[Federal Register: June 16, 2006 (Volume 71, Number 116)]

[Rules and Regulations]

[Page 35005-35046]

From the Federal Register Online via GPO Access [wais.access.gpo.gov]

[DOCID:fr16jn06-23]

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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

[[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

http://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 http://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:

rule.316b@epa.gov.

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

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

Examples of potentially

Standard industrial North American

Category interested entities

classification codes industry codes (NAIC)

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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.

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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, nonwater 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-bycase 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 sitespecific and the decision as to best technology available for intake

design, location, construction, and capacity must be made on a case-bycase 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.

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\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.

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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.

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\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.

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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.

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\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.

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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.

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\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.

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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., nonoffshore 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

m

3) 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.

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\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.

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----

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 nonmonetized 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 costbenefit 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 nonquantified 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 sitespecific.

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 nonfixed (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).

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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 noncash 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 postcompliance. 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, semisubmersibles, 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 postcompliance 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 postcompliance, 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.

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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

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Annualized

private afterNumber of new tax

compliance Facility

Type of oil and gas facility facilities

costs (in impacts Firm impacts

millions,

$2004)

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

MODUs........................................... 103

$1.9 0 0

Platforms....................................... 21

1.3 0 0

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

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

Total....................................... 124

3.2 0 0

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

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

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

Number of

Annualized facilities Number of

social cost subject to facilities

(in

millions, national with impacts

$2004) \1\ \2\ requirements

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

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 .............. ..............

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\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. Nonmanufacturing 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 baselinepass 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 ``nonuse'' 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 caseby-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