[Federal Register: March 19, 2003 (Volume 68, Number 53)]
[Proposed Rules]               
[Page 13521-13587]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr19mr03-29]                         


[[Page 13521]]

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Part IV





Environmental Protection Agency





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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


[[Page 13522]]


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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.

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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 

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

[[Page 13523]]

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 OW-
Docket@epa.gov, Attention Docket ID No. OW-2002-0049. In contrast to 

EPA's electronic public docket, EPA's e-mail 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

[[Page 13524]]

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 site-specific 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 non-quantitative 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.
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    \1\ Note that these numbers are unweighted. On a sample-weighted 
basis, the number of Phase II facilities increased from 550 to 551.
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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/capacity-based 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\
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    \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.

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[[Page 13525]]

    The revised costing assumptions are discussed in detail below. EPA 
notes that the proposed rule includes a compliance option that allows 
site-specific 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 Sec.  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/capacity-based 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 fossil-fuel 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 site-specific 
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 
closed-cycle, 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 
Sec.  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,

[[Page 13526]]

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

[[Page 13527]]

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 site-specific 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 site-specific 
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[reg] 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

[[Page 13528]]

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).
---------------------------------------------------------------------------

    \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 (Southwest Power 
Pool), and WSCC (Western Systems Coordinating Council). Electric 
generators in Alaska and Hawaii are not modeled by the IPM.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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:
---------------------------------------------------------------------------

    \6\ For more information on changes made to the EPA Base Case 
2000, see EBA, Chapter B3, Section B3-2.2.
---------------------------------------------------------------------------

    [sbull] 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 non-
steam 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.
    [sbull] 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:
    [sbull] 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 Sec.  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.
    [sbull] 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

[[Page 13529]]

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.

    [sbull] 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 post-compliance 
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 non-run years are not taken into 
account).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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, non-dispatched 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.

[[Page 13530]]

    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.
---------------------------------------------------------------------------

    \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 

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.
---------------------------------------------------------------------------

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) 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 wholesale prices received by facilities for the sale of 
electric generation; and (5) post-compliance changes in pre-tax income, 
where pre-tax 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)
----------------------------------------------------------------------------------------------------------------
                                                         Closures as     Change in                    Change in
                             Baseline     Incremental       % of         variable       Change in      pre-tax
       NERC region           capacity      capacity       baseline      production    energy price     income
                               (MW)      closures (MW)    capacity     cost per MWh      per MWh       ($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

[[Page 13531]]

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)
----------------------------------------------------------------------------------------------------------------
                                              Incremental closures       Change in
                                Baseline  ---------------------------    variable       Change in     Change in
         NERC region            capacity                    % of        production     generation      pre-tax
                                  (MW)       Capacity     baseline     cost per MWh        (%)       Income (%)
                                               (MW)       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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Reduction                           Increase
                                                           ----------------------------------------------------------------------
                     Economic measures                                                                       No change      N/A
                                                             [lE]=1%      1-3%         3%       [lE]=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

[[Page 13532]]

utilization and generation, most would experience decreases in these 
measures. Exhibit 3 also indicates that the majority of facilities with 
changes in post-compliance 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 13533]]


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)
----------------------------------------------------------------------------------------------------------------
                                            Closure analysis          Change in
                            Baseline  ----------------------------     variable       Change in    Change in pre-
          NERC              capacity     Capacity   % of baseline  production cost    generation     tax income
                              (MW)         (MW)        capacity        per MWh
----------------------------------------------------------------------------------------------------------------
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,

[[Page 13534]]

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Reduction                             Increase
                   Economic measures                   --------------------------------------------------------------------------  No change      N/A
                                                          [lE]1%      1-3%    3%    [lE]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[reg]) 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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

[[Page 13535]]

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).
---------------------------------------------------------------------------

    \14\ The number of baseline closures is different for the 
preferred option and the waterbody/capacity-based option because 
different IPM base cases were used to estimate baseline closures. 
See footnote 8 above for a full explanation.
---------------------------------------------------------------------------

    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       NODA              Change
                                                                ($2001;      ($2002;   -------------------------
                                                                 mill.)       mill.)      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 post-tax compliance costs of the 
preferred option and the waterbody/capacity-based 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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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-to-revenue ratio for the 15 non-baseline closure facilities 
with missing information. The revenues for one of these facilities 
remains unknown.

                   Exhibit 8--Cost-to-Revenue Ratio for the Preferred Option (Facility Level)
----------------------------------------------------------------------------------------------------------------
                                                                      Proposal                    NODA
                                                             ---------------------------------------------------
              Annualized cost-to-revenue ratio                              Percent of                Percent of
                                                               All phase   total phase   All phase   total phase
                                                                   II           II           II           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\

[[Page 13536]]



           Exhibit 9.--Cost-to-Revenue Ratio for the Waterbody/Capacity-Based Option (Facility Level)
----------------------------------------------------------------------------------------------------------------
                                                                      Proposal                    NODA
                                                             ---------------------------------------------------
              Annualized cost-to-revenue ratio                              Percent of                Percent of
                                                               All phase   total phase   All phase   total phase
                                                                   II           II           II           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-to-revenue 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 investor-owned 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.
---------------------------------------------------------------------------

    \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 firm-specific 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.
---------------------------------------------------------------------------

    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)
----------------------------------------------------------------------------------------------------------------
                                                                      Proposal                    NODA
                                                             ---------------------------------------------------
              Annualized cost-to-revenue ratio                              Percent of                Percent of
                                                               All phase   total phase   All phase   total phase
                                                                   II           II           II           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)
----------------------------------------------------------------------------------------------------------------
                                                                      Proposal                    NODA
                                                             ---------------------------------------------------
              Annualized cost-to-revenue ratio                              Percent of                Percent of
                                                               All phase   total phase   All phase   total phase
                                                                   II           II           II           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

[[Page 13537]]


/= 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                      Preferred option                W/C-based
                                                        -------------------------------------------    option
                      NERC region                           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/capacity-based option. The exhibit 
also presents the values for the preferred option at proposal.\19\
---------------------------------------------------------------------------

    \19\ Note that Alaska and Hawaii are not represented in the AEO.

[[Page 13538]]



                                                Exhibit 13.--Summary of Electricity Prices by NERC Region
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Preferred option                            W/C-based option
                                                                  --------------------------------------------------------------------------------------
                                                                         Proposal ($2001)               NODA ($2002)                 NODA ($2002)
                                                                  --------------------------------------------------------------------------------------
                           NERC region                             Annualized pre-              Annualized pre-              Annualized pre-
                                                                   tax compliance  % change in  tax compliance  % change in  tax compliance  % change in
                                                                    cost (cents/      price      cost (cents/      price      cost (cents/      price
                                                                     KWh sales)                   KWh sales)                   KWh sales)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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