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March 19, 2003 Part IV Environmental Protection Agency 40 CFR Part 125 National Pollutant Discharge Elimination System   Proposed Regulations To Establish Requirements for Cooling Water Intake Structures at Phase II Existing Facilities; Notice of Data Availability; Proposed Rule VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13522 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 125 [ FRL   7468   6]

RIN 2040   AD62 National Pollutant Discharge Elimination System   Proposed Regulations To Establish Requirements for Cooling Water Intake Structures at Phase II Existing Facilities; Notice of Data Availability AGENCY: Environmental Protection Agency ( EPA). ACTION: Proposed rule; Notice of data availability.

SUMMARY: On April 9, 2002, EPA published proposed standards for cooling water intake structures at Phase II existing facilities as part of implementing section 316( b) of the Clean Water Act ( CWA). This notice presents a summary of significant data EPA received or collected since proposal, a discussion of how EPA is considering using these data in revised analyses supporting the rule, a discussion of some refinements that EPA is considering for the proposed regulatory requirements, and additional information regarding data quality. This notice also provides new information on a broader suite of technology options that may be appropriate for compliance at specific sites. EPA solicits public comment on the information presented in this notice and the record supporting this notice. DATES: Comments on this notice of data availability and all aspects of the April 9, 2002, proposal must be received or postmarked on or before midnight June 2, 2003. ADDRESSES: Comments may be submitted electronically, by mail, or through hand delivery/ courier. Mail comments to the Water Docket, Environmental Protection Agency, Mailcode: 4101T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention Docket ID No. OW   2002   0049. Follow the detailed instructions as provided in Section I. B. of the SUPPLEMENTARY INFORMATION section for additional ways to submit comments. FOR FURTHER INFORMATION CONTACT: For additional technical information contact Debra D. Hart at ( 202) 566   6379. For additional economic information contact Lynne Tudor, Ph. D. at ( 202) 566   1043. For additional biological information contact Dana A. Thomas, Ph. D. at ( 202) 566   1046. The e mail address for the above contacts is rule. 316b@ epa. gov. SUPPLEMENTARY INFORMATION:

Contents I. General Information A. How Can I Get Copies Of This Document and Other Related Information? B. How and To Whom Do I Submit Comments? C. How Should I Submit CBI To the Agency? II. Purpose of this Notice III. Major Changes to Assumptions Used in EPA's Analyses IV. Engineering Cost Analysis A. Facility Flow Verifications B. Technology Cost Modules C. Facility Level Costing Options D. Clarifications and Corrections V. IPM Analyses A. Changes to the IPM Analyses Since Proposal B. Revised Results for the Preferred Option C. Revised Results for the Waterbody/ Capacity based Option VI. Other Economic Analyses A. National Costs B. Cost to Revenue Measure C. Cost Per Household D. Electricity Price Analysis VII. Performance Standards A. Technology Efficacy Database to Support Performance Standards B. Streamlined Technology Option For Certain Locations VIII. Cost Tests IX. Biology   Supporting Information A. Entrainment Survival B. Restoration C. Request for Impingement and Entrainment Data X. National Benefits A. Case Study Clarifications and Corrections B. Regional Approach To Developing Benefits Estimates C. North Atlantic Regional Study D. Northern California Regional Study E. Nonuse Benefits F. Regional Level Benefit Cost Analysis G. Break Even Analysis XI. Implementation and Other Regulatory Refinements A. Definition and Methods for Determining the `` Calculation Baseline'' B. Options for Evaluating Compliance with Performance Standards C. Compliance Timelines, Schedules, and Determination D. Determining Capacity Utilization Rates E. Clarifications and Corrections XII. General Solicitation of Comments I. General Information A. How Can I Get Copies of This Document and Other Related Information?

1. Docket. EPA has established an official public docket for this action under Docket ID No. OW   2002   0049. The official public docket consists of the documents specifically referenced in this action, any public comments received, and other information related to this action. The official public docket is the collection of materials that is available for public viewing at the Water Docket in the EPA Docket Center, ( EPA/ DC) EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC. The EPA Docket Center Public Reading Room is open from 8: 30 a. m. to 4: 30 p. m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is ( 202) 566   1744, and the telephone number for the Water Docket is ( 202) 566   2426. 2. Electronic Access. You may access this Federal Register document electronically through the EPA Internet under the `` Federal Register'' listings at http:// www. epa. gov/ fedrgstr/. An electronic version of the public docket is available through EPA's electronic public docket and comment system, EPA Dockets. You may use EPA Dockets at http:// www. epa. gov/ edocket/ to submit or view public comments, access the index listing of the contents of the official public docket, and to access those documents in the public docket that are available electronically. Once in the system, select `` search,'' then key in the appropriate docket identification number. Certain types of information will not be placed in EPA Dockets. Information claimed as confidential business information ( CBI) and other information whose disclosure is restricted by statute, which is not included in the official public docket, will not be available for public viewing in EPA's electronic public docket. EPA's policy is that copyrighted material will not be placed in EPA's electronic public docket but will be available only in printed, paper form in the official public docket. To the extent feasible, publicly available docket materials will be made available in EPA's electronic public docket. When a document is selected from the index list in EPA Dockets, the system will identify whether the document is available for viewing in EPA's electronic public docket. Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials through the docket facility identified in Unit I. A1. EPA intends to work towards providing electronic access to all of the publicly available docket materials through EPA's electronic public docket. For public commenters, it is important to note that EPA's policy is that public comments, whether submitted electronically or on paper, will be made available for public viewing in EPA's electronic public docket as EPA receives them and VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13523 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules without change, unless the comment contains copyrighted material, CBI, or other information whose disclosure is restricted by statute. When EPA identifies a comment containing copyrighted material, EPA will provide a reference to that material in the version of the comment that is placed in EPA's electronic public docket. The entire printed comment, including the copyrighted material, will be available in the public docket. Public comments submitted on computer disks that are mailed or delivered to the docket will be transferred to EPA's electronic public docket. Public comments that are mailed or delivered to the Docket will be scanned and placed in EPA's electronic public docket. Where practical, physical objects will be photographed, and the photograph will be placed in EPA's electronic public docket along with a brief description written by the docket staff.

B. How and to Whom Do I Submit Comments? You may submit comments electronically, by mail, or through hand delivery/ courier. Please submit with your comments any references cited in your comments. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your comment. Please ensure that your comments are submitted within the specified comment period. Comments received after the close of the comment period will be marked `` late.'' EPA is not required to consider these late comments, however, late comments may be considered if time permits. If you wish to submit CBI or information that is otherwise protected by statute, please follow the instructions in Unit I. C. Do not use EPA Dockets or e mail to submit CBI or information protected by statute. 1. Electronically. If you submit an electronic comment as prescribed below, EPA recommends that you include your name, mailing address, and an e mail address or other contact information in the body of your comment. Also include this contact information on the outside of any disk or CD ROM you submit, and in any cover letter accompanying the disk or CD ROM. This ensures that you can be identified as the submitter of the comment and allows EPA to contact you in case EPA cannot read your comment due to technical difficulties or needs further information on the substance of your comment. EPA's policy is that EPA will not edit your comment, and any identifying or contact information provided in the body of a comment will be included as part of the comment that is placed in the official public docket, and made available in EPA's electronic public docket. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. i. EPA Dockets. Your use of EPA's electronic public docket to submit comments to EPA electronically is EPA's preferred method for receiving comments. Go directly to EPA Dockets at http:// www. epa. gov/ edocket, and follow the online instructions for submitting comments. To access EPA's electronic public docket from the EPA Internet Home Page, select `` Information Sources,'' `` Dockets,'' and `` EPA Dockets.'' Once in the system, select `` search,'' and then key in Docket ID No. OW   2002   0049. The system is an `` anonymous access'' system, which means EPA will not know your identity, e mail address, or other contact information unless you provide it in the body of your comment. ii. E mail. Comments may be sent by electronic mail ( e mail) to OWDocket epa. gov, Attention Docket ID No. OW   2002   0049. In contrast to EPA's electronic public docket, EPA's email system is not an `` anonymous access'' system. If you send an e mail comment directly to the Docket without going through EPA's electronic public docket, EPA's e mail system automatically captures your e mail address. E mail addresses that are automatically captured by EPA's e mail system are included as part of the comment that is placed in the official public docket, and made available in EPA's electronic public docket. iii. Disk or CD ROM. You may submit comments on a disk or CD ROM that you mail to the mailing address identified in Unit I. B. 2. These electronic submissions will be accepted in WordPerfect or ASCII file format. Avoid the use of special characters and any form of encryption. 2. By Mail. Send an original and three copies of your comments to the Water Docket, Environmental Protection Agency, Mailcode: 4101T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention Docket ID No. OW   2002   0049. 3. By Hand Delivery or Courier. Deliver copies of your comments to: Water Docket, EPA Docket Center, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC, Attention Docket ID No. OW   2002   0049. Such deliveries are only accepted during the Docket's normal hours of operation as identified in Unit I. A. 1. C. How Should I Submit CBI to the Agency?

Do not submit information that you consider to be CBI electronically through EPA's electronic public docket or by e mail. Send information claimed as CBI by mail only to the following address, Office of Science and Technology, Mailcode 4303T, U. S. Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention: Debbi Hart/ Docket ID No. OW   2002   0049. You may claim information that you submit to EPA as CBI by marking any part or all of that information as CBI ( if you submit CBI on disk or CD ROM, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is CBI). Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR Part 2. In addition to one complete version of the comment that includes any information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket and EPA's electronic public docket. If you submit the copy that does not contain CBI on disk or CD ROM, mark the outside of the disk or CD ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and EPA's electronic public docket without prior notice. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section.

II. Purpose of This Notice On April 9, 2002, EPA published proposed standards for cooling water intake structures at Phase II existing facilities ( 67 FR 17122). EPA received voluminous comments and data submissions during the 120 day public comment period on the proposal. However, many commenters, including both industry and environmental groups, requested additional time to review the proposal and the supporting record and to prepare further comments. Therefore, EPA is reopening the comment period on all aspects of the April 9, 2002, proposal. In addition, following publication of the proposal, EPA collected more data and revised several methodologies related to costing and benefits estimations. This notice makes these new data available for comment and discusses the relevance of these data to the analyses conducted by EPA. Thus, EPA also solicits public comment on the information presented VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13524 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 1 Note that these numbers are unweighted. On a sample weighted basis, the number of Phase II facilities increased from 550 to 551. 2 Based on additional research between the proposal and the NODA, some facilities also experienced a change in their projected compliance response. This change, together with the increase in in scope Phase II facilities, may have contributed to the change in total compliance costs. See section IV of the NODA preamble for more information. in this notice and the record supporting this notice. EPA notes that all options and issues discussed in its proposal are still under consideration for the final rule. This notice merely makes new information available for public review that the Agency will consider in making decisions for the final rule.

Summary of Proposed Rule for Existing Facilities The proposed rule would implement section 316( b) of the Clean Water Act ( CWA) for certain existing power producing facilities that employ a cooling water intake structure and that withdraw 50 million gallons per day ( MGD) or more of water from rivers, streams, lakes, reservoirs, estuaries, oceans, or other waters of the U. S. for cooling purposes. The proposed rule constitutes Phase II in EPA's development of section 316( b) regulations and would establish national requirements applicable to the location, design, construction, and capacity of cooling water intake structures at these facilities. The proposed national requirements, which would be implemented through National Pollutant Discharge Elimination System ( NPDES) permits, would minimize the adverse environmental impact associated with the use of these structures. The proposed rule would establish location, design, construction, and capacity requirements that reflect the best technology available for minimizing adverse environmental impact from the cooling water intake structure based on waterbody type and the amount of water withdrawn by a facility. The Environmental Protection Agency ( EPA) proposed to group surface water into five categories   freshwater rivers and streams, lakes and reservoirs, Great Lakes, estuaries and tidal rivers, and oceans   and establish requirements for cooling water intake structures located in distinct waterbody types. In general, the more sensitive or biologically productive the waterbody type, the more stringent the requirements proposed as reflecting the best technology available for minimizing adverse environmental impact. Proposed requirements also vary according to the percentage of the source waterbody withdrawn and facility utilization rate. A facility may choose one of three options for meeting best technology available requirements under the proposed rule. These options are ( 1) demonstrating that the facility's existing design and construction technology, operational measures, and/ or restoration currently meets specified performance standards; ( 2) selecting and implementing design and construction technologies, operational measures, or restoration measures that meet specified performance standards; or ( 3) demonstrating that the facility qualifies for a site specific determination of best technology available because its costs of compliance are significantly greater than either ( 1) the costs considered by the Agency during the development of the rule, or ( 2) a site specific determination of the benefits of compliance with the proposed performance standards. The proposed rule also provides that facilities may use restoration measures in addition to or in lieu of other technology measures to meet the performance standards established in the rule or on a sitespecific basis. EPA expects that the proposed regulation would minimize adverse environmental impact, including substantially reducing the harmful effects of impingement ( organisms trapped against intake screens or other barriers at the entrance of cooling water intake structures) and entrainment ( organisms drawn into a cooling water intake structure), at existing facilities over the next 20 years. As a result, the Agency anticipates that the proposed rule would help protect ecosystems in proximity to cooling water intake structures. The proposal would help preserve aquatic organisms, including threatened and endangered species, and the ecosystems they inhabit in waters used for cooling purposes by existing power producing facilities. EPA considered the potential benefits of the proposed rule and discussed these benefits in both quantitative and nonquantitative terms. Benefits, among other factors, are based on a decrease in expected mortality or injury to aquatic organisms that would otherwise be subject to entrainment into cooling water systems or impingement against screens or other devices at the entrance of cooling water intake structures. Benefits may also accrue at multiple ecological scales including population, community, or ecosystem levels. In addition to the proposed regulatory requirements, EPA also invited comments on a number of other regulatory alternatives. The Agency will continue to consider all of these regulatory alternatives when making decisions on a final rule.

III. Major Changes to Assumptions Used in EPA's Analyses Based on comments received, additional information made available, and the results of subsequent analyses, EPA is considering a number of revisions to the assumptions that were used in developing the engineering costs, the information collection costs, the economic analyses, and the benefits analyses. These new assumptions are presented below and were used in the current analyses, the results of which are presented in this Notice of Data Availability ( NODA). EPA requests comment on each of these revised assumptions.

1. Number of Phase II Facilities Since proposal, EPA verified design flow information for facilities that had been classified as either Phase II or Phase III facilities. This verification resulted in the following changes: five facilities that were classified as Phase II facilities at proposal have been reclassified as Phase III facilities. Conversely, six facilities that were classified as Phase III facilities at proposal have been reclassified as Phase II facilities. As a result, the overall number of Phase II facilities increased from 539 to 540 facilities. 1 For the NODA, all cost and economic analyses are based on the updated set of Phase II facilities.

2. Technology Costs EPA used new information to revise the capital and operation and maintenance ( O& M) costs for several compliance technologies, including those used as the primary basis for the proposed regulatory option. Overall, the cost updates resulted in the following changes. For the preferred option ( discussed above at Section II), total capital costs increased by 66 percent and total O& M costs increased by 48 percent. For the waterbody/ capacitybased option, which would set performance standards for impingement mortality and entrainment reduction based on closed cycle, recirculating cooling for some facilities and technologies such as fine mesh screens and fish return systems for others, total capital costs increased by 40 percent ( net of existing condenser cost savings), while total O& M costs decreased by 13 percent. These comparisons are based on the raw costs, adjusted to year 2002 dollars, which have not been discounted or annualized. 2 VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13525 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules The revised costing assumptions are discussed in detail below. EPA notes that the proposed rule includes a compliance option that allows sitespecific flexibility in cases where compliance costs for a particular facility significantly exceed those estimated in the analysis for the final rule. EPA is currently considering whether the final rule should provide additional guidance on how to conduct this comparison, including how best to use the costing information in the rule record. EPA requests comment on its costing methodology; its relationship to the proposed site specific, cost cost comparison provisions; and what additional guidance, if any, EPA should provide on implementation of these provisions.

3. Permitting and Monitoring Costs At proposal, the single most costly permitting activity was the `` Impingement Mortality and Entrainment Characterization Study,'' a required element of the `` Comprehensive Demonstration Study.'' See proposed § 125.95( b). The proposed rule did not require facilities with cooling towers to conduct these studies but, inadvertently, EPA included costs for the Impingement Mortality and Entrainment Characterization Study in its cost estimates for facilities projected to have cooling towers in the base case ( i. e., those projected to have cooling towers in the absence of the rule). EPA also applied costs for this study to facilities that EPA projected to install cooling towers under certain regulatory options. For the NODA analysis, EPA did not include the cost of the Impingement Mortality and Entrainment Characterization Study for facilities projected to have cooling towers in the base case or the waterbody/ capacitybased option.

4. Net Installation Downtime for Compliance Technologies Other Than Recirculating Cooling Towers In the analysis for the proposed rule, EPA made the assumption that compliance technologies other than recirculating cooling towers would not require facility downtime for installation. EPA has since revised this assumption. EPA expects additional unscheduled downtimes of between two and eight weeks for the installation of the various non recirculating compliance technologies.

5. Net Installation Downtime and Other Site Specific Factors for Recirculating Cooling Towers To support the proposed Phase II rule, EPA assumed that each projected cooling system conversion would require a net downtime of four weeks. This estimate was based on information that had been previously available to EPA on the downtime needed for fossilfuel and nuclear power plants. Just prior to proposal, EPA received additional technical information on the amount of operational downtime needed during cooling system conversions from once through to closed cycle, recirculating with cooling towers at nuclear power plants ( see DCN 4   2529). For the new analyses, EPA is incorporating the new information which suggests that cooling system conversions at nuclear power plants may take seven months. To the extent that conversions at nuclear power plants take less time to complete, costs for this factor would be lower. For non nuclear power plants, EPA's cost estimates at proposal assumed four weeks downtime for the retrofit of wet cooling towers at existing power plants. The Agency requests comment on whether more or less downtime may be required at some plants due to sitespecific factors and, if so, whether EPA should use a different estimate of downtime in analyzing the costs of this regulatory option.

6. Energy Penalties For the proposed Phase II rule, the average annual energy penalty, by region and fuel type, was applied to each facility upgrading to a closedcycle recirculating cooling system. Based on comments received, EPA has changed the energy penalty assumption to attempt to account for seasonal, peak effects. For the new analyses, the energy penalty applied is the greater of the peak summer penalty or the average annual penalty for each facility projected to convert their cooling systems to a closed cycle, recirculating cooling system. EPA notes that the approach used at proposal might have understated potential impacts of the energy penalty on generating capacity. Conversely, using the greater of the peak summer penalty and the average annual penalty might overestimate potential impacts of the energy penalty on generating capacity. EPA has adopted the latter approach in order to ensure that impacts are not underestimated.

7. Capacity Utilization Rates For the proposed Phase II rule, the 15 percent capacity utilization determination was based on the generation and capacity of the entire facility, including steam electric and non steam generators. EPA believes that utilization of the steam electric part of a facility better reflects a facility's potential for adverse environmental impact because only the steam electric generators use cooling water. As discussed at Section XI below, EPA is considering refining its regulatory definition for `` capacity utilization rate'' at the proposed § 125.93 to reflect use of the steam electric part of a facility. For the NODA, EPA is using the capacity utilization of only the steam electric generators at Phase II facilities so that its updated economic analyses include this potential refinement. In addition, at proposal, EPA used the average capacity utilization based on EIA data for 1995 to 1999. This utilization rate was often different from the rate based on the `` IPM base case results'' EPA used to support its estimates of the economic impacts of the rule ( see section V for additional description of EPA's economic analysis methodology. For the NODA analyses, EPA used projected capacity utilization rates for 2008 ( the first model run year in EPA's economic analysis), in order to ensure internal consistency in the analysis. For many facilities, this resulted in a lower capacity utilization rate in the baseline. As a result, the compliance requirements and compliance costs for these facilities may be lower, depending on the waterbody type from which they withdraw and the impingement mortality and entrainment technologies they already have in place in the baseline. Facilities with lower projected compliance costs than under the previous assumption may also have lower projected impacts in the analysis, depending on the magnitude of the cost differential and the facilities' operating characteristics in the baseline ( e. g., a change in cost for marginal units would have a greater effect than for units that generate electricity well below the cost of the marginal unit). EPA requests comment on this change in assumptions.

8. Compliance Schedule At the time of proposal, promulgation of the final section 316( b) Phase II rule was scheduled for August 28, 2003. As a result, EPA assumed that facilities would come into compliance with the preferred option between 2004 and 2008 as their existing NPDES permits expired and were reviewed. For regulatory options based on the reductions in impingement and entrainment achievable using a closed cycle recirculating system, EPA further assumed that facilities costed with a cooling tower would come into compliance between 2005 and 2012. Since proposal, the section 316( b) regulatory development schedule has changed. Promulgation of the final rule is now scheduled for February 16, 2004,

VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13526 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules making it impossible for facilities to come into compliance in 2004 ( the assumption in all economic analyses is that facilities comply in the beginning of the year in which they receive requirements in their permit). As a result, EPA shifted the compliance schedule for the NODA analysis by one year for all Phase II facilities. Facilities costed with a cooling tower are now assumed to have a compliance window from 2005 to 2013, while facilities without a recirculating requirement are assumed to come into compliance between 2005 and 2009 ( during the year of their first post promulgation permit). For purposes of the cost and impacts analysis, EPA used the 2010 model run year instead of the 2008 model run year, as at proposal. Under the preferred option, all facilities are projected to come into compliance by 2009.

9. Number of Facilities Projected To Upgrade to Recirculating Wet Cooling ( Waterbody/ Capacity Based Option) For the proposed Phase II rule, EPA estimated that 51 model facilities would upgrade their cooling systems from once through to closed cycle, recirculating cooling systems under the waterbody/ capacity based option. EPA estimates for these analyses that 44 model facilities would upgrade cooling systems for the same option. The requirements of the regulatory alternative have not changed. The change in number of facilities that would be required to upgrade their cooling system is due to: ( 1) EPA's effort to update, correct, and verify facility design intake flows and ( 2) the fact that EPA no longer needs to use a statistical methodology to determine the number of short technical questionnaire facilities that withdraw more than one percent of the mean tidal excursion. EPA has updated design intake flows for a number of in scope facilities. In a few cases, these database flow changes have impacted the determination of whether a facility is projected to upgrade its cooling system because the requirements for the waterbody/ capacity based option, in some instances, hinge on intake flow. Since proposal, EPA has identified those short technical questionnaire facilities whose design intake flow exceeds one percent of the mean tidal excursion. This information was not available for the analyses supporting the proposal, and as such, EPA utilized a statistical method to project which facilities would meet these criteria. For these current analyses, EPA has utilized the actual data in lieu of the statistical method. As a result, a number of changes have been made to the list of short technical questionnaire model facilities projected to upgrade their cooling systems.

IV. Engineering Cost Analysis A. Facility Flow Verifications In order to ensure the accuracy and quality of the data used for the costing effort, the Agency revisited its database of facility and intake design flows. Flow is an important factor in calculating costs. The Agency first screened the flow data in order to identify facilities with potentially inaccurate flow information. From this first set of facilities, the Agency attempted to identify errors by inspecting the original questionnaires on which the flows were reported. Through this effort, the Agency was able to correct a few flow values by identifying survey reporting errors ( such as unit conversion inconsistencies). The remainder of the potentially inaccurate flow data set required outreach to 25 facilities to solve the identified discrepancies. In many cases, the original reported flows were correct. In others, incorrect initial reporting had led to incorrect calculations of design flow rates. The Agency corrected these flows for the master database used to support analyses presented in this Notice of Data Availability ( see `` Flow Correction and Verification,'' in the Confidential Business Information portion of the docket).

B. Technology Cost Modules The Agency developed a new approach to developing compliance costs that includes a broader range of compliance technologies than it used for calculating compliance costs for the proposed rule requirements. In order to do so, the Agency sought to evaluate new and/ or additional costs for a wider range of intake technologies identified as having the potential to meet the proposed regulation requirements without the expense and energy penalty associated with capacity reduction technologies such as cooling towers. In selecting among available technologies, EPA revised its traditional least cost approach, and instead assigned costs based on the projected performance of available technologies on a site specific basis. This approach is discussed in more detail in section IV. C. below. The revised and new technology modules analyzed by the Agency include the following:   Addition of fish handling and return system to an existing traveling screen system,   Addition of fine mesh screens ( both with and without a fish handling and return system) to an existing traveling screen system,   Addition of a new, larger intake in front of an existing intake screen system,   Addition of passive fine mesh screen system ( cylindrical wedgewire) near shoreline,   Addition of a fish net barrier system,   Addition of an aquatic filter barrier system,   Relocation of an existing intake to a submerged offshore location ( with velocity cap inlet, passive fine mesh screen inlet, or onshore traveling screens),   Addition of a velocity cap inlet to an existing offshore intake,   Addition of passive fine mesh screen to an existing offshore intake,   Addition or modification of a shoreline based traveling screen for an offshore intake system, and   Addition of dual entry, single exit traveling screens ( with fine mesh) to a shoreline intake system. The explanation and derivation of each of these modules is discussed in the public record ( see `` 316( b) Phase II NODA Cost Modules.'') At proposal, EPA based its cost analysis primarily on the addition of fine mesh traveling screens with fish handling systems. EPA recognized at proposal that some facilities would need to add larger intakes, move intakes, or modify offshore intakes, and included an approximate adjustment factor in its cost estimates to account for these types of modifications, but lacked sufficient data to model them explicitly. In the NODA analysis, EPA has added explicit cost modules for each of these activities. As a result, the per facility costs for adding traveling screens with fish handling systems have gone down significantly, but a significant number of facilities ( about 40% of the in scope universe) have been costed for other technologies, which are significantly more expensive than traveling screens. To help commenters better understand the impacts of these revisions, EPA has placed a summary document in the record that shows modeled costs for a range of flows for each major technology module used at proposal and in this NODA, broken out by salt water versus freshwater and nuclear facility versus non nuclear facility ( see `` Comparison of Capital and Net O & M Compliance Costs for Technologies Costed in Proposed Rule and NODA''). As discussed in section III above, EPA also modified its estimate of facility downtime potentially necessary to install these technologies, as well as VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13527 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 3 For a detailed description of the IPM 2000 see Chapter B3 of the Economic and Benefits Analysis ( EBA) document in support of the proposed rule ( DCN 4   0002; http:// www. epa. gov/ ost/ 316b/ econbenefits/ b3. pdf). 4 The ten NERC regions modeled by the IPM are: ECAR ( East Central Area Reliability Coordination Agreement), ERCOT ( Electric Reliability Council of Texas), FRCC ( Florida Reliability Coordinating Council), MAAC ( Mid Atlantic Area Council), MAIN ( Mid America Interconnected Network, Inc.), MAPP ( Mid Continent Area Power Pool), NPCC ( Northeast Power Coordination Council), SERC ( Southeastern Electricity Reliability Council), SPP Continued capacity reduction technologies such as cooling towers. EPA has not yet examined other new information suggesting that site specific factors may affect the costs of retrofitting wet towers at existing power plants. For example, in October 2002, the Department of Energy ( DOE) provided EPA with a study analyzing the costs of retrofitting wet cooling towers at four facilities ( see DCN W   00   32, 316( b) Phase II, comment 2.11). The study found costs at these facilities would be higher than EPA estimated for similar facilities in its proposal record. EPA invites comment on the data contained in the DOE study, and will consider these data as the Agency makes decisions for the final rule. In January 2003, the DOE/ National Energy Technology Laboratory ( NETL) provided EPA with an addendum to their October 2002 ( see DCN W   00   32, 316( b) Phase II, comment 2.14). In that addendum, DOE determined that three out of four facilities would likely require plume abatement technologies that could double the capital costs of the cooling tower portion of a retrofit project. In February 2003, DOE provided additional information indicating that one plant located on brackish waters in a densely populated urban area that is considering a cooling tower retrofit may install a reverse osmosis system to reduce particulate salt emissions ( see `` Astoria Repowering Project Article X Supplement,'' Reliant Energy, November 12, 2002). EPA notes that some other facilities located on brackish water using cooling towers do not use such systems to reduce particulate emissions ( see DCN 4   2553) . The Agency requests comment on whether site specific factors other than those addressed in the Agency's derivation of cost estimates for the waterbody/ capacity based option at proposal could increase or lower the costs of retrofitting a wet cooling tower at an existing plant.

C. Facility Level Costing Options In order to implement the revised costing approach ( see section IV. B. above), the Agency necessarily changed its approach to developing costs at the model facility level. This approach focuses as much as possible on sitespecific characteristics for which the Agency obtained data through the 316( b) questionnaire. In addition, EPA utilized available geographic information, including detailed topographic mapping and overhead satellite imagery, to better utilize sitespecific characteristics of each model facility's intake( s) to inform decisions on the proper costing modules projected for compliance. `` Technology Costing Module Applications for Model Facilities,'' provides the background and explanation of the Agency's approach to model facility level costing. EPA's approach to model facility level costing may be described as follows. In order to project upgrades to technologies as a result of compliance with the proposed rule, the Agency utilizes as much information as is available about the characteristics of the hundreds of facilities within the scope of the proposed rule. By incorporating as many site specific features as possible into the design and implementation of its costing approach the Agency has been able to capture a representative range of compliance costs at what it deems `` model facilities.'' However, the Agency did not have and will never have the opportunity to visit and study in detail all of the engineering aspects of each facility complying with this rule ( over 400 facilities could incur technology related compliance costs as a result of this rule). Therefore, although the Agency has developed costs that represent EPA's best effort to develop a site specific engineering assessment for a particular facility, this assessment does not incorporate certain peculiarities that only long term study of each facility would bear out. Hence, the Agency refers to its approach as a `` model'' facility approach. In selecting technology modules for each model facility, EPA departed from its traditional least cost approach. This is because, while the Agency is confident that the suite of available technologies can achieve compliance with the proposed performance generally ( 60   90% reduction in entrainment and 80   95% reduction in impingement relative to the calculation baseline) EPA lacks sufficient data to determine the performance of each technology on a site specific basis. The Agency thus selected the best performing technology ( rather than the least costly technology) that was suitable for each site, in order to ensure that the technology on which costs were based would in fact achieve compliance at that site. EPA recognizes that this approach may entail a greater degree of cost conservatism than is typical in regulatory analyses, and that this may have implications for the cost cost comparison provisions in the proposed rule. EPA requests comment on its revised approach for selecting model facility cost modules. EPA believes that its modular approach to deriving costs of technologies and the costs to install and operate technologies incorporates sufficient flexibility to derive costs that reflect a broad range of applications. To ensure that the Agency does not underestimate the costs of the rule, EPA has approached the compliance costing effort with great conservatism. When there is uncertainty or the data are inconclusive, EPA has favored conservative approaches to costs ( that is, higher than average). Therefore, the Agency is confident that the compliance costs represented in the analyses accompanying this Notice of Data Availability represent conservative estimates for the range of model facilities represented. However, for a particular facility, the costs may be higher or may be lower than would actually be realized.

D. Clarifications and Corrections Estimating Design Intake Flows for Short Technical Questionnaire Facilities At proposal, the Agency utilized a statistical methodology based on linear regression to assess the design intake flow information for facilities that responded to the short technical questionnaire. Because the Agency initially asked short technical respondents for only their actual annual intake flow for the reporting year, it was necessary to obtain design intake flow information for the purpose of accurately assessing compliance costs. The Agency did not include the statistical methodology for estimating design intake flows for short technical questionnaire facilities and its results in the record for the proposed rule. The Agency continues to use this methodology for this Notice of Data Availability and hereby includes the supporting information in the record ( see DCN 5   2501).

V. IPM Analyses At proposal, EPA used an electricity market model, the Integrated Planning Model 2000 ( IPM   2000), to identify potential economic and operational impacts of various regulatory options considered for proposal. 3 EPA conducted impact analyses at the market level, by North American Electric Reliability Council ( NERC) region, 4 and for facilities subject to the VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13528 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules ( Southwest Power Pool), and WSCC ( Western Systems Coordinating Council). Electric generators in Alaska and Hawaii are not modeled by the IPM. 5 For more information on this analysis, please refer to Section VIII. A of the preamble to the proposed rule and Chapter B3 of the EBA document. 6 For more information on changes made to the EPA Base Case 2000, see EBA, Chapter B3, Section B3   2.2. Phase II regulation. Analyzed characteristics included changes in capacity, generation, revenue, cost of generation, and electricity prices. These changes were identified by comparing two scenarios: ( 1) The base case scenario ( in the absence of any Section 316( b) regulation) and ( 2) the post compliance scenario ( after the implementation of the new Section 316( b) regulations). The results of these comparisons were used to assess the impacts of the preferred option and two of the five alternative regulatory options considered by EPA: ( 1) the `` Intake Capacity Commensurate with Closed Cycle, Recirculating Cooling System based on Waterbody Type/ Capacity'' Option ( hereafter the `` waterbody/ capacity based'' option) and ( 2) the `` Intake Capacity Commensurate with Closed Cycle, Recirculating Cooling System for All Facilities'' Option ( hereafter the `` all closed cycle'' option). Since publication of the proposed rule, EPA has made several changes to its IPM analysis. The following sections present a discussion of these changes and the results of the re analysis of the preferred option and the waterbody/ capacity based option. EPA would use the same methodology as described in Chapter B3 of the EBA ( as amended in this NODA) to analyze other options presented at proposal but not explicitly analyzed for this NODA if they were chosen for promulgation.

A. Changes to the IPM Analyses Since Proposal This section presents the changes to the IPM assumptions and modeling procedures used at proposal. This section also describes modifications EPA made to the analyses to correct errors that were discovered after publication of the proposed rule.

1. IPM Analysis of the Proposed Regulatory Requirements For the proposal, EPA did not explicitly analyze the preferred option because of time constraints. Rather, EPA conducted an electricity market model analyses of two alternative options that had higher costs than those of the preferred option. To assess the expected economic impacts of the preferred option at proposal, EPA adopted an indirect approach. 5 EPA acknowledges that an analysis specific to the requirements of the preferred option is preferable, and, as a result, EPA conducted an IPM model run using the proposed regulatory requirements for this NODA. The results of this analysis are presented in Section V. B below.

2. Model Aggregation At proposal, the steam electric generators of the 530 Phase II facilities that are modeled by the IPM were disaggregated from the existing IPM model plants ( as used in the standard IPM base case used for other EPA regulations, the EPA Base Case 2000) and `` run'' as individual facilities along with the other existing model plants. This change increased the total number of model plants from 1,390 under the EPA Base Case 2000 to 1,777 under the 316( b) Proposal Base Case. 6 For this NODA, EPA made two further changes to the model aggregation, which increased the total number of model plants from 1,777 to 2,096:   Disaggregation of non steam generators at Phase II facilities. At proposal, EPA only disaggregated Phase II steam electric generators from the original model plant specification. These steam electric generators were then re aggregated to the facility level, and the facility level output was used in EPA's facility impact analyses. Disaggregating only steam electric generators led to the underestimation of certain facility level operating characteristics ( e. g., generation and revenues) because the facility level results produced by the model did not include the economic activities of nonsteam generators at Phase II facilities. Therefore, for this NODA analysis, EPA also disaggregated the non steam generators at facilities subject to the rule from the original model plant specification, so that the facility level results include the economic activities of the entire plant.   Phase III facilities. In addition to disaggregating generators at Phase II facilities, EPA also disaggregated generators at Phase III facilities for this NODA. ( At the time this analysis was started, the section 316( b) regulatory schedule called for proposal of the Phase III rule three months before promulgation of the Phase II rule.) Because changes in model aggregation can result in changes to the base case results, EPA compared the base case results generated for the proposal and NODA analyses. This comparison identified little difference in the base case results caused by the modification in the model aggregation: Base case total production costs ( capital, O& M, and fuel) using the revised NODA specifications are lower by 0.2% to 0.3% in the years 2008, 2010, and 2020. Early retirements of base case oil and gas steam capacity under the NODA specifications decreased by 1,258 MW. Early retirements of base case nuclear and coal capacity remained constant. In addition, the revised model specifications result in changes in base case coal and gas fuel use by less than 1.0 percent.

3. Capacity Utilization Under the preferred option and the alternative regulatory options considered at proposal, facilities with a capacity utilization rate of less than 15 percent may be subject to less stringent compliance requirements than facilities with a utilization rate of 15 percent or more, depending on the water body from which they withdraw and the technologies they already have in place. EPA made the following changes to the determination of the capacity utilization of Phase II facilities for the economic analysis:   Capacity utilization rates based on steam electric generators only. At proposal, the 15 percent capacity utilization determination was based on the generation and capacity of the entire facility, including steam electric and non steam generators. As discussed at Section III above, EPA believes that utilization of the steam electric part of the facility better reflects the facility's potential for adverse environmental impact because only the steam electric generators use cooling water subject to this regulation. At Section XI below, EPA invites comment on a refinement to the definition of `` capacity utilization rate'' at proposed § 125.93 to focus only on the steam electric generators at a facility. For the NODA, EPA is using the capacity utilization of only the steam electric generators at Phase II facilities so that the updated economic analyses, including the IPM analysis, include this potential refinement.   IPM capacity utilization rates. At proposal, EPA used the average capacity utilization based on Energy Information Administration ( EIA) data for 1995 to 1999. This utilization rate was often different from the rate based on the IPM base case results. This discrepancy might have led to an underestimation of economic impacts for those facilities whose utilization rate is less than 15 percent based on EIA data but 15 percent or more based on IPM data, and to an overestimation of economic impacts for those facilities whose utilization rate is 15 percent or more based on EIA data but less than 15 VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13529 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 7 Model run years 2020 and 2026 were specified for model balance, while run years 2008, 2010, and 2013 were selected to provide output across the compliance period. Output for 2020 and 2026 is not used in EPA's analyses. For more information on IPM model run years, see Chapter B3, section B3   2.1. d of the EBA. percent based on IPM data. To make the compliance response and costs consistent with the economic performance of facilities in the IPM, EPA used projected IPM capacity utilization rates for 2008 ( the first model run year) for the NODA. As a result of these two changes, of the 530 facilities modeled by the IPM at proposal, 19 facilities that had a capacity utilization rate of less than 15 percent for the proposal analysis have a rate of 15 percent or more for the NODA analysis ( base case using the EPA electricity demand growth assumption). Conversely, 75 facilities that had a rate of 15 percent or more for the proposal analysis have a rate of less than 15 percent for the NODA analysis ( base case using the EPA electricity demand growth assumption). The net effect of these changes is that for the NODA analysis more facilities are estimated to have the less stringent compliance requirements associated with a low capacity utilization rate than was the case for the proposal analysis.   Generation cap. A final modification to the capacity utilization of Phase II facilities relates to the potential change in the utilization rate between the base case and the postcompliance cases. Because facilities with a baseline capacity utilization rate of less than 15 percent are potentially subject to less stringent compliance requirements ( depending on the water body from which they withdraw and the technologies they already have in place), they would not be able to increase their post compliance capacity utilization without incurring more stringent compliance requirements. In order to ensure that the capacity utilization rate in the post compliance case is consistent with the costing assumptions, the generation of facilities with a steam electric capacity of less than 15 percent in the base case was capped so that their post compliance capacity utilization would remain below 15 percent.

4. Treatment of Installation Downtime The IPM models the electric power market over the 26 year period 2005 to 2030. Due to the data intensive processing procedures, the model is run for a limited number of years only. Run years are selected based on analytical requirements and the necessity to maintain a balanced choice of run years throughout the modeled time horizon. EPA selected the following run years for the Section 316( b) analyses: 2008, 2010, 2013, 2020, and 2026.7 2005 to 2009 are mapped into the 2008 run year; 2010 to 2012 are mapped into the 2010 run year; and 2013 to 2015 are mapped into the 2013 run year. The years that are mapped into a run year are assumed to have the same characteristics as the run year itself. This model characteristic creates a challenge in correctly representing estimated downtimes associated with recirculating systems and other compliance technologies exactly the way they are estimated to occur ( downtimes assigned to a model run year are also assigned to non run years, and downtimes assigned to nonrun years are not taken into account). There are different options of accounting for downtimes. At proposal, EPA decided to model the downtime for each facility in its estimated year of compliance. Since 2005 through 2009 are all mapped into 2008, a facility that had downtime in 2008 was modeled as if it also had downtimes in 2005, 2006, 2007, and 2009. This may have understated the net present value ( NPV) of the facility's operations and therefore overestimated its closure decision. Conversely, a facility that had a downtime in a non model run year was modeled as if it had no downtime at all. This may have overestimated its NPV and therefore understated its closure decision. While this approach potentially affected the facility level analysis, it provided for a realistic snapshot of the market effect of downtimes in the model run year. For the NODA analysis, EPA decided to change the representation of downtimes to an average over the years that are mapped into each model run year. For example, a facility with a downtime in 2008 was modeled as if 1/ 5th of its downtime occurred in each year between 2005 and 2009. This approach more closely models potential facility level impacts as it accounts for the correct total amount of downtime for each facility. The potential drawback of this approach is that the snapshot of the market level effect of downtimes during the model run year is the average effect; this approach does not model potential worst case effects of above average amounts of capacity being down in one NERC region during a specific year.

5. Correction of Errors EPA corrected two IPM input errors that were discovered after publication of the proposed rule: ( 1) At proposal, the capital costs of compliance were erroneously considered sunk and were not taken into account in making early retirement decisions; ( 2) The energy penalty was omitted for a few facilities costed with a recirculating system ( one out of 49 facilities under the waterbody/ capacity based option and nine out of 408 facilities under the all closed cycle option). These errors may have led the IPM to understate the modeled economic impacts at these facilities.

6. Other Changes Affecting the IPM Results In addition to the modeling changes described above, a number of other changes affect the results presented below. These changes are outlined in Section III above and include the following: an increase in the estimated number of in scope Phase II facilities from 550 to 551 ( as a result, the number of Phase II facilities modeled by the IPM increased from 530 to 531); revisions of technology and permitting/ monitoring costs; changes to the assumption of construction downtimes of recirculating cooling towers and other compliance technologies; an adjustment of energy penalties; changes in the estimation of the capacity utilization threshold; and adjustments to the compliance schedule. EPA also notes that in 2010, nondispatched capacity in the IPM base case ( based on EPA's electricity demand growth assumption) is approximately 12 percent of total capacity, which is consistent with historical rates to ensure system reliability. ( Non dispatched facilities are those that operate on a stand by basis throughout the year but are not called upon to generate and dispatch electricity.) Most of this capacity is oil/ gas steam capacity ( 66 percent) and gas turbines ( 27 percent). Overall, 11 percent of steam electric capacity and 15 percent of non steam capacity are modeled to be on stand by. A large portion of the non dispatched steam electric capacity is subject to Phase II regulation. In total, approximately 12 percent of Phase II steam electric capacity is not dispatched in the base case. This number is higher than historical data for these facilities. The main reason for this difference is that over time, existing capacity, especially oil/ gas steam capacity, is expected to become less competitive relative to new capacity additions, especially combined cycle facilities. Oil and gas steam units generally have ( a) higher heat rates, ( b) higher fuel costs, ( c) higher variable O& M costs, and ( d) higher emission rates than other steam electric capacity. As a result, some relatively inefficient oil and gas steam units are modeled to be idle in the IPM.

VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13530 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 8 Two base case scenarios were used to analyze the impacts associated with the preferred option and the waterbody/ capacity based option. The base case scenario used to analyze the preferred option was developed using EPA's electricity demand assumption. Under this assumption, demand for electricity is based on the Annual Energy Outlook ( AEO) 2001 forecast adjusted to account for demand reductions resulting from the implementation of the Climate Change Action Plan ( CAAP). The base case for the waterbody/ capacity based option was developed using the unadjusted electricity demand from the AEO 2001. ( See the Appendix of ch. B8 of the EBA, as published for the proposed rule, for further explanation on the two base cases; http:// www. epa. gov/ ost/ 316b/ econbenefits/ b8. pdf.) EPA is currently completing additional IPM runs and will develop analyses of both options using both base cases. EPA intends to place these additional analyses in the docket during the comment period on this Notice. EPA expects to use information from the analyses in today's Notice and these additional analyses to support decision making for the final rule.

9 EPA also analyzed potential market level impacts of the preferred option for a year within the compliance period during which some Phase II facilities experience installation downtimes. This analysis used output from model run year 2008. See ch. B3, sec. B3   4.3 of the EBA, as updated for this NODA analysis, for the results of this analysis. All Phase II facilities are subject to the requirements of the Phase II regulation, even if they do not generate electricity. Therefore, unless EPA modeled a facility to cease operations and exit the marketplace, EPA assigned compliance costs to non dispatched facilities. While none of the Phase II units that stand by in the base case are modeled to be economic closures under the preferred option, it is possible that other economic measures, e. g., impacts on pre tax income, may be overestimated for these facilities. This would be the case because revenues might be understated if the modeling assumption that these facilities do not generate electricity is not realistic. EPA requests comment on this part of the analysis.

B. Revised Results for the Preferred Option This section presents the revised impact analysis of the preferred option. The impacts of compliance with the preferred option are defined as the difference between the model output for the base case scenario and the model output for the post compliance scenario. 8 EPA analyzed impacts from the preferred option using output from model run year 2010. 2010 was chosen to represent the effects of the preferred option for a typical year in which all facilities are in compliance ( compliance years for the preferred option are 2005 to 2009). 9 The analysis was conducted at two levels: the market level including all facilities ( by NERC region) and the Phase II facility level ( including analyses of the in scope Phase II facilities as a group and of individual Phase II facilities). The results of these analyses are presented below.

1. Market Level Impacts of the Preferred Option The market level analysis includes results for all generators located in each NERC region including facilities both in scope and out of scope of the proposed Phase II rule. Exhibit 1 below presents five measures used by EPA to assess market level impacts associated with the preferred option: ( 1) Incremental capacity closures, calculated as the difference between capacity closures under the preferred option and capacity closures under the base case; ( 2) incremental capacity closures as a percentage of baseline capacity; ( 3) postcompliance changes in variable production costs per MWh, calculated as the sum of total fuel and variable O& M costs divided by total generation; ( 4) post compliance changes in energy price, where energy prices are defined as the wholesale prices received by facilities for the sale of electric generation; and ( 5) post compliance changes in pre tax income, where pretax income is defined as total revenues minus the sum of fixed and variable O& M costs, fuel costs, and capital costs. Additional results are presented in Chapter B3: Electricity Market Model Analysis ( sec. B3   4.1) of the EBA, as updated for this NODA analysis. Chapter B3 also presents a more detailed interpretation of the results of the market level analysis.

EXHIBIT 1.   MARKET LEVEL IMPACTS OF THE PREFERRED OPTION ( 2010)

NERC region Baseline capacity ( MW) Incremental capacity closures ( MW) Closures as % of baseline capacity Change in variable production cost per MWh Change in energy price per MWh Change in pre tax income ($ 2002)

ECAR .................... 118,529 0 0.0 0.1 0.0 ¥ 1.1 ERCOT ................. 75,290 0 0.0 0.0 6.1 ¥ 6.0 FRCC .................... 50,324 0 0.0 0.4 0.6 ¥ 3.1 MAAC .................... 63,784 0 0.0 ¥ 0.1 0.0 ¥ 0.9 MAIN ..................... 59,494 434 0.7 0.8 ¥ 0.3 ¥ 0.7 MAPP .................... 35,835 0 0.0 ¥ 0.1 ¥ 0.4 ¥ 0.6 NPCC .................... 72,477 0 0.0 ¥ 0.4 0.9 0.8 SERC .................... 194,485 0 0.0 ¥ 0.1 0.0 ¥ 0.5 SPP ....................... 49,948 0 0.0 ¥ 0.1 ¥ 0.2 ¥ 0.4 WSCC ................... 167,748 0 0.0 0.0 0.0 ¥ 1.1 Total ............... 887,915 434 0.0 0.0 n/ a ¥ 1.1 One of the ten NERC regions modeled, MAIN, would experience economic closures of existing capacity as a result of the preferred option. However, this closure of 434 MW of nuclear capacity represents a relatively small percentage of baseline capacity in the region ( 0.7 percent). Three NERC regions would experience increases in variable production costs per MWh, although the largest increase would not exceed 1.0 percent. In addition, three NERC regions would experience an increase in energy price under the preferred option. Of these, only ERCOT would experience an increase of more than 1.0 percent ( 6.1 percent). Pre tax incomes would decrease in all but one region, but the majority of these changes would be on the order of 1.0 percent or less. ERCOT would experience the largest decrease in pre tax income ( ¥ 6.0 percent). Only one region, NPCC, would experience an increase in market level pre tax income ( 0.8 percent).

2. Facility Level Impacts of the Preferred Option The results from model run year 2010 were used to analyze two potential facility level impacts associated with the preferred option: ( 1) Potential changes in the economic and operational characteristics of the group VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13531 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules of in scope Phase II facilities and ( 2) potential changes to individual facilities within the group of Phase II facilities. EPA analyzed incremental capacity closures, changes in variable production costs per MWh of generation, total generation, and pre tax income to assess impacts to all Phase II facilities resulting from the preferred option. Exhibit 2 below presents the results of this analysis, by NERC region.

EXHIBIT 2.   IMPACTS ON PHASE II FACILITIES OF THE PREFERRED OPTION ( 2010)

NERC region Baseline capacity ( MW) Incremental closures Change in variable production cost per MWh (%) Change in generation (%) Change in pre tax Income (%) Capacity ( MW) % of baseline capacity ECAR .................... 82,313 0 0.0 0.0 ¥ 0.1 ¥ 1.4 ERCOT .................. 43,522 0 0.0 ¥ 0.7 ¥ 1.7 ¥ 11.0 FRCC .................... 27,537 0 0.0 0.3 ¥ 0.8 ¥ 4.1 MAAC .................... 33,590 0 0.0 0.0 0.2 ¥ 1.4 MAIN ..................... 35,373 434 1.2 0.5 ¥ 1.1 ¥ 1.0 MAPP .................... 15,727 0 0.0 0.0 0.0 ¥ 1.6 NPCC .................... 37,651 0 0.0 ¥ 1.4 ¥ 2.3 ¥ 0.8 SERC .................... 107,450 0 0.0 ¥ 0.2 ¥ 0.2 ¥ 0.7 SPP ....................... 20,471 0 0.0 ¥ 0.4 ¥ 0.6 ¥ 1.0 WSCC ................... 27,206 0 0.0 ¥ 1.0 ¥ 5.5 ¥ 27.0 Total ............... 430,840 434 0.1 ¥ 0.5 ¥ 0.8 ¥ 2.0 Similar to the market level results, MAIN is the only region that would experience incremental capacity closures at Phase II facilities under this regulatory option: A total of 434 MW, or 1.2 percent of all Phase II capacity in this region, would be retired. Total capacity closures in MAIN are a net estimate ( i. e., policy case closures minus base cases closures) consisting of 519 MW of capacity retiring at one facility and an 85 MW reduction in closures at a second facility. Variable production costs per MWh at Phase II facilities would increase in two regions and decrease in five regions under the preferred option. No region would experience an increase in Phase II variable production costs that exceeds 0.5 percent while Phase II facilities in NPCC and WSCC would see reductions of 1.4 percent and 1.0 percent, respectively. Phase II facilities in four NERC regions would experience decreases in generation in excess of 1.0 percent as a result of the preferred option. The largest decrease would be in WSCC, where Phase II facilities would experience a 5.5 percent reduction in both generation and revenues. Overall, pre tax income would decrease by 2.0 percent for the group of Phase II facilities. The effects of this change are concentrated in a few regions: WSCC would experience a reduction in pre tax income of 27.0 percent, which is driven by a reduction in both generation and revenues ( not presented in this exhibit). ERCOT and FRCC are estimated to experience a reduction of 11.0 and 4.1 percent, respectively. Results for the group of Phase II facilities as a whole may mask shifts in economic performance among individual facilities subject to this rule. To assess potential distributional effects, EPA analyzed facility specific changes in capacity utilization ( defined as generation divided by capacity times 8,760 hours), generation, revenue, variable production costs per MWh ( defined as variable O& M cost plus fuel cost divided by generation), and pre tax income. Exhibit 3 presents the total number of Phase II facilities with different degrees of change in each of these measures. This exhibit excludes 18 in scope facilities with significant status changes ( 10 facilities are baseline closures, one facility is a policy closure, and seven facilities changed their repowering decision between the base case and the policy case). These facilities are either not operating at all in either the base case or the post compliance case, or they experience fundamental changes in the type of units they operate; therefore, the measures presented below would not be meaningful for these facilities. In addition, the change in variable production cost per MWh of generation could not be developed for 57 facilities with zero generation in either the base case or post compliance scenario. For these facilities, the change in variable production cost per MWh is indicated as `` n/ a.''

EXHIBIT 3.   OPERATIONAL CHANGES AT PHASE II FACILITIES FROM THE PREFERRED OPTION ( 2010) a Economic measures Reduction Increase No change N/ A   = 1% 1   3% > 3%   = 1% 1   3% > 3%

Change in Capacity Utilization b ................... 9 15 24 9 6 9 441 0 Change in Generation .................................. 7 1 44 10 3 17 431 0 Change in Revenue ..................................... 80 27 42 100 22 15 227 0 Change in Variable Production Costs/ MWh 33 13 9 140 13 14 234 57 Change in Pre Tax Income .......................... 105 113 199 22 13 37 24 0 a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent. b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post compliance case. For all other measures, the change is expressed as the percentage change between the base case and post compliance values.

Exhibit 3 indicates that the majority of Phase II facilities would not experience changes in capacity utilization or generation due to compliance with the preferred option. Of those facilities with changes in post compliance capacity VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13532 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 10 Two base case scenarios were used to analyze the impacts associated with the preferred option and the waterbody/ capacity based option. See footnote 8 above for a full explanation. 11 EPA also analyzed potential market level impacts of the alternative waterbody/ capacity based option for a year within the compliance period during which some Phase II facilities experience installation downtimes. This analysis used output from model run year 2008. See Chapter B8, Section B8   4 of the EBA, as updated for this NODA analysis, for the results of this analysis. utilization and generation, most would experience decreases in these measures. Exhibit 3 also indicates that the majority of facilities with changes in postcompliance variable production costs would experience increases. However, more than 80 percent of those increases would not exceed 1.0 percent. Changes in revenues at most Phase II facilities would also not exceed 1.0 percent. The largest effect of the preferred option would be on facilities' pre tax income: over 80 percent of facilities would experience a reduction in pre tax income, with almost 40 percent experiencing a reduction of 3.0 percent or greater.

C. Revised Results for the Waterbody/ Capacity Based Option This section presents the revised impact analysis of the alternative waterbody/ capacity based option. Under this option, facilities that withdraw water from an estuary, tidal river, or ocean and that meet certain intake flow requirements, would generally be required to meet performance standards for reducing impingement mortality and entrainment based on a level that can be attained by using a closed cycle, recirculating cooling system. These facilities would have the choice to comply with Track I or Track II requirements. Facilities that choose to comply with Track I would be required to reduce their intake flow to a level commensurate with that which can be attained by a closed cycle, recirculating system. Facilities that choose to comply with Track II would have to demonstrate that alternative technologies would reduce impingement and entrainment to comparable levels that would be achieved with a closed cycle recirculating system ( see section VI. B. 2 of the proposal preamble for a discussion of Track I and Track II under this option). Other facilities would be required to reduce impingement mortality or impingement mortality and entrainment based on the performance of technologies such as fine mesh screens and fish return systems. EPA's estimation of impacts associated with the alternative waterbody/ capacity based option is based on an electricity market model analysis that assumes that all facilities required to reduce impingement mortality and entrainment based on the performance of a closed cycle recirculating cooling system would choose to comply with the requirements of Track I. This analysis further assumes that such facilities would install a recirculating wet cooling tower. These requirements would be met by the end of the term of the first permit after promulgation of the final rule ( 2005 to 2013), depending on when a permittee's first NPDES permit after promulgation expires. The impacts of compliance with the waterbody/ capacity based option are defined as the difference between the model output for the base case scenario and the model output for the post compliance scenario. 10 EPA analyzed impacts using IPM output from model run year 2013. 2013 was chosen to represent the effects of the waterbody/ capacity based option for a typical year in which all facilities are in compliance ( compliance years for the waterbody/ capacity based option are 2005 to 2013; however, for the purposes of this analysis, all facilities are modeled to comply by 2012). 11 The analysis was conducted at two levels: the market level including all facilities ( by NERC region) and the Phase II facility level ( including analyses of the in scope Phase II facilities as a group and of individual Phase II facilities), using the same framework as the analysis of the preferred option presented above. It should be noted that a direct comparison of the results of the preferred option and the waterbody/ capacity based option is not possible because ( 1) the analyses use output for different model run years ( 2010 for the preferred option and 2013 for the waterbody/ capacity based option) and ( 2) the two analyses use different base cases with different assumptions about future growth in electricity demand. As noted above, EPA will provide analyses of both regulatory options for both base cases and intends to place these in the docket during the comment period on this Notice.

1. Market Level Impacts of the Waterbody/ Capacity Based Option The market level analysis includes results for all generators located in each NERC region including facilities both in scope and out of scope of Phase II regulation. Exhibit 4 below presents the same five measures as discussed for the preferred option: ( 1) Incremental capacity closures, calculated as the difference between capacity closures under the waterbody/ capacity based option and capacity closures under the base case; ( 2) incremental capacity closures as a percentage of baseline capacity; ( 3) post compliance changes in variable production costs per MWh, calculated as the sum of total fuel and variable O& M costs divided by total generation; ( 4) post compliance changes in energy price, where energy prices are defined as the prices received by facilities for the sale of electric generation; and ( 5) post compliance changes in pre tax income, where pretax income is defined as total revenues minus the sum of fixed and variable O& M costs, fuel costs, and capital costs. Additional results are presented in Chapter B8 ( Section B8   2) of the EBA, as updated for this NODA analysis. Chapter B8 also presents a more detailed interpretation of the results of the market level analysis.

EXHIBIT 4.   MARKET LEVEL IMPACTS OF THE WATERBODY/ CAPACITY BASED OPTION ( 2013)   NERC Region Baseline capacity ( MW) Incremental capacity closures ( MW) Closures as % of baseline capacity Change in variable production cost per MWh Change in energy price per MWh Change in pre tax income ($ 2002)

ECAR .................... 133,048 0 0.0% 0.5% 0.8% 1.3% ERCOT .................. 86,609 0 0.0 1.2 1.7 ¥ 0.1 FRCC .................... 57,078 0 0.0 1.7 3.8 ¥ 5.4 MAAC .................... 71,441 0 0.0 1.3 1.4 ¥ 4.1 MAIN ..................... 66,420 1,012 1.5 2.2 1.6 1.4 MAPP .................... 39,694 0 0.0 0.3 1.8 2.0 NPCC .................... 77,557 0 0.0 1.2 1.1 ¥ 3.3 SERC .................... 220,567 0 0.0 1.0 1.4 0.2 SPP ....................... 55,711 0 0.0 0.6 1.5 1.2 VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13533 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules EXHIBIT 4.   MARKET LEVEL IMPACTS OF THE WATERBODY/ CAPACITY BASED OPTION ( 2013)     Continued NERC Region Baseline capacity ( MW) Incremental capacity closures ( MW) Closures as % of baseline capacity Change in variable production cost per MWh Change in energy price per MWh Change in pre tax income ($ 2002)

WSCC ................... 186,001 2,150 1.2 2.9 1.4 ¥ 1.7 Total ............... 994,126 3,162 0.3 1.2 n/ a ¥ 0.5 Two of the ten NERC regions modeled, MAIN and WSCC, would experience economic closures of facilities as a result of this option. The capacity closures in MAIN and WSCC represent 1.5 percent and 1.2 percent, respectively, of baseline capacity in these regions and 0.3 percent of total baseline capacity for all regions taken as a whole. Variable production costs per MWh and energy prices would increase in all NERC regions. The increases in variable production costs would exceed 1.0 percent in six NERC regions, and two regions, MAIN and WSCC, would experience increases of more than 2.0 percent. Energy prices would increase by more than 1.0 percent in nine of the ten regions modeled, with FRCC experiencing the largest increase ( 3.8 percent). Half of the regions would experience a reduction in pre tax income, while the other half would experience increases in this measure. The majority of these changes would be less than 2.0 percent. FRCC, MAAC, and NPCC would experience the largest decrease in pre tax income ( 5.4,  4.1, and  3.3 percent, respectively), while the largest increase would occur in MAPP ( 2.0 percent).

2. Phase II Facility Level Impacts of the Waterbody/ Capacity Based Option The results from model run year 2013 were used to analyze two potential facility level impacts associated with the preferred option: ( 1) Potential changes in the economic and operational characteristics of the group of in scope Phase II facilities and ( 2) potential changes to individual facilities within the group of Phase II facilities. EPA analyzed the same measures as discussed for the preferred option to assess impacts to the group of Phase II facilities resulting from the waterbody/ capacity based option: economic closures, changes in variable production costs per MWh of generation, total generation, and pre tax income. Exhibit 5 below presents the results from this analysis, by NERC region.

EXHIBIT 5.   IMPACTS ON PHASE II FACILITIES OF THE WATERBODY/ CAPACITY   BASED OPTION ( 2013)

NERC Baseline capacity ( MW) Closure analysis Change in variable production cost per MWh Change in generation Change in pre tax income Capacity ( MW) % of baseline capacity ECAR .................... 82,258 0 0.0% 0.3% 0.1% 1.0% ERCOT .................. 44,400 0 0.0 0.3 0.6 0.5 FRCC .................... 27,513 0 0.0 0.3 3.5 10.5 MAAC .................... 34,696 0 0.0 0.8 1.0 7.7 MAIN ..................... 34,944 1,012 2.9 1.2 2.5 1.5 MAPP .................... 15,723 0 0.0 0.0 0.1 2.0 NPCC .................... 37,219 0 0.0 0.8 ¥ 0.6 ¥ 9.2 SERC .................... 107,458 0 0.0 0.7 0.1 ¥ 0.1 SPP ....................... 20,471 0 0.0 ¥ 0.7 ¥ 0.6 1.4 WSCC ................... 28,093 2,150 7.7 0.5 ¥ 29.2 ¥ 30.7 Total ............... 432,776 3,162 0.7 0.0 ¥ 2.1 ¥ 2.1 Similar to the results of the broader market level analysis, MAIN and WSCC are the only regions that would experience incremental capacity closures at Phase II facilities under this regulatory option. In MAIN, 1,012 MW, or 2.9 percent of baseline Phase II capacity, would retire; in WSCC, 2,150 MW, or 7.7 percent of baseline Phase II capacity, would retire. In aggregate, these closures of 3,162 MW represents less than 1.0 percent of total baseline Phase II capacity. Phase II facilities in only one region, MAIN, would experience an increase in excess of 1.0 percent in variable production cost per MWh. Phase II facilities in seven NERC regions would experience a decrease in generation. Of these, three regions would see reductions in excess of 2.0 percent with the largest decrease occurring in WSCC ( 29.2 percent), partially because of the post compliance closures. Similar to the market level, FRCC, MAAC, and NPCC would experience relatively large reductions in pre tax income ( 10.5,  7.7, and  9.2 percent, respectively). However, the highest reduction would be seen in WSCC ( 30.7 percent), where the compliance costs per MW of Phase II capacity is relatively high, and where only a relatively small portion of the overall capacity is regulated under the Phase II rule. To assess potential shifts in economic performance among individual facilities subject to this rule, EPA analyzed the same facility specific changes as for the preferred option: changes in capacity utilization ( defined as generation divided by capacity times 8,760 hours), generation, revenue, variable production costs per MWh ( defined as variable O& M cost plus fuel cost divided by generation), and pre tax income. Exhibit 6 presents the total number of Phase II facilities with different degrees of change in each of these measures. This exhibit excludes 30 in scope facilities with significant status changes ( nine facilities are baseline closures, three facilities are policy closures, and 18 facilities changed their repowering decision between the base case and the policy case). These facilities are either not operating at all in either the base case or the post compliance case, or they experience fundamental changes in the type of units they operate; therefore,

VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13534 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 12 For example, compliance requirements in NERC regions without estuarine/ tidal river or ocean facilities ( i. e., ECAR, MAIN, MAPP, and SPP) are identical under the two options. For this NODA analysis, all facilities in these regions would have had identical compliance costs under the two options, were it not for the difference in base case assumptions. 13 At proposal, EPA assumed that the technologies required to comply with the preferred option would not require installation downtimes ( see Section III. 4 of this Notice). the measures presented below would not be meaningful for these facilities. In addition, the change in variable production cost per MWh of generation could not be developed for 62 facilities with zero generation in either the base case or post compliance scenario. For these facilities, the change in variable production cost per MWh is indicated as `` n/ a.''

EXHIBIT 6.   NUMBER OF PHASE II FACILITIES WITH OPERATIONAL CHANGES AT PHASE II FACILITIES WATERBODY/ CAPACITY BASED OPTION ( 2013) a Economic measures Reduction Increase No change N/ A   1% 1   3% > 3%   1% 1   3% > 3%

Change in Capacity Utilization b .................. 4 11 21 6 14 15 430 0 Change in Generation .................................. 7 24 37 5 7 23 398 0 Change in Revenue ..................................... 56 13 41 108 247 28 8 0 Change in Variable Production Costs/ MWh 18 5 8 154 115 21 118 62 Change in Pre Tax Income .......................... 51 62 164 45 141 36 2 0 a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent. b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post compliance case. For all other measures, the change is expressed as the percentage change between the base case and post compliance values.

Exhibit 6 indicates that the majority of Phase II facilities would not experience changes in capacity utilization or generation due to compliance with the waterbody/ capacity based option. Of facilities with post compliance changes in capacity utilization and/ or generation, the majority would experience a decrease in these measures. Exhibit 6 also indicates that the majority of Phase II facilities would experience increases in both revenues and variable production costs of between 0.0 and 3.0 percent. Similarly, almost all Phase II facilities would experience a change in pre tax income, with a slight majority seeing a reduction in this measure.

VI. Other Economic Analyses EPA updated several of its other economic analyses conducted at proposal to determine the effect of changes made to the assumptions for this NODA on steam electric generating facilities. For more detailed information on these analyses, refer to the memo entitled `` Supporting Documentation of Changes to Economic Impacts in Support of the Section 316( b) Phase II NODA'' ( DCN 5   3004). This section and the supporting memo discuss changes made to EPA's methodology and assumptions as well as the updated results. For a discussion of the original methodology used by EPA for the proposal analysis, refer to the chapters in Part B of the Economic and Benefits Analysis ( EBA) document in support of the proposed rule at http:// www. epa. gov/ waterscience/ 316b/ econbenefits/. It should be noted that the measures presented in this section are provided in addition to the impact measures based on the Integrated Planning Model ( IPM   ) analyses ( see Section V of this Notice). The following measures are used to assess the magnitude of compliance costs; they are not used to predict closures or other types of economic impacts on facilities subject to Phase II regulation. It should also be noted that the results of the preferred option and the waterbody/ capacity based option cannot be directly compared to each other. EPA used two different demand growth assumptions for the IPM base cases of the preferred option ( EPA electricity demand assumption) and the waterbody/ capacity based option ( AEO electricity demand assumption, upon request by the Department of Energy). Since EPA is using IPM base case data in its estimate of the cost of installation downtime, the cost of the energy penalty, and revenues, the results presented in this section could vary between the two options, even for facilities or NERC regions with identical compliance requirements under the two options. 12 EPA intends to place additional IPM runs in the record during the NODA comment period to allow direct comparisons of both policy alternatives under both base cases.

A. National Costs Based on the NODA analysis, EPA estimates that facilities subject to the preferred option would incur annualized post tax compliance costs of approximately $ 265 million ( at proposal, this estimate was $ 178 million). These costs include one time technology costs of complying with the rule, a one time cost of installation downtime, 13 annual operating and maintenance costs, and permitting costs ( including initial permit costs, annual monitoring costs, and permit reissuance costs). This cost estimate does not include the costs of administering the rule by permitting authorities and the federal government. Also excluded are compliance costs for eight facilities that are projected to be baseline closures. Including compliance costs for projected baseline closure facilities would result in a total annualized compliance cost of approximately $ 269 million ( at proposal, this estimate was $ 182 million). The cost differences between proposal and the NODA are accounted for primarily by the expanded range of technology options considered for the NODA and the `` best performing technology'' selection criteria used to assign cost modules to model facilities ( see Section IV of this Notice). EPA also updated the estimated total national annualized post tax cost of compliance for the alternative waterbody/ capacity based option. Costs for this option include the same components as the estimate for the preferred option ( one time technology costs, cost of downtime, annual operating and maintenance costs, and permitting costs) but also include the cost of the energy penalty incurred by facilities estimated to upgrade to a recirculating cooling tower system. For the NODA analysis, the estimated total annualized post tax cost of compliance for the waterbody/ capacity based option is approximately $ 793 million ( at proposal, this estimate was $ 585 million). This increase reflects a number VerDate Jan< 31> 2003 21: 12 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13535 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 14 The number of baseline closures is different for the preferred option and the waterbody/ capacitybased option because different IPM base cases were used to estimate baseline closures. See footnote 8 above for a full explanation.

15 EPA used 2008 rather than 2010 baseline revenues for this analysis because 2008 is the first model run year specified in the IPM analyses. EPA used the first model run year because it more closely resembles the current operating conditions of in scope facilities than later run years ( over time, facilities may be increasingly affected by factors other than a Phase II regulation).

16 For the preferred option, IPM revenues for 2008 were not available for eight facilities estimated to be baseline closures, ten facilities not modeled by the IPM, and five facilities projected to have zero baseline revenues. EPA used facility specific electricity generation and firm specific wholesale prices as reported to the Energy Information Administration ( EIA) to calculate the cost torevenue ratio for the 15 non baseline closure facilities with missing information. The revenues for one of these facilities remains unknown. of changes including increased technology costs, increased downtime for technology installation, and the use of electric demand assumptions from DOE's Annual Energy Outlook. Not included in this estimate are seven facilities that are projected to be baseline closures. 14 Including compliance costs for projected baseline closure facilities would result in a total annualized cost of compliance with the waterbody/ capacity based option of approximately $ 797 million ( at proposal, this estimate was $ 595 million). Exhibit 7 below summarizes the changes between the proposal and NODA analyses for the preferred option and the waterbody/ capacity based option.

EXHIBIT 7   SUMMARY OF CHANGES IN NATIONAL COSTS Proposal ($ 2001; mill.) NODA ($ 2002; mill.) Change Absolute Percent Preferred Option Number of Phase II facilities ........................................................................................... 550 551 1 0.2 All facilities ( pre tax) ........................................................................................................ $ 279 $ 416 $ 137 49.1 All facilities ( post tax) ....................................................................................................... $ 182 $ 269 $ 87 47.8 Number of baseline closures ........................................................................................... 11 8 ( 3)   27.3 Non baseline closures ( pre tax) ...................................................................................... $ 271 $ 410 $ 139 51.3 Non baseline closures ( post tax) ..................................................................................... $ 178 $ 265 $ 87 48.9 Waterbody/ Capacity Based Option Number of Phase II facilities ........................................................................................... 550 551 1 0.2 All facilities ( pre tax) ........................................................................................................ $ 968 $ 1,280 $ 312 32.2 All facilities ( post tax) ....................................................................................................... $ 595 $ 797 $ 202 34.0 Number of baseline closures ........................................................................................... 9 7 ( 2)   22.2 Non baseline closures ( pre tax) ...................................................................................... $ 951 $ 1,273 $ 322 33.9 Non baseline closures ( post tax) ..................................................................................... $ 585 $ 793 $ 208 35.6 B. Cost to Revenue Measure 1. Facility Level Analysis EPA examined the annualized posttax compliance costs of the preferred option and the waterbody/ capacitybased option as a percentage of baseline annual revenues, for each of the 551 facilities subject to Phase II of the Section 316( b) regulation. This measure allows for a comparison of compliance costs incurred by each facility with its revenues in the absence of Phase II regulation. The revenue estimates are facility specific baseline projections from the IPM base case for 2008 ( see Section V of this Notice for a discussion of EPA's analyses using the IPM). 15 Similar to the findings at proposal, the results of this analysis show that the vast majority of facilities subject to the preferred option, 404 out of 551 ( 73 percent), would incur annualized costs of less than one percent of revenues. Of these, 292 facilities would incur compliance costs of less than 0.5 percent of revenues. Ninety seven facilities ( 18 percent) would incur costs of between one and three percent of revenues, and 41 facilities ( seven percent) would incur costs of greater than three percent. Eight facilities are estimated to be baseline closures, and for one facility, revenues are unknown. 16 Exhibit 8 below summarizes these findings and also presents the ratios estimated at proposal.

EXHIBIT 8   COST TO REVENUE RATIO FOR THE PREFERRED OPTION ( FACILITY LEVEL)

Annualized cost to revenue ratio Proposal NODA All phase II Percent of total phase II All phase II Percent of total phase II < 0.5% ............................................................................................................................... 331 60 292 53 >/= 0.5 to < 1.0% .............................................................................................................. 78 14% 112 20 >/= 1.0% to < 3.0% ........................................................................................................... 82 15 97 18 >/= 3.0% .......................................................................................................................... 46 8 41 7 Baseline Closure .............................................................................................................. 11 2 8 1 n/ a .................................................................................................................................... 1 0 1 0 Total .......................................................................................................................... 550 100 551 100 Exhibit 9 below presents the same information for the waterbody/ capacity based option. 17 VerDate Jan< 31> 2003 21: 22 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00015 Fmt 4701 Sfmt 4755 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13536 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 17 For the waterbody/ capacity based option, IPM revenues for 2008 were not available for seven facilities estimated to be baseline closures, ten facilities not modeled by the IPM, and two facilities projected to have zero baseline revenues. EPA used facility specific electricity generation and firmspecific wholesale prices as reported to the Energy Information Administration ( EIA) to calculate the cost to revenue ratio for the 12 non baseline closure facilities with missing information. The revenues for one of these facilities remains unknown. EXHIBIT 9.   COST TO REVENUE RATIO FOR THE WATERBODY/ CAPACITY BASED OPTION ( FACILITY LEVEL)

Annualized cost to revenue ratio Proposal NODA All phase II Percent of total phase II All phase II Percent of total phase II < 0.5% ............................................................................................................................... 355 65 281 51 >/= 0.5 to < 1.0% ............................................................................................................... 60 11 101 18 >/= 1.0 to < 3.0% ............................................................................................................... 57 10 102 19 >/= 3.0% ............................................................................................................................ 67 12 58 11 Baseline Closure .............................................................................................................. 9 2 7 1 n/ a .................................................................................................................................... 1 0 1 0 Total .......................................................................................................................... 550 100 551 100 2. Firm Level Analysis The firms owning the facilities subject to Phase II regulation may experience greater impacts than individual in scope facilities if they own more than one facility with compliance costs. EPA therefore also analyzed the cost torevenue ratios at the firm level. EPA identified the domestic parent entity of each in scope facility and obtained their sales revenue from publicly available data sources ( the Dun and Bradstreet database for parent firms of investorowned utilities and nonutilities; and Form EIA   861 for all other parent entities) and EPA's 2000 Section 316( b) Industry Survey. This analysis showed that 128 unique domestic parent entities own the facilities subject to Phase II regulation. For both analyzed options, EPA compared the aggregated annualized post tax compliance costs for each facility owned by the 128 parent entities to the firms' total sales revenue. Since proposal, EPA has not updated the parent firm determination for Phase II facilities. However, EPA updated the average Form EIA   861 data used for this analysis from 1996 to 1998 ( used at proposal) to 1997 to 1999 ( used for the NODA). In addition, EPA made one modification to the data sources used: At proposal, EPA used Dun and Bradstreet ( D& B) data for any parent entity listed in the database. If D& B data were not available, EPA used the EIA database or the Section 316( b) Survey. For the NODA analysis, EPA used the D& B database for privately owned entities only. For other entities, EPA used the EIA database. For the preferred option, EPA estimates that of the 128 unique entities, only two entities would incur compliance costs of greater than three percent of revenues; 11 entities would incur compliance costs of between one and three percent of revenues; eight entities would incur compliance costs of between 0.5 and one percent of revenues; and the remaining 107 entities would incur compliance costs of less than 0.5 percent of revenues. The highest estimated cost to revenue ratio for this NODA analysis is 7.4 percent of the entities' annual sales revenue ( at proposal this value was 5.3 percent). Exhibit 10 below summarizes these findings and also presents the ratios estimated at proposal.

EXHIBIT 10.   COST TO REVENUE RATIO FOR THE PREFERRED OPTION ( FIRM LEVEL)

Annualized cost to revenue ratio Proposal NODA All phase II Percent of total phase II All phase II Percent of total phase II < 0.5% ............................................................................................................................... 104 79 107 84 >/= 0.5 to < 1.0% .............................................................................................................. 12 9 8 6 >/= 1.0 to < 3.0% .............................................................................................................. 10 8 11 9 >/= 3.0% .......................................................................................................................... 3 2 2 2 Baseline Closure .............................................................................................................. 2 2 0 0 Total .......................................................................................................................... 131 100 128 100 Exhibit 11 below presents the same information for the waterbody/ capacity based option.

EXHIBIT 11.   COST TO REVENUE RATIO FOR THE WATERBODY/ CAPACITY BASED OPTION ( FIRM LEVEL)

Annualized cost to revenue ratio Proposal NODA All phase II Percent of total phase II All phase II Percent of total phase II < 0.5% .............................................................................................................................. 108 82 95 74 >/= 0.5 to < 1.0% .............................................................................................................. 12 9 16 13 >/= 1.0 to < 3.0% .............................................................................................................. 6 5 15 12 VerDate Jan< 31> 2003 19: 17 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13537 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 18 There are twelve NERC regions: ASCC ( Alaska Systems Coordinating Council), ECAR ( East Central Area Reliability Coordination Agreement), ERCOT ( Electric Reliability Council of Texas), FRCC ( Florida Reliability Coordinating Council), HI ( Hawaii), MAAC ( Mid Atlantic Area Council), MAIN ( Mid America Interconnected Network, Inc.), MAPP ( Mid Continent Area Power Pool), NPCC ( Northeast Power Coordination Council), SERC ( Southeastern Electricity Reliability Council), SPP ( Southwest Power Pool), and WSCC ( Western Systems Coordinating Council).

19 Note that Alaska and Hawaii are not represented in the AEO. EXHIBIT 11.   COST TO REVENUE RATIO FOR THE WATERBODY/ CAPACITY BASED OPTION ( FIRM LEVEL)   Continued Annualized cost to revenue ratio Proposal NODA All phase II Percent of total phase II All phase II Percent of total phase II >/= 3.0% .......................................................................................................................... 3 2 2 2 Baseline Closure .............................................................................................................. 2 2 0 0 Total .......................................................................................................................... 131 100 128 100 C. Cost Per Household EPA also conducted an analysis that evaluates the potential cost per household, if Phase II facilities were able to pass compliance costs on to their customers. This analysis estimates the average compliance cost per household for each North American Electricity Reliability Council ( NERC) region, 18 using two data inputs: ( 1) The average annual pre tax compliance cost per megawatt hour ( MWh) of total electricity sales and ( 2) the average annual MWh of residential electricity sales per household. The results of this analysis show that the average annual cost per residential household would range from $ 0.55 ( in ASCC) to $ 5.69 ( in HI) for the preferred option and from $ 0.55 ( in ASCC) to $ 20.41 ( in HI) for the waterbody/ capacity based option. Exhibit 12 below presents the values for each NERC region for the preferred option and the waterbody/ capacity based option. The exhibit also presents the values for the preferred option at proposal.

EXHIBIT 12.   SUMMARY OF COST PER HOUSEHOLD BY NERC REGION NERC region Preferred option W/ C based option Proposal ($ 2001) NODA ($ 2002) Change NODA ($ 2002)

ASCC ..................................................................................................................... $ 0.33 $ 0.55 $ 0.22 $ 0.55 ECAR ..................................................................................................................... 0.99 1.49 0.50 1.52 ERCOT .................................................................................................................. 1.01 1.12 0.11 1.75 FRCC ..................................................................................................................... 1.58 2.04 0.46 12.08 HI ........................................................................................................................... 2.55 5.69 3.14 20.41 MAAC ..................................................................................................................... 1.16 1.50 0.34 9.53 MAIN ...................................................................................................................... 0.84 1.32 0.48 1.32 MAPP ..................................................................................................................... 0.88 1.09 0.21 1.10 NPCC ..................................................................................................................... 1.09 1.49 0.40 4.57 SERC ..................................................................................................................... 0.83 1.17 0.34 3.21 SPP ........................................................................................................................ 0.64 0.88 0.24 0.88 WSCC .................................................................................................................... 0.36 0.94 0.58 5.08 U. S. Average ......................................................................................................... 0.87 1.30 0.43 4.00 D. Electricity Price Analysis EPA also considered potential effects of the proposed Phase II rule on electricity prices. EPA used three data inputs in this analysis: ( 1) Total pre tax compliance cost incurred by facilities subject to Phase II regulation, ( 2) total electricity sales, based on the Annual Energy Outlook ( AEO) 2002, and ( 3) prices by end use sector ( residential, commercial, industrial, and transportation), also from the AEO 2002. All three data elements were calculated by NERC region. The results of the NODA analysis show that the annualized costs of complying ( in cents per KWh sales) range from 0.007 cents in SPP to 0.020 cents in NPCC for the preferred option, and from 0.007 cents in SPP to 0.096 cents in MAAC for the waterbody/ capacity based option. To determine potential effects of these compliance costs on electricity prices, EPA compared the per KWh compliance cost to baseline electricity prices by end use sector and for the average of the sectors. This analysis shows that the average increase in electricity prices would be 0.17 percent under the preferred option and 0.51 percent under the waterbody/ capacity based option. ( At proposal, the estimated increase in electricity prices for the preferred option was 0.11 percent.) Exhibit 13 below presents the values for each NERC region for the preferred option and the waterbody/ capacitybased option. The exhibit also presents the values for the preferred option at proposal. 19 VerDate Jan< 31> 2003 19: 17 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13538 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules EXHIBIT 13.   SUMMARY OF ELECTRICITY PRICES BY NERC REGION NERC region Preferred option W/ C based option Proposal ($ 2001) NODA ($ 2002) NODA ($ 2002)

Annualized pretax compliance cost ( cents/ KWh sales) % change in price Annualized pretax compliance cost ( cents/ KWh sales) % change in price Annualized pretax compliance cost ( cents/ KWh sales) % change in price ECAR ............................................................. 0.010 0.15 0.015 0.23 0.015 0.23 ERCOT ........................................................... 0.007 0.11 0.008 0.12 0.013 0.18 FRCC ............................................................. 0.012 0.15 0.015 0.20 0.088 1.16 MAAC ............................................................. 0.012 0.13 0.015 0.17 0.096 1.05 MAIN .............................................................. 0.010 0.14 0.016 0.22 0.016 0.22 MAPP ............................................................. 0.008 0.13 0.010 0.15 0.010 0.16 NPCC ............................................................. 0.017 0.19 0.020 0.22 0.061 0.68 SERC ............................................................. 0.006 0.10 0.008 0.14 0.023 0.38 SPP ................................................................ 0.005 0.09 0.007 0.12 0.007 0.12 WSCC ............................................................ 0.004 0.05 0.010 0.13 0.053 0.70 U. S. Average .................................................. 0.008 0.11 0.012 0.17 0.037 0.51 VII. Performance Standards In the proposed rule, EPA set up a framework that would require facilities that did not reduce their intake capacity commensurate with a closed cycle recirculating cooling system to meet certain other performance standards for reducing impingement mortality and entrainment based on technologies such as fine mesh screens and fish return systems. These other performance standards were based on the source water body type where the cooling water intake structure is located, the facility's capacity utilization rate, and the proportion or volume of the water body that is withdrawn by the facility. In general, most facilities would be required to implement control technologies that reduce impingement mortality by 80 to 95 percent and/ or entrainment by 60 to 90 percent unless they demonstrate the need for a sitespecific determination of best technology available. ( See proposed § 125.94 and Chapter VI. Best Technology Available for Minimizing Adverse Environmental Impact at Phase II Existing Facilities ( 67 FR 17140)).

A. Technology Efficacy Database to Support Performance Standards In an effort to document and further assess the performance of various technologies and operational measures designed to minimize the impacts of cooling water withdrawals, EPA compiled a database of documents that analyzes the efficacy of a specific technology or suite of technologies. The database contains materials that range from brief journal articles to more intensive analyses found in historical section 316( b) demonstration reports and technology evaluations. At this time, EPA is assembling as much documentation as possible to support future Agency decisions. Information entered into the database includes some notation of the limitations the individual studies may have for use in further analyses ( e. g., no biological data or conclusions). EPA's intent in assembling this information is four fold. First, EPA seeks to develop a categorized database containing a comprehensive collection of available literature regarding technology performance that will serve as a more rigorous compilation of data supporting the determination that the proposed performance standards are best technology available. Second, EPA expects to use the data to demonstrate that the technologies chosen as compliance technologies for costing purposes are reasonable and can meet the performance standards. Third, the availability of a user friendly database would allow EPA, State permit writers, and the public to more easily evaluate potential compliance options, facility compliance with performance standards, and data pertaining to the streamlined option described in this NODA ( see section VII. B below). Fourth, EPA has attempted to evaluate the technology efficacy data against objective criteria in order to assess the general quality and thoroughness of each study. This may assist in further analysis of conclusions made using the data. Basic information from each document is recorded in the database ( e. g., type of technology evaluated, facility at which it was tested, etc.) In addition to basic document information, the database contains information in two principal areas: ( 1) General facility information and ( 2) detailed study information. For those documents that refer to a specific facility ( or facilities), basic technical information is included to enable EPA to classify facilities according to general categories. EPA collected locational data ( e. g., waterbody type, name, state) as well as basic cooling water intake structure configuration information. Each technology evaluated in the study is also recorded, along with specific details regarding its design and operation. Major categories of technology include modified traveling screens, wedge wire screens, fine mesh screens, velocity caps, barrier nets, and behavioral barriers. ( Data identifying the technologies present at a facility as well as the configuration of the intake structure refer to the configuration at the time the study was conducted and do not necessarily reflect the present facility set up.) Information on the type of study and any study results, is recorded in the second portion of the database. EPA identifies whether the study evaluates the technology with respect to impingement mortality reduction ( or avoidance), entrainment survival, or entrainment exclusion ( or avoidance). Some studies address more than one area of concern and are noted accordingly. If provided, EPA records basic biological data used to evaluate the technology. These include target or commercially/ recreationally valuable species, species type, life history stage, size, sample size, and raw numbers of impinged and/ or entrained organisms. Finally, EPA records any overall conclusions reached by the study, usually presented as a percentage reduction or increase, depending on the area of focus. Identifying this information for each document allows EPA and others to more readily locate VerDate Jan< 31> 2003 19: 17 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13539 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules 20 Information to support the use of restoration measures and/ or the use of site specific determinations would be required to be collected and submitted only by permit applicants that choose to use restoration measures or demonstrate that a site specific determination of best technology available is appropriate for their facility. and compare documents addressing similar technologies. Each document is reviewed according to five areas of data quality where possible: ( 1) Applicability and utility, ( 2) soundness, ( 3) clarity and completeness, ( 4) uncertainty and variability, and ( 5) evaluation and review. Because the literature in question comes from many different sources and was developed under widely varying standards, EPA was not able to evaluate all of these criteria for all documents contained in the database. To date, EPA has collected 148 documents for inclusion in the database. EPA did not exclude any document that addressed technology performance in relation to impingement and entrainment, regardless of the overall quality of the data. Sample questions are included in Exhibit 1 below. The proposed technology database is available in the record ( See the document `` Technology Efficacy Database'' in the docket).

EXHIBIT 1.   QUALITY ASSURANCE SAMPLE QUESTIONS QA Criteria Sample Questions Applicability and Utility.   Does the study address impingement and/ or entrainment reduction?   Does the study evaluate a technology ( or technologies) in situ or against performance data from another source?   Does the study include biological data?

Soundness .........   Does the study detail the CWIS configuration at the time of the study?   Are SOPs for sampling and testing included?   Is some measure of before and after biological data included?   Are O& M procedures described for the test period?

Clarity and Completeness   Is the sampling method clearly described?   Is a complete biological data set included?   Are results clearly and completely documented

Uncertainty and Variability.   Does the study identify potential uncertainties or mitigating factors such as those due to environmental conditions EXHIBIT 1.   QUALITY ASSURANCE SAMPLE QUESTIONS   Continued QA Criteria Sample Questions Evaluation and Review.   What is the source of the document?   Is the document a primary study?   Has the document been peer reviewed?   Was the purpose of the study to evaluate the performance of a specific technology?

EPA is seeking comment on the applicability, quality, and quantity of the information and analyses in this database upon which EPA is relying. More specifically, EPA requests comment on whether these data are of sufficient quantity and quality to support the determination that the proposed performance standards are best technology available and that the existing facilities can meet these standards by implementing design and construction technologies either singly or in conjunction with other design and construction technologies ( including operational and restoration measures). In addition, EPA requests comment on limitations of the data and identification of other relevant information available to be included in this database. Based on a preliminary review of the available data, the Agency continues to believe that an 80   95% reduction in impingement mortality and a 60   90% reduction in entrainment are achievable.

B. Streamlined Technology Option for Certain Locations EPA received a number of comments expressing concern that the proposed Comprehensive Demonstration Study requirements at § 125.95( b) would impose a significant burden on permit applicants. As proposed, the Comprehensive Demonstration Study would have as many as seven different components: ( 1) A Proposal for Information Collection, ( 2) Source Waterbody Flow Information; ( 3) an Impingement Mortality and Entrainment Characterization Study; ( 4) a Design and Construction Technology Plan; ( 5) Information to Support any Proposed Restoration Measures; ( 6) Information to Support Site Specific Determination of Best Technology Available for Minimizing Adverse Environmental Impact; and ( 7) a Verification Monitoring Plan. 20 The proposed Comprehensive Demonstration Study requirement would allow a permit applicant to either identify and compile available existing data, or to perform new site specific studies to characterize the waterbody within the influence of the cooling water intake structure and the efficacy of proposed technologies. Some commenters suggested that EPA provide an additional, more streamlined compliance option under which a facility could implement certain specified technologies that are deemed highly protective in exchange for not having to perform, or greatly reducing the scope of, the proposed Comprehensive Demonstration Study required at § 125.95( b). In response to these comments EPA is considering, and invites the public to comment on two variations of a streamlined compliance option that would reduce the information collection burden imposed on permit applicants. Under the first variation, EPA would evaluate the effectiveness of specific technologies using the impingement mortality and entrainment performance standards specified in the proposed rule as assessment criteria. Specifically, EPA would require that the demonstrated efficacy of the control technology would at least reduce impingement mortality by 80 to 95 percent for fish and shellfish. If it was also to be used by facilities with an additional requirement to reduce entrainment by 60 to 90 percent for all life stages of fish and shellfish, then EPA would ensure that the technology would also satisfy this requirement. Evaluation of the level of impingement mortality or entrainment reduction would be based on review and analysis of available data, studies, and literature. The Agency also would assess the conditions where such technologies are effective ( e. g., location, whether a technology reduces impingement or entrainment or both, flow, velocity, species, life stage, etc.). If, based on such an assessment, the Agency identifies technologies that are sufficiently protective and for which applicability conditions can be defined, EPA would promulgate regulations ( either as part of the 316( b) Phase II rule or at some later date) that allow for their use as a means of complying with Phase II section 316( b) requirements. EPA is in the process of assessing this option and has not completed a comprehensive review of control technology efficacy data for the purpose of identifying and delineating technologies that might qualify under this option. However, the efficacy data VerDate Jan< 31> 2003 19: 17 Mar 18, 2003 Jkt 200001 PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 19MRP2. SGM 19MRP2 13540 Federal Register / Vol. 68, No. 53 / Wednesday, March 19, 2003 / Proposed Rules currently available to EPA do seem to support the use of a streamlined technology option for certain limited locations. Such a technology would be used to treat the entire cooling water intake flow and would not be used in combination with restoration measures to meet the performance standards. EPA is considering whether the following technology operated in the following locations would qualify for streamlined application requirements:

Use of submerged wedge wire screens where the cooling water intake structure is located in a freshwater river or stream, sustained countercurrents exist to promote cleaning of the screen face, and the design intake velocity is 0.5 feet per second ( ft/ s) or less.