National Pollutant Discharge Elimination System-Final Regulations To Establish Requirements for Cooling Water Intake Structures at Phase III Facilities, 35006-35046 [06-5218]
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Federal Register / Vol. 71, No. 116 / Friday, June 16, 2006 / Rules and Regulations
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
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
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-bycase, best professional judgment basis.
This final action constitutes Phase III of
EPA’s section 316(b) regulation
development. This rule does not alter
the regulatory requirements for facilities
subject to the Phase I or Phase II
regulations.
DATES: This regulation is effective July
17, 2006. For judicial review purposes,
this final rule is promulgated as of 1
p.m. Eastern Daylight Time (EDT) on
June 30, 2006 as provided in 40 CFR
23.2.
ADDRESSES: EPA has established a
docket for this action under Docket ID
No. EPA–OW–2004–0002. All
documents in the docket are listed on
the www.regulations.gov web site.
Although listed in the index, some
information is not publicly available,
e.g., confidential business information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
www.regulations.gov or in hard copy at
the Water Docket in the EPA Docket
Center, EPA/DC, EPA West, Room B102,
1301 Constitution Ave., NW,
Washington, DC. The Public Reading
Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holidays. The telephone number
for the Public Reading Room is (202)
566–1744, and the telephone number for
the Water Docket is (202) 566–2426.
FOR FURTHER INFORMATION CONTACT: For
additional technical information contact
Paul Shriner, OW/OST at (202) 566–
1076. For additional biological
information contact Ashley Allen, OW/
OST at (202) 566–1012. The address for
the above contacts is: Office of Science
and Technology, Engineering Analysis
Division (Mailcode 4303T),
Environmental Protection Agency, 1200
Pennsylvania Ave., NW., Washington,
DC 20460; fax number: (202) 566–1053;
e-mail address: 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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North American industry
codes (NAIC)
Operators of steam electric generating point source
dischargers that employ cooling water intake structures.
Operators of industrial point source dischargers that
employ cooling water intake structures.
Agricultural production ...................................................
Metal mining ..................................................................
Oil and gas extraction ...................................................
Mining and quarrying of nonmetallic minerals ..............
Food and kindred products ...........................................
4911 and 493 ....................
221111, 221112, 221113,
221119, 221121, 221122
See below ..........................
See below
0133 ...................................
1011 ...................................
1311, 1321 ........................
1474 ...................................
2046, 2061, 2062, 2063,
2075, 2085.
2141 ...................................
2211 ...................................
2415, 2421, 2436, 2493 ....
2611, 2621, 2631, 2676 ....
Chemical and allied products ........................................
Industry ................................
Standard industrial
classification codes
Paper and allied products .............................................
Federal, State and local
government.
Examples of potentially interested entities
Tobacco products ..........................................................
Textile mill products ......................................................
Lumber and wood products, except furniture ...............
Category
28 (except 2895, 2893,
2851, and 2879).
111991, 11193
21221
211111, 211112
212391
311221, 311311, 311312,
311313, 311222,
311225, 31214
312229, 31221
31321
321912, 321113, 321918,
321999, 321212, 321219
3221, 322121, 32213,
322121, 322122, 32213,
322291
325 (except 325182,
32591, 32551, 32532)
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EXHIBIT I–1.—INDUSTRIAL FACILITY TYPES POTENTIALLY INTERESTED IN THIS FINAL ACTION—Continued
Examples of potentially interested entities
Standard industrial
classification codes
North American industry
codes (NAIC)
Petroleum refining and related industries .....................
Rubber and miscellaneous plastics ..............................
2911, 2999 ........................
3011, 3069 ........................
Stone, clay, glass, and concrete products ....................
Primary metal industries ................................................
3241 ...................................
3312, 3313, 3315, 3316,
3317, 3334, 3339, 3353,
3363, 3365, 3366.
Fabricated metal products, except machinery and
transportation equipment.
3421, 3499 ........................
Industrial and commercial machinery and computer
equipment.
3523, 3531 ........................
Transportation equipment .............................................
3724, 3743, 3764 ..............
Measuring, analyzing, and controlling instruments,
photographic, medical, and optical goods, watches
and clocks.
Electric, gas, and sanitary services ..............................
3861 ...................................
32411, 324199
326211, 31332, 326192,
326299
32731
324199, 331111, 331112,
331492, 331222,
332618, 331221, 22121,
331312, 331419,
331315, 331521,
331524, 331525
332211, 337215, 332117,
332439, 33251, 332919,
339914, 332999
333111, 332323, 332212,
333922, 22651, 333923,
33312
336412, 333911, 33651,
336416
333315, 325992
Educational services .....................................................
Engineering, accounting, research, management and
related services.
8221 ...................................
8731 ...................................
Category
4911, 4931, 4939, 4961 ....
section.
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.
B. Supporting Documentation
Table of Contents
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
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
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 § 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
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FOR FURTHER INFORMATION CONTACT
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221111, 221112, 221113,
221119, 221121,
221122, 22121, 22133
61131
54171
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,
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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
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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 § 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
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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 § 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
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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-bycase, best professional judgment (BPJ)
basis. See 40 CFR 125.90(b).
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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)
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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 NPDESpermitted 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,
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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
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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
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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
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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 caseby-case basis. In Re Public Service Co.
of New Hampshire, 10 ERC 1257 (June
17, 1977); In Re Public Service Co. of
New Hampshire, 1 EAD 455 (Aug. 4,
1978); Seacoast Anti-Pollution League v.
Costle, 597 F.2d 306 (1st Cir. 1979).
In addition to helping EPA determine
the effects of candidate technologies on
the receiving water, considering the
relationship of costs and benefits also
helps EPA determine whether the
technologies are economically
practicable. EPA has long recognized,
with the support of legislative history,
that section 316(b) does not require
adverse environmental impact to be
minimized beyond that which can be
achieved at an economically practicable
cost. See 118 Cong. Rec. 33762 (1972)
reprinted in 1 Legislative History of the
Water Pollution Control Act
Amendments of 1972, at 264 (1973)
(Statement of Representative Don H.
Clausen). EPA therefore may consider
costs and benefits in deciding whether
any of the technology options for Phase
III existing facilities actually do
minimize adverse environmental
impact—or whether the choice of
technologies should be left to BPJ
decision-making. When the costs of
establishing a national categorical rule
substantially outweigh the benefits of
such a rule, a national categorical
section 316(b) rule may not be
economically practicable, and therefore
not the ‘‘best technology available for
minimizing adverse environmental
impact.’’
Nothing in section 316(b) requires
EPA to promulgate a regulation to
implement the requirements for cooling
water intake structures. Section 316(b)
of the CWA grants EPA broad authority
to establish performance standards for
cooling water intake structures based on
the ‘‘best technology available to
minimize adverse environmental
impact.’’ Although EPA has chosen
under section 316(b) to promulgate
national categorical performance
standards applicable to certain classes
of point sources using cooling water
intake structures, see 40 CFR part 125,
Subpart I (new facilities), Subpart J
(existing power generating facilities),
and Subpart N (new offshore oil and gas
facilities), the statute does not preclude
EPA from determining BTA on a sitespecific basis. Indeed, the U.S. Court of
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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-bycase 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
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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
§ 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)
§ 402.10 (Applicability), (2) § 402.11
(Specialized definitions), and (3)
§ 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,
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35011
which reiterates the statutory
requirement, remains in effect.
Since the Fourth Circuit remanded
EPA’s section 316(b) regulations in
1977, NPDES permit authorities have
made decisions implementing section
316(b) on a case-by-case, site-specific
basis. EPA published draft guidance
addressing section 316(b)
implementation in 1977. See Draft
Guidance for Evaluating the Adverse
Impact of Cooling Water Intake
Structures on the Aquatic Environment:
Section 316(b) P.L. 92–500 (U.S. EPA,
1977). This draft guidance described the
studies recommended for evaluating the
impact of cooling water intake
structures on the aquatic environment
and recommended a basis for
determining the best technology
available for minimizing adverse
environmental impact. The 1977 section
316(b) draft guidance states, ‘‘The
environmental-intake interactions in
question are highly site-specific and the
decision as to best technology available
for intake design, location, construction,
and capacity must be made on a caseby-case basis.’’ (Section 316(b) Draft
Guidance, U.S. EPA, 1977, p. 4). This
case-by-case approach was also
consistent with the approach described
in the 1976 Development Document
referenced in the remanded regulation.
The 1977 section 316(b) draft
guidance suggested a general process for
developing information needed to
support section 316(b) decisions and
presenting that information to the
permitting authority. The process
involved the development of a sitespecific 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
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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
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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)
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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,
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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,
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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.
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
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.
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
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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.
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.
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
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.
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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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.
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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 § 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
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
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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.
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 lowvelocity standard for mobile facilities.
Further, a Track II demonstration
generally requires consideration of sitespecific factors. Since mobile facilities
are designed to operate at multiple
locations over their use life, it is
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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generally not possible for them to
provide in advance the information that
would be necessary for a Track II
demonstration.
As described in § 125.135, facilities
have the opportunity to conduct a costcost test and provide data to show that
compliance with the requirements of
§ 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
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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
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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.
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This regulation fulfills that commitment
and establishes national requirements
for new offshore oil and gas extraction
facilities that meet the applicability
requirements in § 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 § 125.131 and that employ sea
chests as cooling water intake structures
and are fixed facilities would have to
comply with the requirements in
§ 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
§ 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
§ 125.134(b)(1)(i). The one additional
requirement for these facilities is
§ 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
§ 125.134(b)(1)(iii), which address
intake flow velocity, specific impact
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concerns (e.g., threatened or endangered
species, critical habitat, migratory or
sport or commercial species), required
information submission, monitoring,
and recordkeeping. Track II is not
available to non-fixed (mobile) facilities
because non-fixed facilities, which are
expected to operate at multiple
locations, would not be able to perform
a site-specific demonstration. For this
same reason, EPA has dropped some of
the other site-dependent requirements
for non-fixed facilities (e.g., provision of
source waterbody flow information).
EPA has limited information on
specific environmental impacts
associated with the use of cooling water
intake structures at new offshore oil and
gas extraction facilities but believes the
potential for such impacts is sufficient
to warrant including requirements for
new offshore oil and gas extraction
facilities in this rule (see section IV for
more detailed discussion). SEAMAP
data for the Gulf of Mexico identified
over 600 different fish taxa and indicate
that ichthyoplankton occurs throughout
the Gulf of Mexico, with densities
highest (e.g., average densities greater
than 450 organisms/100 m3) at sampling
stations in the shallower regions (less
than 50 meters deep) of the Gulf, and
lower in deeper waters. (70 FR 71,059–
71,060). Most offshore oil and gas
facilities, if they employ cooling water
intake structures, operate them in nearsurface (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
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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
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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.
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 closedcycle 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
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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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
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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. Nonuse 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 nonuse 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
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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
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are already regulated by the Phase II
rule. Most of the reductions in fish
impinged and entrained at existing
facilities, and therefore most of the
benefits, are also already obtained
through implementation of the Phase II
regulations. The other options EPA
considered—involving 200 MGD and
100 MGD facilities—involved even less
flow and fewer regulated facilities than
the 50 MGD option.
A comparison of the cost-benefit ratio
for Phase II to the cost-benefit ratio for
the primary Phase III option supports
EPA’s decision here. The ratio of costs
to monetized benefits for the Phase II
50MGD rule was approximately 5 to 1.
In contrast, the ratio of monetized costs
to monetized benefits for the proposed
Phase III 50 MGD rule ranges from 17 to
1 to 22 to 1. Moreover, due to the tenfold 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 nonuse 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
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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 decisionmaking for Phase III existing facilities
does not mean that EPA is merely
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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 caseby-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
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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
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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.
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35019
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
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decision to rely on the existing sitespecific regulatory framework for Phase
III facilities. EPA believes the sitespecific approach is particularly suited
to addressing these non-quantified
impacts because the nature and
magnitude of such impacts is itself
highly site-specific.
VIII. Implementation
Final section 316(b) requirements for
new offshore oil and gas extraction
facilities will be implemented through
the NPDES permit program. This final
rule establishes implementation
requirements for new offshore oil and
gas extraction facilities that are
generally similar to the Phase I
requirements. This regulation
establishes application requirements
under 40 CFR 122.21 and § 125.136,
monitoring requirements under
§ 125.137, and record keeping and
reporting requirements under § 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 (§ 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?
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General Information
This final rule modifies regulations at
§ 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
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with their application for permit
issuance.
1. Source Water Physical Data
(§ 122.21(r)(2))
Under the requirements at
§ 122.21(r)(2), new offshore oil and gas
extraction facilities are required to
provide the source water physical data
specified at § 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
(§ 122.21(r)(3))
New offshore oil and gas extraction
facilities are required to submit the
cooling water intake structure data
specified at § 122.21(r)(3) to characterize
the cooling water intake structure and
evaluate the potential for impingement
and entrainment of aquatic organisms.
Note that § 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.
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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 nonfixed (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
§ 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 § 122.21(r)(2) (except
(r)(2)(iv)), (3), and (4) and § 125.136 of
Subpart N if they are fixed facilities and
choose to comply with the Track I or II
requirements in § 125.134(b) or (c). A
fixed facility is defined as a bottom
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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 § 125.135, new
offshore oil and gas extraction facilities
have the opportunity to conduct a costcost test and provide data to assist the
permit writer in determining if
compliance with the Subpart N
requirements would result in
compliance costs wholly out of
proportion to those EPA considered in
establishing the requirement, or would
result in significant adverse impacts on
local water resources other than
impingement or entrainment, or
significant adverse impacts on energy
markets. In this case, alternative
requirements may be imposed in the
permit. See the Phase I final preamble
for a more detailed explanation of this
cost-cost test which is different than the
cost-cost test for Phase II facilities (66
FR 65256).
In this final rule, fixed facilities with
sea chests and all non-fixed (or
‘‘mobile’’) facilities are not required to
comply with standards for entrainment.
Fixed facilities with sea chests may
choose either Track I or Track II to
comply with impingement mortality
performance standards. Non-fixed
facilities must comply with the Track I
0.5 feet per second through-screen
design intake flow velocity performance
standard for impingement mortality. In
addition, the Director must consider
whether more stringent conditions are
reasonably necessary to comply with
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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 § 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 nonfixed 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 (§ 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
§ 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
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35021
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 § 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
§ 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 § 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
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in the preamble to the final Phase I rule
at section VII.B.1.d.
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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
§ 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
§ 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
§ 125.134(b)(2) and, for facilities
without sea chests, in § 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
§ 125.134(b)(2) and, for facilities
without sea chests, in § 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
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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
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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
§ 125.134(b)(2) and, for facilities
without sea chests, § 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 § 125.134(b)(2) and, for
facilities without sea chests,
§ 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.
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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 § 125.134(c), and that the
operation of the technology has been
optimized.
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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
§ 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
§ 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
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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 24hour 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 § 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
§ 125.134(b)(2). If the facility uses
devices other than surface intake
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35023
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
§ 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 § 125.136,
and any compliance monitoring data
submitted under § 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 § 125.137(a);
• Velocity and head loss monitoring
records for each cooling water intake
structure as required by § 125.137(b);
and
• Records of visual or remote
inspections as required in § 125.137(c).
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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 § 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.
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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 § 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 § 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
§ 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)
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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
§ 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
§ 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.
• Records of visual or remote
inspections as required in § 125.137(c).
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 § 125.136,
and any compliance monitoring data
submitted under § 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 § 125.137(b);
and
A. New Offshore Oil and Gas Extraction
Facilities
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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.
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
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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-
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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
EPA estimates that direct compliance
costs will be $3.4 million and $2.8
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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35025
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
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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-torevenue 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 20year 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 30year operating period for each new
facility. Consistent with generally
accepted methods of business value
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analysis, EPA would have preferred to
use the present value of after-tax cash
flow instead of net income as the basis
for this analysis. However, because it
could not reliably estimate all of the
elements of cash flow, EPA instead used
the present value of net income for its
closure test. In particular, EPA was
unable to estimate the ongoing capital
outlays (apart from those resulting from
regulatory compliance) that MODUs
would need to make as part of their
ordinary business operations. In
performing the analysis in this way,
EPA essentially used the facility’s
reported depreciation and
amortization—which, being non-cash
items, are normally excluded from cash
flow accounting—as an approximation
of ongoing capital outlays. How use of
reported depreciation and amortization,
instead of a reliable estimate of capital
outlays, affects the findings from this
analysis cannot be precisely known. For
some businesses—in particular those
with relatively strong financial
performance—depreciation and
amortization may be less than ongoing
capital outlays; for these businesses, the
analysis will tend to overstate business
value and understate the potential effect
of compliance outlays on financial
performance and business value. On the
other hand, for some businesses—in
particular those with relatively weak
financial performance—depreciation
and amortization may exceed ongoing
capital outlays; for these businesses, the
analysis will tend to understate business
value and overstate the potential effect
of compliance outlays on financial
performance and business value. The
second model used by EPA is an aftertax 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
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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 30year 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 aftertax 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 compliancerelated 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 midyear 2003 basis). EPA calculated
depreciation for the compliance capital
outlay using the modified accelerated
cost recovery system (MACRS) and
included it in the pre-tax compliance
cost stream. The compliance cost stream
was then reduced by the amount of
avoided tax liability, based on the
estimated marginal tax rate, to yield the
after-tax compliance cost stream (for
more information on these calculations,
see DCN 7–4016). The final result of
these calculations is the present value of
after-tax compliance costs.
The present value of after-tax
compliance costs was then subtracted
from the present value of baseline net
income for the vessel. If the present
value of net income remained positive
after accounting for compliance costs,
EPA assumed that the MODU would
operate post-compliance. If the present
value of net income became negative,
EPA assumed that the new MODU
would not be a financially viable project
and was counted as a potential
‘‘regulatory closure.’’
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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 upfront 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
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material effect on decisions to build
new MODUs.
iii. Firm-Level Cost-to-Revenue Analysis
EPA’s research showed that firms
likeliest to build MODUs with a design
intake flow of 2 MGD or more are those
that currently own such MODUs. EPA
identified nine firms that either already
own jackups, semi-submersibles, or drill
ships that would be subject to the
requirements for new facilities if newly
constructed, or that are currently in the
process of building such MODUs. Most
of these firms are among the largest
firms in the industry. EPA estimates that
these nine firms would own the 103
new MODUs subject to the final
national requirements for new facilities.
To determine the potential impact of the
final rule on the nine firms determined
likely to build new MODUs subject to
regulation, EPA used a cost-to-revenue
test, which compares the annualized
pre-tax and after-tax costs of compliance
(calculated for representative new
MODUs), with 2004 revenue reported by
these firms. Because nearly all of the
firms (other than foreign-owned) are
publicly owned, EPA relied on revenue
data compiled from corporate 10K
reports (see Chapter C2 of the EA). EPA
then assigned a number of MODUs
potentially subject to regulation to each
of the firms and used the average perMODU 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
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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 aftertax 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 platformlevel 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.
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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-torevenue 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
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incurred in pre-production years, O&M,
monitoring costs, and repermitting
costs) are input into the model in the
year in which they occur, until the
model shows the platform is
uneconomical to operate. To determine
the shut-in year, projected net revenue
is compared to operating costs in each
production year. Net revenue is based
on an assumed price of oil, current and
projected production of oil and gas, well
production decline rates, and severance
and royalty rates. Operating costs are
based on a calculated cost per barrel of
oil equivalent (BOE) produced. The
model simulates operations for the
lesser of 30 years or to the year when
operating costs exceed production
revenue, at which point the operator is
assumed to terminate production. The
model calculates the lifetime of the
project, total production, and the net
present value of the operation (net
income of the operation over the life of
the project in terms of today’s dollars).
A comparison of the baseline model
outputs to the post-compliance model
outputs yields any losses of production
and project duration and the net present
value of the operation. If the net present
value of the operation is positive in the
baseline but negative post-compliance,
the project is considered nonviable postcompliance. 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
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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 postcompliance 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. postcompliance shows any differences in
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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these variables following the imposition
of compliance costs.
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
Number of
new facilities
Type of oil and gas facility
Annualized private after-tax
compliance
costs
(in millions,
$2004)
Facility
impacts
Firm impacts
MODUs ............................................................................................................
Platforms ..........................................................................................................
103
21
$1.9
1.3
0
0
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
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regulation for new offshore oil and gas
extraction facilities.
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EXHIBIT IX–2.—SUMMARY OF ECONOMIC ANALYSIS FOR THE 316(b) PHASE III FINAL REGULATION APPLICABLE TO NEW
OFFSHORE OIL AND GAS EXTRACTION FACILITIES
Annualized
social cost
(in millions,
$2004) 1 2
Direct Compliance Cost for New Oil and Gas Facilities .............................................................
Total State and Federal Administrative Cost ..............................................................................
$3.4–$2.8
$0.4–$0.3
Total Social Cost ..................................................................................................................
Number of
facilities subject to national
requirements
Number of
facilities with
impacts
$3.8—$3.2
1 The
124
0
left side of the each range is the cost discounted at 3% and the right side is cost discounted at 7%.
may not sum to totals due to independent rounding.
2 Numbers
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 regulation, based
on applicability
criteria
Industry
Subject to
National requirements,
excluding
baseline closures
Baseline
closures
50 MGD All Waterbodies
Primary Man. Industries ...............................................................................................................
Other Industries ...........................................................................................................................
155
7
14
1
140
6
Total ......................................................................................................................................
Total DIF (MGD) ............................................................................................................
161
31,215
15
1,907
146
29,308
Primary Man. Industries ...............................................................................................................
Other Industries ...........................................................................................................................
31
2
1
1
30
1
Total ......................................................................................................................................
33
2
31
Total DIF (MGD) ............................................................................................................
18,973
682
18,292
24
3
3
1
21
2
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200 MGD All Waterbodies
100 MGD Coastal/Great Lakes
Primary Man. Industries ...............................................................................................................
Other Industries ...........................................................................................................................
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Federal Register / Vol. 71, No. 116 / Friday, June 16, 2006 / Rules and Regulations
EXHIBIT IX–3.—PHASE III EXISTING MANUFACTURERS FACILITY COUNTS, BY DIF OPTION—Continued
Facilities
potentially
subject to regulation, based
on applicability
criteria
Industry
Subject to
National requirements,
excluding
baseline closures
Baseline
closures
Total ......................................................................................................................................
27
4
23
Total DIF (MGD) ............................................................................................................
8,654
747
7,907
Note: Totals may not sum due to independent rounding.
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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 facilityspecific process information using a
detailed technical survey of Electric
Generators and Manufacturers (see 69
FR 68457). EPA first calculated facilityspecific 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
10 Benefits are tallied and discounted in the same
way, although the total time profile for recognition
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cost, with some choices above and some
choices below. EPA believes that the
best-performing technology approach,
unlike a least-cost approach, takes sitespecific considerations that cannot be
accurately predicted in advance into
account. EPA believes that the bestperforming 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).
of benefits is longer than the profile for recognition
of costs to account for a 1–6 year lag reflecting
population dynamics.
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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.
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Federal Register / Vol. 71, No. 116 / Friday, June 16, 2006 / Rules and Regulations
EXHIBIT IX–4.—ANNUALIZED SOCIAL COST 1
(In millions, $2004)
50 MGD all
waterbodies
200 MGD all
waterbodies
100 MGD
CWB
Direct Compliance Cost:
Primary Manufacturing Industries .........................................................................................
Other Industries ....................................................................................................................
$36.3–37.1
1.3–1.2
$18.8–$19.5
0.5–0.4
$13.7–$13.3
0.7–0.7
Total Direct Compliance Cost .......................................................................................
State and Federal Administrative Cost ........................................................................................
37.6–38.3
0.6–0.6
19.3–20.0
0.2–0.2
14.4–13.9
0.2–0.2
Total Social Cost ..................................................................................................................
38.2–39.0
19.5–20.2
14.6–14.1
1 The
left side of each range is the cost discounted at 3%, and the right side of each range presents the cost with a 7% discount rate. The effect of the discount rate varies across regulatory options in the table because the time profile of costs varies across facilities and technology
choices.
3. Economic Impacts for Manufacturers
The economic impact analyses assess
how facilities, and the firms that own
them, would potentially be affected
financially by the national categorical
options. The facility impact analysis
uses compliance cost estimates (see
section IX.A.2) to calculate how
incurring these costs would affect the
financial performance and condition of
the regulated facilities.
This section presents EPA’s estimated
economic impacts on manufacturers for
the national categorical regulatory
options considered by EPA. Impact
measures include (1) facility closures
and associated losses in employment,
(2) financial stress short of closure
(‘‘moderate impacts’’), and (3) firm-level
impacts. EPA eliminated from this
analysis those facilities showing
materially inadequate financial
performance in the absence of
additional regulation (‘‘baseline
closures’’).
For the remaining facilities, EPA
identified a facility as a regulatory
closure if it would have operated under
baseline conditions but would fall
below an acceptable financial
performance level under additional
regulatory requirements. EPA’s analysis
of regulatory closures is based on the
estimated change in facility after-tax
cash flow and business value as a result
of the national categorical regulatory
options considered. (See EA, Chapter B3
for details of the cash flow calculation
and assessment of the potential for
facility closure as a result of additional
regulatory requirements.)
EPA’s analysis of moderate financial
impact is based on change in facility
financial performance and condition as
indicated by Interest Coverage Ratio
(ICR) and Pre-Tax Return on Assets
(PTRA). (See EA Appendix B3–A6 for
details of the moderate impacts
analysis.) See the EA for a detailed
description of EPA’s baseline closure
analysis and firm level analyses.
As shown in Exhibit IX–5, EPA
estimated that none of the baseline-pass
facilities would incur a severe impact
(closure) or a moderate economic
impact (financial impact short of
closure) under the national categorical
regulatory options considered.
EXHIBIT IX–5.—SUMMARY OF COST AND REGULATORY IMPACTS FOR EXISTING MANUFACTURING FACILITIES BY
REGULATORY OPTION
50 MGD All
Facilities Operating in Baseline ...................................................................................................
Facilities with Regulatory Requirements .....................................................................................
Percentage of Facilities with Regulatory Requirements .............................................................
Facilities Assessed as Closures (Severe Impacts) .....................................................................
Percentage of Facilities with Regulatory Requirements Assessed as Closures ........................
Facilities Assessed as Moderate Impacts ...................................................................................
Percentage of Facilities with Regulatory Requirements with Moderate Impacts ........................
Annualized Compliance Costs (after tax, million $2004) ............................................................
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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
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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
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144
144
100.0%
0
0.0%
0
0.0%
$26.8
200 MGD All
144
30
20.8%
0
0.0%
0
0.0%
$11.8
100 MGD
CWB
144
24
16.7%
0
0.0%
0
0.0%
$12.1
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
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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.
To obtain a national estimate of losses
at all potentially regulated facilities,
EPA extrapolated impingement and
35033
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
equivalent
fish
Baseline ...................................................................................................................................................................
50 MGD All Option ..................................................................................................................................................
200 MGD All Option ................................................................................................................................................
100 MGD CWB Option ............................................................................................................................................
a I&E
9,640,000
4,770,000
3,290,000
4,510,000
data are rounded to three significant figures.
C. National Benefits
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265,000,000
98,200,000
74,500,000
71,100,000
Foregone
fishery yield
(lbs)
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 nonharvested fish that are prey for
harvested fish. The second category
includes benefits that are independent
of any current or anticipated use of the
resource; these are known as ‘‘non-use’’
or ‘‘passive use’’ values. Non-use values
include ‘‘nonmarketed’’ goods and
services, which reflect human values
associated with existence, bequest, and
altruistic motives.
EPA estimated the economic benefits
from the national categorical regulatory
options using a range of valuation
methods, depending on the benefit
category, data availability, and other
suitable factors. EPA calculated benefits
11 ‘‘Potentially regulated Phase III facilities’’ refers
to all existing facilities with design intake flows
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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 midyear). 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 metaanalysis of recreational fishing valuation
studies designed to measure the various
factors that determine willingness-topay 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.
greater than 2 MGD and not regulated under the
Phase II rule.
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EXHIBIT X–2.—SUMMARY OF MONETIZED SOCIAL USE BENEFITS UNDER THE NATIONAL CATEGORICAL REGULATORY
OPTIONS
[Thousands, $2004] a
Annualized
commercial
fishing benefits
Option
50 MGD All ..................................................................................................................................
200 MGD All ................................................................................................................................
100 MGD CWB ............................................................................................................................
Annualized
recreational
fishing benefits
Total
annualized
value of
monetizable
impingement
and entrainment reductions b
$255–$321
167–211
244–308
$1,543–$1,931
1,027–1,288
1,244–1,564
$1,798–$2,251
1,194–1,499
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
facilities
subject to option
Option
50 MGD All Waterbodies .....................................................
200 MGD All Waterbodies ...................................................
100 MGD Coastal/Great Lakes ...........................................
Number of
facilities installing technology
146
31
23
111
27
22
Total
annualized
use value
of I&E reductions a
$1.80–$2.25
1.19–1.5
1.49–1.87
Total
annualized
costs b
$38.27–$39.00
19.48–20.14
14.57–14.11
Cost/benefit
ratio
17/1–22/1
13/1–17/1
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.
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XII. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review
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.
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:
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• 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;
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• 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 §§ 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
§ 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
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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
(§ 122.21(r)(2)) (§ 122.21(r)(2)(iv) only
for non-fixed new offshore oil and gas
extraction facilities)
• Cooling Water Intake Structure Data
(§ 122.21(r)(3)) (§ 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:
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• Source Water Baseline Biological
Characterization Data (§ 122.21(r)(4))
(not required for non-fixed facilities)
• Velocity Information
(§ 125.136(b)(1))
• Source Waterbody Flow
Information (§ 125.136(b)(2)) (only
applicable to fixed facilities located in
estuaries or tidal waters)
• Design and Construction
Technology Plan (§ 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 (§ 125.136(c)(1)) (only
applicable to fixed facilities located in
estuaries or tidal waters)
• Comprehensive Demonstration
Study (§ 125.136(c)(2))
Æ Source Water Biological Study
(§ 125.136(c)(2)(iii)(A))
Æ Evaluation of Potential Cooling
Water Intake Structure Effects
(§ 125.136(c)(2)(iii)(B))
Æ Verification Monitoring Plan
(§ 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 § 125.136
and in accordance with § 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
§ 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,
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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-forprofit enterprise which is independently
owned and operated and is not
dominant in its field.
The SBA small business size
standards changed from a SIC codebased 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.
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.
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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.
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.
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
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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
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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 costto-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,
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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
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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
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35037
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. NPDESauthorized 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
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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.
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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
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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
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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,
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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.
recordkeeping requirements, Waste
treatment and disposal, Water pollution
control.
Dated: June 1, 2006.
Stephen L. Johnson,
Administrator.
For the reasons set forth in the
preamble, chapter I of title 40 of the
Code of Federal Regulations is amended
as follows:
I
PART 9—OMB APPROVALS UNDER
THE PAPERWORK REDUCTION ACT
1. The authority citation for part 9
continues to read as follows:
I
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.
2. In § 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:
I
§ 9.1 OMB approvals under the Paperwork
Reduction Act.
40 CFR Part 125
Environmental protection, Cooling
water intake structure, Reporting and
*
*
*
*
*
40 CFR citation
*
OMB control No.
*
*
*
*
*
EPA Administered Permit Programs: The National Pollutant Discharge Elimination System
*
*
*
*
*
*
122.21(r) ........................................................................................................................................................................................
*
*
*
*
*
*
Criteria and Standards for the National Pollutant Discharge Elimination System
*
*
2040–0241, 2040–
0257, 2040–0268
*
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*
*
*
*
*
*
..........................................................................................................................................................................................
..........................................................................................................................................................................................
..........................................................................................................................................................................................
..........................................................................................................................................................................................
..........................................................................................................................................................................................
..........................................................................................................................................................................................
*
2040–0268
2040–0268
2040–0268
2040–0268
2040–0268
2040–0268
*
125.134
125.135
125.136
125.137
125.138
125.139
*
*
*
PART 122—EPA ADMINISTERED
PERMIT PROGRAMS: THE NATIONAL
POLLUTANT DISCHARGE
ELIMINATION SYSTEM
3. The authority citation for part 122
continues to read as follows:
I
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*
*
Authority: The Clean Water Act, 33 U.S.C.
1251 et seq.
4. Section 122.21 is amended as
follows:
I a. Revising paragraph (r)(1)(i).
I
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*
b. Removing ‘‘and’’ from the end of
paragraph (r)(2)(ii).
I c. Removing the period at the end of
paragraph (r)(2)(iii) and adding ‘‘; and’’
in its place.
I d. Adding a new paragraph (r)(2)(iv).
I
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e. Revising paragraph (r)(4)
introductory text.
I
§ 122.21 Application for a permit
(applicable to State programs, see § 123.25)
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*
*
*
*
*
(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 § 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 § 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 § 125.136 of this chapter
as part of their application. Requests for
alternative requirements under § 125.85
or § 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 § 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 § 125.86(b)(4) or
§ 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
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do so. The information you submit must
include:
*
*
*
*
*
I 5. Section 122.44 is amended by
revising paragraph (b)(3) to read as
follows:
Authority: Clean Water Act, 33 U.S.C. 1251
et seq.; unless otherwise noted.
§ 122.44 Establishing limitations,
standards, and other permit conditions
(applicable to State NPDES programs, see
§ 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
6. The authority citation for part 123
continues to read as follows:
I
Authority: The Clean Water Act, 33 U.S.C.
1251 et seq.
7. Section 123.25 is amended by
revising paragraph (a)(36) to read as
follows:
I
§ 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
8. The authority citation for part 124
continues to read as follows:
I
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.
9. Section 124.10 is amended by
revising paragraph (d)(1)(ix) to read as
follows:
I
§ 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
10. The authority citation for part 125
continues to read as follows:
I
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11. In § 125.93 revise the definition of
‘‘existing facility’’ to read as follows:
I
§ 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 § 125.83.
*
*
*
*
*
I 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
§ 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
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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 § 125.131(a) must meet requirements
determined by the Director on a case-bycase, 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.
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§ 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
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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-bycase, best professional judgment (BPJ)
basis.
§ 125.132
subpart?
When must I comply with this
You must comply with this subpart
when an NPDES permit containing
requirements consistent with this
subpart is issued to you.
§ 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 § 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 semisubmersibles, jack-ups, submersibles,
tender-assisted rigs, and drill barges).
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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.
§ 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
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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 throughscreen 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 § 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 § 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 § 125.136(b) as part of your
application.
(7) You must implement the
monitoring requirements specified in
§ 125.137; and
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(8) You must implement the
recordkeeping requirements specified in
§ 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 § 125.136(c);
(4) You must implement the
monitoring requirements specified in
§ 125.137;
(5) You must implement the recordkeeping requirements specified in
§ 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).
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§ 125.135 May alternative requirements be
authorized?
(a) Any interested person may request
that alternative requirements less
stringent than those specified in
§ 125.134(a) through (d) be imposed in
the permit. The Director may establish
alternative requirements less stringent
than the requirements of § 125.134(a)
through (d) only if:
(1) There is an applicable requirement
under § 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.
§ 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 § 125.134(b); or
(ii) If you are a fixed facility, you may
choose to comply with the Track II
requirements in § 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 § 125.134(b), you must
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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 § 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
§ 125.134(b)(3).
(3) Design and Construction
Technology Plan. To comply with
§ 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
§ 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:
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(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
§ 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 § 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
§ 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 § 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
§ 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
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greater of the reduction that would have
been achieved through the applicable
requirements in § 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
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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
§ 125.134(b)(2) and, for facilities
without sea chests, § 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 § 125.134(b)(2) and, for
facilities without sea chests,
§ 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
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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 § 125.134(c), and that the
operation of the technology has been
optimized.
§ 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 § 125.134 or alternative
requirements under § 125.135.
(a) Biological monitoring. (1)(i) Fixed
facilities without sea chests that choose
to comply with the Track I requirements
in § 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 § 125.134(b)(4) or more
stringent requirements in accordance
with § 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 § 125.134(b)(4) or more
stringent requirements in accordance
with § 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
§ 125.134(b)(4) or more stringent
requirements in accordance with
§ 125.134(d).
(iv) Fixed facilities with sea chests
that choose to comply with Track II
requirements in accordance with
§ 125.134(c), must monitor for
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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 § 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 § 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
§ 125.134(b)(1)(i), or if your facility is
subject to § 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 § 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
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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 § 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
§ 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.
§ 125.138 As an owner or operator of a
new offshore oil and gas extraction facility,
must I keep records and report?
rwilkins on PROD1PC63 with RULES2
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 § 125.136,
and any compliance monitoring data
submitted under § 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
§ 125.137(a);
(2) Velocity and head loss monitoring
records for each cooling water intake
structure as required by § 125.137(b);
and
(3) Records of visual or remote
inspections as required in § 125.137(c).
§ 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
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submitted by the applicant under 40
CFR 122.21(r), § 125.135, and § 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 § 125.134 or
§ 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
§ 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 § 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
§ 125.134(b)(2), (3), (4) and (5);
§ 125.134(c)(1) and (2); or § 125.135.
(i) For a facility that chooses Track I,
you must review the Design and
Construction Technology Plan required
in § 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,
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35045
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 § 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 § 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 § 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
§ 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 § 125.134(b)(2) and, if
applicable, § 125.134(b)(5).
(iii) If a facility requests alternative
requirements in accordance with
§ 125.135, you must determine if data
specific to the facility meet the
requirements in § 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 § 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
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the Verification Monitoring Plan in
§ 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 § 125.138.
[FR Doc. 06–5218 Filed 6–15–06; 8:45 am]
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BILLING CODE 6560–50–P
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]]>Agencies
[Federal Register Volume 71, Number 116 (Friday, June 16, 2006)]
[Rules and Regulations]
[Pages 35006-35046]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-5218]
[[Page 35005]]
-----------------------------------------------------------------------
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 9, 122, 123, et al.
National Pollutant Discharge Elimination System; Establishing
Requirements for Cooling Water Intake Structures at Phase III
Facilities; Final Rule
Federal Register / Vol. 71, No. 116 / Friday, June 16, 2006 / Rules
and Regulations
[[Page 35006]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
SUMMARY: On November 1, 2004, EPA published a proposal that contained
several options for the control of cooling water intake structures at
existing Phase III facilities and at new offshore oil and gas
extraction facilities. This rule establishes categorical section 316(b)
requirements for intake structures at new offshore oil and gas
extraction facilities that have a design intake flow threshold of
greater than 2 million gallons per day and that withdraw at least 25
percent of the water exclusively for cooling purposes. For existing
Phase III facilities, EPA determined that uniform national standards
are not the most effective way at this time to address cooling water
intake structures at these facilities. Instead, EPA believes that it is
better to continue to rely upon the existing National Pollutant
Discharge Elimination System (NPDES) program, which implements section
316(b) for existing facilities not covered under the Phase II rule on a
case-by-case, best professional judgment basis. This final action
constitutes Phase III of EPA's section 316(b) regulation development.
This rule does not alter the regulatory requirements for facilities
subject to the Phase I or Phase II regulations.
DATES: This regulation is effective July 17, 2006. For judicial review
purposes, this final rule is promulgated as of 1 p.m. Eastern Daylight
Time (EDT) on June 30, 2006 as provided in 40 CFR 23.2.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-OW-2004-0002. All documents in the docket are listed on the
www.regulations.gov web site. Although listed in the index, some
information is not publicly available, e.g., confidential business
information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the Internet and will be publicly available only in hard
copy form. Publicly available docket materials are available either
electronically through www.regulations.gov or in hard copy at the Water
Docket in the EPA Docket Center, EPA/DC, EPA West, Room B102, 1301
Constitution Ave., NW, Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Water Docket is (202) 566-
2426.
FOR FURTHER INFORMATION CONTACT: For additional technical information
contact Paul Shriner, OW/OST at (202) 566-1076. For additional
biological information contact Ashley Allen, OW/OST at (202) 566-1012.
The address for the above contacts is: Office of Science and
Technology, Engineering Analysis Division (Mailcode 4303T),
Environmental Protection Agency, 1200 Pennsylvania Ave., NW.,
Washington, DC 20460; fax number: (202) 566-1053; e-mail address:
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
----------------------------------------------------------------------------------------------------------------
Examples of potentially Standard industrial North American
Category interested entities classification codes industry codes (NAIC)
----------------------------------------------------------------------------------------------------------------
Federal, State and local government Operators of steam electric 4911 and 493.......... 221111, 221112,
generating point source 221113, 221119,
dischargers that employ 221121, 221122
cooling water intake
structures.
Industry........................... Operators of industrial See below............. See below
point source dischargers
that employ cooling water
intake structures.
Agricultural production.... 0133.................. 111991, 11193
Metal mining............... 1011.................. 21221
Oil and gas extraction..... 1311, 1321............ 211111, 211112
Mining and quarrying of 1474.................. 212391
nonmetallic minerals.
Food and kindred products.. 2046, 2061, 2062, 311221, 311311,
2063, 2075, 2085. 311312, 311313,
311222, 311225, 31214
Tobacco products........... 2141.................. 312229, 31221
Textile mill products...... 2211.................. 31321
Lumber and wood products, 2415, 2421, 2436, 2493 321912, 321113,
except furniture. 321918, 321999,
321212, 321219
Paper and allied products.. 2611, 2621, 2631, 2676 3221, 322121, 32213,
322121, 322122,
32213, 322291
Chemical and allied 28 (except 2895, 2893, 325 (except 325182,
products. 2851, and 2879). 32591, 32551, 32532)
[[Page 35007]]
Petroleum refining and 2911, 2999............ 32411, 324199
related industries.
Rubber and miscellaneous 3011, 3069............ 326211, 31332, 326192,
plastics. 326299
Stone, clay, glass, and 3241.................. 32731
concrete products.
Primary metal industries... 3312, 3313, 3315, 324199, 331111,
3316, 3317, 3334, 331112, 331492,
3339, 3353, 3363, 331222, 332618,
3365, 3366. 331221, 22121,
331312, 331419,
331315, 331521,
331524, 331525
Fabricated metal products, 3421, 3499............ 332211, 337215,
except machinery and 332117, 332439,
transportation equipment. 33251, 332919,
339914, 332999
Industrial and commercial 3523, 3531............ 333111, 332323,
machinery and computer 332212, 333922,
equipment. 22651, 333923, 33312
Transportation equipment... 3724, 3743, 3764...... 336412, 333911, 33651,
336416
Measuring, analyzing, and 3861.................. 333315, 325992
controlling instruments,
photographic, medical, and
optical goods, watches and
clocks.
Electric, gas, and sanitary 4911, 4931, 4939, 4961 221111, 221112,
services. 221113, 221119,
221121, 221122,
22121, 22133
Educational services....... 8221.................. 61131
Engineering, accounting, 8731.................. 54171
research, management and
related services.
----------------------------------------------------------------------------------------------------------------
This exhibit is not intended to be exhaustive, but rather provides
a guide for readers regarding entities likely to be interested in this
action. This exhibit also lists the types of entities that EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the exhibit could also be regulated. To
determine whether your facility is regulated by this action, you should
carefully examine the applicability criteria in Sec. 125.131 of this
rule. If you have questions regarding the applicability of this action
to a particular entity, consult the persons listed for technical
information in the FOR FURTHER INFORMATION CONTACT section.
B. Supporting Documentation
The final regulation is supported by three major documents:
1. Economic and Benefits Analysis for the Final Section 316(b)
Phase III Existing Facilities Rule (EPA-821-R-06-001), hereafter
referred to as the Economic and Benefits Analysis or EA. This document
presents the methodology employed to assess economic impacts of the
options we considered for this action and the results of the analysis.
2. Regional Analysis for the Final Section 316(b) Phase III
Existing Facilities Rule (EPA-821-R-06-002), hereafter referred to as
the Regional Analysis Document. This document examines cooling water
intake structure impacts and the environmental benefits of the national
categorical regulatory options we considered for this action at the
regional level.
3. Technical Development Document for the Final Section 316(b)
Phase III Existing Facilities Rule (EPA-821-R-06-003), hereafter
referred to as the Technical Development Document. This document
presents the technical information that formed the basis for our
decisions in this action, including information on the costs and
performance of the impingement and entrainment reduction technologies
we considered.
Table of Contents
I. General Information
II. Scope and Applicability of the Final Rule
III. Legal Authority, Purpose, and Background of This Regulation
IV. Environmental Impacts Associated with Cooling Water Intake
Structures
V. Description of the Rule
VI. Basis for the Final Rule Decision
VII. Response to Major Comments on the Proposed Rule and Notice of
Data Availability (NODA)
VIII. Implementation
IX. Economic Impact Analysis
X. Benefits Analysis
XI. Comparison of Benefits and Costs
XII. Statutory and Executive Order Reviews
II. Scope and Applicability of the Final Rule
The national categorical requirements in this rule apply to new
offshore oil and gas extraction facilities, which were specifically
excluded from the Phase I new facility rule. (40 CFR part 125, Subpart
I). This rule defines the term ``new offshore oil and gas extraction
facility'' to encompass facilities in both the offshore and the coastal
subcategories of EPA's Oil and Gas Extraction Point Source Category for
which effluent limitations are established at 40 CFR part 435. Although
the term ``offshore'' denotes only one of these two subcategories for
purposes of the effluent guidelines, EPA is using the term ``offshore''
here to denote facilities in either subcategory because the
requirements in this rule are the same for both offshore and coastal
facilities and the term ``offshore'' is commonly understood to include
any facilities not located on land. In order to be covered by this
rule, these facilities would need to use cooling water intake
structures to withdraw water from waters of the U.S. and meet all other
applicability criteria, as described in this section.
New offshore oil and gas facilities that meet all of the following
criteria are subject to this rule:
The facility is a point source;
The facility uses or proposes to use cooling water intake
structures,
[[Page 35008]]
including a cooling water intake structure operated by one or more
independent suppliers (other than a public water system), with a total
design intake flow equal to or greater than 2 million gallons per day
(MGD) to withdraw cooling water from waters of the United States;
The facility is expected to use at least 25 percent of
water withdrawn exclusively for cooling purposes, based on the new
facility's design and measured as a monthly average, during at least
one month over the course of a year.
For the purposes of this rule, a new facility is a point source if
it has, or is required to have, an NPDES permit. If a new facility is a
point source that uses a cooling water intake structure, but does not
meet the applicable design intake flow/source waterbody threshold or
the 25 percent cooling water use threshold, it would continue to be
subject to permit conditions implementing CWA section 316(b) set by the
permit director on a case-by-case, best professional judgment basis.
Section II.A of the preamble discusses what constitutes a ``new''
offshore oil and gas extraction facility for purposes of the section
316(b) Phase III rule. Requirements for new offshore oil and gas
extraction facilities are specified in 40 CFR Subpart N.
Existing Phase III facilities, including manufacturing facilities,
electric power producers with a design intake flow (DIF) less than 50
MGD, and existing offshore oil and gas extraction facilities, are not
subject to the national categorical requirements of this final rule.
These facilities will continue to be regulated on a case-by-case basis
using a permit director's best professional judgment.
Finally, this rule does not establish national categorical
requirements for seafood processing vessels or offshore liquefied
natural gas import terminals. Those facilities would be subject to
permit conditions implementing CWA section 316(b) set by the permit
director on a case-by-case, best professional judgment basis where the
facility is a point source and uses a cooling water intake structure.
A. What Is a ``New'' Offshore Oil and Gas Extraction Facility for
Purposes of the Section 316(b) Phase III Rule?
For purposes of this rule, new offshore oil and gas extraction
facilities are those facilities that (1) are subject to the Offshore or
Coastal subcategories of the Oil and Gas Extraction Point Source
Category Effluent Guidelines (i.e., 40 CFR part 435 Subpart A (Offshore
Subcategory) or 40 CFR part 435 Subpart D (Coastal Subcategory)); (2)
commence construction after July 17, 2006; and (3) meet the definition
of a ``new facility'' in 40 CFR 125.83. For a discussion of the
definition of new facility, see 66 FR 65256, 65258-59, 65785-87
(December 18, 2001) and 69 FR 41576, 41578-80 (July 9, 2004). New
offshore oil and gas extraction facilities were not subject to the
Phase I new facility rule.
The determination of whether a facility is ``new'' or ``existing''
is focused on the point source discharger--not on the cooling water
intake structure. In other words, modifications or additions to the
cooling water intake structure (or even the total replacement of an
existing cooling water intake structure with a new one) does not
convert an otherwise unchanged existing facility into a new facility,
regardless of the purpose of such changes. Rather, the determination as
to whether a facility is new or existing focuses on the point source
itself.
B. What Is ``Cooling Water'' and What Is a ``Cooling Water Intake
Structure?''
This rule adopts the same definition of a ``cooling water intake
structure'' that applies to new facilities under the final Phase I rule
and existing facilities under the final Phase II rule. Under this final
rule, a cooling water intake structure is defined as the total physical
structure and any associated constructed waterways used to withdraw
cooling water from waters of the United States. Under this definition,
the cooling water intake structure extends from the point at which
water is withdrawn from the surface water source up to and including
the intake pumps. This rule also adopts the definition of ``cooling
water'' used in the Phase I and Phase II rules: water used for contact
or noncontact cooling, including water used for equipment cooling,
evaporative cooling tower makeup, and dilution of effluent heat
content. The definition specifies that the intended use of cooling
water is to absorb waste heat rejected from the processes used or
auxiliary operations on the facility's premises. As is the case with
the Phase I and Phase II rules, only the water used exclusively for
cooling purposes is to be counted when determining whether the 25
percent threshold in Sec. 125.131(a)(2) is met.
C. Would My Facility Be Covered if It Is a Point Source Discharger?
This rule applies only to facilities that have an NPDES permit or
are required to obtain one. This is the same requirement EPA included
in the Phase I and Phase II final rules (see 40 CFR 125.81(a)(1) and 40
CFR 125.91(a)(1), respectively). Requirements for complying with
section 316(b) will continue to be applied through NPDES permits.
The Agency recognizes that some facilities that have or are
required to have an NPDES permit might not own and operate the intake
structure that supplies their facility with cooling water. For example,
facilities operated by separate entities might be located on the same,
adjacent, or nearby property(ies); one of these facilities might take
in cooling water and then transfer it to other facilities prior to
discharge of the cooling water to a water of the United States. Section
125.92(c) of this rule addresses such a situation. It provides that use
of a cooling water intake structure includes obtaining cooling water by
any sort of contract or arrangement with one or more independent
suppliers of cooling water if the supplier withdraws water from waters
of the United States. This provision is intended to prevent new Phase
III facilities from circumventing the requirements of this rule by
creating arrangements to receive cooling water from an entity that is
not itself subject to the requirements of Phase III. EPA expects that a
facility that is otherwise subject to the requirements of Phase I and
that is an independent supplier to a Phase III facility would still be
subject to the requirements of Phase I.
D. When Would a New Offshore Oil and Gas Extraction Facility Be
Required To Comply With Any New 316(b) Requirements?
This final rule will become effective July 17, 2006. After that
date, new offshore oil and gas extraction Phase III facilities will
need to comply when an NPDES permit containing requirements consistent
with this rule is issued to the facility (see Sec. 125.132). Under
current NPDES program regulations, this will occur when a new NPDES
permit is issued or when an existing NPDES permit is issued, reissued,
or modified or revoked and reissued.
Most offshore oil and gas extraction facilities are covered by
general permits issued by EPA. New offshore oil and gas extraction
facilities that meet the applicability criteria for the Phase III rule
may obtain permit coverage under these general permits until they
expire. When EPA reissues these general permits, EPA will incorporate
requirements based on today's rule. Facilities that are new offshore
oil and gas extraction facilities, as defined in today's rule, will be
subject to those Phase III section 316(b) new facility
[[Page 35009]]
requirements should they seek permit coverage under those reissued
general permits.
III. Legal Authority, Purpose, and Background of This Final Regulation
A. Legal Authority
This action is issued under the authority of sections 101, 301,
308, 316, 401, 402, 501, and 510 of the Clean Water Act (CWA), 33
U.S.C. 1251, 1311, 1318, 1326, 1341, 1342, 1361, and 1370. Publication
of this action fulfills the final obligation of the U.S. Environmental
Protection Agency (EPA) under a consent decree in Riverkeeper, Inc. v.
Johnson, No. 93 Civ. 0314, (S.D.N.Y).
B. Purpose of This Regulation
Section 316(b) of the CWA provides that any standard established
pursuant to section 301 or 306 of the CWA and applicable to a point
source must require that the location, design, construction, and
capacity of cooling water intake structures reflect the best technology
available for minimizing adverse environmental impact. This rule
establishes requirements that apply to new offshore oil and gas
extraction facilities that have a design intake flow threshold of
greater than 2 MGD. This is the same design intake flow threshold as
for new facilities in the Phase I rule. To be covered, a facility would
need to use at least 25 percent of the water withdrawn exclusively for
cooling purposes and meet other specified criteria in order to be
within the scope of the rule (see section II--Scope and Applicability
of Final Rule). In this action, EPA is not promulgating any new section
316(b) requirements for existing facilities. Therefore, existing
facilities that are not covered by the Phase II rule (Phase II is
described in section III.C.5 of this preamble) must continue to meet
requirements under Section 316(b) of the CWA determined by the
permitting authority on a case-by-case, best professional judgment
(BPJ) basis. See 40 CFR 125.90(b).
C. Background
1. The Clean Water Act
The Federal Water Pollution Control Act, also known as the Clean
Water Act (CWA), 33 U.S.C. 1251 et seq., seeks to ``restore and
maintain the chemical, physical, and biological integrity of the
nation's waters.'' 33 U.S.C. 1251(a). The CWA establishes a
comprehensive regulatory program, key elements of which are (1) a
prohibition on the discharge of pollutants from point sources to waters
of the United States, except as authorized by the statute; (2)
authority for EPA or authorized States or Tribes to issue National
Pollutant Discharge Elimination System (NPDES) permits that regulate
the discharge of pollutants; and (3) requirements for limitations in
NPDES permits based on effluent limitations guidelines and standards
and water quality standards.
Section 316(b) addresses the adverse environmental impact caused by
the intake of cooling water, not discharges into water. Despite this
special focus, the requirements of section 316(b) are closely linked to
several of the core elements of the NPDES permit program established
under section 402 of the CWA to control discharges of pollutants into
navigable waters. For example, while effluent limitations apply to the
discharge of pollutants by NPDES-permitted point sources to waters of
the United States, section 316(b) applies to facilities subject to
NPDES requirements that withdraw water from waters of the United States
for cooling and that use a cooling water intake structure to do so.
Section 301 of the CWA prohibits the discharge of any pollutant by
any person, except in compliance with specified statutory requirements,
including section 402. Section 402 of the CWA provides authority for
EPA or an authorized State or Tribe to issue an NPDES permit to any
person discharging any pollutant or combination of pollutants from a
point source into waters of the United States. Forty-five States and
one U.S. territory are currently authorized under section 402(b) to
administer the NPDES permitting program. NPDES permits restrict the
types and amounts of pollutants, including heat, that may be discharged
from various industrial, commercial, and other sources of wastewater.
These permits control the discharge of pollutants primarily by
requiring dischargers to meet effluent limitations established pursuant
to section 301 or section 306. Effluent limitations are based on
Federal effluent limitations guidelines and new source performance
standards, or in cases where there are no applicable effluent
guidelines or standards, on the best professional judgment of the
permit writer. Limitations based on these guidelines, standards, or
best professional judgment are known as technology-based effluent
limits. Where technology-based effluent limits are inadequate to ensure
attainment of water quality standards applicable to the receiving
water, section 301(b)(1)(C) of the CWA requires permits to include more
stringent limits based on applicable water quality standards. NPDES
permits also routinely include monitoring and reporting requirements,
and other conditions, including conditions to implement the
requirements of section 316(b).
Section 510 of the CWA provides that, except as provided in the
CWA, nothing in the Act shall preclude or deny the right of any State
or political subdivision thereof to adopt or enforce any requirement
respecting control or abatement of pollution; except that if a
limitation, prohibition or standard of performance is in effect under
the CWA, such State or political subdivision may not adopt or enforce
any other limitation, prohibition or standard of performance which is
less stringent than the limitation, prohibition or standard of
performance under the Act. EPA interprets this to reserve for the
States authority to implement requirements that are more stringent than
the Federal requirements under State law. PUD No. 1 of Jefferson County
v. Washington Dep't of Ecology, 511 U.S. 700, 705 (1994).
Under sections 301, 304, and 306 of the CWA, EPA issues effluent
limitations guidelines and new source performance standards for
categories of industrial dischargers based on the pollutants of concern
discharged by the industry, the degree of control that can be attained
using various levels of pollution control technology, consideration of
economics, as appropriate to each level of control, and other factors
identified in sections 304 and 306 of the CWA. EPA has promulgated
regulations setting effluent limitations guidelines and standards under
sections 301, 304, and 306 of the CWA for more than 50 industries. See
40 CFR parts 405 through 471. EPA has established effluent limitations
guidelines and standards that apply to most of the industry categories
that use cooling water intake structures (e.g., steam electric power
generation, iron and steel manufacturing, pulp and paper manufacturing,
petroleum refining, and chemical manufacturing).
Section 316(b) states that any standard established pursuant to
section 301 or section 306 of [the Clean Water] Act and applicable to a
point source shall require that the location, design, construction, and
capacity of cooling water intake structures reflect the best technology
available for minimizing adverse environmental impact.
The phrase ``best technology available'' in CWA section 316(b) is
not defined in the statute, but its meaning can be understood in light
of similar phrases used elsewhere in the CWA. See Riverkeeper, Inc. v.
EPA, 358 F.3d 174, 186 (2nd Cir. 2004) (noting that the cross-reference
in CWA section 316(b) to CWA section 306 ``is an invitation to
[[Page 35010]]
look to section 306 for guidance in discerning what factors Congress
intended the EPA to consider in determining ``best technology
available'' for new sources).
In sections 301 and 306, Congress directed EPA to set effluent
discharge standards for new sources based on the ``best available
demonstrated control technology'' and for existing sources based on the
``best available technology economically achievable.'' For new sources,
section 306(b)(1)(B) directs EPA to establish ``standards of
performance.'' The phrase ``standards of performance'' under section
306(a)(1) is defined as being the effluent reduction that is
``achievable through application of the best available demonstrated
control technology, processes, operating methods or other alternatives
* * * .'' This is commonly referred to as ``best available demonstrated
technology'' or ``BADT.'' For existing dischargers, section
301(b)(1)(A) requires the establishment of effluent limitations based
on ``the application of best practicable control technology currently
available.'' This is commonly referred to as ``best practicable
technology'' or ``BPT.'' Further, section 301(b)(2)(A) directs EPA to
establish effluent limitations for certain classes of pollutants
``which shall require the application of the best available technology
economically achievable.'' This is commonly referred to as ``best
available technology'' or ``BAT.'' Section 301 specifies that both BPT
and BAT limitations must reflect determinations made by EPA under CWA
section 304. Under these provisions, the limitations on the discharge
of pollutants from point sources are based upon the capabilities of the
equipment or ``control technologies'' available to control those
discharges.
The phrases ``best available demonstrated technology'' and ``best
available technology''--like ``best technology available'' in CWA
section 316(b)--are not defined in the statute. However, section 304 of
the CWA specifies factors to be considered in establishing the best
practicable control technology currently available and best available
technology.
For best practicable control technology currently available, the
CWA directs EPA to consider the total cost of application of technology
in relation to the effluent reduction benefits to be achieved from such
application, and shall also take into account the age of the equipment
and facilities involved, the process employed, the engineering aspects
of the application of various types of control techniques, process
changes, non-water quality environmental impact (including energy
requirements), and such other factors as [EPA] deems appropriate. (33
U.S.C. 1314(b)(1)(B)).
For ``best available technology,'' the CWA directs EPA to consider
the age of equipment and facilities involved, the process employed, the
engineering aspects * * * of various types of control techniques,
process changes, the cost of achieving such effluent reduction, non-
water quality environmental impacts (including energy requirements),
and such other factors as [EPA] deems appropriate. (33 U.S.C.
1314(b)(2)(B)).
Section 316(b) expressly refers to section 301, and the phrase
``best technology available'' is very similar to ``best available
technology'' in that section. These facts, coupled with the brevity of
section 316(b) itself, prompted EPA to look to section 301 and,
ultimately, section 304 for guidance in determining the ``best
technology available to minimize adverse environmental impact'' of
cooling water intake structures for Phase III existing facilities.
By the same token, however, there are significant differences
between section 316(b) and sections 301 and 304. See Riverkeeper, 358
F.3d at 186 (``not every statutory directive contained [in sections 301
and 306] is applicable'' to a section 316(b) rulemaking). Section
316(b) requires that cooling water intake structures reflect ``the best
technology available for minimizing adverse environmental impact.'' In
contrast to the effluent limitations provisions, the object of the
``best technology available'' is explicitly articulated by reference to
the receiving water: To minimize adverse environmental impact in the
waters from which cooling water is withdrawn. In other words, EPA must
consider the receiving water effects of the candidate technologies.
Because section 316(b) is silent as to the factors EPA should
consider in deciding whether a candidate technology minimizes adverse
environmental impact, EPA has broad discretion to identify the
appropriate criteria. See Riverkeeper, 358 F.3d at 187, n.12 (brevity
of section 316(b) reflects an intention to delegate significant
rulemaking authority to EPA); see id. at 195 (appellate courts give EPA
``considerable discretion to weigh and balance the various factors''
where the statute does not state what weight should be accorded)
(citation omitted).
For this Phase III rulemaking, EPA therefore interprets the phrase
``best available technology for minimizing adverse environmental
impacts'' as authorizing EPA to consider the relationship of the costs
of the technologies to the benefits associated with them. EPA has
previously considered the costs of technologies in relation to the
benefits of minimizing adverse environmental impact in establishing
section 316(b) limits, which historically have been done on a case-by-
case basis. In Re Public Service Co. of New Hampshire, 10 ERC 1257
(June 17, 1977); In Re Public Service Co. of New Hampshire, 1 EAD 455
(Aug. 4, 1978); Seacoast Anti-Pollution League v. Costle, 597 F.2d 306
(1st Cir. 1979).
In addition to helping EPA determine the effects of candidate
technologies on the receiving water, considering the relationship of
costs and benefits also helps EPA determine whether the technologies
are economically practicable. EPA has long recognized, with the support
of legislative history, that section 316(b) does not require adverse
environmental impact to be minimized beyond that which can be achieved
at an economically practicable cost. See 118 Cong. Rec. 33762 (1972)
reprinted in 1 Legislative History of the Water Pollution Control Act
Amendments of 1972, at 264 (1973) (Statement of Representative Don H.
Clausen). EPA therefore may consider costs and benefits in deciding
whether any of the technology options for Phase III existing facilities
actually do minimize adverse environmental impact--or whether the
choice of technologies should be left to BPJ decision-making. When the
costs of establishing a national categorical rule substantially
outweigh the benefits of such a rule, a national categorical section
316(b) rule may not be economically practicable, and therefore not the
``best technology available for minimizing adverse environmental
impact.''
Nothing in section 316(b) requires EPA to promulgate a regulation
to implement the requirements for cooling water intake structures.
Section 316(b) of the CWA grants EPA broad authority to establish
performance standards for cooling water intake structures based on the
``best technology available to minimize adverse environmental impact.''
Although EPA has chosen under section 316(b) to promulgate national
categorical performance standards applicable to certain classes of
point sources using cooling water intake structures, see 40 CFR part
125, Subpart I (new facilities), Subpart J (existing power generating
facilities), and Subpart N (new offshore oil and gas facilities), the
statute does not preclude EPA from determining BTA on a site-specific
basis. Indeed, the U.S. Court of
[[Page 35011]]
Appeals for the Second Circuit, in upholding virtually the entire
316(b) Phase I rule for new facilities, specifically noted that section
316(b) does not compel EPA to regulate cooling water intake structures
using any particular format, e.g. overarching regulation, different
regulations for different categories of sources, or individually on a
case-by-case basis. Riverkeeper, 358 F.3d at 203. In fact, EPA and
state permitting authorities have been implementing Section 316(b) on a
case-by-case basis for over 25 years (see Section III.C.3 below), and
courts have recognized this practice as consistent with the statute.
See Hudson Riverkeeper Fund v. Orange & Rockland Utils., Inc., 835 F.
Supp. 160, 165 (S.D.N.Y. 1993) (``This leaves to the Permit Writer an
opportunity to impose conditions on a case-by-case basis, consistent
with the statute * * * ''). Moreover, in both the Phase I and II rules,
EPA uses a case-by-case, BPJ permitting regime for facilities that do
not meet the applicability criteria for EPA's national categorical
rules. See 40 CFR 125.81(a), 125.90(b). In Riverkeeper, this provision
of the Phase I rule was upheld by the Second Circuit. 358 F.3d at 203
(``[w]e see no textual bar in sections 306 or 316(b) to regulating
below-threshold structures on a case-by-case basis.'').
2. Consent Decree
This final action fulfills EPA's obligation to comply with the
Second Amended Consent Decree, which was filed on November 25, 2002, in
the United States District Court, Southern District of New York, in
Riverkeeper, Inc. v. Johnson, No. 93 Civ 0314 (AGS). That case was
brought against EPA by a coalition of individuals and environmental
groups. The original Consent Decree, filed on October 10, 1995,
provided that EPA was to propose regulations implementing section
316(b) by July 2, 1999, and take final action with respect to those
regulations by August 13, 2001. Under subsequent interim orders, the
Amended Consent Decree filed on November 22, 2000, and the Second
Amended Consent Decree, EPA divided the rulemaking into three phases.
EPA took final action promulgating a rule governing cooling water
intake structures used by new facilities (Phase I) on November 9, 2001
(66 FR 65255, December 18, 2001). EPA took final action promulgating a
rule governing cooling water intake structures used by large existing
power producers (Phase II) on February 16, 2004 (69 FR 41576, July 9,
2004). The consent decree further requires that EPA propose by November
1, 2004, and take final action on by June 1, 2006 regulations
applicable to the following categories: Utility and non-utility power
producers not covered by the Phase II regulations, pulp and paper
manufacturing, petroleum and coal products manufacturing, chemical and
allied products manufacturing, and primary metals manufacturing (Phase
III). EPA proposed Phase III regulations on November 1, 2004 (69 FR
68444) and this final action fulfills EPA's obligations for Phase III.
3. What Other EPA Rulemakings and Guidance Address Cooling Water Intake
Structures?
In April 1976, EPA published a final rule under section 316(b) that
addressed cooling water intake structures. 41 FR 17387 (April 26,
1976), see also the proposed rule at 38 FR 34410 (December 13, 1973).
The rule added a new Sec. 401.14 to 40 CFR Chapter I that reiterated
the requirements of CWA section 316(b). It also added a new part 402,
which included three sections: (1) Sec. 402.10 (Applicability), (2)
Sec. 402.11 (Specialized definitions), and (3) Sec. 402.12 (Best
technology available for cooling water intake structures). Section
402.10 stated that the provisions of part 402 applied to ``cooling
water intake structures for point sources for which effluent
limitations are established pursuant to section 301 or standards of
performance are established pursuant to section 306 of the Act.''
Section 402.11 defined the terms ``cooling water intake structure,''
``location,'' ``design,'' ``construction,'' ``capacity,'' and
``Development Document.'' Section 402.12 included the following
language:
The information contained in the Development Document shall be
considered in determining whether the location, design,
construction, and capacity of a cooling water intake structure of a
point source subject to standards established under section 301 or
306 reflect the best technology available for minimizing adverse
environmental impact.
In 1977, fifty-eight electric utility companies challenged those
regulations, arguing that EPA had failed to comply with the
requirements of the Administrative Procedure Act (APA) in promulgating
the rule. Specifically, the utilities argued that EPA had neither
published the Development Document in the Federal Register nor properly
incorporated the document into the rule by reference. The United States
Court of Appeals for the Fourth Circuit agreed and, without reaching
the merits of the regulations themselves, remanded the rule.
Appalachian Power Co. v. Train, 566 F.2d 451 (4th Cir. 1977). EPA later
withdrew part 402.44 FR 32956 (June 7, 1979). The regulation at 40 CFR
401.14, which reiterates the statutory requirement, remains in effect.
Since the Fourth Circuit remanded EPA's section 316(b) regulations
in 1977, NPDES permit authorities have made decisions implementing
section 316(b) on a case-by-case, site-specific basis. EPA published
draft guidance addressing section 316(b) implementation in 1977. See
Draft Guidance for Evaluating the Adverse Impact of Cooling Water
Intake Structures on the Aquatic Environment: Section 316(b) P.L. 92-
500 (U.S. EPA, 1977). This draft guidance described the studies
recommended for evaluating the impact of cooling water intake
structures on the aquatic environment and recommended a basis for
determining the best technology available for minimizing adverse
environmental impact. The 1977 section 316(b) draft guidance states,
``The environmental-intake interactions in question are highly site-
specific and the decision as to best technology available for intake
design, location, construction, and capacity must be made on a case-by-
case basis.'' (Section 316(b) Draft Guidance, U.S. EPA, 1977, p. 4).
This case-by-case approach was also consistent with the approach
described in the 1976 Development Document referenced in the remanded
regulation.
The 1977 section 316(b) draft guidance suggested a general process
for developing information needed to support section 316(b) decisions
and presenting that information to the permitting authority. The
process involved the development of a site-specific study of the
environmental effects associated with each facility that uses one or
more cooling water intake structures, as well as consideration of that
study by the permitting authority in determining whether the facility
must make any changes for minimizing adverse environmental impact.
Where adverse environmental impact is present, the 1977 draft guidance
suggested a stepwise approach that considers size, location, capacity,
available technology, and other factors.
The draft guidance left the decisions on the appropriate location,
design, capacity, and construction of cooling water intake structures
to the permitting authority. Under this framework, the Director
determined whether appropriate studies have been performed, whether a
given facility has minimized adverse environmental impact, and what, if
any, technologies may be required.
4. Phase I New Facility Rule
On November 9, 2001, EPA took final action on Phase I regulations
governing
[[Page 35012]]
cooling water intake structures at new facilities. 66 FR 65255
(December 18, 2001). On December 26, 2002, EPA made minor changes to
the Phase I regulations. 67 FR 78947. The final Phase I new facility
rule (40 CFR part 125, Subpart I) establishes requirements applicable
to the location, design, construction, and capacity of cooling water
intake structures at new facilities that withdraw greater than two (2)
MGD and use at least twenty-five (25) percent of the water they
withdraw solely for cooling purposes.
With the new facility rule, EPA promulgated national minimum
requirements for the location, design, capacity, and construction of
cooling water intake structures at new facilities. The final new
facility rule establishes a reasonable framework that creates certainty
for permitting of new facilities, while providing significant
flexibility to take site-specific factors into account.
EPA specifically excluded new offshore oil and gas extraction
facilities from the Phase I new facility rule, but committed to
consider establishing requirements for such facilities in the Phase III
rulemaking. 66 FR 65338 (December 18, 2001).
5. Phase II Existing Facility Rule
On February 16, 2004, EPA took final action on regulations
governing cooling water intake structures at certain existing power
producing facilities. 69 FR 41576 (July 9, 2004). The final Phase II
rule applies to existing facilities that are point sources; that, as
their primary activity, both generate and transmit electric power or
generate electric power for sale to another entity for transmission;
that use or propose to use cooling water intake structures with a total
design intake flow of 50 MGD or more to withdraw cooling water from
waters of the United States; and that use at least 25 percent of the
withdrawn water exclusively for cooling purposes.
Under the Phase II rule, EPA established performance standards for
the reduction of impingement mortality and entrainment (see 40 CFR
125.94). The performance standards consist of ranges of reductions in
impingement mortality and/or entrainment. These performance standards
reflect the best technology available for minimizing adverse
environmental impacts at facilities covered by the Phase II rule. The
type of performance standard applicable to a particular facility (i.e.,
reductions in impingement mortality only or impingement mortality and
entrainment) is based on several factors, including the facility's
location (i.e., source waterbody), rate of use (capacity utilization
rate), and the proportion of the waterbody withdrawn. The Phase II
regulations address more than 90 percent of total cooling water intake
flows in the United States.
6. Public Participation
EPA worked extensively with stakeholders from industry, public
interest groups, State agencies, and other Federal agencies in the
development of this rule. EPA included industry groups, environmental
groups, and other government entities in the development, testing,
refinement, and completion of the section 316(b) survey, which was used
as a primary source of data for Phase III. As discussed in section III
of this preamble, the survey, ``Information Collection Request,
Detailed Industry Questionnaires: Phase II Cooling Water Intake
Structures & Watershed Case Study Short Questionnaire,'' was initiated
in 1997, and was used to collect data during 2000.
EPA sponsored a Symposium on Cooling Water Intake Technologies to
Protect Aquatic Organisms, on May 6-7, 2003. This symposium brought
together professionals from Federal, State, and Tribal regulatory
agencies; industry; environmental organizations; engineering consulting
firms; science and research organizations; academia; and others
concerned with mitigating harm to the aquatic environment by cooling
water intake structures. Efficacy and costs of various technologies to
mitigate impacts to aquatic organisms from cooling water intake
structures, as well as research and other future needs, were discussed.
During the development of this regulation, EPA met several times
with trade associations whose members would be subject to Phase III
requirements. EPA also conducted Phase III-specific data collection
activities, including a study of entrainment at Phase III facilities,
contacting Phase III facilities to request biological studies and
conducting an industry survey of offshore oil and gas extraction
facilities and seafood processing vessels.
In developing requirements for new offshore oil and gas extraction
facilities, EPA drew on its experience from the offshore oil and gas,
the coastal oil and gas, and the synthetic drilling fluids effluent
limitations guidelines, which included extensive public outreach,
meetings, public comment periods, industry surveys, and economic
analysis and modeling of representative oil and gas operations as
detailed in 61 FR 66086-66130 and 66 FR 6849-6919.
Finally, EPA convened a Small Business Advocacy Review (SBAR) panel
(in accordance with the Regulatory Flexibility Act section 609(b) as
amended by the Small Business Regulatory and Enforcement Fairness Act)
to provide information to small entities and receive feedback during
the Phase III rulemaking process. EPA hosted a pre-panel outreach
meeting for small entities potentially subject to Phase III on January
22, 2004. The SBAR panel held an outreach meeting with small entity
representatives (SERs) on March 16, 2004. Based on the information
gathered from the participating small entities during these outreach
meetings and subsequent correspondence, the SBAR panel produced a final
report to the EPA Administrator on April 27, 2004. Results of the final
report were considered in the development of the Phase III rule.
These coordination efforts and all of the meetings described in
this section, as well as the comments submitted on the Phase I and II
section 316(b) rules and EPA's response to these comments, are
documented or summarized in the dockets for these three rules. The
Administrative Record for this rule includes all materials from the
Phase I, Phase II, and Phase III section 316(b) rule dockets.
IV. Environmental Impacts Associated With Cooling Water Intake
Structures
EPA has identified a variety of environmental impacts that may be
associated with cooling water intake structures at Phase III
facilities, depending on conditions at an individual facility's site.
These impacts include organism entrainment and impingement, which can
contribute to impacts to threatened and endangered species; reductions
in ecologically critical aquatic organisms, including important
elements of an ecosystem's food chain; diminishment of population
compensatory reserves; losses to populations, including reductions of
commercial and recreational fisheries; and stresses to overall
communities and ecosystems as evidenced by reductions in diversity,
changes in species composition, or other changes in ecosystem structure
or function. (See discussion at 69 FR 68461-66.)
The withdrawal of water affects a variety of aquatic organisms
including phytoplankton (tiny, free-floating photosynthetic organisms
suspended in the water column), zooplankton (small aquatic animals,
including fish eggs and larvae, which may consume phytoplankton and
other zooplankton), macroinvertebrates, shellfish, and fish. Other
organisms, including reptiles,
[[Page 35013]]
birds, and mammals can also be impinged or entrained.
Impingement takes place when organisms are trapped against a
cooling water intake structure, particularly screening materials, by
the force of water being drawn through the intake structure. The
velocity of the water intake by the structure can remove fish scales or
other organism structures, prevent proper gill function, or otherwise
physically harm or cause the death of impinged organisms through
exhaustion, starvation, asphyxiation, and descaling or other injury.
Death from impingement (``impingement mortality'') can take place while
organisms are impinged on an intake structure or it can take place
after organisms have escaped impingement and have returned to a
waterbody. An organism can die despite escaping impingement because of
injuries it receives during the impingement process.
Entrainment occurs when organisms are drawn through a cooling water
intake structure into a facility's cooling system. Organisms that
become entrained are typically relatively small aquatic organisms,
including many early life stages of fish and shellfish. As entrained
organisms pass through a facility's cooling system they can be subject
to mechanical, thermal, and/or, chemical stress. Sources of stress
include physical impacts in the pumps and condenser tubing, pressure
changes caused by diversion of the cooling water into the plant or by
the hydraulic effects of the condensers, shear stress, thermal shock in
the condenser and discharge tunnel, and chemical toxic effects from
cooling system antifouling agents such as chlorine. Similar to
impingement mortality, death from entrainment can occur during
entrainment or at some time after the entrainment and return of
entrained organisms to a waterbody.
Environmental Impacts from New Offshore Oil and Gas Extraction Facility
Cooling Water Intake Structures
Offshore oil and gas extraction facilities currently operate off
the coasts of California and Alaska and throughout the Gulf of Mexico.
Most activity currently takes place in the Gulf of Mexico. EPA expects
that most new facility activity will also take place in this region.
(See Phase III TDD; DCN [9-0004], Chapter 3.)
While EPA is not aware of any studies that directly examine or
document impingement mortality and entrainment by offshore oil and gas
extraction facilities, numerous studies show that offshore marine
environments provide habitat for a number of species of fish,
shellfish, and other aquatic organisms. Many of these species have life
stages that are small and planktonic or have limited swimming ability.
These life stages are potentially vulnerable to entrainment by cooling
water intake structures. Larger life stages are potentially vulnerable
to impingement. The introduction of cooling water intake structures
into the offshore habitat in which these organisms live creates the
potential for impingement and entrainment of these organisms.
The densities of organisms in the immediate vicinity of offshore
oil and gas extraction facilities relative to densities in estuaries
and other nearshore coastal waters is not well characterized. In the
Phase III Notice of Data Availability (NODA) (70 FR 71059), EPA
presented an analysis of additional data from the general regions in
which existing offshore oil and gas extraction facilities operate and
where new facilities might operate in the future in order to better
characterize the potential for impingement and entrainment by these
facilities.
EPA obtained data on densities of ichthyoplankton (planktonic fish
eggs and larvae) in the Gulf of Mexico from the Southeast Area
Monitoring and Assessment Program (SEAMAP).12
This long-term sampling program collects information on the density of
fish eggs and larvae throughout the Gulf of Mexico. EPA analyzed the
SEAMAP data to determine average ichthyoplankton densities in the Gulf
of Mexico for the period of time for which sampling data was available
(1982-2003). Actual conditions at any one location and at any one point
in time may vary from the calculated averages.
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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
