FR Doc 03-6453

[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

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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

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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

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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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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
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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