in section II.A of this preamble, new offshore 
oil and gas extraction facilities are defined based on three criteria, 
one of which is that the facility meets the definition of a ``new 
facility'' in 40 CFR 125.83.

B. Applicability to Phase III Existing Facilities/Costs & Benefits

    Numerous commenters argued that Phase III facilities should be 
regulated on a case-by-case basis, citing the proposed rule's high 
cost, low benefits, and a lack of Phase III data indicating 
environmental harm. Commenters questioned the need for and benefit of 
promulgating national standards covering existing manufacturing 
facilities and small electric utility plants that comprise smaller 
cooling water flows.
    Many commenters expressed concern over the high costs relative to 
the monetized benefits of all three regulatory approaches presented in 
the proposed rule and indicated that EPA should thus withdraw the 
proposed rule.
    As discussed in section VI of this preamble, EPA has decided not to 
promulgate national categorical requirements for Phase III existing 
facilities based in part on a consideration of relative costs and 
benefits. Section 316(b) requirements for these facilities will 
continue to be developed by permit writers using their best 
professional judgment.

C. Environmental Impacts Associated With Cooling Water Intake 
Structures

    Many commenters asserted that there is no demonstrated need for 
national requirements at Phase III facilities since Phase III 
facilities have much smaller flows than Phase II facilities. These 
commenters also stated that most of the environmental impact data cited 
in the Phase III proposed rule is from Phase II power generator 
facilities and is not relevant to Phase III facilities. One commenter 
stated that EPA did not define adverse environmental impact. Another 
commenter argued that any measure of impingement or entrainment 
constitutes adverse environmental impact.
    Another commenter stated that the low number of 316(b) studies 
conducted at Phase III facilities indicates that these facilities are 
not causing a problem. Other commenters maintained that actual national 
impacts due to cooling water intake structures are vastly 
underestimated due to poor data collection methodologies utilized when 
the majority of the studies were performed and because studies 
conducted on impinged and entrained organisms overlooked the vast 
majority of affected species.
    As discussed in section IV of this preamble, EPA collected 
impingement mortality and entrainment data from multiple existing 
facilities including many Phase III facilities, and believes that the 
data is sufficient to demonstrate the potential for adverse 
environmental impacts by Phase III facilities (see also Regional 
Analysis Document). Consistent with discussions presented in the Phase 
I and Phase II rules, EPA believes that it is reasonable to interpret 
adverse environmental impact as the loss of aquatic organisms due to 
impingement mortality and entrainment. Commenters did not suggest 
alternative interpretations of adverse environmental impact. For 
additional discussion, see section IV of this preamble.
    EPA believes that the studies collected from existing facilities 
and utilized in its analysis of impingement and entrainment impacts are 
sufficient to estimate and generally characterize the potential for 
national level impacts for the purposes of this action. The Regional 
Analysis document discusses a number of issues associated with the 
quality of the data in these studies. It is difficult to predict the 
effects of these study limitations on the impacts estimates, 
specifically whether they have led to an overestimate or underestimate 
of impacts. EPA acknowledges that the studies often measure impacts to 
only some of the fish and shellfish species impacted by cooling water 
intake structures and typically do not measure impacts to other marine 
organisms such as phytoplankton or invertebrates. However, EPA fully 
considered these impacts in its assessment of potential non-monetized 
benefits. For the reasons discussed above, including the much smaller 
withdraws associated with Phase III facilities relative to Phase II, 
EPA has determined that for these facilities impacts were not likely to 
be of sufficient magnitude to change its

[[Page 35020]]

decision to rely on the existing site-specific regulatory framework for 
Phase III facilities. EPA believes the site-specific approach is 
particularly suited to addressing these non-quantified impacts because 
the nature and magnitude of such impacts is itself highly site-
specific.

VIII. Implementation

    Final section 316(b) requirements for new offshore oil and gas 
extraction facilities will be implemented through the NPDES permit 
program. This final rule establishes implementation requirements for 
new offshore oil and gas extraction facilities that are generally 
similar to the Phase I requirements. This regulation establishes 
application requirements under 40 CFR 122.21 and Sec.  125.136, 
monitoring requirements under Sec.  125.137, and record keeping and 
reporting requirements under Sec.  125.138. The regulations also 
require the Director to review application materials submitted by each 
regulated facility and include monitoring and record keeping 
requirements in the permit (Sec.  125.139).

A. When Does the Final Rule Become Effective?

    This rule becomes effective July 17, 2006. Under this final rule, 
new offshore oil and gas extraction facilities will need to comply with 
the Subpart N requirements when an NPDES permit containing requirements 
consistent with Subpart N is issued to the facility.

B. What Information Will I Be Required To Submit to the Director When I 
Apply for My NPDES Permit?

General Information
    This final rule modifies regulations at Sec.  122.21 to require new 
offshore oil and gas extraction facilities to prepare and submit some 
of the same information required for new Phase I and existing Phase II 
facilities. New offshore oil and gas extraction facilities may be 
required to submit the Source Water Baseline Biological 
Characterization Data depending on whether they are fixed or non-fixed 
facilities. Non-fixed facilities are exempt from the requirement. 
Specific data requirements for the Source Water Baseline Biological 
Characterization Data are described later in this section. Studies to 
be submitted by new offshore oil and gas extraction facilities are 
described below. Under EPA's NPDES regulations new facilities must 
apply for their NPDES permit at least 180 days prior to commencement of 
operation. Under this final rule, new offshore oil and gas extraction 
facilities must submit the specified information with their application 
for permit issuance.
1. Source Water Physical Data (Sec.  122.21(r)(2))
    Under the requirements at Sec.  122.21(r)(2), new offshore oil and 
gas extraction facilities are required to provide the source water 
physical data specified at Sec.  122.21(r)(2) in their application for 
a permit. EPA believes these data are necessary to characterize the 
facility and evaluate the type of waterbody and species potentially 
affected by the cooling water intake structure. EPA intends for the 
Director to use this information to evaluate the appropriateness of the 
design and construction technologies and/or operational measures 
proposed by the applicant.
    The applicant is required to submit the following specific data: 
(1) A narrative description and scale drawings showing the physical 
configuration of all source waterbodies used by the facility, including 
areal dimensions, depths, salinity and temperature regimes, and other 
documentation; (2) an identification and characterization of the source 
waterbody's hydrological and geomorphological features, as well as the 
methods used to conduct any physical studies to determine the intake's 
zone of influence and the results of such studies; and (3) locational 
maps. For new non-fixed (mobile) offshore oil and gas extraction 
facilities, this provision requires only some of the location 
information and not the source water physical data required for new 
fixed offshore oil and gas extraction facilities.
    EPA recognizes that mobile facilities may not always know where 
they will be operating during the permit term, and the requirement in 
(r)(2)(iv) is not meant to restrict them only to locations identified 
in the permit application. However, EPA expects that permit applicants 
will provide, based on available information, their best estimate as to 
where they will be operating during the permit term, at whatever level 
of detail they can.
2. Cooling Water Intake Structure Data (Sec.  122.21(r)(3))
    New offshore oil and gas extraction facilities are required to 
submit the cooling water intake structure data specified at Sec.  
122.21(r)(3) to characterize the cooling water intake structure and 
evaluate the potential for impingement and entrainment of aquatic 
organisms. Note that Sec.  122.21(r)(3)(ii)--latitude and longitude of 
each intake structure--is not applicable to non-fixed (mobile) offshore 
oil and gas extraction facilities. Information on the design of the 
intake structure and its location in the water column allows the permit 
writer to evaluate which species or life stages are potentially subject 
to impingement mortality and entrainment. A diagram of the facility's 
water balance is used to identify the proportion of intake water used 
for cooling, make-up, and process water. The water balance diagram also 
provides a picture of the total flow in and out of the facility, 
allowing the permit writer to evaluate the suitability of proposed 
design and construction technologies and/or operational measures.
    The applicant is required to submit the following specific data: 
(1) A narrative description of the configuration of each of its cooling 
water intake structures and where they are located in the waterbody and 
in the water column; (2) latitude and longitude in degrees, minutes, 
and seconds for each of its cooling water intake structures (not 
applicable to new non-fixed (mobile) offshore oil and gas extraction 
facilities); (3) a narrative description of the operation of each of 
the cooling water intake structures, including design intake flows, 
daily hours of operation, number of days of the year in operation, and 
seasonal operation schedules, if applicable; (4) a flow distribution 
and water balance diagram that includes all sources of water to the 
facility, recirculating flows, and discharges; and (5) engineering 
drawings of the cooling water intake structure.
    The applicability criterion in Sec.  125.131(a)(3) is based on 
total design intake flow. Total design intake flow must be specified by 
the applicant with the information required above. A facility may 
permanently decrease its total design intake flow (e.g., by removing an 
intake structure or installing intake pumps with a lower maximum 
capacity) and request that the permitting authority consider the 
facility's new total design intake flow to determine the applicability 
of the 316(b) Phase III Rule at the time of permitting. Note that for a 
facility that has a variable speed pump, the total design flow is the 
maximum intake capacity for the cooling water intake structure.

Specific Requirements

    Under this final rule, new offshore oil and gas extraction 
facilities are required to submit the application requirements 
consistent with Sec.  122.21(r)(2) (except (r)(2)(iv)), (3), and (4) 
and Sec.  125.136 of Subpart N if they are fixed facilities and choose 
to comply with the Track I or II requirements in Sec.  125.134(b) or 
(c). A fixed facility is defined as a bottom

[[Page 35021]]

founded offshore oil and gas extraction facility permanently attached 
to the seabed or subsoil of the outer continental shelf (e.g., 
platforms, guyed towers, articulated gravity platforms) or a buoyant 
facility securely and substantially moored so that it cannot be moved 
without a special effort (e.g., tension leg platforms, permanently 
moored semi-submersibles) and which is not intended to be moved during 
the production life of the well. This definition does not include MODUs 
(e.g., drill ships, temporarily moored semi-submersibles, jack-ups, 
submersibles, tender-assisted rigs, and drill barges). The Track I and 
Track II application requirements are generally consistent with the 
Phase I requirements for new facilities (66 FR 65256). Under Track I, 
this includes velocity information, source waterbody flow information, 
and a design and construction technology plan. Track II requirements 
include source waterbody flow information and Track II comprehensive 
demonstration study (including source water biological study, 
evaluation of potential cooling water intake structure effects, and 
verification monitoring plan). These requirements are detailed later in 
this section.
    As described in Sec.  125.135, new offshore oil and gas extraction 
facilities have the opportunity to conduct a cost-cost test and provide 
data to assist the permit writer in determining if compliance with the 
Subpart N requirements would result in compliance costs wholly out of 
proportion to those EPA considered in establishing the requirement, or 
would result in significant adverse impacts on local water resources 
other than impingement or entrainment, or significant adverse impacts 
on energy markets. In this case, alternative requirements may be 
imposed in the permit. See the Phase I final preamble for a more 
detailed explanation of this cost-cost test which is different than the 
cost-cost test for Phase II facilities (66 FR 65256).
    In this final rule, fixed facilities with sea chests and all non-
fixed (or ``mobile'') facilities are not required to comply with 
standards for entrainment. Fixed facilities with sea chests may choose 
either Track I or Track II to comply with impingement mortality 
performance standards. Non-fixed facilities must comply with the Track 
I 0.5 feet per second through-screen design intake flow velocity 
performance standard for impingement mortality. In addition, the 
Director must consider whether more stringent conditions are reasonably 
necessary to comply with any provision of federal or state law, 
including compliance with applicable water quality standards. Thus, the 
Director may determine that additional design and construction 
technologies to minimize impingement mortality are necessary where 
there are either protected species or critical habitat for these 
species or other species of impingement concern within the hydrologic 
zone of influence of the cooling water intake structure, or based on 
other information from fishery management services or agencies. The new 
mobile facility, when applying to operate under a general permit, must 
identify where it expects to be operating. EPA expects the Director to 
consult with the fishery management agencies, consider their data as 
well as any other relevant data, and decide whether to propose 
additional requirements based on any concerns the Director identifies 
(see Sec.  125.134(b)(4)). For example, Region 10 has established a 
general permit for Cook Inlet that established a 0.1 feet per second 
through-screen design intake flow velocity performance standard. 
However, non-fixed facilities are not required to submit the source 
water baseline biological characterization data and some aspects of the 
source water physical data. Requirements for non-fixed facilities are 
described later in this section.
1. For New Offshore Oil and Gas Extraction Fixed Facilities, What 
Information Is Required To Be Collected for the NPDES Application?

Source Water Baseline Biological Characterization Data (Sec.  
122.21(r)(4))

    Under this final rule, Track I and Track II new offshore oil and 
gas extraction fixed facilities are required to submit source water 
baseline biological characterization data, just as other new facilities 
were required to do under Phase I. The data will be used to 
characterize the biological community in the vicinity of the cooling 
water intake structure and to characterize the operation of the cooling 
water intake structure. The data must include existing data (if 
available) supplemented with new field studies as necessary. Detailed 
data requirements are at Sec.  122.21(r)(4). EPA recognizes that many 
offshore oil and gas extraction facilities are regulated under NPDES 
general permits and that regional studies are typically conducted as 
part of the general permit requirements. EPA expects that some new 
offshore oil and gas extraction fixed facilities may choose to jointly 
conduct a regional study to collect the source water baseline 
biological characterization data. The biological conditions 
characterized by a regional study should reflect the conditions found 
at each individual cooling water intake structure. EPA anticipates the 
regional studies would be conducted once each permit cycle. Under this 
final rule, the regional study would also include annual monitoring 
requirements.

Velocity Information (Track I)

    The final rule requires that new offshore oil and gas extraction 
fixed facilities submit velocity information consistent with Sec.  
125.136(b)(2). The information will be used to demonstrate to the 
Director that the facility is complying with the requirement to meet a 
maximum through-screen design intake velocity of no more than 0.5 feet 
per second at the cooling water intake structure. The following 
information must be submitted: (1) a narrative description of the 
design, structure, equipment, and operation used to meet the velocity 
requirement; and (2) design calculations showing that the velocity 
requirement would be met at minimum ambient source water surface 
elevations (based on best professional judgment using available 
hydrological data) and maximum head loss across the screens or other 
device or, if the facility uses devices other than a surface intake 
screen, at the point of entry to the device.

Source Waterbody Flow Information (Track I and II)

    The final rule also requires that new offshore oil and gas 
extraction fixed facilities located in an estuary or tidal river to 
submit source waterbody flow information in accordance with Sec.  
125.136(b)(2) or (c)(1). The information will be used to demonstrate to 
the Director that a new coastal facility's cooling water intake 
structure meets the proportional flow requirements at Sec.  
125.134(b)(3) or (c)(2). These requirements include specific provisions 
for fixed facilities located on estuaries or tidal rivers to provide 
greater protection for these sensitive waters. Specifically, the final 
rule requires that the total design intake flow over one tidal cycle of 
ebb and flow must be no greater than one (1) percent of the volume of 
the water column within the area centered about the opening of the 
intake with a diameter defined by the distance of one tidal excursion 
at the mean low water level. See the final Phase I rule for the basis 
for this design intake flow limitation. Calculations and guidance on 
determining the tidal excursion is found

[[Page 35022]]

in the preamble to the final Phase I rule at section VII.B.1.d.

Design and Construction Technology Plan (Track I)

    The final regulation requires that new offshore oil and gas 
extraction fixed facilities submit a design and construction technology 
plan consistent with Subpart N requirements at Sec.  125.136(b)(3). The 
design and construction technology plan must demonstrate that the 
facility has selected and will implement the design and construction 
technologies necessary to minimize impingement mortality and/or 
entrainment in accordance with Sec.  125.134(b)(4) and/or (5). The 
design and construction technology plan requires delineation of the 
hydrologic zone of influence for the cooling water intake structure; a 
description of the technologies implemented (or to be implemented) at 
the facility; the basis for the selection of that technology; the 
expected performance of the technology, and design calculations, 
drawings and estimates to support the technology description and 
performance. The Agency recognizes that the selection of a specific 
technology or a group of technologies depends on the individual 
facility and waterbody conditions.

Track II Comprehensive Demonstration Study (Track II)

    If a fixed facility chooses to comply under the Track II approach, 
the facility must perform and submit the results of a Comprehensive 
Demonstration Study (Study). This information will be used to 
characterize the source water baseline in the vicinity of the cooling 
water intake structure(s); characterize operation of the cooling water 
intake(s); and to confirm that the technology(ies) proposed and/or 
implemented at the cooling water intake structure reduce the impacts to 
fish and shellfish to levels comparable to those the facility would 
achieve were it to implement the applicable requirements in Sec.  
125.134(b)(2) and, for facilities without sea chests, in Sec.  
125.134(b)(5). To meet the ``comparable level'' requirement, the 
facility must demonstrate that it has reduced both impingement 
mortality and entrainment of all life stages of fish and shellfish to 
90 percent or greater of the reduction that would be achieved through 
the applicable requirements in Sec.  125.134(b)(2) and, for facilities 
without sea chests, in Sec.  125.134(b)(5).
    Similar to the Proposal for Information Collection required in 
Phase II, the facility must develop and submit a plan to the Director 
containing a proposal for how information will be collected to support 
the study. The plan must include:
     A description of the proposed and/or implemented 
technology(ies) to be evaluated in the Study;
     A list and description of any historical studies 
characterizing the physical and biological conditions in the vicinity 
of the proposed or actual intakes and their relevancy to the proposed 
Study. If the facility proposes to rely on existing source waterbody 
data, the data must be no more than 5 years old, and the facility must 
demonstrate that the existing data are sufficient to develop a 
scientifically valid estimate of potential impingement mortality and 
entrainment impacts, and provide documentation showing that the data 
were collected using appropriate quality assurance/quality control 
procedures;
     Any public participation or consultation with Federal or 
State agencies undertaken in developing the plan; and
     A sampling plan for data that will be collected using 
actual field studies in the source waterbody. The sampling plan must 
document all methods and quality assurance procedures for sampling and 
data analysis. The sampling and data analysis methods proposed must be 
appropriate for a quantitative survey and based on consideration of 
methods used in other studies performed in the source waterbody. The 
sampling plan must include a description of the study area (including 
the area of influence of the cooling water intake structure and at 
least 100 meters beyond); taxonomic identification of the sampled or 
evaluated biological assemblages (including all life stages of fish and 
shellfish); and sampling and data analysis methods.
    The facility must submit documentation of the results of the Study 
to the Director. Documentation of the results of the Study includes: 
Source Water Biological Study, an evaluation of potential cooling water 
intake structure effects, and a verification monitoring plan as 
described below.

Source Water Biological Study

    The Source Water Biological Study is similar to, but will generally 
be more comprehensive than, the Source Water Baseline Biological 
Characterization Study which is required for both Tracks I and II. The 
Source Water Biological Study must include:
    (1) A taxonomic identification and characterization of aquatic 
biological resources including: a summary of historical and 
contemporary aquatic biological resources; determination and 
description of the target populations of concern (those species of fish 
and shellfish and all life stages that are most susceptible to 
impingement and entrainment); and a description of the abundance and 
temporal/spatial characterization of the target populations based on 
the collection of multiple years of data to capture the seasonal and 
daily activities (e.g., spawning, feeding and water column migration) 
of all life stages of fish and shellfish found in the vicinity of the 
cooling water intake structure;
    (2) An identification of all threatened or endangered species that 
might be susceptible to impingement and entrainment by the proposed 
cooling water intake structure(s); and
    (3) A description of additional chemical, water quality, and other 
anthropogenic stresses on the source waterbody.

Evaluation of Potential Cooling Water Intake Structure Effects

    This evaluation must include:
    (1) Calculations of the reduction in impingement mortality and, if 
applicable, entrainment of all life stages of fish and shellfish that 
would need to be achieved by the technologies selected to meet 
requirements under Track II. To do this, the facility must determine 
the reduction in impingement mortality and entrainment that would be 
achieved by implementing the requirements of Sec.  125.134(b)(2) and, 
for facilities without sea chests, Sec.  125.134(b)(5).
    (2) An engineering estimate of efficacy for the proposed and/or 
implemented technologies used to minimize impingement mortality and, if 
applicable, entrainment of all life stages of fish and shellfish and 
maximize survival of impinged life stages of fish and shellfish. The 
facility must demonstrate that the technologies reduce impingement 
mortality and, if applicable, entrainment of all life stages of fish 
and shellfish to a comparable level to that which would be achieved if 
the facility were to implement the requirements in Sec.  125.134(b)(2) 
and, for facilities without sea chests, Sec.  125.134(b)(5). The 
efficacy projection must include a site-specific evaluation of 
technology suitability for reducing impingement mortality and 
entrainment based on the results of the Source Water Biological Study. 
Efficacy estimates may be determined based on case studies that have 
been conducted in the vicinity of the cooling water intake structure 
and/or site-specific technology prototype studies.

[[Page 35023]]

Verification Monitoring Plan

    Under Track II, a fixed facility must include a plan to conduct, at 
a minimum, two years of monitoring to verify the full-scale performance 
of the proposed or implemented technologies, and/or operational 
measures. The verification study must begin at the start of operations 
of the cooling water intake structure and continue for a sufficient 
period of time to demonstrate that the facility is reducing the level 
of impingement mortality and entrainment to the level required for 
Track II compliance. The plan must describe the frequency of monitoring 
and the parameters to be monitored. The Director will use the 
verification monitoring to confirm that the facility is meeting the 
level of impingement mortality and entrainment reduction required in 
Sec.  125.134(c), and that the operation of the technology has been 
optimized.
2. As an Owner or Operator of a New Offshore Oil and Gas Extraction 
Fixed Facility, What Monitoring Is Required?
    Monitoring requirements for new offshore oil and gas extraction 
fixed facilities vary based on whether the facility selects Track I or 
Track II and whether it has a sea chest. For fixed facilities pursuing 
Track I that have sea chests, no monitoring is required. For fixed 
facilities pursuing Track I that do not have sea chests, only 
entrainment monitoring is required. Under Track II, fixed facilities 
with sea chests are required to conduct impingement mortality 
monitoring; fixed facilities without sea chests must conduct monitoring 
for both impingement mortality and entrainment.
    Under this final rule, monitoring must characterize the impingement 
and, if applicable, entrainment rates of commercial, recreational, and 
forage base fish and shellfish species identified in either the Source 
Water Baseline Biological Characterization data required by 40 CFR 
122.21(r)(4) (for Track I) or the Comprehensive Demonstration Study 
required by Sec.  125.136(c)(2 (for Track II). The monitoring methods 
used must be consistent with those used for the Source Water Baseline 
Biological Characterization data required in 40 CFR 122.21(r)(4) or the 
Comprehensive Demonstration Study required by Sec.  125.136(c)(2). For 
Track II, monitoring must be conducted in accordance with the 
Verification Monitoring Plan.
    The fixed facility must follow the monitoring frequencies 
identified below for at least two (2) years after the initial permit 
issuance. After that time, the Director may approve a request for less 
frequent sampling in the remaining years of the permit term and when 
the permit is reissued, if supporting data show that less frequent 
monitoring would still allow for the detection of any variations in the 
species and numbers of individuals that are impinged or entrained.
    Impingement sampling. The facility must collect samples to monitor 
impingement rates (simple enumeration) for each species over a 24-hour 
period and no less than once per month when the cooling water intake 
structure is in operation.
    Entrainment sampling. If the fixed facility does not use a sea 
chest, it must collect samples to monitor entrainment rates (simple 
enumeration) for each species over a 24-hour period and no less than 
biweekly during the primary period of reproduction, larval recruitment, 
and peak abundance identified during the Source Water Baseline 
Biological Characterization required by 40 CFR 122.21(r)(4) or the 
Comprehensive Demonstration Study required in Sec.  125.136(c)(2). 
Samples must be collected only when the cooling water intake structure 
is in operation.
    Velocity monitoring. All new offshore oil and gas extraction 
facilities must conduct velocity monitoring. Velocity monitoring 
consists of a demonstration requirement based on the new facilities' 
proposed design, and a compliance monitoring requirement that verifies 
the velocity limitation is being met.
    Facilities must submit design specifications for the impingement 
control system to the Director. Impingement control systems must be 
designed to prevent flow velocities from exceeding 0.5 feet per second. 
The facility must demonstrate the 0.5 feet per second velocity limit 
will be met by submitting (1) a narrative description of the technology 
used to meet the velocity requirement, and (2) a design calculation 
that uses head loss to show the design flow through the screen will 
meet the velocity requirement.
    After start-up, if the facility uses a surface intake screen 
system, it must monitor head loss across the screens and correlate the 
measured value with the design intake velocity. The head loss across 
the intake screen must be measured at the minimum ambient source water 
surface elevation (using best professional judgment based on available 
hydrological data). The maximum head loss across the screen for each 
cooling water intake structure will be used to determine compliance 
with the velocity requirement in Sec.  125.134(b)(2). If the facility 
uses devices other than surface intake screens, it must monitor 
velocity at the point of entry through the device. Head loss or 
velocity must be monitored during initial facility startup, and 
thereafter, at the frequency specified in the NPDES permit, but no less 
than once per quarter.
    Facilities must monitor and record flow data through the cooling 
water intake structure continuously in order to verify that flows do 
not exceed the maximum design flow for the system, therefore causing 
flow velocities to exceed 0.5 ft/sec. As a minimum, facilities must 
summarize and provide flow data to the Director on an annual basis in 
order to verify that flow rates through cooling water intake structure 
did not exceed design capacity. Flow data can be collected and 
submitted to the Director either electronically or by hard copy.
    Visual or remote inspections. The facility must conduct visual 
inspections or employ remote monitoring devices during the period the 
cooling water intake structure is in operation. Visual inspections must 
be conducted at least weekly to ensure that any design and construction 
technologies required in Sec.  125.134(b)(4), (b)(5), (c), and/or (d) 
are maintained and operated to ensure that they will continue to 
function as designed. Alternatively, the facility must inspect via 
remote monitoring devices to ensure that the impingement and 
entrainment technologies are functioning as designed.
3. What Recordkeeping and Reporting Is Required for New Offshore Oil 
and Gas Extraction Fixed Facilities?
    Owners and operators of new offshore oil and gas extraction fixed 
facilities must keep records of all the data used to complete the 
permit application and show compliance with the requirements, any 
supplemental information developed under Sec.  125.136, and any 
compliance monitoring data submitted under Sec.  125.137, for a period 
of at least three years from the date of permit issuance. The Director 
may require that these records be kept for a longer period.
    Additionally, this final rule requires that new offshore oil and 
gas extraction fixed facilities submit the following in a yearly status 
report:
     Biological monitoring records for each cooling water 
intake structure as required by Sec.  125.137(a);
     Velocity and head loss monitoring records for each cooling 
water intake structure as required by Sec.  125.137(b); and
     Records of visual or remote inspections as required in 
Sec.  125.137(c).

[[Page 35024]]

4. For New Non-fixed (Mobile) Offshore Oil and Gas Extraction 
Facilities, What Information Is Required To Be Collected for the NPDES 
Application?

Velocity Information (Track I)

    This final rule at Sec.  125.136(b)(1) requires that new nonfixed 
(mobile) offshore oil and gas extraction facilities submit velocity 
information. The information will be used to demonstrate to the 
Director that the facility is complying with the requirement to meet a 
maximum through-screen design intake velocity of no more than 0.5 feet 
per second at the cooling water intake structure. The following 
information must be submitted: (1) a narrative description of the 
design, structure, equipment, and operation used to meet the velocity 
requirement; and (2) design calculations showing that the velocity 
requirement would be met at minimum ambient source water surface 
elevations (based on best professional judgment using available 
hydrological data) and maximum head loss across the screens or other 
device.

Design and Construction Technology Plan (Track I)

    When the Director determines that additional design and 
construction technologies to minimize impingement mortality of fish and 
shellfish are necessary, pursuant to Sec.  125.134(b)(4), new nonfixed 
(mobile) offshore oil and gas extraction facilities must submit a 
design and construction technology plan. As set forth in Sec.  
125.136(b)(3), the design and construction technology plan must 
demonstrate that the facility has selected and will implement the 
design and construction technologies necessary to minimize impingement 
mortality in accordance with Sec.  125.134(b)(4). The design and 
construction technology plan requires delineation of the hydrologic 
zone of influence for the cooling water intake structure; a description 
of the technologies implemented (or to be implemented) at the facility; 
the basis for the selection of that technology; the expected 
performance of the technology, and design calculations, drawings and 
estimates to support the technology description and performance. The 
Agency recognizes that the selection of a specific technology or a 
group of technologies depends on the individual facility and waterbody 
conditions.
5. As an Owner or Operator of a New Non-fixed (Mobile) Offshore Oil and 
Gas Extraction Facility, What Monitoring Is Required?
    Biological monitoring. Under this final rule, new non-fixed 
(mobile) offshore oil and gas extraction facilities are not required to 
conduct biological monitoring unless specified by the Director.
    Velocity monitoring. If the mobile facility uses a surface intake 
screen system, it must monitor head loss across the screens and 
correlate the measured value with the design intake velocity. The head 
loss across the intake screen must be measured at the minimum ambient 
source water surface elevation (using best professional judgment based 
on available hydrological data). The maximum head loss across the 
screen for each cooling water intake structure will be used to 
determine compliance with the velocity requirement in Sec.  
25.134(b)(2). If the facility uses devices other than surface intake 
screens, it must monitor velocity at the point of entry through the 
device. Head loss or velocity must be monitored during initial facility 
startup, and thereafter, at the frequency specified in the NPDES 
permit, but no less than once per quarter.
    Visual or remote inspections. The facility must conduct visual 
inspections or employ remote monitoring devices during the period the 
cooling water intake structure is in operation. Visual inspections must 
be conducted at least weekly to ensure that any design and construction 
technologies required in Sec.  125.134(b)(4), (b)(5), (c), and/or (d) 
are maintained and operated to ensure that they will continue to 
function as designed. Alternatively, the facility must inspect via 
remote monitoring devices to ensure that the impingement technologies 
are functioning as designed.
6. What Recordkeeping and Reporting Is Required for New Non-Fixed 
(Mobile) Offshore Oil and Gas Extraction Facilities?
    Owners and operators of new mobile offshore oil and gas extraction 
facilities must keep records of all the data used to complete the 
permit application and show compliance with the requirements, any 
supplemental information developed under Sec.  125.136, and any 
compliance monitoring data submitted under Sec.  125.137, for a period 
of at least three years from the date of permit issuance. The Director 
may require that these records be kept for a longer period.
    Additionally, this final rule requires that new mobile offshore oil 
and gas extraction facilities submit the following in a yearly status 
report:
     Velocity and head loss monitoring records for each cooling 
water intake structure as required by Sec.  125.137(b); and
     Records of visual or remote inspections as required in 
Sec.  125.137(c).

C. Are Permits for New Offshore Oil and Gas Extraction Facilities 
Subject to Requirements Under Other Federal Statutes?

    EPA's NPDES permitting regulations at 40 CFR 122.49 contain a list 
of federal laws that might apply to NPDES permits issued by EPA. These 
include the Wild and Scenic Rivers Act, 16 U.S.C. 1273 et seq.; the 
National Historic Preservation Act of 1966, 16 U.S.C. 470 et seq.; the 
Endangered Species Act, 16 U.S.C. 1531 et seq.; the Coastal Zone 
Management Act, 16 U.S.C. 1451 et seq.; and the National Environmental 
Policy Act, 42 U.S.C. 4321 et seq. See 40 CFR 122.49 for a brief 
description of each of these laws. In addition, the provisions of the 
Magnuson-Stevens Fishery Conservation and Management Act, 16 U.S.C. 
1801 et seq., relating to essential fish habitat might be relevant. 
Nothing in this final rulemaking authorizes activities that are not in 
compliance with these or other applicable Federal laws.

IX. Economic Impact Analysis

    This section summarizes EPA's analysis of total social cost and 
economic impacts for the 316(b) Phase III final regulation for new 
offshore oil and gas extraction facilities and the regulatory options 
that were considered for promulgation of a final regulation for 
existing facilities. EPA's assessment of costs and economic impacts can 
be found in the Economics and Benefits Analysis.

A. New Offshore Oil and Gas Extraction Facilities

    This rule establishes requirements for new offshore oil and gas 
extraction facilities that are point sources, employ a cooling water 
intake structure, are designed to withdraw 2 MGD or more from waters of 
the United States, and use at least 25 percent of the water withdrawn 
exclusively for cooling purposes. Oil and gas extraction facilities 
(``Oil and Gas Facilities'') are facilities primarily engaged in oil 
and gas production and drilling activities. This analysis includes oil 
and gas production platforms/structures and MODUs. EPA estimates that 
21 new oil and gas extraction platforms and 103 new MODUs would be 
subject to the national requirements of the rule, assuming a 20-year 
period of construction from 2007 (the assumed effective date of the 
rule) to 2026. Each newly-constructed facility is assumed to operate 
for 30 years, extending the

[[Page 35025]]

entire analysis period to 49 years (2007 to 2055).
    Two types of cost analysis are presented. The social cost analysis 
includes before tax compliance costs to facilities and implementation 
costs to EPA. In this analysis, costs are discounted to 2007, assuming 
it would take a facility about 6 months to begin incurring costs. If 
the start date is actually later than 2007, social costs will be 
slightly reduced from those estimated here in present value terms. For 
the second type of cost analysis, industry after-tax compliance costs, 
costs are discounted for each individual facility to the year of 
compliance (the year the vessel is launched or the platform/structure 
come on line, which ranges from 2007 to 2026). The present value 
calculated for each facility is used in the economic impact analysis. 
These costs are subsequently discounted to 2004 and are then totaled to 
produce an aggregate present value of compliance costs. For both 
approaches annualized costs are then calculated by annualizing at a 3 
percent (social costs) or 7 percent discount rate (social costs and 
industry compliance costs) over 30 years. All dollar values presented 
in this preamble are in $2004 (average or mid-year).
1. General Approach for Costing Impingement and Entrainment Equipment 
for Offshore Oil and Gas Extraction Facilities
    EPA's general approach to estimate compliance costs associated with 
the use of impingement and entrainment controls for offshore oil and 
gas facilities was to first identify the different types of cooling 
water intake structures (e.g., simple pipes, caissons, sea chests) 
being employed by the various types of offshore oil and gas extraction 
facilities (e.g., jackups, platforms, MODUs, drill ships). EPA then 
identified available impingement and entrainment control technologies 
(e.g., cylindrical wedgewire systems, flat panel wedgewire screens) for 
the different configurations of offshore oil and gas extraction 
facilities and cooling water intake structures. EPA estimated both 
capital and annual operating costs for each technology option for the 
different configurations of offshore oil and gas extraction facilities 
and cooling water intake structures.
    In order to estimate the related economic impacts associated with 
this rule, EPA used the available impingement and entrainment control 
technologies with superior reliability and performance and ease of 
operation. For example, EPA considered technologies such as airburst 
cleaning systems, which ensure that the through-screen intake 
velocities are relatively constant and as low as possible, and cooling 
water intake structures constructed with copper-nickel alloy components 
for biofouling control where necessary. While EPA recognized that 
operators complying with this rule may choose alternate impingement and 
entrainment control technologies than those upon which EPA based its 
economic analysis, EPA chose this method of estimating costs because 
EPA judged those compliance technologies to be the best technologies 
available, and accordingly used these technologies as the basis for the 
requirements in this rule
    Using this methodology, EPA estimated compliance costs for the 
various configurations of offshore oil and gas extraction facilities 
and cooling water intake structures using the following:
     Stainless steel wedge wire screens with and without air 
sparging;
     Copper-nickel wedge wire screens with and without air 
sparging;
     Stainless steel velocity caps;
     Copper-nickel alloy velocity caps;
     Flat panel wedge wire screens over sea chests; and
     Horizontal flow diverters associated with sea chests.
    EPA's detailed methodology for estimating these compliance costs is 
outlined in the Technical Development Document and the record 
supporting the final rule.
2. Social Cost for New Oil and Gas Extraction Facilities
    The total annualized social cost of this rule for new Oil and Gas 
facilities is estimated at $3.8 million using a 3 percent discount 
rate, and $3.2 million using a 7 percent discount rate. The largest 
component of social cost is the pre-tax cost of regulatory compliance 
incurred by complying facilities; these costs include one-time 
technology costs of complying with the rule, annual O&M costs, and 
permitting costs (initial permit costs, annual monitoring costs, and 
permit reissuance costs). Social cost also includes implementation 
costs incurred by the Federal government. EPA expects that the final 
regulation will be implemented under general permits.\8\
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    \8\ Because individual permits are typically not issued to 
offshore oil and gas extraction facilities, costs for pre-permitting 
and re-permitting studies are assumed to be shared among groups of 
new facilities expected to be covered by the general permits (see 
DCN 7-4036 for detailed information on how permitting costs are 
assumed to be shared under the general permits).
---------------------------------------------------------------------------

    EPA estimates that direct compliance costs will be $3.4 million and 
$2.8 million, using a 3 percent and 7 percent discount rate, 
respectively. The estimated Federal government cost for administering 
the rule for new facilities is comparatively minor in relation to the 
estimated direct cost of regulatory compliance. Federal administrative 
costs are estimated to be $0.4 million and $0.3 million per year under 
the 3 percent and 7 percent discount rates, respectively. EPA did not 
estimate costs to States for administering the new rule because the 
waters in which the regulated facilities would be located generally lie 
outside the States' jurisdiction. Specifically, facilities more than 3 
miles off the coast are in federal waters. In the case of Alaska which 
does not have NPDES program authority, EPA Region 10 is expected to 
write NPDES permits for facilities in Alaskan waters. EPA does not 
expect any new facilities to locate in California because no new 
platforms have been constructed there since 1994, and a moratorium on 
lease sales extends to the year 2012.
3. Economic Impacts for New Oil and Gas Extraction Facilities
    The following two subsections present economic impacts for MODUs 
and production platforms/structures, respectively. Certain aspects of 
the methodology differ between the two segments. Oil and gas production 
operations involve production of a finite resource, which limits the 
potential life of a production platform. Thus, the analysis for 
production platforms/structures must account for the production and 
resulting exhaustion of the finite oil and gas resource. Key 
considerations in the platforms analysis are: (1) When does production 
terminate? and (2) would the year of termination change due to 
regulation? The economic life of a MODU is not limited by such 
considerations and the analysis for MODUs is accordingly simpler. The 
Economic and Benefits Analysis and the rulemaking record contain 
additional data and details on the methodology and assumptions used in 
these analyses.
a. Mobile Offshore Drilling Units (MODUs)
    EPA projects that 80 new jackups, 20 new semi-submersibles, and 
three new drill ships will be constructed over the 20 years for which 
new facility additions are analyzed. The economic impact analysis for 
these new MODUs is conducted at two levels: the vessel level and the 
firm level. EPA conducted two vessel-level analyses and one firm-level 
analysis:
     The first vessel-level analysis is a closure analysis, 
which assesses

[[Page 35026]]

changes in vessel cash flow and net income. Because the financial 
condition of new vessels is unknown, EPA used financial information 
from representative existing vessels, collected in EPA's 316(b) survey 
of MODUs ([DCN 7-0008 and DCN 7-0018), to represent the financial 
characteristics of new facilities. The financial information from these 
representative vessels is used for a general assessment of how well 
these vessels would perform financially under the requirements of the 
final regulation. This analysis is used as an alternative assessment of 
the potential for a barrier to entry.
     The second vessel-level analysis is a barrier-to-entry 
analysis for new facilities. This analysis computes the present value 
of estimated initial permitting costs, which are assumed to be incurred 
over five years prior to the incorporation of section 316(b) permit 
requirements in the applicable general permits (see DCN 7-4036) and are 
discounted to the year of compliance (the year the vessel is assumed to 
be launched). The one-time capital costs of compliance (assumed to be 
incurred in the year of compliance) are then added to this figure. 
These summed compliance costs are then compared to the baseline 
construction costs for each type of MODU. Neither recurring costs of 
compliance (e.g., repermitting costs or recurring capital costs of 
intake controls) nor recurring baseline costs (e.g., O&M, refitting 
costs) are considered in this analysis. The analysis compares baseline 
start-up costs and incremental start-up costs associated with the final 
rule.
     The firm-level analysis is a cost-to-revenue test which 
compares the annualized compliance costs for representative new vessels 
to the revenue of firms likely to construct MODUs, assuming each of 
these firms builds a share of the 103 new MODUs expected to be 
constructed over the 20-year construction time frame. This analysis was 
conducted on a pre-tax and after-tax basis.
i. Vessel-Level Closure Analysis
    To estimate potential closures (or more precisely, decisions not to 
proceed with constructing and placing a vessel into service) as a 
result of this rule for new MODUs, EPA used two models. The first model 
is a net income model, which computes the estimated present value of 
baseline after-tax net income (i.e., without compliance costs) for 
representative MODUs (based on survey data from existing MODUs) over a 
30-year operating period for each new facility. Consistent with 
generally accepted methods of business value analysis, EPA would have 
preferred to use the present value of after-tax cash flow instead of 
net income as the basis for this analysis. However, because it could 
not reliably estimate all of the elements of cash flow, EPA instead 
used the present value of net income for its closure test. In 
particular, EPA was unable to estimate the ongoing capital outlays 
(apart from those resulting from regulatory compliance) that MODUs 
would need to make as part of their ordinary business operations. In 
performing the analysis in this way, EPA essentially used the 
facility's reported depreciation and amortization--which, being non-
cash items, are normally excluded from cash flow accounting--as an 
approximation of ongoing capital outlays. How use of reported 
depreciation and amortization, instead of a reliable estimate of 
capital outlays, affects the findings from this analysis cannot be 
precisely known. For some businesses--in particular those with 
relatively strong financial performance--depreciation and amortization 
may be less than ongoing capital outlays; for these businesses, the 
analysis will tend to overstate business value and understate the 
potential effect of compliance outlays on financial performance and 
business value. On the other hand, for some businesses--in particular 
those with relatively weak financial performance--depreciation and 
amortization may exceed ongoing capital outlays; for these businesses, 
the analysis will tend to understate business value and overstate the 
potential effect of compliance outlays on financial performance and 
business value. The second model used by EPA is an after-tax cost 
calculation model, which estimates the present value of after-tax 
compliance costs using engineering and permitting cost inputs. 
Comparing the results of these two models shows the potential effect of 
costs on vessel net income.
    EPA estimated after-tax net income using data provided by surveyed 
operators of existing MODUs (EPA received economic surveys for three 
semi-submersibles, three jackups, and two drill ships). EPA was only 
able to undertake financial analysis for those MODUs with a positive 
net income for the three years of financial information provided in the 
survey (2000 to 2002). EPA assumed that any MODU whose net income is 
negative over the three years is unlikely to be a viable operation in 
the baseline and cannot be analyzed with respect to compliance costs.
    EPA used the net income over the three years of survey data to 
create a moving cycle of net income over the period of analysis. Among 
the years of data collected (2000 to 2002), 2002 was generally a poor 
year of financial condition for the industry as a whole. EPA was thus 
able to represent industry financials in both good and bad years. The 
three-year cycle simulates the effect of volatility in oil and gas 
prices and other business conditions (e.g., rig utilization rates) over 
each facility's 30-year operating period. Future operating periods are 
likely to include major swings in the prices of oil and gas, the 
driving force behind the level of operations, rig pricing, and, thus, 
financial performance of the newly constructed vessels. EPA assumed 
that net income will be flat, on a three-year average basis, over the 
30 years of analysis and thus did not apply any factors to increase or 
decrease net income over the years of analysis. The net income figures 
from the survey, therefore, repeat every three years for 30 years. EPA 
then computed the present value of that stream of net income and 
compared it to the present value of after-tax compliance costs for the 
final regulation.
    EPA used the estimated compliance cost elements--capital, O&M, and 
permitting costs--for each new MODU to calculate the present value of 
the after-tax cost of compliance with this final requirements. Each 
compliance-related cost was accounted for in the year it is assumed to 
be incurred. Tax effects of compliance outlays were based on the owner 
company's marginal tax rate as determined from the firm's average 
taxable earnings over the three years of survey data (converted to a 
mid-year 2003 basis). EPA calculated depreciation for the compliance 
capital outlay using the modified accelerated cost recovery system 
(MACRS) and included it in the pre-tax compliance cost stream. The 
compliance cost stream was then reduced by the amount of avoided tax 
liability, based on the estimated marginal tax rate, to yield the 
after-tax compliance cost stream (for more information on these 
calculations, see DCN 7-4016). The final result of these calculations 
is the present value of after-tax compliance costs.
    The present value of after-tax compliance costs was then subtracted 
from the present value of baseline net income for the vessel. If the 
present value of net income remained positive after accounting for 
compliance costs, EPA assumed that the MODU would operate post-
compliance. If the present value of net income became negative, EPA 
assumed that the new MODU would not be a financially viable project and 
was counted as a potential ``regulatory closure.''

[[Page 35027]]

    The analysis is based on the assumption that costs cannot be passed 
through to customers. EPA bases this assumption on the fact that new 
MODUs will be competing with existing MODUs, which will not incur 
compliance costs. Based on EPA's assumption that finances for new MODUs 
will look like those for existing MODUs, this analysis found that no 
new MODUs would be a regulatory closure as a result of the incremental 
compliance costs associated with the final rule.
ii. Vessel-Level Barrier-to-Entry Analysis
    The barrier-to-entry analysis compares the present value of 
compliance costs (including the present value of initial permitting 
costs discounted to the compliance year and first-time capital/
installation costs, excluding recurring costs), to the costs of 
constructing a new MODU. If compliance costs comprised a small fraction 
of construction costs, EPA assumed that compliance costs would have no 
effect on the decision to build a new MODU.
    EPA developed incremental compliance costs for new MODUs using 
estimated initial permitting costs and technology cost estimates. The 
initial permitting costs are based on each new MODU's share of regional 
permitting costs (EPA expects that facilities in a particular 
geographic region would collect data from representative facilities in 
that region) and individual administrative start-up and permit 
application costs. The technology costs are based on the weighted 
average cost of installing controls at existing MODUs, by type of MODU, 
for all existing MODUs with technical data. The estimated present value 
of the initial permitting cost stream, plus the first-time capital/
installation costs of compliance costs, sum to approximately $130,000 
for semi-submersibles, $269,000 for jackups, and $261,000 for drill 
ships. According to Rigzone (2006), the cost of new MODUs averages $285 
million for semi-submersibles, $130 million for jackups, and $385 
million for drill ships (DCN 9-4002). The present value of initial 
permitting costs plus one-time capital/installation compliance costs is 
therefore estimated to range from 0.03 percent to 0.21 percent of 
construction costs for the three types of MODU. Because total up-front 
costs represent a very small fraction of total costs of construction 
(and even of contingency costs, which typically range from 10 percent 
to 20 percent of capital costs), EPA believes that these costs would 
not have a material effect on decisions to build new MODUs.
iii. Firm-Level Cost-to-Revenue Analysis
    EPA's research showed that firms likeliest to build MODUs with a 
design intake flow of 2 MGD or more are those that currently own such 
MODUs. EPA identified nine firms that either already own jackups, semi-
submersibles, or drill ships that would be subject to the requirements 
for new facilities if newly constructed, or that are currently in the 
process of building such MODUs. Most of these firms are among the 
largest firms in the industry. EPA estimates that these nine firms 
would own the 103 new MODUs subject to the final national requirements 
for new facilities. To determine the potential impact of the final rule 
on the nine firms determined likely to build new MODUs subject to 
regulation, EPA used a cost-to-revenue test, which compares the 
annualized pre-tax and after-tax costs of compliance (calculated for 
representative new MODUs), with 2004 revenue reported by these firms. 
Because nearly all of the firms (other than foreign-owned) are publicly 
owned, EPA relied on revenue data compiled from corporate 10K reports 
(see Chapter C2 of the EA). EPA then assigned a number of MODUs 
potentially subject to regulation to each of the firms and used the 
average per-MODU compliance costs multiplied by the number of these 
MODUs to calculate the total compliance costs that might be faced by 
these firms.
    Estimated total annual pre-tax compliance costs are approximately 
$15,300 for a semi-submersible, $33,800 for a jackup, and $39,100 for a 
drill ship. Estimated after-tax costs are approximately $10,000, 
$22,000, and $25,400, respectively, based on a 35 percent marginal 
corporate tax rate assumption, which is the highest marginal corporate 
tax rate applicable (all potentially affected entities are large or 
very large corporations whose earnings generally would put them in this 
tax bracket). These annualized costs are very small compared to the 
revenue a MODU might receive for drilling even one exploratory well in 
deepwater. Exploratory wells cost at least $30 million to drill, a 
large portion of which is paid to MODU operators (DCN 7-4017). 
Compliance costs are also small compared to the typical day rates 
(daily charges) paid to MODUs while drilling wells. These rates can 
range up to $180,000 per day (DCN 9-4001). Because EPA assumed that the 
majority of rigs to be constructed will be jackups, EPA used the 
compliance cost of a jackup rig to represent the cost of compliance 
with this rule in order to judge impacts on firms. Seven firms are each 
assumed to build 9 jackups over the time frame of the analysis 
(approximately one MODU every other year). The two additional firms, 
GlobalSantaFe and Transocean, are the dominant firms in the industry. 
These two firms are each assumed to build 18 jackups, plus one drill 
ship and two drill ships, respectively, over the time frame of the 
analysis for a total of 19 or 21 MODUs in total. For the comparison of 
annualized costs of compliance with annual revenue, EPA assumed that 
all of a firm's new rigs would be constructed in one year. If this 
assumption has any effect, it would increase the likelihood of finding 
economic impacts. With no firm-level impacts found under this scenario, 
then there will also be no impacts under other more likely scenarios in 
which costs are incurred over several years.
    Using these assumptions, EPA estimates that the annualized pre-tax 
costs per firm range from $0.3 to $0.7 million, and the after-tax costs 
range from $0.2 to $0.4 million. The pre-tax cost-to-revenue ratio 
ranges from 0.01 percent to 0.2 percent, while the after-tax ratios 
range from 0.01 percent to 0.1 percent. Given that the highest 
estimated ratio is 0.2 percent, EPA concludes that firm-level impacts 
would not pose a barrier to entry.
b. Oil and Gas Production Platforms
    EPA projects that 20 deepwater platforms and one Alaska platform 
will be constructed over the 20 years over which new facility additions 
are analyzed. The economic impact analysis for these new platforms is 
conducted at two levels: the platform level and the firm level. EPA 
conducted two platform-level analyses and one firm-level analysis:
     The first platform-level analysis assesses the potential 
effects of compliance costs on platform operation. Two effects of the 
final rule are considered: (1) A reduction in the expected economic 
value of the platform, driven by all costs of compliance, which could 
prevent oil and gas resources from being brought into production, and 
(2) earlier production shut-in, driven by the increase in O&M costs. 
The baseline operating and financial profile for this analysis is based 
on data from existing platforms whose cooling water intake rates would 
cause them to be subject to the final rule if they were being newly 
constructed after rule promulgation. These existing platforms serve as 
a baseline model of the operating and financial conditions of new 
platforms that would be regulated under the rule.

[[Page 35028]]

Estimated compliance costs are added to the baseline cost profile in 
the analysis of the impact of compliance costs on platform operations.
     The second platform-level analysis is a barrier-to-entry 
analysis for new facilities. This analysis compares the present value 
of estimated initial permitting costs plus the one-time capital costs 
of compliance (excluding any recurring costs) to the construction costs 
for each type of platform.
     The firm-level analysis is a cost-to-revenue test, which 
compares the annualized compliance costs for representative new 
platforms to the revenue of firms likely to construct new platforms/
structures. This analysis assumes that each firm likely to build a 
deepwater platform/structure subject to regulation would bring two 
platforms/structures on line over the time frame of the analysis; and 
that only one firm will build an Alaska platform during the analysis 
period. To reflect the possibility that two structures could be built 
in one year by one firm, those firms assumed to bring two deepwater 
structures on line are assigned the annualized costs of compliance for 
two platforms in one year for comparison against one year's revenue. 
This analysis was conducted on a pre-tax and after-tax basis. If the 
assumption of two platforms built in one year has any effect, it would 
increase the likelihood of finding economic impacts. With no firm-level 
impacts found under this scenario, then there will also be no impacts 
under other, possibly more likely, scenarios in which costs are 
incurred over several years.
i. Platform-Level Production/Shut-In Analysis
    Compliance costs resulting from the final regulation may affect a 
platform's financial performance and related operating decisions in two 
ways. First, increased costs from regulatory compliance will reduce the 
expected economic value of an oil and gas production project, and may 
prevent an otherwise financially viable project from being undertaken. 
Second, even if a project overall remains financially viable, increased 
operating costs may lead to an earlier production shut-in than would 
occur in the baseline. Details of the analysis of these effects are 
provided below.
    For the analysis of these effects, EPA constructed a general 
platform analysis model, which simulates the operations and economics 
of oil and gas development and production. The platform model analyzes 
production over a period extending as long as 30 years. Pre-tax costs 
(including costs incurred in pre-production years, O&M, monitoring 
costs, and repermitting costs) are input into the model in the year in 
which they occur, until the model shows the platform is uneconomical to 
operate. To determine the shut-in year, projected net revenue is 
compared to operating costs in each production year. Net revenue is 
based on an assumed price of oil, current and projected production of 
oil and gas, well production decline rates, and severance and royalty 
rates. Operating costs are based on a calculated cost per barrel of oil 
equivalent (BOE) produced. The model simulates operations for the 
lesser of 30 years or to the year when operating costs exceed 
production revenue, at which point the operator is assumed to terminate 
production. The model calculates the lifetime of the project, total 
production, and the net present value of the operation (net income of 
the operation over the life of the project in terms of today's 
dollars). A comparison of the baseline model outputs to the post-
compliance model outputs yields any losses of production and project 
duration and the net present value of the operation. If the net present 
value of the operation is positive in the baseline but negative post-
compliance, the project is considered nonviable post-compliance. It is 
assumed the platform would not be built.
    The model uses as baseline data, financial information from 
representative existing platforms, collected in EPA's 316(b) survey of 
production platforms to represent the financial characteristics of 
future platforms that would be subject to this final regulation. EPA 
received an economic survey from only one deepwater platform with 
cooling water intake rates meeting the final regulatory criteria. EPA 
used data from this survey and from other sources of publicly available 
information, such as the Minerals Management Service, to develop a 
model new deepwater oil and gas production platform. EPA also received 
a survey from a platform in Alaska but did not include it in the 
analysis because the surveyed platform is a very old structure and at 
the end of its productive life. EPA believed that it would not be 
representative of new platforms being built after the Phase III rule is 
finalized. The Alaska platform is therefore analyzed only in the 
barrier to entry analysis.

Analysis of Project Viability

    As noted above, any increase in costs, whether operating, capital, 
or permitting, will reduce the expected economic value of an oil and 
gas project, as represented by the present value of project net income, 
and may cause an otherwise economic oil and gas production project to 
never be undertaken. In this case, the entire economic value of the 
project and its otherwise recoverable oil and gas production are 
assumed to be lost. (EPA notes that this loss need not be permanent but 
may only be delayed until higher product prices, or reduced development 
and production costs allow the project to become financially viable.) 
For this potential impact, EPA analyzed whether the reduction in value 
from all regulatory compliance outlays would be sufficient to cause the 
expected discounted net income of an otherwise economically viable oil 
and gas production project to be negative at the outset. In this case, 
the operator is assumed not to proceed with development and production. 
If the platform has a positive net present value under baseline 
conditions but a negative net present value in the post-compliance 
scenario, EPA notes an impact on the platform and estimates the lost 
production resulting from the costs of regulatory compliance.

Analysis of Production Shut-In Effects

    Although a project overall remains financially viable, the 
increased operating costs from regulatory compliance may lead to an 
earlier production shut-in than would occur in the baseline. Apart from 
the financial impact, an earlier shut-in will also lead to reduced 
production of otherwise economically recoverable oil and gas. For this 
analysis, projected net revenue is compared to operating costs at each 
year for the model project.\9\ Net revenue (after subtracting royalties 
and severance, which are payments to the lease owner and a State, if 
relevant) is based on an assumed price of oil, current and projected 
production of oil and gas, well production decline rates, and severance 
and royalty rates. Operating costs are based on a calculated cost per 
barrel of oil equivalent (BOE) produced. The model simulates operations 
for the lesser of 30 years or to the year when operating costs exceed 
production revenue, at which point the operator is assumed to terminate 
production. A comparison of total production and total project lifetime 
in the baseline vs. post-compliance shows any differences in

[[Page 35029]]

these variables following the imposition of compliance costs.
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    \9\ Following engineering review of surveyed deepwater 
platforms/structures, only one was determined to have a total design 
cooling water intake structure intake flow rate meeting the proposed 
316(b) thresholds for regulation of oil and gas facilities, had the 
structure been newly constructed, so only one model of deepwater 
structures was developed.
---------------------------------------------------------------------------

    This analysis found no impacts on deepwater oil and gas development 
or production as a result of the incremental compliance costs 
associated with this rule, for the one platform that was analyzed. 
Impacts on net present value were very small.
ii. Platform-Level Barrier-to-Entry Analysis
    The barrier-to-entry analysis compares the present value of the 
initial permitting cost stream (discounted to the year of compliance) 
plus one-time capital/installation costs to the costs of constructing a 
new platform. If compliance costs comprise a small fraction of 
construction costs, EPA assumes that compliance costs would not have an 
effect on the decision to build a new platform.
    The estimated total present values of incremental compliance costs 
are $306,323 for deepwater projects and $708,058 for Alaska projects. 
Costs for constructing new deepwater platforms are estimated to range 
from $114 million to $2.3 billion (see EA for the Synthetic Drilling 
Fluid Effluent Limitations Guidelines in the rulemaking record, DCN 7-
4017). For Alaska, EPA used a value of $120 million (DCN 7-4028). The 
ratio of incremental compliance costs to current total construction 
costs therefore ranges from 0.01 percent to 0.3 percent for deepwater 
projects and is estimated to be 0.6 percent for an Alaska project. 
Because this represents a small fraction of total construction costs 
(and even of contingency costs), EPA believes that these costs would 
not have a material effect on decisions to build new platforms.
iii. Firm-Level Cost-to-Revenue Analysis
     To determine the potential impact of the final rule on 
firms, EPA used a cost-to-revenue test, which compares the annualized 
pre-tax and after-tax costs of compliance (calculated for a 
representative new platform times the maximum number of platforms 
assumed built by each firm in any one year), with 2004 revenue reported 
by all firms determined likely to be affected by this regulation. The 
firms that are considered affected are (1) those identified as 
currently having existing deepwater platforms or structures that would 
be subject to regulation if they were newly constructed and (2) the 
likeliest type of firm to build a new Alaska platform during the time 
frame of the analysis. EPA assumed each of the 11 firms operating in 
the deepwater Gulf would bring on-line two platforms during the period 
of analysis. To reflect the possibility that two structures could be 
built in one year by one firm, EPA assumes the two platforms come on 
line in one year for comparison with one year's revenue at each firm. 
If this assumption has any effect, it would increase the likelihood of 
finding economic impacts. With no firm-level impacts found under this 
scenario, then there will also be no impacts under other, possibly more 
likely, scenarios in which costs are incurred over several years. In 
addition, one small firm is assumed to build the one Alaska platform 
over the period of analysis, and the annualized compliance cost is also 
compared to one year's revenue at that firm.
    Using these assumptions, EPA estimates that the annualized pre-tax 
costs per firm are about $0.2 million, and the after-tax costs are 
about $0.1 million. The pre-tax cost-to-revenue ratio ranges from 
<0.001 percent to 0.032 percent, while the after-tax ratios range from 
<0.001 percent to 0.021 percent. Given that the highest estimated ratio 
is 0.032 percent, EPA concludes that firm-level impacts would not pose 
a barrier to entry.
c. Total Facility Compliance Costs and Impacts for All New Oil and Gas 
Facilities
    Exhibit IX-1 summarizes the total facility compliance costs and 
impacts associated with the final regulation for Phase III new offshore 
oil and gas facilities. Annualized after-tax costs total $1.9 million 
per year for MODUs and $1.3 million per year for platforms, or a total 
of $3.2 million per year for all affected new oil and gas operations 
estimated to be constructed over the period of the analysis (using a 7 
percent discount rate). Costs are incurred assuming 20 years of new 
facility construction, with each facility incurring costs over a 30-
year operating period, discounted to the year the facility is launched 
or comes on-line. The present value of these costs is calculated, then 
annualized over the 30 operating years at 7 percent. The present value 
of private after-tax costs is less than the previously described 
present value of social costs, which are based on pre-tax costs, 
because of differences in the discounting for private costs and social 
costs. Private costs are discounted, for each analysis, only to the 
first year of compliance. In contrast, for the social cost calculation, 
all costs are discounted to the beginning of 2007, regardless of when 
new facilities come into operation. Because new facilities are 
scheduled to begin operation for a 20 year period following rule 
promulgation, the total effect of discounting is much greater for the 
present value of social cost calculation than for the private cost 
calculation. As a result, the present value of social cost, even though 
based on pre-tax costs, is less than the present value of private, 
after-tax cost.

               Exhibit IX-1.--Summary of Private Costs and Impacts for New Oil and Gas Facilities
----------------------------------------------------------------------------------------------------------------
                                                                    Annualized
                                                                  private after-
                                                   Number of new  tax compliance     Facility
          Type of oil and gas facility              facilities      costs  (in        impacts      Firm impacts
                                                                     millions,
                                                                      $2004)
----------------------------------------------------------------------------------------------------------------
MODUs...........................................             103            $1.9               0               0
Platforms.......................................              21             1.3               0               0
                                                 ---------------------------------------------------------------
    Total.......................................             124             3.2               0              0
----------------------------------------------------------------------------------------------------------------
Note: Component values may not sum to the reported total due to independent rounding.

    Exhibit IX-2, below, summarizes total social costs and impacts for 
the final regulation for new offshore oil and gas extraction 
facilities.

[[Page 35030]]



Exhibit IX-2.--Summary of Economic Analysis for the 316(b) Phase III Final Regulation Applicable to New Offshore
                                        Oil and Gas Extraction Facilities
----------------------------------------------------------------------------------------------------------------
                                                                                     Number of
                                                                    Annualized      facilities       Number of
                                                                    social cost     subject to      facilities
                                                                   (in millions,     national      with  impacts
                                                                  $2004) \1\ \2\   requirements
----------------------------------------------------------------------------------------------------------------
Direct Compliance Cost for New Oil and Gas Facilities...........       $3.4-$2.8             124               0
Total State and Federal Administrative Cost.....................       $0.4-$0.3  ..............  ..............
                                                                 -----------------------------------------------
    Total Social Cost...........................................      $3.8--$3.2  ..............  ..............
----------------------------------------------------------------------------------------------------------------
\1\ The left side of the each range is the cost discounted at 3% and the right side is cost discounted at 7%.
\2\ Numbers may not sum to totals due to independent rounding.

B. Existing Phase III Facilities

    As described earlier in this Preamble, EPA has decided that Phase 
III facilities should continue to be permitted on a case-by-case best 
professional judgment basis. Since EPA is not promulgating a national 
categorical section 316(b) rule for existing Phase III facilities, 
there are no additional compliance costs associated with this action 
for these facilities. However, EPA did estimate the costs for the 
national categorical regulatory options we considered. More information 
on the costing analysis can be found in the Development Document and in 
the public record for this action.
    This part of the Preamble describes the cost and economic impact 
analyses undertaken for the three national categorical regulatory 
options that were considered for the Phase III final regulation for 
existing facilities. These three options were defined by a regulatory 
applicability threshold based on design intake flow (DIF) and by the 
type of waterbody from which cooling water is withdrawn. As described 
at Proposal, these regulatory options are as follows:
    1. Facilities with a total design intake flow of 50 million gallons 
per day (MGD) or more and located on any source waterbody type (50 MGD 
All Waterbodies);
    2. Facilities with a total design intake flow of 200 MGD or more 
and located on any source waterbody type (200 MGD All Waterbodies);
    3. Facilities with a total design intake flow of 100 MGD or more 
and located on certain source waterbody types (i.e., an ocean, estuary, 
tidal river/stream or one of the Great Lakes) (100 MGD Coastal/Great 
Lakes).
    These facilities are primarily engaged in the manufacturing of 
paper, chemicals, petroleum, aluminum, and steel, but include other 
industries such as food production as well as a few non-manufacturing 
facilities. As described in the NODA, EPA evaluated Food and Kindred 
Products as a primary industry; see Chapter B2F of the final EA. Non-
manufacturing industries comprise less than 1 percent of the total 
facilities potentially regulated under each of the co-proposed options. 
In addition to engaging in production activities, some facilities also 
generate electricity for their own use and occasionally for sale.

Summary of Facilities Potentially Subject to a Final National 
Categorical Phase III Regulation for Existing Facilities

    Exhibit IX-3 presents, by DIF option, EPA's estimates of (1) the 
number of existing facilities potentially subject to this rulemaking, 
(2) the number of baseline closures, and (3) the number of existing 
facilities subject to national requirements under the proposed 
regulations, after removal of baseline closures.

                 Exhibit IX-3.--Phase III Existing Manufacturers Facility Counts, by DIF Option
----------------------------------------------------------------------------------------------------------------
                                                                    Facilities
                                                                    potentially                     Subject to
                                                                    subject to                       National
                            Industry                                regulation,      Baseline      requirements,
                                                                     based on        closures        excluding
                                                                   applicability                     baseline
                                                                     criteria                        closures
----------------------------------------------------------------------------------------------------------------
                                             50 MGD All Waterbodies
----------------------------------------------------------------------------------------------------------------
Primary Man. Industries.........................................             155              14             140
Other Industries................................................               7               1               6
                                                                 -----------------------------------------------
    Total.......................................................             161              15             146
        Total DIF (MGD).........................................          31,215           1,907          29,308
----------------------------------------------------------------------------------------------------------------
  200 MGD All Waterbodies
----------------------------------------------------------------------------------------------------------------
Primary Man. Industries.........................................              31               1              30
Other Industries................................................               2               1               1
                                                                 -----------------------------------------------
    Total.......................................................              33               2              31
                                                                 ===============================================
        Total DIF (MGD).........................................          18,973             682          18,292
----------------------------------------------------------------------------------------------------------------
                                           100 MGD Coastal/Great Lakes
----------------------------------------------------------------------------------------------------------------
Primary Man. Industries.........................................              24               3              21
Other Industries................................................               3               1               2
                                                                 -----------------------------------------------

[[Page 35031]]

 
    Total.......................................................              27               4              23
                                                                 ===============================================
        Total DIF (MGD).........................................           8,654             747          7,907
----------------------------------------------------------------------------------------------------------------
Note: Totals may not sum due to independent rounding.

1. Method for Estimating Costs to Manufacturers
    Detailed information was not available for the universe of 
potential Phase III facilities, and the precise cost and performance of 
each technology on a site-specific basis cannot be determined. Thus, 
EPA developed model facility costs using the methodology outlined at 
proposal (see 69 FR 68498) and discussed in Chapter 5 of the TDD. EPA 
collected facility-specific process information using a detailed 
technical survey of Electric Generators and Manufacturers (see 69 FR 
68457). EPA first calculated facility-specific costs for 354 facilities 
for which detailed information was available, and applied the model 
facility approach used at proposal to the remaining facilities to 
calculate the industry-level costs. This universe included all 
potential Phase III facilities, including those with a design intake 
flow of 2 MGD to 50 MGD that were not included in any of the proposed 
regulatory options.
    As was the case in its analysis of compliance costs for the oil and 
gas extraction rule promulgated today, EPA adopted the best-performing 
technology approach for estimating compliance costs at cooling water 
intakes for Phase III existing facilities. EPA recognizes that the 
actual technology and/or operational measures that each facility might 
select are based on site-specific considerations. In particular, it is 
difficult to determine the precise performance of each technology on a 
site-specific basis for several hundred facilities. The Agency thus 
selected, for the subset of sites where multiple technologies could be 
considered to meet the proposed national categorical requirements, a 
best performing technology rather than the least cost technology from 
among the choices. As articulated in the preamble to the Phase II final 
rule (69 FR 41650), the best performing technology concept relies on 
assigning technologies around a median cost, with some choices above 
and some choices below. EPA believes that the best-performing 
technology approach, unlike a least-cost approach, takes site-specific 
considerations that cannot be accurately predicted in advance into 
account. EPA believes that the best-performing technology approach is 
appropriate to use for existing facilities under Phase III, and it has 
continued to rely upon it here. EPA notes that the proposal and NODA 
identified refinements made to the methodology, and made it available 
for public comment.
    In addition to the capital and annual operating costs of the 
selected technology module, some facilities were projected to incur net 
downtime costs. Downtime costs generally reflect decreased revenue due 
to lost production or costs of supplemental power purchases during the 
retrofit of existing cooling water intake structures. As described in 
the NODA (70 FR 71057), EPA's record suggests that some manufacturers 
have the flexibility to alter processes or use other intakes to avoid 
downtime, and other manufacturers may be able to purchase power and 
would experience a cost lower than the cost of lost production. For 
example, 14 percent of manufacturing facilities operate less than 75 
percent of the year and would likely avoid downtime by scheduling 
installation of design and construction technologies during this 
downtime. Some facilities indicated they would select engineering 
solutions that avoid the need for downtime. However, downtime may be 
unavoidable at some facilities. For Phase III model facilities with 
multiple intakes, final downtime estimates remain at zero for those 
facilities with shoreline intakes that are not dedicated intakes, as 
discussed in the proposal. Using the approach presented in the NODA, 
downtime estimates were reduced by 49 weeks (47 percent), 14 weeks (87 
percent), and 11 weeks (39 percent), respectively, for the three 
regulatory options (50 MGD All Waterbodies, 100 MGD Coastal/Great 
Lakes, and 200 MGD All Waterbodies, respectively). Costs also reflect 
the corrected design intake flow as described in the NODA. See chapter 
5, section 5 of the TDD and DCN 8-6601A, Downtime Duration Input and 
Analysis of Manufacturing Facilities, for additional details on the 
final downtime analysis.
    Permit costs, including costs for permitting, monitoring, permit 
reissuance, and recordkeeping were developed separately as part of the 
proposed Information Collection Request (ICR) for Cooling Water Intake 
Structures Phase III (``ICR''; DCN 7-0001). The per facility permit 
costs were added to the incremental compliance costs, along with 
installation downtime costs (where appropriate), in developing the 
total model facility cost. The per facility permit costs may be found 
in Chapter B1 of the EA (also see the ICR for this rule, DCN 9-0001, 
for more information).

2. Social Cost for Existing Manufacturing Facilities

    EPA calculated the social cost of the principal regulatory options 
for existing manufacturing facilities using two discount rate values: 3 
percent and 7 percent. All dollar values presented are in $2004 
(average or mid-year). For the analysis of social costs, EPA discounted 
all costs to the beginning of 2007, assuming that it would take 
facilities about six months to begin incurring costs. EPA assumed that 
all facilities subject to the regulation would achieve compliance 
between 2010 and 2014. EPA estimated the time profile of compliance and 
related costs over 30 years from the year of compliance for each 
complying facility.\10\ Costs incurred by governments for administering 
the regulation were analyzed over the same time frame. The last year 
for which costs were tallied is 2043. Exhibit IX-4 presents the total 
social cost.
---------------------------------------------------------------------------

    \10\ Benefits are tallied and discounted in the same way, 
although the total time profile for recognition of benefits is 
longer than the profile for recognition of costs to account for a 1-
6 year lag reflecting population dynamics.

[[Page 35032]]



                                    Exhibit IX-4.--Annualized Social Cost \1\
                                              (In millions, $2004)
----------------------------------------------------------------------------------------------------------------
                                                                    50 MGD all      200 MGD all
                                                                    waterbodies     waterbodies     100 MGD CWB
----------------------------------------------------------------------------------------------------------------
Direct Compliance Cost:
    Primary Manufacturing Industries............................      $36.3-37.1     $18.8-$19.5     $13.7-$13.3
    Other Industries............................................         1.3-1.2         0.5-0.4         0.7-0.7
                                                                 -----------------------------------------------
        Total Direct Compliance Cost............................       37.6-38.3       19.3-20.0       14.4-13.9
State and Federal Administrative Cost...........................         0.6-0.6         0.2-0.2         0.2-0.2
                                                                 -----------------------------------------------
    Total Social Cost...........................................       38.2-39.0       19.5-20.2      14.6-14.1
----------------------------------------------------------------------------------------------------------------
\1\ The left side of each range is the cost discounted at 3%, and the right side of each range presents the cost
  with a 7% discount rate. The effect of the discount rate varies across regulatory options in the table because
  the time profile of costs varies across facilities and technology choices.

3. Economic Impacts for Manufacturers
    The economic impact analyses assess how facilities, and the firms 
that own them, would potentially be affected financially by the 
national categorical options. The facility impact analysis uses 
compliance cost estimates (see section IX.A.2) to calculate how 
incurring these costs would affect the financial performance and 
condition of the regulated facilities.
    This section presents EPA's estimated economic impacts on 
manufacturers for the national categorical regulatory options 
considered by EPA. Impact measures include (1) facility closures and 
associated losses in employment, (2) financial stress short of closure 
(``moderate impacts''), and (3) firm-level impacts. EPA eliminated from 
this analysis those facilities showing materially inadequate financial 
performance in the absence of additional regulation (``baseline 
closures'').
    For the remaining facilities, EPA identified a facility as a 
regulatory closure if it would have operated under baseline conditions 
but would fall below an acceptable financial performance level under 
additional regulatory requirements. EPA's analysis of regulatory 
closures is based on the estimated change in facility after-tax cash 
flow and business value as a result of the national categorical 
regulatory options considered. (See EA, Chapter B3 for details of the 
cash flow calculation and assessment of the potential for facility 
closure as a result of additional regulatory requirements.)
    EPA's analysis of moderate financial impact is based on change in 
facility financial performance and condition as indicated by Interest 
Coverage Ratio (ICR) and Pre-Tax Return on Assets (PTRA). (See EA 
Appendix B3-A6 for details of the moderate impacts analysis.) See the 
EA for a detailed description of EPA's baseline closure analysis and 
firm level analyses.
    As shown in Exhibit IX-5, EPA estimated that none of the baseline-
pass facilities would incur a severe impact (closure) or a moderate 
economic impact (financial impact short of closure) under the national 
categorical regulatory options considered.

Exhibit IX-5.--Summary of Cost and Regulatory Impacts for Existing Manufacturing Facilities by Regulatory Option
----------------------------------------------------------------------------------------------------------------
                                                                    50 MGD All      200 MGD All     100 MGD CWB
----------------------------------------------------------------------------------------------------------------
Facilities Operating in Baseline................................             144             144             144
Facilities with Regulatory Requirements.........................             144              30              24
Percentage of Facilities with Regulatory Requirements...........          100.0%           20.8%           16.7%
Facilities Assessed as Closures (Severe Impacts)................               0               0               0
Percentage of Facilities with Regulatory Requirements Assessed              0.0%            0.0%            0.0%
 as Closures....................................................
Facilities Assessed as Moderate Impacts.........................               0               0               0
Percentage of Facilities with Regulatory Requirements with                  0.0%            0.0%            0.0%
 Moderate Impacts...............................................
Annualized Compliance Costs (after tax, million $2004)..........           $26.8           $11.8           $12.1
----------------------------------------------------------------------------------------------------------------

X. Benefits Analysis

A. Introduction

    Since EPA is not promulgating national section 316(b) requirements 
for existing Phase III facilities, this action will achieve no benefits 
with respect to existing facilities. Any benefits associated with 
establishing section 316(b) requirements for existing Phase III 
facilities will be realized at the permitting level, as is currently 
the case, and therefore should not be attributed to today's decision. 
However, EPA did estimate the benefits for the national categorical 
regulatory options considered. These benefits estimates should be 
compared only to the cost estimates for these options for existing 
Phase III facilities.
    The benefit estimates presented below reflect impingement mortality 
and entrainment reductions at Phase III existing facilities but not at 
new offshore oil and gas extraction facilities. EPA does not project 
benefits for facilities that have not yet been built because to do so 
would require projecting where these facilities would be built and/or 
operate. For a comparison of social use benefits and total social 
costs, refer to Section XI.

B. Study Design and Methods

    The methodologies used here are built upon those used for 
estimating benefits of the final rule for Phase II facilities (see FR 
69, 41576-693). The national benefit estimates are derived from a 
series of regional studies for a range of waterbody types throughout 
the U.S. EPA evaluated impingement and entrainment data from 76 Phase 
II facilities and 20 potentially regulated

[[Page 35033]]

Phase III facilities.\11\ Using standard fishery modeling techniques, 
EPA combined facility-derived impingement and entrainment counts with 
relevant life history data to derive estimates of (1) age-one 
equivalent losses (the number of individuals of different ages impinged 
and entrained expressed as an equivalent number of age-one fish), and 
(2) foregone fishery yield (pounds of commercial harvest and numbers of 
recreational fish and shellfish not harvested due to impingement and 
entrainment). Of the organisms that were anticipated to be protected by 
the national categorical analysis option, approximately 2 to 3 percent 
would have been eventually harvested by commercial and recreational 
fishers and therefore can be valued with direct use valuation 
techniques.
---------------------------------------------------------------------------

    \11\ ``Potentially regulated Phase III facilities'' refers to 
all existing facilities with design intake flows greater than 2 MGD 
and not regulated under the Phase II rule.
---------------------------------------------------------------------------

    To obtain a national estimate of losses at all potentially 
regulated facilities, EPA extrapolated impingement and entrainment 
rates from facilities with data (model facilities) to facilities 
without data, on the basis of operational intake flow in millions of 
gallons per day (MGD). Exhibit X-1 presents EPA's estimates of current 
annual impingement and entrainment (I&E) and EPA's estimates of annual 
I&E reductions under the national categorical regulatory options.

 Exhibit X-1.--Annual Impingement and Entrainment a Baseline Losses and
 Estimated Reductions Under the National Categorical Regulatory Options
------------------------------------------------------------------------
                                               Age-1         Foregone
                                            equivalent     fishery yield
                                               fish            (lbs)
------------------------------------------------------------------------
Baseline................................     265,000,000       9,640,000
50 MGD All Option.......................      98,200,000       4,770,000
200 MGD All Option......................      74,500,000       3,290,000
100 MGD CWB Option......................      71,100,000      4,510,000
------------------------------------------------------------------------
\a\ I&E data are rounded to three significant figures.

C. National Benefits

    Economic benefits of the national categorical regulatory options 
for the section 316(b) regulation for Phase III existing facilities can 
be defined according to categories of goods and services provided by 
the species affected by impingement and entrainment by cooling water 
intake structures.
    The first category includes benefits that pertain to the use 
(direct or indirect) of the affected fishery resources. Use value 
reflects the value of all current direct and indirect uses of a good or 
service such as commercial and recreational harvest of fish (Mitchell 
and Carson, 1989, DCN 5-1287). In this context, direct use values are 
associated with harvested fish, while indirect use values are 
associated with non-harvested fish that are prey for harvested fish. 
The second category includes benefits that are independent of any 
current or anticipated use of the resource; these are known as ``non-
use'' or ``passive use'' values. Non-use values include ``nonmarketed'' 
goods and services, which reflect human values associated with 
existence, bequest, and altruistic motives.
    EPA estimated the economic benefits from the national categorical 
regulatory options using a range of valuation methods, depending on the 
benefit category, data availability, and other suitable factors. EPA 
calculated benefits of the national categorical regulatory options for 
existing Phase III facilities using two discount rate values: 3 percent 
and 7 percent. All dollar values presented are in $2004 (average or 
mid-year). Because avoided fish deaths occur mainly in fish that are 
younger than harvestable age (eggs, larvae and juveniles), the benefits 
from avoided impingement and entrainment would be realized typically 3-
4 years after their avoided death. A detailed description of the 
approaches used can be found in the Regional Analysis Document.
1. Use Benefits
    To estimate recreational benefits of the national categorical 
regulatory options, EPA developed a benefits transfer approach based on 
a meta-analysis of recreational fishing valuation studies designed to 
measure the various factors that determine willingness-to-pay for 
catching an additional fish per trip. To estimate the benefits, EPA 
multiplied the per fish values by the number of additional fish that 
would be caught by anglers under the national categorical regulatory 
options due to reductions in impingement and entrainment, compared to 
current levels of recreational catch. To estimate commercial fishing 
benefits, EPA monetized the reduction in forgone fishery yield using 
market prices, effectively assuming that the change in forgone yield 
was small enough to have an insignificant impact on price.
2. Non-Use Benefits
    To assess the public policy significance of the ecological gains 
from the national categorical regulatory options for Phase III 
facilities, EPA also attempted to quantify nonuse benefits associated 
with reduction in impingement and entrainment of fish, shellfish, and 
other aquatic organisms under the national categorical regulatory 
options, but was unable to do so in time to meet the consent decree 
deadline. EPA also conducted a break-even analysis of non-use benefits 
(see the Regional Analysis Document for details).
3. National Benefits
    This section presents EPA's estimated benefits of the national 
categorical regulatory options considered by EPA's final regulation for 
Phase III existing facilities. Since the Agency was unable to monetize 
non-use benefits, the monetized estimates of total benefits reflect use 
values only. National use benefit estimates (see Exhibit X-2) are 
subject to uncertainties inherent in valuation approaches used for 
assessing the benefits categories. The combined effect of these 
uncertainties is of unknown magnitude or direction (i.e., the estimates 
may over- or under-state the anticipated national-level benefits); 
however, EPA has no data to indicate that the results for each benefit 
category are atypical or unreasonable.

[[Page 35034]]



    Exhibit X-2.--Summary of Monetized Social Use Benefits Under the National Categorical Regulatory Options
                                              [Thousands, $2004] a
----------------------------------------------------------------------------------------------------------------
                                                                                                       Total
                                                                                                    annualized
                                                                    Annualized      Annualized       value of
                                                                    commercial     recreational     monetizable
                             Option                                   fishing         fishing       impingement
                                                                     benefits        benefits           and
                                                                                                    entrainment
                                                                                                  reductions \b\
----------------------------------------------------------------------------------------------------------------
50 MGD All......................................................       $255-$321   $1,543-$1,931   $1,798-$2,251
200 MGD All.....................................................         167-211     1,027-1,288     1,194-1,499
100 MGD CWB.....................................................         244-308     1,244-1,564    1,489-1,872
----------------------------------------------------------------------------------------------------------------
\a\ All benefits presented in this table are annualized. These annualized benefits represent the value of all
  benefits generated over the time frame of the analysis, discounted to 2007, and then annualized over a thirty
  year period. For a more detailed discussion of the discounting methodology, refer to section X.D.2 of this
  preamble. The low end of these ranges is based on the value of benefits discounted using a 7% discount rate
  while the high end is based on the value of benefits discounted using a 3% discount rate.
\b\ The estimate of the total monetizable value of impingement and entrainment reductions includes use benefits
  only.

XI. Comparison of Benefits and Costs

    Since EPA is not promulgating national section 316(b) requirements 
for existing Phase III facilities, there are no benefits or compliance 
costs for existing facilities from this action. However, EPA did 
estimate the benefits and costs for the regulatory options considered 
for existing facilities. You can find more information on these benefit 
and cost analyses in the Economic and Benefits Analysis, Regional 
Analysis Document, and in the public record for this action.
    EPA does not project benefits for facilities that have not yet been 
built because such estimates would rely on speculating where these 
facilities would be built and/or operate. EPA has no basis to predict 
exactly where the new facilities might locate, when the facilities 
might commence operation, or when and where mobile facilities may 
relocate; therefore EPA did not develop benefits estimates for new 
offshore oil and gas extraction facilities. Hence it is not possible to 
compare quantified costs and benefits associated with this final rule.
    This section presents comparisons of the national benefits and 
costs of the national categorical regulatory options. The benefit-cost 
analysis for the national categorical regulatory options compares total 
annualized use benefits to total annualized pre-tax costs (social 
costs) at existing facilities that remain open in the baseline. 
Benefits and costs were discounted using both a 3 percent and a 7 
percent discount rate. The cost estimates include costs of compliance 
to facilities subject to the final rule as well as administrative costs 
incurred by state and local governments and by the federal government. 
The benefits estimates include monetized benefits to commercial and 
recreational fishing. The total monetizable benefits include only use 
benefits. The non-use benefits were evaluated qualitatively.
    Exhibit XI-1 summarizes total annualized use benefits, total 
annualized costs, and net benefits for the national categorical 
options.

        Exhibit XI.--Summary of Social Benefits and Costs for the National Categorical Regulatory Options
                                                [Millions; $2004]
----------------------------------------------------------------------------------------------------------------
                                      Number         Number of         Total
                                    facilities      facilities    annualized use       Total       Cost/benefit
             Option                 subject to      installing     value  of I&E    annualized         ratio
                                      option        technology    reductions \a\     costs \b\
----------------------------------------------------------------------------------------------------------------
50 MGD All Waterbodies..........             146             111     $1.80-$2.25   $38.27-$39.00       17/1-22/1
200 MGD All Waterbodies.........              31              27        1.19-1.5     19.48-20.14       13/1-17/1
100 MGD Coastal/Great Lakes.....              23              22       1.49-1.87     14.57-14.11       8/1-10/1
----------------------------------------------------------------------------------------------------------------
\a\ The total monetizable value of I&E reductions includes use benefits only. EPA evaluated non-use benefits
  only qualitatively. The low and high use values reflect the range of benefits values presented in Section X of
  the preamble.
\b\ Total costs are based on pre-tax facility costs and include State, local, and Federal administrative costs
  of $0.6 million. The low and high cost values reflect the range of cost values presented in Section IX of the
  preamble.

XII. Statutory and Executive Order Reviews

    The discussion of the regulatory statutes and Executive Orders in 
this section addresses requirements relevant to new offshore oil and 
gas extraction facilities. As discussed in section VI of this preamble, 
EPA has decided not to promulgate national categorical standards for 
Phase III existing facilities.

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866, (58 FR 51735 (October 4, 1993)) the 
Agency must determine whether the regulatory action is ``significant'' 
and therefore subject to OMB review and the requirements of the 
Executive Order. The Order defines ``significant regulatory action'' as 
one that is likely to result in a rule that may:
     Have an annual effect on the economy of $100 million or 
more or adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
     Create a serious inconsistency or otherwise interfere with 
an action taken or planned by another agency;

[[Page 35035]]

     Materially alter the budgetary impact of entitlements, 
grants, user fees, or loan programs or the rights and obligations of 
recipients thereof; or
     Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.''
    Pursuant to the terms of Executive Order 12866, it has been 
determined that this rule is a ``significant regulatory action.'' As 
such, this action was submitted to OMB for review. Substantive changes 
made in response to OMB suggestions or recommendations will be 
documented in the public record.

B. Paperwork Reduction Act

    The Office of Management and Budget (OMB) has approved the 
information collection requirements contained in this rule under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control number 2040-0268.
    The information collected under this final rule will assist EPA in 
regulating environmental impacts, namely impingement mortality and 
entrainment, at cooling water intake structures at new offshore oil and 
gas extraction facilities. This information will be used by these 
facilities as appropriate to prepare permit applications and 
comprehensive demonstration studies, monitor impingement mortality and 
entrainment, verify compliance, and prepare annual reports as required 
under this rule. The information collected will be reviewed by EPA to 
ensure that appropriate National Pollutant Discharge Elimination System 
(NPDES) permit conditions regulating cooling water intake structures 
are developed and complied with. Compliance with the applicable 
information collection requirements imposed under this final rule is 
mandatory (see Sec. Sec.  122.21(r), 125.136, 125.137, 125, 138).
    EPA does not consider the specific data that will be collected 
under this final rule to be confidential business information. However, 
if a respondent does consider this information to be confidential, the 
respondent may request that such information be treated as 
confidential. All confidential data submitted to EPA will be handled in 
accordance with 40 CFR 122.7, 40 CFR part 2, and EPA's Security Manual 
Part III, Chapter 9, dated August 9, 1976.
    This final rule modifies regulations at Sec.  122.21 to require new 
offshore oil and gas extraction facilities to prepare and submit 
information consistent with that required for Phase I facilities (the 
requirements vary based on whether the facility is a ``fixed'' facility 
and whether it uses a sea chest). A detailed list of required data 
items is provided below.
    The total average annual burden of the information collection 
requirements for new offshore oil and gas facilities associated with 
this final rule is estimated at 11,238 hours for an average of 22 
facilities during the first three years after promulgation of the rule. 
Hence, the annual average reporting and recordkeeping burden for the 
collection of information from facilities complying with the final rule 
is estimated to be 511 hours per respondent.
    For new offshore oil and gas extraction facilities, the permitting 
process is handled directly by EPA Regions. Because this burden is 
incurred by the Federal Government rather than the States, it is not 
included as part of the burden statement for State Directors. Hence, 
there will be no increase in the Director reporting and recordkeeping 
burden for the review, oversight, and administration of the rule.
    The corresponding estimates of costs other than labor (labor and 
non-labor costs are included in the total cost of the final rule 
discussed in section IX of this preamble) during the first three years 
after promulgation of the rule is $0.58 million. Non-labor costs 
include activities such as capital costs for remote monitoring devices, 
laboratory services, photocopying, and the purchase of supplies. The 
burden and costs are for the information collection, reporting, and 
recordkeeping requirements for the three-year period beginning with the 
assumed effective date of this rule. Additional information collection 
requirements will occur after this initial three-year period as new 
offshore oil and gas extraction facilities are issued permits and such 
requirements will be counted in a subsequent information collection 
request.
    Studies to be submitted by new offshore oil and gas extraction 
facilities under this final rule are listed below. New offshore oil and 
gas fixed platforms would be required to provide the general 
information listed below.
     Source Water Physical Data (Sec.  122.21(r)(2)) (Sec.  
122.21(r)(2)(iv) only for non-fixed new offshore oil and gas extraction 
facilities)
     Cooling Water Intake Structure Data (Sec.  122.21(r)(3)) 
(Sec.  122.21(r)(3)(ii) not applicable to non-fixed new offshore oil 
and gas extraction facilities)
    New offshore oil and gas extraction facilities would be required to 
submit the following information under Track I:
     Source Water Baseline Biological Characterization Data 
(Sec.  122.21(r)(4)) (not required for non-fixed facilities)
     Velocity Information (Sec.  125.136(b)(1))
     Source Waterbody Flow Information (Sec.  125.136(b)(2)) 
(only applicable to fixed facilities located in estuaries or tidal 
waters)
     Design and Construction Technology Plan (Sec.  
125.136(b)(3))
    Under Track II, new offshore oil and gas extraction facilities 
would be required to submit the following information:
     Source Waterbody Flow Information (Sec.  125.136(c)(1)) 
(only applicable to fixed facilities located in estuaries or tidal 
waters)
     Comprehensive Demonstration Study (Sec.  125.136(c)(2))
    [cir] Source Water Biological Study (Sec.  125.136(c)(2)(iii)(A))
    [cir] Evaluation of Potential Cooling Water Intake Structure 
Effects (Sec.  125.136(c)(2)(iii)(B))
    [cir] Verification Monitoring Plan (Sec.  125.136(c)(2)(iii)(C))
    In addition to the information requirements of the permit 
application, NPDES permits normally specify monitoring and reporting 
requirements to be met by the permitted entity. New offshore oil and 
gas extraction fixed facilities would be required to perform monitoring 
as determined by the Track I or Track II requirements in Sec.  125.136 
and in accordance with Sec.  125.137. Additional ambient water quality 
monitoring may also be required of facilities depending on the 
specifications of their permits (e.g., as part of velocity monitoring 
at Sec.  125.137(b)). New offshore oil and gas extraction facilities 
would be expected to analyze the results from their monitoring efforts 
and are required to provide these results in an annual status report to 
the permitting authority. Finally, facilities would be required to 
maintain records of all submitted documents, supporting materials, and 
monitoring results for at least three years.
    All impacted facilities would carry out the specific activities 
necessary to fulfill the general information collection requirements. 
The estimated burden includes developing a water balance diagram that 
can be used to identify the proportion of intake water used for 
cooling, make-up, and process water. Facilities would also gather data 
to calculate the reduction in impingement mortality and entrainment of 
all life stages of fish and shellfish that would be achieved by the 
technologies and operational measures they select. The burden estimates 
include sampling,

[[Page 35036]]

assessing the source waterbody, estimating the magnitude of impingement 
mortality and entrainment, and reporting results in a comprehensive 
demonstration study. The burden may also include conducting a pilot 
study to evaluate the suitability of the technologies and operational 
measures based on the species that are found at the site.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    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. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9. In addition, EPA is 
amending the table in 40 CFR part 9 of currently approved OMB control 
numbers for various regulations to list the regulatory citations for 
the information requirements contained in this final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. This section summarizes EPA's analyses in 
compliance with the RFA.
1. Definition of Small Entity
    Small entities include small businesses, small organizations, and 
small governmental jurisdictions. For assessing the impacts of this 
rule on small entities, a small entity is defined as: (1) A small 
business as defined by the Small Business Administration's (SBA) 
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction 
that is a government of a city, county, town, school district or 
special district with a population of less than 50,000; and (3) a small 
organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field.
    The SBA small business size standards changed from a SIC code-based 
system to a NAICS code-based system on October 1, 2000. The SBA revised 
the size standards upwards effective January 5, 2006. Since EPA 
conducted its data collection effort for existing facilities before 
these changes, EPA performed the small entity analysis for existing 
facilities based on SIC codes. EPA then conducted a subsequent analysis 
to determine if the size standards based on the revised NAICS codes 
would have any effect on the results of the small entity analysis. To 
be conservative, for those SIC codes that are associated with more than 
one NAICS code, the highest threshold of the associated NAICS codes was 
used as the threshold for the SIC code (e.g., if an SIC was associated 
with two NAICS codes, one with a small business threshold of 500 
employees and one with a small business threshold of 750 employees, the 
SIC code was assigned a small business threshold of 750 employees, the 
higher of the associated NAICS). This process ensured that at least all 
small entities would be captured, but could potentially overstate the 
total number of small entities. This analysis showed there would be no 
changes to the small entity determination, and therefore to small 
entity impacts, as a result of switching from SIC-based size standards 
to NAICS-based size standards.
2. Certification Statement
    After considering the economic impacts of this rule on small 
entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. This 
regulation applies to new offshore oil and gas extraction facilities 
that withdraw 2 MGD or more from waters of the United States.
3. Statement of Basis
    From its analysis, EPA estimates that the final rule will apply 
national standards to only one small entity, a new offshore oil and gas 
platform. EPA estimates this entity will incur annualized, after-tax 
compliance costs of less than 0.1 percent of annual revenue. EPA does 
not know precisely which firms will undertake construction of new 
offshore oil and gas extraction facilities. However, based on the firms 
that are currently active in building the types of facilities 
representative of those covered by the rulemaking, EPA believes that 
the small firm analyzed represents the smallest firm that will be 
involved in such activities over the period of the analysis.
4. Summary of Small Business Advocacy Review Panel
    As described at Proposal, although not required by the RFA, EPA 
convened a Small Business Advocacy Review (SBAR) Panel to obtain advice 
and recommendations from small entity representatives (SERs) during 
development of the proposed regulation. A summary of EPA's small entity 
outreach and information on the composition, process, and findings of 
the SBAR panel can be found in the preamble of the Proposal. As noted 
above, only one small entity is estimated to be subject to national 
standards under this final regulation.
5. Small Entity Flexibility Analysis
    Despite the determination that this rule will not have a 
significant economic impact on a substantial number of small entities, 
EPA prepared at Proposal, and updated its analysis for the final 
regulation, a Small Entity Flexibility Analysis that has all the 
components of a Final Regulatory Flexibility Analysis (FRFA). A FRFA 
examines the impact of a rule on small entities along with regulatory 
alternatives that could reduce that impact. The Small Entity 
Flexibility Analysis (which is described in detail in the Economic 
Analysis document) is available for review in the docket.
    Under the final regulation, EPA estimates that only one small 
entity (a new offshore oil and gas facility) will be subject to the 
national categorical requirements. The one new offshore oil and gas 
facility potentially affected by the final rule is estimated to have a 
cost-to-revenue ratio of less than 0.1 percent.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub. 
L. 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed,

[[Page 35037]]

section 205 of the UMRA generally requires EPA to identify and consider 
a reasonable number of regulatory alternatives and adopt the least 
costly, most cost-effective, or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including Tribal governments, it must have developed under 
section 203 of the UMRA, a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with regulatory requirements.
    From its analysis for the final regulation, EPA estimates the total 
annualized after-tax costs of compliance to be $1.9 million ($2004). 
All of these direct facility costs are incurred by the private sector 
(124 oil and gas facilities). No facility owned by State or local 
governments is subject to the national requirements under the final 
rule. Additionally, permitting authorities will not incur costs to 
administer the rule for new offshore oil and gas extraction facilities 
because these facilities are not likely to be under State jurisdiction. 
As required by UMRA section 202, EPA estimates that the highest 
undiscounted after-tax cost incurred by the private sector in any one 
year is approximately $1.5 million in 2013.
    From this analysis, EPA determined that this rule does not contain 
a Federal mandate that would result in expenditures of $100 million or 
more for State, local, and Tribal governments, in the aggregate, or the 
private sector in any one year. (See Economic Analysis, Chapter D2: 
UMRA Analysis, for more detailed information.) At proposal, when 
including the potential costs of the national categorical rule options, 
EPA determined that the proposal may have resulted in expenditures of 
$100 million or more for State, local, or Tribal governments, in the 
aggregate, or the private sector in any one year (69 FR 68539). Since 
EPA has chosen to continue to rely upon the permitting authority's best 
professional judgment to establish section 316(b) limits for existing 
facilities not covered by the Phase II rule, those potential costs were 
not included in the estimate for the final rule. EPA has determined 
that this final rule does not contain a federal mandate of $100 million 
or more. EPA has determined that this rule contains no regulatory 
requirements that might significantly or uniquely affect small 
governments. Thus, this rule is not subject to the requirements of 
sections 202 and 205 of UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999) requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications.'' ``Policies that have 
federalism implications'' are defined in the Executive Order to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.''
    This final rule does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the Federal government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. Rather, this rule would result 
in minimal administrative costs to States that have an authorized NPDES 
program.
    States do not incur any burden hours and nonlabor costs to 
administer the rule for new offshore oil and gas extraction facilities 
since these facilities are outside of the jurisdiction of the States. 
EPA has identified zero Phase III existing facilities that are owned by 
federal, state or local government entities; therefore, the annual 
impacts on these facilities are zero.
    The national cooling water intake structure requirements would be 
implemented through permits issued under the NPDES program. Forty-five 
States and the Virgin Islands are currently authorized pursuant to 
section 402(b) of the CWA to implement the NPDES program. In States not 
authorized to implement the NPDES program, EPA issues NPDES permits. 
Under the CWA, States are not required to become authorized to 
administer the NPDES program. Rather, such authorization is available 
to States if they operate their programs in a manner consistent with 
section 402(b) and applicable regulations. Generally, these provisions 
require that State NPDES programs include requirements that are as 
stringent as Federal program requirements. States retain the ability to 
implement requirements that are broader in scope or more stringent than 
Federal requirements. (See section 510 of the CWA.)
    This rule would not have substantial direct effects on either 
authorized or nonauthorized States or on local governments because it 
would not change how EPA and the States and local governments interact 
or their respective authority or responsibilities for implementing the 
NPDES program. This rule would establish national requirements for new 
offshore oil and gas extraction facilities with cooling water intake 
structures. NPDES-authorized States that currently do not comply with 
the regulations based on this rule might need to amend their 
regulations or statutes to ensure that their NPDES programs are 
consistent with Federal section 316(b) requirements. For purposes of 
this rule, the relationship and distribution of power and 
responsibilities between the Federal government and the States and 
local governments are established under the CWA (e.g., sections 402(b) 
and 510); nothing in this rule would alter that. Thus, the requirements 
of section 6 of the Executive Order do not apply to this rule.
    Although section 6 of Executive Order 13132 does not apply to this 
rule, EPA did consult with State governments and representatives of 
local governments in developing the rule. During the development of the 
proposed and final Phase I and Phase II section 316(b) rules and the 
proposed Phase III rule, EPA conducted several outreach activities 
through which State and local officials were informed about this rule 
and they provided information and comments to the Agency. The outreach 
activities were intended to provide EPA with feedback on issues such as 
adverse environmental impact, best technology available, and the 
potential cost associated with various regulatory alternatives. These 
outreach activities are discussed in section III of the preamble to the 
proposed rule at 69 FR 68457, as well as in the Response to Comment 
Document.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 6, 2000), 
requires EPA

[[Page 35038]]

to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.''
    This rule would not have tribal implications. It would not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian Tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian Tribes, as specified in Executive Order 13175. At 
this time, there are no Tribes that own or operate facilities covered 
under this rule. Accordingly, the requirements of Executive Order 13175 
do not apply to this rule.
    Nevertheless, in the spirit of Executive Order 13175 and consistent 
with EPA policy to promote communications between EPA and Tribal 
governments, EPA solicited comment on the proposed rule from all 
stakeholders. EPA did not receive any comments from Tribal governments.

G. Executive Order 13045: Protection of Children From Environmental 
Health and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any 
rule that (1) is determined to be ``economically significant'' as 
defined under Executive Order 12866, and (2) concerns an environmental 
health or safety risk that EPA has reason to believe might have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health and 
safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency. This final 
rule is not an economically significant rule (using the $100 million 
threshold) as defined under Executive Order 12866. Further, it does not 
concern an environmental health or safety risk that would have a 
disproportionate effect on children.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This rule is not subject to Executive Order 13211, ``Actions 
Concerning Regulations That Significantly Affect Energy Supply, 
Distribution, or Use'' (66 FR 28355 (May 22, 2001)) because it is not a 
significant regulatory action under Executive Order 12866. Based on 
comments received at Proposal, EPA examined the potential for the 
regulation to cause a ``significant adverse effect'' on the Nation's 
energy economy through its potential impact on petroleum refining 
operations. EPA performed this analysis, which is documented in the 
Economic Analysis Report for the final regulation, in accordance with 
guidance for implementing Executive Order 13211 (``Actions Concerning 
Regulations That Significantly Affect Energy Supply, Distribution, or 
Use''). Based on this analysis, EPA continues to find, as stated at 
Proposal, that the 316(b) Phase III regulation will not cause a 
Significant Adverse Effect and does not constitute a Significant Energy 
Action within the meaning of Executive Order 13211. As a result, EPA 
did not prepare a Statement of Energy Effects.

I. National Technology Transfer and Advancement Act

    As noted in the proposed rule, section 12(d) of the National 
Technology Transfer and Advancement Act (NTTAA) of 1995, Public Law 
104-113, Sec. 12(d) directs EPA to use voluntary consensus standards in 
its regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, and business practices) that are developed or 
adopted by voluntary consensus standard bodies. The NTTAA directs EPA 
to provide Congress, through the Office of Management and Budget (OMB), 
explanations when the Agency decides not to use available and 
applicable voluntary consensus standards. This rule does not involve 
any technical standards. Therefore, EPA did not considering the use of 
any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 requires that, to the greatest extent 
practicable and permitted by law, each Federal agency must make 
achieving environmental justice part of its mission. Executive Order 
12898 provides that each Federal agency must conduct its programs, 
policies, and activities that substantially affect human health or the 
environment in a manner that ensures such programs, policies, and 
activities do not have the effect of excluding persons (including 
populations) from participation in, denying persons (including 
populations) the benefits of, or subjecting persons (including 
populations) to discrimination under such programs, policies, and 
activities because of their race, color, or national origin.
    The Executive Order's main provision directs federal agencies, to 
the greatest extent practicable and permitted by law, to make 
environmental justice part of their mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects of their programs, policies, and 
activities on minority populations and/or low-income populations.
    This rule would require that the location, design, construction, 
and capacity of cooling water intake structures at new offshore oil and 
gas extraction facilities reflect the best technology available for 
minimizing adverse environmental impact. Due to the offshore location 
of these facilities, EPA does not expect that this rule would have an 
exclusionary effect, deny persons the benefits of the participating in 
a program, or subject persons to discrimination because of their race, 
color, or national origin.
    In fact, because EPA expects that this rule would help to preserve 
the health of aquatic ecosystems located in reasonable proximity to new 
offshore oil and gas extraction facilities, it believes that all 
populations, including minority and low-income populations, would 
benefit from improved environmental conditions as a result of this 
rule. Thus EPA concludes that this action will not have the effect of 
excluding persons (including populations) from participating in, 
denying persons (including populations) the benefits of, or subjecting 
persons (including populations) to discrimination because of their 
race, color, or national origin.

K. Executive Order 13158: Marine Protected Areas

    Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to 
``expeditiously propose new science based regulations, as necessary, to 
ensure appropriate levels of protection for the marine environment.'' 
EPA may take action to enhance or expand protection of existing marine 
protected areas and to establish or recommend, as appropriate, new 
marine protected areas. The purpose of the Executive Order is to 
protect the significant natural and cultural resources within the 
marine environment, which means ``those areas of coastal and ocean 
waters, the Great Lakes and their connecting waters, and submerged 
lands thereunder, over which the United States exercises jurisdiction, 
consistent with international law.''
    This final rule recognizes the biological sensitivity of tidal 
rivers,

[[Page 35039]]

estuaries, and oceans and their susceptibility to adverse environmental 
impact from cooling water intake structures. This rule provides 
requirements for reducing both impingement and entrainment using 
technologies to minimize adverse environmental impact for cooling water 
intake structures located on these types of waterbodies.
    EPA expects that this rule would reduce impingement and entrainment 
at new offshore oil and gas extraction facilities. The rule would 
afford protection of aquatic organisms at individual, population, 
community, and/or ecosystem levels of ecological structures. Therefore, 
EPA expects this rule would advance the objective of the Executive 
Order to protect marine areas.

L. Congressional Review Act

    The Congressional Review Act, 5. U.S.C. 801 et seq., as added by 
the Small Business Regulatory Enforcement Fairness Act (SBREFA) of 
1996, generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. EPA will submit a report containing this 
rule and other required information to the U.S. Senate, the U.S. House 
of Representatives, and the Comptroller General of the United States 
prior to publication of the rule in the Federal Register. A major rule 
can not take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This will be effective July 17, 2006.

List of Subjects

40 CFR Part 9

    Environmental protection, Reporting and recordkeeping requirements.

40 CFR Part 122

    Environmental protection, Administrative practice and procedure, 
Confidential business information, Hazardous substances, Reporting and 
recordkeeping requirements, Water pollution control.

40 CFR Part 23

    Environmental protection, Administrative practice and procedure, 
Confidential business information, Hazardous substances, Indians-lands, 
Intergovernmental relations, Penalties, Reporting and recordkeeping 
requirements, Water pollution control.

40 CFR Part 124

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous waste, Indians-lands, Reporting and 
recordkeeping requirements, Water pollution control, Water supply.

40 CFR Part 125

    Environmental protection, Cooling water intake structure, Reporting 
and recordkeeping requirements, Waste treatment and disposal, Water 
pollution control.

    Dated: June 1, 2006.
Stephen L. Johnson,
Administrator.

0
For the reasons set forth in the preamble, chapter I of title 40 of the 
Code of Federal Regulations is amended as follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

0
1. The authority citation for part 9 continues to read as follows:

    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003, 
2005, 2006, 2601-2671, 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330, 
1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 
1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 
300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 
300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542, 
9601-9657, 11023, 11048.

0
2. In Sec.  9.1 the table is amended by revising the entry for 
``122.21(r)'' and by adding entries in numerical order under the 
indicated heading to read as follows:


Sec.  9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                   40 CFR citation                      OMB control No.
------------------------------------------------------------------------
 
                             * * * * * * *
   EPA Administered Permit Programs: The National Pollutant Discharge
                           Elimination System
 
                              * * * * * * *
122.21(r)............................................   2040-0241, 2040-
                                                         0257, 2040-0268
 
                             * * * * * * *
 Criteria and Standards for the National Pollutant Discharge Elimination
                                 System
 
                              * * * * * * *
125.134..............................................          2040-0268
125.135..............................................          2040-0268
125.136..............................................          2040-0268
125.137..............................................          2040-0268
125.138..............................................          2040-0268
125.139..............................................          2040-0268
 
                              * * * * * * *
------------------------------------------------------------------------

PART 122--EPA ADMINISTERED PERMIT PROGRAMS: THE NATIONAL POLLUTANT 
DISCHARGE ELIMINATION SYSTEM

0
3. The authority citation for part 122 continues to read as follows:

    Authority: The Clean Water Act, 33 U.S.C. 1251 et seq.


0
4. Section 122.21 is amended as follows:
0
a. Revising paragraph (r)(1)(i).
0
b. Removing ``and'' from the end of paragraph (r)(2)(ii).
0
c. Removing the period at the end of paragraph (r)(2)(iii) and adding 
``; and'' in its place.
0
d. Adding a new paragraph (r)(2)(iv).

[[Page 35040]]

0
e. Revising paragraph (r)(4) introductory text.


Sec.  122.21  Application for a permit (applicable to State programs, 
see Sec.  123.25)

* * * * *
    (r) Application requirements for facilities with cooling water 
intake structures--(1)(i) New facilities with new or modified cooling 
water intake structures. New facilities (other than offshore oil and 
gas extraction facilities) with cooling water intake structures as 
defined in part 125, subpart I, of this chapter must submit to the 
Director for review the information required under paragraphs (r)(2) 
(except (r)(2)(iv)), (3), and (4) of this section and Sec.  125.86 of 
this chapter as part of their application. New offshore oil and gas 
extraction facilities with cooling water intake structures as defined 
in part 125, subpart N, of this chapter that are fixed facilities must 
submit to the Director for review the information required under 
paragraphs (r)(2) (except (r)(2)(iv)), (3), and (4) of this section and 
Sec.  125.136 of this chapter as part of their application. New 
offshore oil and gas extraction facilities that are not fixed 
facilities must submit to the Director for review only the information 
required under paragraphs (r)(2)(iv), (r)(3) (except (r)(3)(ii)), and 
Sec.  125.136 of this chapter as part of their application. Requests 
for alternative requirements under Sec.  125.85 or Sec.  125.135 of 
this chapter must be submitted with your permit application.
* * * * *
    (2) * * *
    (iv) For new offshore oil and gas facilities that are not fixed 
facilities, a narrative description and/or locational maps providing 
information on predicted locations within the waterbody during the 
permit term in sufficient detail for the Director to determine the 
appropriateness of additional impingement requirements under Sec.  
125.134(b)(4).
* * * * *
    (4) Source water baseline biological characterization data. This 
information is required to characterize the biological community in the 
vicinity of the cooling water intake structure and to characterize the 
operation of the cooling water intake structures. The Director may also 
use this information in subsequent permit renewal proceedings to 
determine if your Design and Construction Technology Plan as required 
in Sec.  125.86(b)(4) or Sec.  125.136(b)(3) of this chapter should be 
revised. This supporting information must include existing data (if 
they are available). However, you may supplement the data using newly 
conducted field studies if you choose to do so. The information you 
submit must include:
* * * * *

0
5. Section 122.44 is amended by revising paragraph (b)(3) to read as 
follows:


Sec.  122.44  Establishing limitations, standards, and other permit 
conditions (applicable to State NPDES programs, see Sec.  123.25).

* * * * *
    (b) * * *
    (3) Requirements applicable to cooling water intake structures 
under section 316(b) of the CWA, in accordance with part 125, subparts 
I, J, and N of this chapter.
* * * * *

PART 123--STATE PROGRAM REQUIREMENTS

0
6. The authority citation for part 123 continues to read as follows:

    Authority: The Clean Water Act, 33 U.S.C. 1251 et seq.


0
7. Section 123.25 is amended by revising paragraph (a)(36) to read as 
follows:


Sec.  123.25  Requirements for permitting.

    (a) * * *
    (36) Subparts A, B, D, H, I, J, and N of part 125 of this chapter;
* * * * *

PART 124--PROCEDURES FOR DECISIONMAKING

0
8. The authority citation for part 124 continues to read as follows:

    Authority: Resource Conservation and Recovery Act, 42 U.S.C. 
6901 et seq.; Safe Drinking Water Act, 42 U.S.C. 300f et seq.; Clean 
Water Act, 33 U.S.C. 1251 et seq.; Clean Air Act, 42 U.S.C. 7401 et 
seq.

0
9. Section 124.10 is amended by revising paragraph (d)(1)(ix) to read 
as follows:


Sec.  124.10  Public notice of permit actions and public comment 
period.

* * * * *
    (d) * * *
    (1) * * *
    (ix) Requirements applicable to cooling water intake structures 
under section 316(b) of the CWA, in accordance with part 125, subparts 
I , J, and N of this chapter.
* * * * *

PART 125--CRITERIA AND STANDARDS FOR THE NATIONAL POLLUTANT 
DISCHARGE ELIMINATION SYSTEM

0
10. The authority citation for part 125 continues to read as follows:

    Authority: Clean Water Act, 33 U.S.C. 1251 et seq.; unless 
otherwise noted.


0
11. In Sec.  125.93 revise the definition of ``existing facility'' to 
read as follows:


Sec.  125.93  What special definitions apply to this subpart?

* * * * *
    Existing facility means any facility that commenced construction as 
described in 40 CFR 122.29(b)(4) on or before January 17, 2002 or July 
17, 2006 for an offshore oil and gas extraction facility); and any 
modification of, or any addition of a unit at such a facility that does 
not meet the definition of a new facility at Sec.  125.83.
* * * * *

0
12. Add subpart N to part 125 to read as follows:

Subpart N--Requirements Applicable to Cooling Water Intake 
Structures for New Offshore Oil and Gas Extraction Facilities Under 
Section 316(b) of the Act

Sec.
125.130 What are the purpose and scope of this subpart?
125.131 Who is subject to this subpart?
125.132 When must I comply with this subpart?
125.133 What special definitions apply to this subpart?
125.134 As an owner or operator of a new offshore oil and gas 
extraction facility, what must I do to comply with this subpart?
125.135 May alternative requirements be authorized?
125.136 As an owner or operator of a new offshore oil and gas 
extraction facility, what must I collect and submit when I apply for 
my new or reissued NPDES permit?
125.137 As an owner or operator of a new offshore oil and gas 
extraction facility, must I perform monitoring?
125.138 As an owner or operator of a new offshore oil and gas 
extraction facility, must I keep records and report?
125.139 As the Director, what must I do to comply with the 
requirements of this subpart?

Subpart N--Requirements Applicable to Cooling Water Intake 
Structures for New Offshore Oil and Gas Extraction Facilities Under 
Section 316(b) of the Act


Sec.  125.130  What are the purpose and scope of this subpart?

    (a) This subpart establishes requirements that apply to the 
location, design, construction, and capacity of cooling water intake 
structures at new offshore oil and gas extraction facilities. The 
purpose of these requirements is to establish the best technology 
available for minimizing adverse environmental

[[Page 35041]]

impact associated with the use of cooling water intake structures at 
these facilities. These requirements are implemented through National 
Pollutant Discharge Elimination System (NPDES) permits issued under 
section 402 of the Clean Water Act (CWA).
    (b) This subpart implements section 316(b) of the CWA for new 
offshore oil and gas extraction facilities. Section 316(b) of the CWA 
provides that any standard established pursuant to sections 301 or 306 
of the CWA and applicable to a point source shall require that the 
location, design, construction, and capacity of cooling water intake 
structures reflect the best technology available for minimizing adverse 
environmental impact.
    (c) New offshore oil and gas extraction facilities that do not meet 
the threshold requirements regarding amount of water withdrawn or 
percentage of water withdrawn for cooling water purposes in Sec.  
125.131(a) must meet requirements determined by the Director on a case-
by-case, best professional judgement (BPJ) basis.
    (d) Nothing in this subpart shall be construed to preclude or deny 
the right of any State or political subdivision of a State or any 
interstate agency under section 510 of the CWA to adopt or enforce any 
requirement with respect to control or abatement of pollution that is 
more stringent than those required by Federal law.


Sec.  125.131  Who is subject to this subpart?

    (a) This subpart applies to a new offshore oil and gas extraction 
facility if it meets all of the following criteria:
    (1) It is a point source that uses or proposes to use a cooling 
water intake structure;
    (2) It has at least one cooling water intake structure that uses at 
least 25 percent of the water it withdraws for cooling purposes as 
specified in paragraph (c) of this section; and
    (3) It has a design intake flow greater than two (2) million 
gallons per day (MGD).
    (b) Use of a cooling water intake structure includes obtaining 
cooling water by any sort of contract or arrangement with an 
independent supplier (or multiple suppliers) of cooling water if the 
supplier or suppliers withdraw(s) water from waters of the United 
States. Use of cooling water does not include obtaining cooling water 
from a public water system or the use of treated effluent that 
otherwise would be discharged to a water of the U.S.
    (c) The threshold requirement that at least 25 percent of water 
withdrawn be used for cooling purposes must be measured on an average 
monthly basis. A new offshore oil and gas extraction facility meets the 
25 percent cooling water threshold if, based on the new facility's 
design, any monthly average over a year for the percentage of cooling 
water withdrawn is expected to equal or exceed 25 percent of the total 
water withdrawn.
    (d) Neither this subpart nor Subpart I of this part applies to 
seafood processing vessels or offshore liquefied natural gas import 
terminals that are new facilities as defined in 40 CFR 125.83. Seafood 
processing vessels and offshore liquefied natural gas import terminals 
must meet requirements established by the Director on a case-by-case, 
best professional judgment (BPJ) basis.


Sec.  125.132  When must I comply with this subpart?

    You must comply with this subpart when an NPDES permit containing 
requirements consistent with this subpart is issued to you.


Sec.  125.133  What special definitions apply to this subpart?

    In addition to the definitions set forth at 40 CFR 125.83, the 
following special definitions apply to this subpart:
    Cooling water means water used for contact or noncontact cooling, 
including water used for equipment cooling, evaporative cooling tower 
makeup, and dilution of effluent heat content. The intended use of the 
cooling water is to absorb waste heat rejected from the process or 
processes used, or from auxiliary operations on the facility's 
premises. Cooling water that is used in another industrial process 
either before or after it is used for cooling is considered process 
water rather than cooling water for the purposes of calculating the 
percentage of a new offshore oil and gas extraction facility's intake 
flow that is used for cooling purposes in Sec.  125.131(c).
    Fixed facility means a bottom founded offshore oil and gas 
extraction facility permanently attached to the seabed or subsoil of 
the outer continental shelf (e.g., platforms, guyed towers, articulated 
gravity platforms) or a buoyant facility securely and substantially 
moored so that it cannot be moved without a special effort (e.g., 
tension leg platforms, permanently moored semi-submersibles) and which 
is not intended to be moved during the production life of the well. 
This definition does not include mobile offshore drilling units (MODUs) 
(e.g., drill ships, temporarily moored semi-submersibles, jack-ups, 
submersibles, tender-assisted rigs, and drill barges).
    Minimum ambient source water surface elevation means the mean low 
tidal water level for estuaries or oceans. The mean low tidal water 
level is the average height of the low water over at least 19 years.
    New offshore oil and gas extraction facility means any building, 
structure, facility, or installation that: meets the definition of a 
``new facility'' at 40 CFR 125.83; and is regulated by the Offshore or 
Coastal Subcategories of the Oil and Gas Extraction Point Source 
Category Effluent Guidelines in 40 CFR 435.10 or 40 CFR 435.40; but 
only if it commences construction after July 17, 2006.
    Offshore liquefied natural gas (LNG) import terminal means any 
facility located in waters defined in 40 CFR 435.10 or 40 CFR 435.40 
that liquefies, re-gasifies, transfers, or stores liquefied natural 
gas.
    Sea chest means the underwater compartment or cavity within the 
facility or vessel hull or pontoon through which sea water is drawn in 
(for cooling and other purposes) or discharged.
    Seafood processing vessel means any offshore or nearshore, 
floating, mobile, facility engaged in the processing of fresh, frozen, 
canned, smoked, salted or pickled seafood, seafood paste, mince, or 
meal.


Sec.  125.134  As an owner or operator of a new offshore oil and gas 
extraction facility, what must I do to comply with this subpart?

    (a)(1) The owner or operator of a new offshore oil and gas 
extraction facility must comply with:
    (i) Track I in paragraph (b) or Track II in paragraph (c) of this 
section, if it is a fixed facility; or
    (ii) Track I in paragraph (b) of this section, if it is not a fixed 
facility.
    (2) In addition to meeting the requirements in paragraph (b) or (c) 
of this section, the owner or operator of a new offshore oil and gas 
extraction facility may be required to comply with paragraph (d) of 
this section.
    (b) Track I requirements for new offshore oil and gas extraction 
facilities. (1)(i) New offshore oil and gas extraction facilities that 
do not employ sea chests as cooling water intake structures and are 
fixed facilities must comply with all of the requirements in paragraphs 
(b)(2) through (8) of this section.
    (ii) New offshore oil and gas extraction facilities that employ sea 
chests as cooling water intake structures and are fixed facilities must 
comply with the requirements in paragraphs (b)(2), (3), (4), (6), (7), 
and (8) of this section.
    (iii) New offshore oil and gas extraction facilities that are not 
fixed

[[Page 35042]]

facilities must comply with the requirements in paragraphs (b)(2), (4), 
(6), (7), and (8) of this section.
    (2) You must design and construct each cooling water intake 
structure at your facility to a maximum through-screen design intake 
velocity of 0.5 ft/s;
    (3) For cooling water intake structures located in an estuary or 
tidal river, the total design intake flow over one tidal cycle of ebb 
and flow must be no greater than one (1) percent of the volume of the 
water column within the area centered about the opening of the intake 
with a diameter defined by the distance of one tidal excursion at the 
mean low water level;
    (4) You must select and implement design and construction 
technologies or operational measures for minimizing impingement 
mortality of fish and shellfish if the Director determines that:
    (i) There are threatened or endangered or otherwise protected 
federal, state, or tribal species, or critical habitat for these 
species, within the hydraulic zone of influence of the cooling water 
intake structure; or
    (ii) Based on information submitted by any fishery management 
agency(ies) or other relevant information, there are migratory and/or 
sport or commercial species of impingement concern to the Director that 
pass through the hydraulic zone of influence of the cooling water 
intake structure; or
    (iii) Based on information submitted by any fishery management 
agency(ies) or other relevant information, that the proposed facility, 
after meeting the technology-based performance requirements in 
paragraphs (b)(2) and (5) of this section, would still contribute 
unacceptable stress to the protected species, critical habitat of those 
species, or species of concern;
    (5) You must select and implement design and construction 
technologies or operational measures for minimizing entrainment of 
entrainable life stages of fish and shellfish;
    (6) You must submit the applicable application information required 
in 40 CFR 122.21(r) and Sec.  125.136(b). If you are a fixed facility 
you must submit the information required in 40 CFR 122.21(r)(2) (except 
(r)(2)(iv)), (3), and (4) and Sec.  125.136(b) of this subpart as part 
of your application. If you are a not a fixed facility, you must only 
submit the information required in 40 CFR 122.21(r)(2)(iv), (r)(3) 
(except (r)(3)(ii)) and Sec.  125.136(b) as part of your application.
    (7) You must implement the monitoring requirements specified in 
Sec.  125.137; and
    (8) You must implement the recordkeeping requirements specified in 
Sec.  125.138.
    (c) Track II requirements for new offshore oil and gas extraction 
facilities. The owner or operator of a new offshore oil and gas 
extraction facility that is a fixed facility and chooses to comply 
under Track II must comply with the following requirements:
    (1) You must demonstrate to the Director that the technologies 
employed will reduce the level of adverse environmental impact from 
your cooling water intake structures to a comparable level to that 
which you would achieve were you to implement the applicable 
requirements of paragraph (b)(2) and, if your facility is a fixed 
facility without a sea chest, also paragraph (b)(5) of this section. 
This demonstration must include a showing that the impacts to fish and 
shellfish, including important forage and predator species, will be 
comparable to those which would result if you were to implement the 
requirements of paragraph (b)(2) and, if your facility is a fixed 
facility without a sea chest, also paragraph (b)(5) of this section. In 
identifying such species, the Director may consider information 
provided by any fishery management agency(ies) along with data and 
information from other sources;
    (2) For cooling water intake structures located in an estuary or 
tidal river, the total design intake flow over one tidal cycle of ebb 
and flow must be no greater than one (1) percent of the volume of the 
water column within the area centered about the opening of the intake 
with a diameter defined by the distance of one tidal excursion at the 
mean low water level;
    (3) You must submit the applicable information required in 40 CFR 
122.21(r)(2) (except (r)(2)(iv)), (3) and (4) and Sec.  125.136(c);
    (4) You must implement the monitoring requirements specified in 
Sec.  125.137;
    (5) You must implement the record-keeping requirements specified in 
Sec.  125.138.
    (d) You must comply with any more stringent requirements relating 
to the location, design, construction, and capacity of a cooling water 
intake structure or monitoring requirements at a new offshore oil and 
gas extraction facility that the Director deems are reasonably 
necessary to comply with any provision of federal or state law, 
including compliance with applicable state water quality standards 
(including designated uses, criteria, and antidegradation 
requirements).


Sec.  125.135  May alternative requirements be authorized?

    (a) Any interested person may request that alternative requirements 
less stringent than those specified in Sec.  125.134(a) through (d) be 
imposed in the permit. The Director may establish alternative 
requirements less stringent than the requirements of Sec.  125.134(a) 
through (d) only if:
    (1) There is an applicable requirement under Sec.  125.134(a) 
through (d);
    (2) The Director determines that data specific to the facility 
indicate that compliance with the requirement at issue would result in 
compliance costs wholly out of proportion to the costs EPA considered 
in establishing the requirement at issue or would result in significant 
adverse impacts on local water resources other than impingement or 
entrainment, or significant adverse impacts on energy markets;
    (3) The alternative requirement requested is no less stringent than 
justified by the wholly out of proportion cost or the significant 
adverse impacts on local water resources other than impingement or 
entrainment, or significant adverse impacts on energy markets; and
    (4) The alternative requirement will ensure compliance with other 
applicable provisions of the Clean Water Act and any applicable 
requirement of federal or state law.
    (b) The burden is on the person requesting the alternative 
requirement to demonstrate that alternative requirements should be 
authorized.


Sec.  125.136  As an owner or operator of a new offshore oil and gas 
extraction facility, what must I collect and submit when I apply for my 
new or reissued NPDES permit?

    (a)(1) As an owner or operator of a new offshore oil and gas 
extraction facility, you must submit to the Director a statement that 
you intend to comply with either:
    (i) The Track I requirements for new offshore oil and gas 
extraction facilities in Sec.  125.134(b); or
    (ii) If you are a fixed facility, you may choose to comply with the 
Track II requirements in Sec.  125.134(c).
    (2) You must also submit the application information required by 40 
CFR 122.21(r) and the information required in either paragraph (b) of 
this section for Track I or, if you are a fixed facility that chooses 
to comply under Track II, paragraph (c) of this section when you apply 
for a new or reissued NPDES permit in accordance with 40 CFR 122.21.
    (b) Track I application requirements. To demonstrate compliance 
with Track I requirements in Sec.  125.134(b), you must

[[Page 35043]]

collect and submit to the Director the information in paragraphs (b)(1) 
through (3) of this section.
    (1) Velocity information. You must submit the following information 
to the Director to demonstrate that you are complying with the 
requirement to meet a maximum through-screen design intake velocity of 
no more than 0.5 ft/s at each cooling water intake structure as 
required in Sec.  125.134(b)(2):
    (i) A narrative description of the design, structure, equipment, 
and operation used to meet the velocity requirement; and
    (ii) Design calculations showing that the velocity requirement will 
be met at minimum ambient source water surface elevations (based on 
best professional judgment using available hydrological data) and 
maximum head loss across the screens or other device.
    (2) Source waterbody flow information. If you are a fixed facility 
and your cooling water intake structure is located in an estuary or 
tidal river, you must provide the mean low water tidal excursion 
distance and any supporting documentation and engineering calculations 
to show that your cooling water intake structure facility meets the 
flow requirements in Sec.  125.134(b)(3).
    (3) Design and Construction Technology Plan. To comply with Sec.  
125.134(b)(4) and/or (5), if applicable, you must submit to the 
Director the following information in a Design and Construction 
Technology Plan:
    (i) If the Director determines that additional impingement 
requirements should be included in your permit:
    (A) Information to demonstrate whether or not you meet the criteria 
in Sec.  125.134(b)(4);
    (B) Delineation of the hydraulic zone of influence for your cooling 
water intake structure;
    (ii) New offshore oil and gas extraction facilities required to 
install design and construction technologies and/or operational 
measures must develop a plan explaining the technologies and measures 
you have selected. (Examples of appropriate technologies include, but 
are not limited to, increased opening to cooling water intake structure 
to decrease design intake velocity, wedgewire screens, fixed screens, 
velocity caps, location of cooling water intake opening in waterbody, 
etc. Examples of appropriate operational measures include, but are not 
limited to, seasonal shutdowns or reductions in flow, continuous 
operations of screens, etc.) The plan must contain the following 
information, if applicable:
    (A) A narrative description of the design and operation of the 
design and construction technologies, including fish-handling and 
return systems, that you will use to maximize the survival of those 
species expected to be most susceptible to impingement. Provide 
species-specific information that demonstrates the efficacy of the 
technology;
    (B) To demonstrate compliance with Sec.  125.134(b)(5), if 
applicable, a narrative description of the design and operation of the 
design and construction technologies that you will use to minimize 
entrainment of those species expected to be the most susceptible to 
entrainment. Provide species-specific information that demonstrates the 
efficacy of the technology; and
    (C) Design calculations, drawings, and estimates to support the 
descriptions provided in paragraphs (b)(3)(ii)(A) and (B) of this 
section.
    (c) Application requirements for Track II. If you are a fixed 
facility and have chosen to comply with the requirements of Track II in 
Sec.  125.134(c) you must collect and submit the following information:
    (1) Source waterbody flow information. If your cooling water intake 
structure is located in an estuary or tidal river, you must provide the 
mean low water tidal excursion distance and any supporting 
documentation and engineering calculations to show that your cooling 
water intake structure facility meets the flow requirements in Sec.  
125.134(c)(2);
    (2) Track II Comprehensive Demonstration Study. You must perform 
and submit the results of a Comprehensive Demonstration Study (Study). 
This information is required to characterize the source water baseline 
in the vicinity of the cooling water intake structure(s), characterize 
operation of the cooling water intake(s), and to confirm that the 
technology(ies) proposed and/or implemented at your cooling water 
intake structure reduce the impacts to fish and shellfish to levels 
comparable to those you would achieve were you to implement the 
applicable requirements in Sec.  125.134(b).
    (i) To meet the ``comparable level'' requirement, you must 
demonstrate that:
    (A) You have reduced impingement mortality of all life stages of 
fish and shellfish to 90 percent or greater of the reduction that would 
be achieved through the applicable requirements in Sec.  125.134(b)(2); 
and
    (B) If you are a facility without sea chests, you have minimized 
entrainment of entrainable life stages of fish and shellfish to 90 
percent or greater of the reduction that would have been achieved 
through the applicable requirements in Sec.  125.134(b)(5);
    (ii) You must develop and submit a plan to the Director containing 
a proposal for how information will be collected to support the study. 
The plan must include:
    (A) A description of the proposed and/or implemented 
technology(ies) to be evaluated in the Study;
    (B) A list and description of any historical studies characterizing 
the physical and biological conditions in the vicinity of the proposed 
or actual intakes and their relevancy to the proposed Study. If you 
propose to rely on existing source water body data, it must be no more 
than 5 years old, you must demonstrate that the existing data are 
sufficient to develop a scientifically valid estimate of potential 
impingement mortality and (if applicable) entrainment impacts, and 
provide documentation showing that the data were collected using 
appropriate quality assurance/quality control procedures;
    (C) Any public participation or consultation with Federal or State 
agencies undertaken in developing the plan; and
    (D) A sampling plan for data that will be collected using actual 
field studies in the source water body. The sampling plan must document 
all methods and quality assurance procedures for sampling and data 
analysis. The sampling and data analysis methods you propose must be 
appropriate for a quantitative survey and based on consideration of 
methods used in other studies performed in the source water body. The 
sampling plan must include a description of the study area (including 
the area of influence of the cooling water intake structure and at 
least 100 meters beyond); taxonomic identification of the sampled or 
evaluated biological assemblages (including all life stages of fish and 
shellfish); and sampling and data analysis methods; and
    (iii) You must submit documentation of the results of the Study to 
the Director. Documentation of the results of the Study must include:
    (A) Source Water Biological Study. The Source Water Biological 
Study must include:
    (1) A taxonomic identification and characterization of aquatic 
biological resources including: A summary of historical and 
contemporary aquatic biological resources; determination and 
description of the target populations of concern (those species of fish 
and shellfish and all life stages that are most susceptible to 
impingement and entrainment); and a description of the

[[Page 35044]]

abundance and temporal/spatial characterization of the target 
populations based on the collection of multiple years of data to 
capture the seasonal and daily activities (e.g., spawning, feeding and 
water column migration) of all life stages of fish and shellfish found 
in the vicinity of the cooling water intake structure;
    (2) An identification of all threatened or endangered species that 
might be susceptible to impingement and entrainment by the proposed 
cooling water intake structure(s); and
    (3) A description of additional chemical, water quality, and other 
anthropogenic stresses on the source waterbody.
    (B) Evaluation of potential cooling water intake structure effects. 
This evaluation must include:
    (1) Calculations of the reduction in impingement mortality and, (if 
applicable), entrainment of all life stages of fish and shellfish that 
would need to be achieved by the technologies you have selected to 
implement to meet requirements under Track II. To do this, you must 
determine the reduction in impingement mortality and entrainment that 
would be achieved by implementing the requirements of Sec.  
125.134(b)(2) and, for facilities without sea chests, Sec.  
125.134(b)(5) of Track I at your site.
    (2) An engineering estimate of efficacy for the proposed and/or 
implemented technologies used to minimize impingement mortality and (if 
applicable) entrainment of all life stages of fish and shellfish and 
maximize survival of impinged life stages of fish and shellfish. You 
must demonstrate that the technologies reduce impingement mortality and 
(if applicable) entrainment of all life stages of fish and shellfish to 
a comparable level to that which you would achieve were you to 
implement the requirements in Sec.  125.134(b)(2) and, for facilities 
without sea chests, Sec.  125.134(b)(5) of Track I. The efficacy 
projection must include a site-specific evaluation of technology(ies) 
suitability for reducing impingement mortality and (if applicable) 
entrainment based on the results of the Source Water Biological Study 
in paragraph (c)(2)(iii)(A) of this section. Efficacy estimates may be 
determined based on case studies that have been conducted in the 
vicinity of the cooling water intake structure and/or site-specific 
technology prototype studies.
    (C) Verification monitoring plan. You must include in the Study a 
plan to conduct, at a minimum, two years of monitoring to verify the 
full-scale performance of the proposed or implemented technologies and/
or operational measures. The verification study must begin at the start 
of operations of the cooling water intake structure and continue for a 
sufficient period of time to demonstrate that the facility is reducing 
the level of impingement mortality and (if applicable) entrainment to 
the level documented in paragraph (c)(2)(iii)(B) of this section. The 
plan must describe the frequency of monitoring and the parameters to be 
monitored. The Director will use the verification monitoring to confirm 
that you are meeting the level of impingement mortality and entrainment 
reduction required in Sec.  125.134(c), and that the operation of the 
technology has been optimized.


Sec.  125.137  As an owner or operator of a new offshore oil and gas 
extraction facility, must I perform monitoring?

    As an owner or operator of a new offshore oil and gas extraction 
facility, you will be required to perform monitoring to demonstrate 
your compliance with the requirements specified in Sec.  125.134 or 
alternative requirements under Sec.  125.135.
    (a) Biological monitoring. (1)(i) Fixed facilities without sea 
chests that choose to comply with the Track I requirements in Sec.  
125.134(b)(1)(i) must monitor for entrainment. These facilities are not 
required to monitor for impingement, unless the Director determines 
that the information would be necessary to evaluate the need for or 
compliance with additional requirements in accordance with Sec.  
125.134(b)(4) or more stringent requirements in accordance with Sec.  
125.134(d).
    (ii) Fixed facilities with sea chests that choose to comply with 
Track I requirements are not required to perform biological monitoring 
unless the Director determines that the information would be necessary 
to evaluate the need for or compliance with additional requirements in 
accordance with Sec.  125.134(b)(4) or more stringent requirements in 
accordance with Sec.  125.134(d).
    (iii) Facilities that are not fixed facilities are not required to 
perform biological monitoring unless the Director determines that the 
information would be necessary to evaluate the need for or compliance 
with additional requirements in accordance with Sec.  125.134(b)(4) or 
more stringent requirements in accordance with Sec.  125.134(d).
    (iv) Fixed facilities with sea chests that choose to comply with 
Track II requirements in accordance with Sec.  125.134(c), must monitor 
for impingement only. Fixed facilities without sea chests that choose 
to comply with Track II requirements, must monitor for both impingement 
and entrainment.
    (2) Monitoring must characterize the impingement rates and (if 
applicable) entrainment rates) of commercial, recreational, and forage 
base fish and shellfish species identified in the Source Water Baseline 
Biological Characterization data required by 40 CFR 122.21(r)(4), 
identified in the Comprehensive Demonstration Study required by Sec.  
125.136(c)(2), or as specified by the Director.
    (3) The monitoring methods used must be consistent with those used 
for the Source Water Baseline Biological Characterization data required 
in 40 CFR 122.21(r)(4), those used by the Comprehensive Demonstration 
Study required by Sec.  125.136(c)(2), or as specified by the Director. 
You must follow the monitoring frequencies identified below for at 
least two (2) years after the initial permit issuance. After that time, 
the Director may approve a request for less frequent sampling in the 
remaining years of the permit term and when the permit is reissued, if 
supporting data show that less frequent monitoring would still allow 
for the detection of any seasonal variations in the species and numbers 
of individuals that are impinged or entrained.
    (4) Impingement sampling. You must collect samples to monitor 
impingement rates (simple enumeration) for each species over a 24-hour 
period and no less than once per month when the cooling water intake 
structure is in operation.
    (5) Entrainment sampling. If your facility is subject to the 
requirements of Sec.  125.134(b)(1)(i), or if your facility is subject 
to Sec.  125.134(c) and is a fixed facility without a sea chest, you 
must collect samples to monitor entrainment rates (simple enumeration) 
for each species over a 24-hour period and no less than biweekly during 
the primary period of reproduction, larval recruitment, and peak 
abundance identified during the Source Water Baseline Biological 
Characterization required by 40 CFR 122.21(r)(4) or the Comprehensive 
Demonstration Study required in Sec.  125.136(c)(2). You must collect 
samples only when the cooling water intake structure is in operation.
    (b) Velocity monitoring. If your facility uses a surface intake 
screen systems, you must monitor head loss across the screens and 
correlate the measured value with the design intake velocity. The head 
loss across the intake screen must be measured at the

[[Page 35045]]

minimum ambient source water surface elevation (best professional 
judgment based on available hydrological data). The maximum head loss 
across the screen for each cooling water intake structure must be used 
to determine compliance with the velocity requirement in Sec.  
125.134(b)(2). If your facility uses devices other than surface intake 
screens, you must monitor velocity at the point of entry through the 
device. You must monitor head loss or velocity during initial facility 
startup, and thereafter, at the frequency specified in your NPDES 
permit, but no less than once per quarter.
    (c) Visual or remote inspections. You must either conduct visual 
inspections or employ remote monitoring devices during the period the 
cooling water intake structure is in operation. You must conduct visual 
inspections at least weekly to ensure that any design and construction 
technologies required in Sec.  125.134(b)(4), (b)(5), (c), and/or (d) 
are maintained and operated to ensure that they will continue to 
function as designed. Alternatively, you must inspect via remote 
monitoring devices to ensure that the impingement and entrainment 
technologies are functioning as designed.


Sec.  125.138  As an owner or operator of a new offshore oil and gas 
extraction facility, must I keep records and report?

    As an owner or operator of a new offshore oil and gas extraction 
facility you are required to keep records and report information and 
data to the Director as follows:
    (a) You must keep records of all the data used to complete the 
permit application and show compliance with the requirements, any 
supplemental information developed under Sec.  125.136, and any 
compliance monitoring data submitted under Sec.  125.137, for a period 
of at least three (3) years from the date of permit issuance. The 
Director may require that these records be kept for a longer period.
    (b) You must provide the following to the Director in a yearly 
status report:
    (1) For fixed facilities, biological monitoring records for each 
cooling water intake structure as required by Sec.  125.137(a);
    (2) Velocity and head loss monitoring records for each cooling 
water intake structure as required by Sec.  125.137(b); and
    (3) Records of visual or remote inspections as required in Sec.  
125.137(c).


Sec.  125.139  As the Director, what must I do to comply with the 
requirements of this subpart?

    (a) Permit application. As the Director, you must review materials 
submitted by the applicant under 40 CFR 122.21(r), Sec.  125.135, and 
Sec.  125.136 at the time of the initial permit application and before 
each permit renewal or reissuance.
    (1) After receiving the initial permit application from the owner 
or operator of a new offshore oil and gas extraction facility, the 
Director must determine applicable standards in Sec.  125.134 or Sec.  
125.135 to apply to the new offshore oil and gas extraction facility. 
In addition, the Director must review materials to determine compliance 
with the applicable standards.
    (2) For each subsequent permit renewal, the Director must review 
the application materials and monitoring data to determine whether 
requirements, or additional requirements, for design and construction 
technologies or operational measures should be included in the permit.
    (3) For Track II facilities, the Director may review the 
information collection proposal plan required by Sec.  
125.136(c)(2)(ii). The facility may initiate sampling and data 
collection activities prior to receiving comment from the Director.
    (b) Permitting requirements. Section 316(b) requirements are 
implemented for a facility through an NPDES permit. As the Director, 
you must determine, based on the information submitted by the new 
offshore oil and gas extraction facility in its permit application, the 
appropriate requirements and conditions to include in the permit based 
on the track (Track I or Track II), or alternative requirements in 
accordance with Sec.  125.135, the new offshore oil and gas extraction 
facility has chosen to comply with. The following requirements must be 
included in each permit:
    (1) Cooling water intake structure requirements. At a minimum, the 
permit conditions must include the performance standards that implement 
the applicable requirements of Sec.  125.134(b)(2), (3), (4) and (5); 
Sec.  125.134(c)(1) and (2); or Sec.  125.135.
    (i) For a facility that chooses Track I, you must review the Design 
and Construction Technology Plan required in Sec.  125.136(b)(3) to 
evaluate the suitability and feasibility of the technology proposed to 
minimize impingement mortality and (if applicable) entrainment of all 
life stages of fish and shellfish. In the first permit issued, you must 
include a condition requiring the facility to reduce impingement 
mortality and/or entrainment commensurate with the implementation of 
the technologies in the permit. Under subsequent permits, the Director 
must review the performance of the technologies implemented and require 
additional or different design and construction technologies, if needed 
to minimize impingement mortality and/or entrainment of all life stages 
of fish and shellfish. In addition, you must consider whether more 
stringent conditions are reasonably necessary in accordance with Sec.  
125.134(d).
    (ii) For a fixed facility that chooses Track II, you must review 
the information submitted with the Comprehensive Demonstration Study 
information required in Sec.  125.136(c)(2), evaluate the suitability 
of the proposed design and construction technology and/or operational 
measures to determine whether they will reduce both impingement 
mortality and/or entrainment of all life stages of fish and shellfish 
to 90 percent or greater of the reduction that could be achieved 
through Track I. In addition, you must review the Verification 
Monitoring Plan in Sec.  125.136(c)(2)(iii)(C) and require that the 
proposed monitoring begin at the start of operations of the cooling 
water intake structure and continue for a sufficient period of time to 
demonstrate that the technologies and operational measures meet the 
requirements in Sec.  125.134(c)(1). Under subsequent permits, the 
Director must review the performance of the additional and /or 
different technologies or measures used and determine that they reduce 
the level of adverse environmental impact from the cooling water intake 
structures to a comparable level that the facility would achieve were 
it to implement the requirements of Sec.  125.134(b)(2) and, if 
applicable, Sec.  125.134(b)(5).
    (iii) If a facility requests alternative requirements in accordance 
with Sec.  125.135, you must determine if data specific to the facility 
meet the requirements in Sec.  125.135(a) and include in the permit 
requirements that are no less stringent than justified by the wholly 
out of proportion cost or the significant adverse impacts on local 
water resources other than impingement or entrainment, or significant 
adverse impacts on energy markets.
    (2) Monitoring conditions. At a minimum, the permit must require 
the permittee to perform the monitoring required in Sec.  125.137. You 
may modify the monitoring program when the permit is reissued and 
during the term of the permit based on changes in physical or 
biological conditions in the vicinity of the cooling water intake 
structure. The Director may require continued monitoring based on the 
results of monitoring done pursuant to

[[Page 35046]]

the Verification Monitoring Plan in Sec.  125.136(c)(2)(iii)(C).
    (3) Record keeping and reporting. At a minimum, the permit must 
require the permittee to report and keep records as required by Sec.  
125.138.
[FR Doc. 06-5218 Filed 6-15-06; 8:45 am]
BILLING CODE 6560-50-P