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

Evaluation of Potential Cooling Water Intake Structure Effects

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

Verification Monitoring Plan

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

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

Velocity Information (Track I)

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

Design and Construction Technology Plan (Track I)

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

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

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

IX. Economic Impact Analysis

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

A. New Offshore Oil and Gas Extraction Facilities

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

entire analysis period to 49 years (2007 to 2055).
    Two types of cost analysis are presented. The social cost analysis
includes before tax compliance costs to facilities and implementation
costs to EPA. In this analysis, costs are discounted to 2007, assuming
it would take a facility about 6 months to begin incurring costs. If
the start date is actually later than 2007, social costs will be
slightly reduced from those estimated here in present value terms. For
the second type of cost analysis, industry after-tax compliance costs,
costs are discounted for each individual facility to the year of
compliance (the year the vessel is launched or the platform/structure
come on line, which ranges from 2007 to 2026). The present value
calculated for each facility is used in the economic impact analysis.
These costs are subsequently discounted to 2004 and are then totaled to
produce an aggregate present value of compliance costs. For both
approaches annualized costs are then calculated by annualizing at a 3
percent (social costs) or 7 percent discount rate (social costs and
industry compliance costs) over 30 years. All dollar values presented
in this preamble are in $2004 (average or mid-year).
1. General Approach for Costing Impingement and Entrainment Equipment
for Offshore Oil and Gas Extraction Facilities
    EPA's general approach to estimate compliance costs associated with
the use of impingement and entrainment controls for offshore oil and
gas facilities was to first identify the different types of cooling
water intake structures (e.g., simple pipes, caissons, sea chests)
being employed by the various types of offshore oil and gas extraction
facilities (e.g., jackups, platforms, MODUs, drill ships). EPA then
identified available impingement and entrainment control technologies
(e.g., cylindrical wedgewire systems, flat panel wedgewire screens) for
the different configurations of offshore oil and gas extraction
facilities and cooling water intake structures. EPA estimated both
capital and annual operating costs for each technology option for the
different configurations of offshore oil and gas extraction facilities
and cooling water intake structures.
    In order to estimate the related economic impacts associated with
this rule, EPA used the available impingement and entrainment control
technologies with superior reliability and performance and ease of
operation. For example, EPA considered technologies such as airburst
cleaning systems, which ensure that the through-screen intake
velocities are relatively constant and as low as possible, and cooling
water intake structures constructed with copper-nickel alloy components
for biofouling control where necessary. While EPA recognized that
operators complying with this rule may choose alternate impingement and
entrainment control technologies than those upon which EPA based its
economic analysis, EPA chose this method of estimating costs because
EPA judged those compliance technologies to be the best technologies
available, and accordingly used these technologies as the basis for the
requirements in this rule
    Using this methodology, EPA estimated compliance costs for the
various configurations of offshore oil and gas extraction facilities
and cooling water intake structures using the following:
     Stainless steel wedge wire screens with and without air
sparging;
     Copper-nickel wedge wire screens with and without air
sparging;
     Stainless steel velocity caps;
     Copper-nickel alloy velocity caps;
     Flat panel wedge wire screens over sea chests; and
     Horizontal flow diverters associated with sea chests.
    EPA's detailed methodology for estimating these compliance costs is
outlined in the Technical Development Document and the record
supporting the final rule.
2. Social Cost for New Oil and Gas Extraction Facilities
    The total annualized social cost of this rule for new Oil and Gas
facilities is estimated at $3.8 million using a 3 percent discount
rate, and $3.2 million using a 7 percent discount rate. The largest
component of social cost is the pre-tax cost of regulatory compliance
incurred by complying facilities; these costs include one-time
technology costs of complying with the rule, annual O&M costs, and
permitting costs (initial permit costs, annual monitoring costs, and
permit reissuance costs). Social cost also includes implementation
costs incurred by the Federal government. EPA expects that the final
regulation will be implemented under general permits.\8\
---------------------------------------------------------------------------

    \8\ Because individual permits are typically not issued to
offshore oil and gas extraction facilities, costs for pre-permitting
and re-permitting studies are assumed to be shared among groups of
new facilities expected to be covered by the general permits (see
DCN 7-4036 for detailed information on how permitting costs are
assumed to be shared under the general permits).
---------------------------------------------------------------------------

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

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

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

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

Analysis of Project Viability

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

Analysis of Production Shut-In Effects

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

these variables following the imposition of compliance costs.
---------------------------------------------------------------------------

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

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

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

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

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

B. Existing Phase III Facilities

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

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

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

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

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

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

2. Social Cost for Existing Manufacturing Facilities

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

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

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

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

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

X. Benefits Analysis

A. Introduction

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

B. Study Design and Methods

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

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

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

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

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

C. National Benefits

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

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

XI. Comparison of Benefits and Costs

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

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

XII. Statutory and Executive Order Reviews

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

A. Executive Order 12866: Regulatory Planning and Review

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

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

B. Paperwork Reduction Act

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

assessing the source waterbody, estimating the magnitude of impingement
mortality and entrainment, and reporting results in a comprehensive
demonstration study. The burden may also include conducting a pilot
study to evaluate the suitability of the technologies and operational
measures based on the species that are found at the site.
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. In addition, EPA is
amending the table in 40 CFR part 9 of currently approved OMB control
numbers for various regulations to list the regulatory citations for
the information requirements contained in this final rule.

C. Regulatory Flexibility Act

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

D. Unfunded Mandates Reform Act

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

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

E. Executive Order 13132: Federalism

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

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

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

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

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

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

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

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

I. National Technology Transfer and Advancement Act

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

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

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

K. Executive Order 13158: Marine Protected Areas

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

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

L. Congressional Review Act

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

List of Subjects

40 CFR Part 9

    Environmental protection, Reporting and recordkeeping requirements.

40 CFR Part 122

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

40 CFR Part 23

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

40 CFR Part 124

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

40 CFR Part 125

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

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

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

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

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

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

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

Sec.  9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                   40 CFR citation                      OMB control No.
------------------------------------------------------------------------

                             * * * * * * *
   EPA Administered Permit Programs: The National Pollutant Discharge
                           Elimination System

                              * * * * * * *
122.21(r)............................................   2040-0241, 2040-
                                                         0257, 2040-0268

                             * * * * * * *
 Criteria and Standards for the National Pollutant Discharge Elimination
                                 System

                              * * * * * * *
125.134..............................................          2040-0268
125.135..............................................          2040-0268
125.136..............................................          2040-0268
125.137..............................................          2040-0268
125.138..............................................          2040-0268
125.139..............................................          2040-0268

                              * * * * * * *
------------------------------------------------------------------------

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

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

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

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

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

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

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