A list and description of any historical studies characterizing the physical and biological conditions in the vicinity of the proposed or actual intakes and their relevancy to the proposed Study. If the facility proposes to rely on existing source waterbody data, the data must be no more than 5 years old, and the facility must demonstrate that the existing data are sufficient to develop a scientifically valid estimate of potential impingement mortality and entrainment impacts, and provide documentation showing that the data were collected using appropriate quality assurance/ quality control procedures; Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 70   Any public participation or consultation with Federal or State agencies undertaken in developing the plan; and   A sampling plan for data that will be collected using actual field studies in the source waterbody. The sampling plan must document all methods and quality assurance procedures for sampling, and data analysis. The sampling and data analysis methods proposed must be appropriate for a quantitative survey and based on consideration of methods used in other studies performed in the source waterbody. The sampling plan must include a description of the study area ( including the area of influence of the cooling water intake structure and at least 100 meters beyond); taxonomic identification of the sampled or evaluated biological assemblages ( including all life stages of fish and shellfish); and sampling and data analysis methods.

The facility must submit documentation of the results of the Study to the Director.

Documentation of the results of the Study includes: Source Water Biological Study, an evaluation of potential cooling water intake structure effects, and a verification monitoring plan as described below.

Source Water Biological Study.

The Source Water Biological Study 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of the abundance and temporal/ spatial characterization of Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 71 the target populations based on the collection of multiple years of data to capture the seasonal and daily activities ( e. g.,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 implement to meet requirements under Track II. To do this, the facility must determine the reduction in impingement mortality and entrainment that would be achieved by implementing the requirements of ' 125.134( b)( 2) and, for facilities without sea chests, ' 125.134( b)( 5).

( 2) An engineering estimate of efficacy for the proposed and/ or implemented technologies used to minimize impingement mortality and, if applicable, entrainment of all life stages of fish and shellfish and maximize survival of impinged life stages of fish and shellfish. The facility must demonstrate that the technologies reduce impingement mortality and, if applicable, entrainment of all life stages of fish and shellfish to a comparable level to that which would be achieved if the facility were to implement the requirements in ' 125.134( b)( 2) and, for facilities without sea chests, ' 125.134( b)( 5).

The efficacy projection must include a site specific evaluation of technology( ies) Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 72 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.

The fixed facility must include in the Study a plan to conduct, at a minimum, two years of monitoring to verify the full scale performance of the proposed or implemented technologies, and/ or operational measures. The verification study must begin at the start of operations of the cooling water intake structure and continue for a sufficient period of time to demonstrate that the facility is reducing the level of impingement mortality and entrainment to the level documented under the evaluation of potential cooling water intake structure effects. The plan must describe the frequency of monitoring and the parameters to be monitored. The Director will use the verification monitoring to confirm that the facility is meeting the level of impingement mortality and entrainment reduction required in ' 125.134( c), and that the operation of the technology has been optimized.

2. As an Owner of 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 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 73 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) or the Comprehensive Demonstration Study required by ' 125.136( c)( 2), depending on whether the facility has a sea chest. The monitoring methods used must be consistent with those used for the Source Water Baseline Biological Characterization data required in 40 CFR 122.21( r)( 4)

or the Comprehensive Demonstration Study required by ' 125.136( c)( 2).

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 seasonal and daily 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 74 Biological Characterization required by 40 CFR 122.21( r)( 4) or the Comprehensive Demonstration Study required in ' 125.136( c)( 2). Samples must be collected only when the cooling water intake structure is in operation.

Velocity monitoring. If the facility uses a surface intake screen system, it must monitor head loss across the screens and correlate the measured value with the design intake velocity. The head loss across the intake screen must be measured at the minimum ambient source water surface elevation ( using best professional judgment based on available hydrological data). The maximum head loss across the screen for each cooling water intake structure will be used to determine compliance with the velocity requirement in ' 125.134( b)( 2). If the facility uses devices other than surface intake screens, it must monitor velocity at the point of entry through the device. Head loss or velocity would be monitored during initial facility startup, and thereafter, at the frequency specified in the NPDES permit, but no less than once per quarter.

To verify the flow velocity is maintained less than 0.5 ft/ sec through the cooling water intake structure, facilities would be required to 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 ft/ second at the maximum design flow of the cooling water intake structure. Facilities must monitor and record flow data through the cooling water intake structure continuously to verify 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 to verify flow rates through cooling water intake structure did not exceed Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 75 design capacity. Flow data can be collected and submitted to the Director either electronically or by hard copy.

Visual or remote inspections. The facility must conduct visual inspections or employ remote monitoring devices during the period the cooling water intake structure is in operation. Visual inspections must be conducted at least weekly to ensure that any design and construction technologies required in ' 125.134( b)( 4), ( b)( 5), ( c), and/ or ( d)

are maintained and operated to ensure that they will continue to function as designed.

Alternatively, the facility must inspect via remote monitoring devices to ensure that the impingement and entrainment technologies are functioning as designed.

3. What Recordkeeping and Reporting is Required for New Offshore Oil and Gas Extraction Fixed Facilities?

Owners and operators of new offshore oil and gas extraction fixed facilities must keep records of all the data used to complete the permit application and show compliance with the requirements, any supplemental information developed under ' 125.136, and any compliance monitoring data submitted under ' 125.137, for a period of at least three years from the date of permit issuance. The Director may require that these records be kept for a longer period.

Additionally, this final rule requires that new offshore oil and gas extraction fixed facilities submit the following in a yearly status report:

  Biological monitoring records for each cooling water intake structure as required by ' 125.137( a); Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 76   Velocity and head loss monitoring records for each cooling water intake structure as required by ' 125.137( b); and   Records of visual or remote inspections as required in ' 125.137( c).

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 requires that new nonfixed ( mobile) offshore oil and gas extraction facilities submit velocity information consistent with ' 125.136( b)( 1). 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)

The final rule requires that new nonfixed ( mobile) offshore oil and gas extraction facilities submit a design and construction technology plan only when required by the Director consistent with ' 125.134( b)( 4). The design and construction technology plan must demonstrate that the facility has selected and will implement the design and Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 77 construction technologies necessary to minimize impingement mortality in accordance with ' 125.134( b)( 4). The design and construction technology plan requires delineation of the hydrologic zone of influence for the cooling water intake structure; a description of the technologies implemented ( or to be implemented) at the facility; the basis for the selection of that technology; the expected performance of the technology, and design calculations, drawings and estimates to support the technology description and performance. The Agency recognizes that the selection of a specific technology or a group of technologies depends on the individual facility and waterbody conditions.

5. As an Owner of 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 ' 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 78 velocity must be monitored during initial facility startup, and thereafter, at the frequency specified in the NPDES permit, but no less than once per quarter.

Visual or remote inspections. The facility must conduct visual inspections or employ remote monitoring devices during the period the cooling water intake structure is in operation. Visual inspections must be conducted at least weekly to ensure that any design and construction technologies required in ' 125.134( b)( 4), ( b)( 5), ( c), and/ or ( d)

are maintained and operated to ensure that they will continue to function as designed.

Alternatively, the facility must inspect via remote monitoring devices to ensure that the impingement technologies are functioning as designed.

6. What Recordkeeping and Reporting is Required for New Non fixed ( Mobile)

Offshore Oil and Gas Extraction Facilities?

Owners and operators of new mobile offshore oil and gas extraction facilities must keep records of all the data used to complete the permit application and show compliance with the requirements, any supplemental information developed under '

125.136, and any compliance monitoring data submitted under ' 125.137, for a period of at least three years from the date of permit issuance. The Director may require that these records be kept for a longer period.

Additionally, this final rule requires that new mobile offshore oil and gas extraction facilities submit the following in a yearly status report:

  Velocity and head loss monitoring records for each cooling water intake structure as required by ' 125.137( b); and   Records of visual or remote inspections as required in ' 125.137( c). Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 79 D. 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 Federally issued NPDES permits. 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 80 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 for cooling purposes. 9 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 methods of discounting over the time period of the analysis are employed. Social 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, compliance costs will be slightly reduced from those estimated here in 9 See section II. B for a definition of a new offshore oil and gas extraction facility for the purposes of this rule. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 81 present value terms. Industry compliance 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 then totaled to produce an aggregate present value of compliance costs. 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 the this final rule, EPA used the available impingement and entrainment control technologies with Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 82 superior reliability and performance ( e. g., technologies such as airburst cleaning systems to ensure that the through screen intake velocities are relatively constant and as low as possible) and ease of operation ( e. g., cooling water intake structures constructed with copper nickel alloy components for biofouling control). Consequently, EPA is likely overestimating the actual incremental compliance costs resulting from the implementation of this final rule as operators may choose less expensive impingement and entrainment control technologies that comply with the impingement and entrainment control performance standards in this final rule. Based on these criteria, EPA estimated the following compliance costs for the various configurations of configurations of offshore oil and gas extraction facilities and cooling water intake structures:

° 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 detailed methodology for estimating these compliance costs are 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 83 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. The final regulation would be implemented under general permits, two in the Gulf of Mexico, and one in Cook Inlet Alaska. 10 States are not likely to be involved in administering the permits for new regulated offshore oil and gas facilities. Rather, general permits are administered by the applicable EPA regions ( Regions 4, 6, and 10), even if facilities are located in State waters. 11 EPA estimates that direct compliance costs would 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.

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 10 Because individual permits are not issued, 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). 11 Alaska does not have NPDES program authority so EPA Region 10 writes NPDES permits for Alaskan waters. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 84 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 EA 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 9 XXXX]), 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 85 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 standard 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 86 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: ( 1) 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, 12 and ( 2) 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.

12 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 87 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, Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 88 based on the estimated marginal tax rate, to yield the after tax compliance cost stream ( for more information 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. Assuming zero cost pass through may overestimate potential economic impacts on MODUs because new MODUs will be competing with existing MODUs,

which will not incur compliance costs.

This analysis found that no new MODUs ( based on an assumption that finances for new MODUs will look like those for existing MODUs) would be a regulatory closure as a result of the incremental compliance costs associated with the final rule ( detailed results are provided in the CBI portion of the record; DCN 7 4020; no comments were received on costs or analyses, and no new survey information has been collected since proposal so the analysis was not rerun).

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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 89 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 semisubmersibles $ 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 90 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 owning jackups, semi submersibles, or drill ships that would be subject to the requirements for new facilities if newly constructed or were in the process of building MODUs currently. 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 91 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). Seven firms are each assumed to build 9 jackups or semi submersibles 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 jackup or semi submersibles, 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 simplicity and because the majority of rigs anticipated to be constructed will be jackups, EPA used the higher compliance cost of a jackup rig to represent the cost of compliance for both jackups and semi submersibles in judging impacts on firms. For simplicity, for a conservatively high estimate of compliance costs that a firm might face,

and to reflect the small possibility that all a firm's new rigs might be constructed in one year, EPA assumed that the annualized costs of compliance for all MODUs constructed over the period of analysis by each firm are incurred in one year for comparison to one year's revenue.

Using these assumptions, EPA estimates that the annualized pre tax costs per firm range from $ 0.3 to $ 0.7 million, and the after tax costs range from $ 0.2 to $ 0.4 million.

The pre tax cost to revenue ratio ranges from 0.01 percent to 0.2 percent, while the aftertax ratios range from 0.01 percent to 0.1 percent. Given that the highest estimated ratio is 0.2 percent, EPA concludes that firm level impacts would not pose a barrier to entry. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 92 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 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 93   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. For simplicity, to develop a conservatively high estimate of compliance costs in any one year, and 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 aftertax basis.

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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 94 production. The platform model analyzes production over a period extending as long as 30 years. Pre tax costs ( including costs incurred in pre production years, O& M,

monitoring costs, and repermitting costs) are input into the model in the year in which they occur, until the model shows the platform is uneconomical to operate. To determine the shut in year, projected net revenue is compared to operating costs in each production year. Net revenue is based on an assumed price of oil, current and projected production of oil and gas, well production decline rates, and severance and royalty rates. Operating costs are based on a calculated cost per barrel of oil equivalent ( BOE) produced. The model simulates operations for the lesser of 30 years or to the year when operating costs exceed production revenue, at which point the operator is assumed to terminate production. The model calculates the lifetime of the project, total production, and the net present value of the operation ( net income of the operation over the life of the project in terms of today's dollars). A comparison of the baseline model outputs to the postcompliance model outputs yields any losses of production and project lifetimes and the net present value of the operation. If the net present value of the operation is positive in the baseline but negative post compliance, the project is considered nonviable postcompliance It is assumed the platform would not be built.

The model uses as baseline data, financial information from representative existing platforms, collected in EPA's 316( b) survey of production platforms ([ DCN 9

XXXX]) 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, Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 95 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. It is likely 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 ( note:

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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 96 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. 13 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.

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.

( Detailed results are included in the CBI portion of the record at DCN 7 4038; no 13 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 97 substantive comments were received on costs or the analysis, and no new survey information was received since proposal, so this analysis was not rerun).

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 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

torevenue test, which compares the annualized pre tax and after tax costs of compliance Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 98 ( 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. For simplicity, to develop a conservatively high estimate of compliance costs in any one year, and 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. 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

torevenue 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 99 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). 14 Exhibit IX 1   Summary of Private Costs and Impacts for New Oil and Gas Facilities Type of Oil and Gas Facility Number of New Facilities Annualized Private After tax Compliance Costs ( in millions, $ 2004) Facility Impacts Firm Impacts 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.

14 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 pretax costs, is less than the present value of private, after tax cost. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 100 Exhibit IX 2   Summary of Economic Analysis for the 316( b) Phase III Final Regulation Applicable to New Offshore Oil and Gas Extraction Facilities Annualized Social Cost ( in millions, $ 2004) 1,2 Number of Facilities Subject to National Requirements Number of Facilities with Impacts New Offshore Oil and Gas Extraction Facilities 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 we are not promulgating a national section 316( b) rule for existing Phase III facilities, there are no additional compliance costs associated with this action for these facilities. However, we 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 principal regulatory national categorical 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: Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 101 1. Facilities with a total DIF 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 food production as well as a few non manufacturing facilities. As described in the NODA, EPA now evaluates Food and Kindred Products as a primary industry; see Chapter B2F of the final EA.

Nonmanufacturing industries comprise less than 1 percent of the total facilities potentially regulated under each of the co proposed options. In addition to engaging in production activities, some facilities also generate electricity for their own use and occasionally for sale.

Summary of Facilities Potentially Subject to a Final National Categorical Phase III Regulation for Existing Facilities Exhibit IX 3 presents, by DIF option, EPA's estimates of ( 1) the number of existing facilities potentially subject to this rulemaking, ( 2) the number of baseline closures, and ( 3) the number of existing facilities subject to national requirements under the proposed regulations, after removal of baseline closures. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 102 Exhibit IX 3   Phase III Existing Manufacturers Facility Counts, by DIF Option Industry Facilities Potentially Subject to Regulation, Based on Applicability Criteria Baseline Closures Subject to National Requirements, Excluding Baseline 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 73 5 21 Other Industries 4 1 2 Total 77 6 23 Total DIF ( MGD) 25,328 1,284 24,044 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 facilityspecific costs for 354 facilities for which detailed information was available, and applied the model facility approach used at proposal to the remaining facilities to calculate the industry level costs.

EPA reasonably adopted the best performing technology approach for estimating compliance costs at cooling water intakes. EPA believes that this methodology is more Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 103 appropriate than a least cost approach. 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 of 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 these site specific considerations into account. EPA does not have any reason to believe that the best performing technology approach is inappropriate 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 104 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, 14 weeks, and 11 weeks, 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, are not included in the cost test tool. Costs for these activities 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). Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 105 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. 15 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.

Exhibit IX 4   Annualized Social Cost1 ( in millions, $ 2004)

50 MGD All Waterbodies 200 MGD All 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 the each range is the cost discounted at 3%, and the right side of each range presents the cost with a 7% discount rate.

15 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. The time profile of the recognition of benefits is longer than that of costs due to lag effects in the population dynamics of species impacted by the cooling water intake structure. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 106 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 incurrence of these costs would affect 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 107 impacts analysis). See EA for 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 as Closures 0.0% 0.0% 0.0%

Facilities Assessed as Moderate Impacts 0 0 0 Percentage of Facilities with Regulatory Requirements with Moderate Impacts 0.0% 0.0% 0.0%

Annualized Compliance Costs ( after tax, million $ 2004) $ 26.8 $ 11.8 $ 12.1 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 108 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.

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 it 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. 16 Using standard fishery modeling techniques, EPA combined facility derived impingement and entrainment counts with 16 " 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 109 relevant life history data to derive estimates of ( 1) age one equivalent losses ( the number of individuals of different ages impinged and entrained expressed as an equivalent number of age one fish), and ( 2) foregone fishery yield ( pounds of commercial harvest and numbers of recreational fish and shellfish not harvested due to impingement and entrainment). Of the organisms that were anticipated to be protected by the national categorical analysis option, approximately 2 to 3 percent would have been eventually harvested by commercial and recreational fishers and therefore can be valued with direct use valuation techniques.

To obtain a national estimate of losses at all potentially regulated facilities, EPA extrapolated impingement and 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 Entrainmenta Baseline Losses and Estimated Reductions under the National Categorical Regulatory Options Age 1 Equivalent Fish Foregone Fishery Yield ( 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 110 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 nonharvested fish that are prey for harvested fish. The second category includes benefits that are independent of any current or anticipated use of the resource; these are known as " non use" or " passive use" values. Non use values include " nonmarketed" goods and services, which reflect human values associated with existence, bequest, and altruistic motives.

EPA estimated the economic benefits from the national categorical regulatory options using a range of valuation methods, depending on the benefit category, data availability, and other suitable factors. EPA calculated benefits 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 111 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 benefit 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, since the reduction in forgone yield has an insignificant impact on prices.

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). Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 112 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 Option Annualized Commercial Fishing Benefits Annualized Recreational Fishing Benefits Total Annualized Value of Monetizable Impingement and Entrainment Reductionsb 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 113 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 it would require projecting where these facilities would be built and/ or operate; thus there are no benefits estimates for new offshore oil and gas extraction facilities. Hence it is not possible to compare the costs and benefits associated with this action.

This section presents comparisons of the benefits and costs of the primary analysis options by study region. The benefit cost analysis for the primary analysis 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 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. These cost categories are consistent with those typically considered in technology based rulemakings. The benefits estimates include monetized benefits to commercial and recreational fishing. The total monetizable benefits include only use benefits. The nonuse benefits were evaluated qualitatively. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 114 Exhibit XI 1 summarizes total annualized use benefits, total annualized costs, and net benefits for the primary analysis options.

Exhibit XI 1   Summary of Social Benefits and Costs for the Primary Analysis Options ( Millions; $ 2004)

Option Number of Facilities Subject to Option Number of Facilities Installing Technology Total Annualized Use Value of I& E Reductionsa Total Annualized Costsb Net Benefits 50 MGD All Waterbodies 146 111 $ 1.80  $ 2.25 $ 38.27  $ 39.00 $ 36.5  $ 36.7 200 MGD All Waterbodies 31 27 $ 1.19  $ 1.5 $ 19.48  $ 20.14 $ 18.3  $ 18.6 100 MGD Coastal / Great Lakes 23 22 $ 1.49  $ 1.87 $ 14.57  $ 14.11 $ 13.1  $ 12.2 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. National total costs also include State, local, and Federal administrative costs of $ 0.6 million that cannot be attributed to individual study regions. The low and high cost values reflect the range of cost values presented in Section IX of the preamble. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 115 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 Federal Register 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" because the rule raises novel policy issues arising Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 116 out of the President's priorities. As such, this action was submitted to OMB for review.

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 20XXXXXX

The information collected under this final rule would 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 would be used by these facilities as appropriate to prepare permit applications, comprehensive demonstration studies, monitor impingement mortality and entrainment, verify compliance, and prepare annual reports as required under this rule. The information collected would be reviewed by EPA to ensure that appropriate National Pollutant Discharge Elimination System ( NPDES) permit conditions regulating cooling water intake structures would be developed. Compliance with the applicable information collection requirements imposed under this final rule is mandatory ( see '' 122.21( r),

125.136, 125.137, 125.138).

EPA does not consider the specific data that would 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 117 treated as confidential. All confidential data submitted to EPA will be handled in accordance with 40 CFR 122.7, 40 CFR Part 2, and EPA= s Security Manual Part III,

Chapter 9, dated August 9, 1976.

This final rule modifies regulations at ' 122.21 to require new offshore oil and gas extraction facilities to prepare and submit information consistent with that required for Phase I facilities ( the requirements vary based on whether the facility 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. Hence, the annual average reporting and recordkeeping burden for the collection of information by facilities responding to 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 average annual cost 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) is $ 0.58 million for 31 new offshore oil and gas facilities during the first three years after promulgation of the rule. Non labor costs include activities such as capital costs for remote monitoring devices, laboratory services, photocopying, and the Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 118 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 collect the general information listed below.

  Source Water Physical Data (' 122.21( r)( 2)) (' 122.21( r)( 2)( iv) only for nonfixed new offshore oil and gas extraction facilities)

  Cooling Water Intake Structure Data (' 122.21( r)( 3)) (' 122.21( r)( 3)( ii) not applicable to non fixed new offshore oil and gas extraction facilities)

New offshore oil and gas extraction facilities would be required to submit the following information under Track I:

  Source Water Baseline Biological Characterization Data (' 122.21( r)( 4)) ( not required for non fixed facilities)

  Velocity Information (' 125.136( b)( 1))

  Source Waterbody Flow Information (' 125.136( b)( 2)) ( not required for nonfixed facilities)

  Design and Construction Technology Plan (' 125.136( b)( 3)) Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 119 Under Track II, new offshore oil and gas extraction facilities would be required to submit the following information:

  Source Waterbody Flow Information (' 125.136( c)( 1))

  Comprehensive Demonstration Study (' 125.136( c)( 2))

o Source Water Biological Study (' 125.136( c)( 2)( iii)( A))

o Evaluation of Potential Cooling Water Intake Structure Effects ('

125.136( c)( 2)( iii)( B))

o Verification Monitoring Plan (' 125.136( c)( 2)( iii)( C))

In addition to the information requirements of the permit renewal application,

NPDES permits normally specify monitoring and reporting requirements to be met by the permitted entity. New offshore oil and gas extraction fixed facilities would be required to perform monitoring as determined by the Track I or Track II requirements in ' 125.136 and in accordance with ' 125.137. Additional ambient water quality monitoring may also be required of facilities depending on the specifications of their permits ( e. g., as part of velocity monitoring at ' 125.137( b)). New offshore oil and gas extraction facilities would be expected to analyze the results from their monitoring efforts and are required to provide these results in an annual status report to the permitting authority. Finally,

facilities would be required to maintain records of all submitted documents, supporting materials, and monitoring results for at least three years.

All impacted facilities would carry out the specific activities necessary to fulfill the general information collection requirements. The estimated burden includes developing a water balance diagram that can be used to identify the proportion of intake water used for cooling, make up, and process water. Facilities would also gather data to Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 120 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 121 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

forprofit enterprise which is independently owned and operated and is not dominant in its field.

The SBA small business size standards changed from a SIC 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 122 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 123 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 124 D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 ( UMRA), P. 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 125 From its analysis for the final regulation, EPA estimates the total annualized aftertax 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 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 126 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 is 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 127 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 128 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. Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 129 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 130 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. E. O. 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 131 its mission. E. O. 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 132 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. E. O. 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 Interagency Review Draft 05/ 05/ 06 Deliberative: do not cite, quote or distribute 133 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 [ INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 1 For the reasons set forth in the preamble, chapter I of title 40 of the Code of Federal Regulations is to be amended as follows:

PART 9  OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT 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.

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

§ 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 * * * * * * * EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 2 122.21( r) ..................................................................................................... 2040 0241, 2040 0257, xxxx xxxx * * * * * * *

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

125.134                         .       .

125.135                         .       .

125.136                                ..

125.137                                ..

125.138                                ..

125.139                                .. XXXXXXXX XXXXXXXX XXXXXXXX XXXXXXXX XXXXXXXX XXXXXXXX * * * * * * * EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 3 PART 122  EPA ADMINISTERED PERMIT PROGRAMS: THE NATIONAL POLLUTANT DISCHARGE ELIMINATION SYSTEM 1. The authority citation for part 122 continues to read as follows:

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

2. Section 122.21 is amended as follows:

a. Revising paragraph ( r)( 1)( i).

b. Adding a new paragraph ( r)( 2)( iv).

c. Revising paragraph ( r)( 4) introductory text.

§ 122.21 Application for a permit ( applicable to State programs, see § 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 § 125.86 of this chapter as part of their application. New offshore oil and gas extraction facilities with cooling water intake structures as defined in part 125, subpart N, of this chapter that are fixed facilities must submit to the Director for review the information required under paragraphs ( r)( 2) ( except ( r)( 2)( iv)), ( 3), and ( 4) of this section and § 125.136 of this chapter as part of their application. New offshore oil and gas extraction facilities that are not fixed facilities must submit to the Director for review only the information required under paragraphs ( r)( 2)( iv), ( r)( 3) ( except ( r)( 3)( ii)),

and § 125.136 of this chapter as part of their application. Requests for alternative EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 4 requirements under § 125.85 or § 125.135 of this chapter must be submitted with your permit application.

* * * * *

( 2) * * *

( iv) For new offshore oil and gas facilities that are not fixed facilities, a narrative description and/ or locational maps providing information on predicted locations within the waterbody during the permit term in sufficient detail for the Director to determine the appropriateness of additional impingement requirements under §

125.134( b)( 4).

* * * * *

( 4) Source water baseline biological characterization data. This information is required to characterize the biological community in the vicinity of the cooling water intake structure and to characterize the operation of the cooling water intake structures.

The Director may also use this information in subsequent permit renewal proceedings to determine if your Design and Construction Technology Plan as required in § 125.86( b)( 4)

or § 125.136( b)( 3) of this chapter should be revised. This supporting information must include existing data ( if they are available). However, you may supplement the data using newly conducted field studies if you choose to do so. The information you submit must include:

* * * * * EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 5 3. Section 122.44 is amended by revising paragraph ( b)( 3) to read as follows:

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

* * * * *

( b) * * *

( 3) Requirements applicable to cooling water intake structures under section 316( b)

of the CWA, in accordance with part 125, subparts I, J, and N of this chapter.

* * * * *

PART 123  STATE PROGRAM REQUIREMENTS 1. The authority citation for part 123 continues to read as follows:

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

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

§ 123.25 Requirements for permitting.

( a) * * *

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

* * * * *

PART 124  PROCEDURES FOR DECISIONMAKING 1. The authority citation for part 124 continues to read as follows:

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

Clean Air Act, 42 U. S. C. 7401 et seq. EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 6 2. Section 124.10 is amended by revising paragraph ( d)( 1)( ix) to read as follows:

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

* * * * *

( d) * * *

( 1) * * *

( ix) Requirements applicable to cooling water intake structures under section 316( b)

of the CWA, in accordance with part 125, subparts I , J, and N of this chapter.

* * * * *

PART 125  CRITERIA AND STANDARDS FOR THE NATIONAL POLLUTANT DISCHARGE ELIMINATION SYSTEM 1. The authority citation for part 125 continues to read as follows:

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

2. Add subpart N to part 125 to read as follows:

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

125.130 What are the purpose and scope of this subpart?

125.131 Who is subject to this subpart?

125.132 When must I comply with this subpart?

125.133 What special definitions apply to this subpart?

125.134 As an owner or operator of a new offshore oil and gas extraction facility,

what must I do to comply with this subpart?

125.135 May alternative requirements be authorized? EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 7 125.136 As an owner or operator of a new offshore oil and gas extraction facility,

what must I collect and submit when I apply for my new or reissued NPDES permit?

125.137 As an owner or operator of a new offshore oil and gas extraction facility,

must I perform monitoring?

125.138 As an owner or operator of a new offshore oil and gas extraction facility,

must I keep records and report?

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

Subpart N  Requirements Applicable to Cooling Water Intake Structures for New Offshore Oil and Gas Extraction Facilities Under Section 316( b) of the Act § 125.130 What are the purpose and scope of this subpart?

( a) This subpart establishes requirements that apply to the location, design,

construction, and capacity of cooling water intake structures at new offshore oil and gas extraction facilities. The purpose of these requirements is to establish the best technology available for minimizing adverse environmental impact associated with the use of cooling water intake structures at these facilities. These requirements are implemented through National Pollutant Discharge Elimination System ( NPDES) permits issued under section 402 of the Clean Water Act ( CWA).

( b) This subpart implements section 316( b) of the CWA for new offshore oil and gas extraction facilities. Section 316( b) of the CWA provides that any standard established pursuant to sections 301 or 306 of the CWA and applicable to a point source shall require that the location, design, construction, and capacity of cooling water intake EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 8 structures reflect the best technology available for minimizing adverse environmental impact.

( c) New offshore oil and gas extraction facilities that do not meet the threshold requirements regarding amount of water withdrawn or percentage of water withdrawn for cooling water purposes in § 125.131( a) must meet requirements determined by the Director on a case by case, best professional judgement ( BPJ) basis.

( d) Nothing in this subpart shall be construed to preclude or deny the right of any State or political subdivision of a State or any interstate agency under section 510 of the CWA to adopt or enforce any requirement with respect to control or abatement of pollution that is more stringent than those required by Federal law.

§ 125.131 Who is subject to this subpart?

( a) This subpart applies to a new offshore oil and gas extraction facility if it meets all of the following criteria:

( 1) It is a point source that uses or proposes to use a cooling water intake structure;

( 2) It has at least one cooling water intake structure that uses at least 25 percent of the water it withdraws for cooling purposes as specified in paragraph ( c) of this section; and ( 3) It has a design intake flow greater than two ( 2) million gallons per day ( MGD).

( b) Use of a cooling water intake structure includes obtaining cooling water by any sort of contract or arrangement with an independent supplier ( or multiple suppliers)

of cooling water if the supplier or suppliers withdraw( s) water from waters of the United EPA Interagency Review Draft  05/ 11/ 2006 Deliberative: do not cite, quote or distribute 9 States. Use of cooling water does not include obtaining cooling water from a public water system or the use of treated effluent that otherwise would be discharged to a water of the U. S. This provision is intended to prevent circumvention of these requirements by creating arrangements to receive cooling water from an entity that is not itself a point source.

( c) The threshold requirement that at least 25 percent of water withdrawn be used for cooling purposes must be measured on an average monthly basis. A new offshore oil and gas extraction facility meets the 25 percent cooling water threshold if,

based on the new facility's design, any monthly average over a year for the percentage of cooling water withdrawn is expected to equal or exceed 25 percent of the total water withdrawn.

( d) Neither this subpart nor Subpart I applies to seafood processing vessels and offshore liquefied natural gas import terminals that are new facilities as defined in 40 CFR 125.83. Seafood processing vessels and offshore liquefied natural gas import terminals must meet requirements established by the Director on a case by case, best professional judgment ( BPJ) basis.

§ 125.132 When must I comply with this subpart?