United States Office of Water EPA-821-R-02-001
Environmental Protection (4303) February 2002
Agency
&EPA Economic and Benefits
Analysis for the Proposed
Section 316(b) Phase II
Existing Facilities Rule
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Economic and Benefits Analysis for the Proposed Section
316(b) Phase II Existing Facilities Rule
U.S. Environmental Protection Agency
Office of Science and Technology
Engineering and Analysis Division
Washington, DC 20460
February 28, 2002
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ACKNOWLEDGMENTS AND DISCLAIMER
This document was prepared by the Office of Water staff. The following contractors provided assistance and support in
performing the underlying analysis supporting the conclusions detailed in this document.
Abt Associates Inc.
Science Applications International Corporation
Stratus Consulting Inc.
Tetra Tech
The Office of Water has reviewed and approved this document for publication. The Office of Science and Technology
directed, managed, and reviewed the work of the contractors in preparing this document. Neither the United States
Government nor any of its employees, contractors, subcontractors, or their employees makes any warranty, expressed or
implied, or assumes any legal liability or responsibility for any third party's use of or the results of such use of any
information, apparatus, product, or process discussed in this document, or represents that its use by such party would not
infringe on privately owned rights.
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§ 316(b) Phase II EBA Table of Contents
Table of Contents
PART A: BACKGROUND INFORMATION
Chapter Al: Introduction and Overview
Al-l Scope of the Proposed Rule Al-1
Al-2 Definitions of Key Concepts Al-2
Al-3 Summary of the Proposed Rule Al-3
Al-3.1 Proposed Performance Standards Al-3
Al-4 Summary of Alternative Regulatory Options Al-6
A1-5 Compliance Responses of the Proposed Rule and Alternative Options A1-8
Al-6 Organization of the EBA Report Al-10
References Al-12
Chapter A2: The Need for Section 316(b) Regulation
A2-1 Overview of Regulated Facilities A2-1
A2-1.1 Phase II Sector Information A2-1
A2-1.2 Phase II Facility Information A2-2
A2-2 The Need for Section 316(b) Regulation A2-4
A2-2.1 Low Levels of Protection at Phase II Facilities A2-5
A2-2.2 Reducing Adverse Environmental Impacts A2-7
A2-2.3 Addressing Market Imperfections A2-8
A2-2.4 Reducing Differences Between the States A2-10
A2-2.5 Reducing Transaction Costs A2-12
References A2-14
Chapter A3: Profile of the Electric Power Industry
A3-1 Industry Overview A3-1
A3-1.1 Industry Sectors A3-2
A3-1.2 Prime Movers A3-2
A3-1.3 Ownership A3-3
A3-2 Domestic Production A3-5
A3-2.1 Generating Capacity A3-6
A3-2.2 Electricity Generation A3-7
A3-2.3 Geographic Distribution A3-8
A3-3 Existing Plants with CWIS and NPDES Permits A3-11
A3-3.1 Existing Section 316(b) Utility Plants A3-13
A3-3.2 Existing Section 316(b) Nonutility Plants A3-18
A3-4 Industry Outlook A3-24
A3-4.1 Current Status of Industry Deregulation A3-24
A3-4.2 Energy Market Model Forecasts A3-25
Glossary A3-27
References A3-29
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§ 316(b) Phase II EBA Table of Contents
PART B: COSTS AND ECONOMIC IMPACTS
Chapter Bl: Summary of Compliance Costs
Bl-l Unit Costs Bl-1
Bl-1.1 Technology Costs Bl-2
Bl-1.2 Energy Costs Bl-6
Bl-1.3 Administrative Costs Bl-9
Bl-2 Assigning Compliance Years to Facilities Bl-13
Bl-3 Total Private Compliance Costs Bl-14
Bl-3.1 Methodology Bl-14
Bl-3.2 Total Private Costs of the Proposed Rule Bl-16
Bl-4 Limitations and Uncertainties Bl-17
References Bl-18
Appendix to ChapterBl Bl-20
B1-A. 1 Assignment of Compliance Years for Cooling Tower Options B1-20
Bl-A.1.1 Methodology Bl-20
Bl-A.1.2 Summary of Cooling Tower Facilities by Compliance Year Bl-21
Chapter B2: Cost Impact Analysis
B2-1 Cost-to-Revenue Measure B2-1
B2-1.1 Facility Analysis B2-2
B2-1.2 Firm Analysis B2-3
B2-2 Cost Per Household B2-4
B2-3 Electricity Price Analysis B2-6
References B2-8
Chapter B3: Electricity Market Model Analysis
B3-1 Summary Comparison of Energy Market Models B3-1
B3-2 Integrated Planning Model Overview B3-3
B3-2.1 Modeling Methodology B3-3
B3-2.2 Specifications for the Section 316(b) Analysis B3-6
B3-2.3 Model Inputs B3-7
B3-2.4 Model Outputs B3-8
B3-3 Economic Impact Analysis Methodology B3-9
B3-3.1 Market-level Impact Measures B3-9
B3-3.1 Facility-level Impact Measures B3-10
B3-4 Analysis Results for the Proposed Rule B3-11
B3-4.1 Market Analysis B3-13
B3-4.2 Analysis of Phase II Facilities B3-15
B3-5 Summary of Findings B3-17
B3-6 Uncertainties and Limitations B3-17
References B3-19
Appendix to Chapter B3 B3-20
B3-A. 1 Summary Comparison of Energy Market Models B3-20
B3-A.2 Differences Between EPA Base Case 2000 and Previous Model Specifications B3-25
Chapter B4: Regulatory Flexibility Analysis
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§ 316(b) Phase II EBA Table of Contents
B4-1 Number of In-Scope Facilities Owned by Small Entities B4-2
B4-1.1 Identification of Domestic Parent Entities B4-2
B4-1.2 Size Determination of Domestic Parent Entities B4-3
B4-2 Percent of Small Entities Regulated B4-5
B4-3 Sales Test for Small Entities B4-6
B4-4 Summary B4-7
References B4-8
Chapter B5: UMRA Analysis
B5-1 Analysis of Impacts on Government Entities B5-1
B5-1.1 Compliance Costs for Government-Owned Facilities B5-2
B5-1.2 Administrative Costs B5-2
B5-1.3 Impacts on Small Governments B5-6
B5-2 Compliance Costs for the Private Sector B5-7
B5-3 Summary of UMRA Analysis B5-8
References B5-9
Chapter B6: Other Administrative Requirements
B6-1 E.G. 12866: Regulatory Planning and Review B6-1
B6-2 E.G. 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income
Populations B6-1
B6-3 E.G. 13045: Protection of Children from Environmental Health Risks and Safety Risks B6-3
B6-4 E.G. 13132: Federalism B6-4
B6-5 E.G. 13158: Marine Protected Areas B6-5
B6-6 E.G. 13175: Consultation with Tribal Governments B6-6
B6-7 E.G. 13211: Energy Effects B6-6
B6-8 Paperwork Reduction Act of 1995 B6-7
B6-9 National Technology Transfer and Advancement Act B6-7
References B6-8
Chapter B7: Alternative Options - Costs and Economic Impacts
B7-1 Waterbody/Capacity-based Option B7-2
B7-1.1 Compliance Costs B7-2
B7-1.2 Cost-to-Revenue Measure B7-4
B7-1.3 SBREFA Analysis B7-6
B7-2 Impingement Mortality and Entrainment Controls Everywhere Option B7-6
B7-2.1 Compliance Costs B7-6
B7-2.2 Cost-to-Revenue Measure B7-8
B7-2.3 SBREFA Analysis B7-9
B7-3 All Cooling Towers Option B7-9
B7-3.1 Compliance Costs B7-9
B7-3.2 Cost-to-Revenue Measure B7-11
B7-3.3 SBREFA Analysis B7-12
B7-4 Dry Cooling Option B7-12
B7-4.1 Compliance Costs B7-12
B7-4.2 Cost-to-Revenue Measure B7-14
B7-4.3 SBREFA Analysis B7-15
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§ 316(b) Phase II EBA Table of Contents
Chapter B8: Alternative Options - Electricity Market Model Analysis
B8-1 Overview of IPM Analysis of Alternative Options B8-1
B8-2 Market Analysis Level B8-2
B8-3 Analysis of Phase II Facilities B8-12
B8-3.1 Group of Phase II Facilities B8-12
B8-3.2 Individual Phase II Facilities B8-20
B8-4 Uncertainties and Limitations B8-22
References B8-24
Appendix to Chapter B8 B8-26
B8-A1 Market Analysis B8-26
B8-A2 Phase II Facility Analysis B8-31
B8-A2.1 Group of Phase II Facilities B8-31
B8-A2.2 Individual Phase II Facilities B8-35
PART C: NATIONAL BENEFITS
Chapter Cl: Introduction to the Case Studies
Cl-l Why Case Studies were Undertaken Cl-1
Cl-2 What Sites were Chosen and Why Cl-1
Cl-3 Steps Taken in the Case Studies Cl-3
Cl-4 Summary of Case Study Analyses Cl-3
Cl-5 Data Uncertainties Leading to Underestimates of Case Study Impacts and Benefits Cl-6
Cl-5.1 Data Limitations Cl-6
Cl-5.2 Estimated Technology Effectiveness Cl-6
Cl-5.3 Potential Cumulative Impacts Cl-6
Cl-5.4 Recreational Benefits Cl-7
Cl-5.5 Secondary (indirect) Economic Impacts Cl-7
Cl-5.6 Commercial Benefits Cl-7
Cl-5.7 Forage Species Cl-7
Cl-5.8 Nonuse Benefits Cl-8
Cl-5.9 Incidental Benefits Cl-8
Appendix to Chapter Cl Cl-10
Cl-A. 1 Options with Benefit Estimates Cl-10
C1-A.2 Impingement Reductions and Benefits Cl-11
C1-A.3 Entrainment Reductions and Benefits Cl-12
C1-A.4 Benefits Associated with Various Percentage Reductions Cl-13
C1.A.5 Benefits Associated with the Proposed Option Cl-13
Chapter C2: Summary of Case Study Results
C2-1 The Delaware Estuary Watershed (Mid-Atlantic Estuaries) C2-1
C2-2 Tampa Bay Watershed Study (Gulf Estuaries) C2-3
C2-3 The Ohio River Watershed Study (Large Rivers) C2-4
C2-4 San Francisco Bay/Delta (Western Estuaries) C2-6
C2-5 Mount Hope Bay (New England Estuaries) C2-7
C2-6 Oceans (New England Coast) C2-8
C2-7 The GreatLakes C2-9
C2-8 Large River Tributary to the Great Lakes C2-10
IV
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§ 316(b) Phase II EBA Table of Contents
C2-9 National Baseline Losses Due to I&E at In-Scope Facilities C2-11
Chapter £3: National Extrapolation of Baseline Economic Losses
C3-1 Extrapolation Methodology C3-1
C3-1.1 Consideration of Volume of Water (Flow) C3-2
C3-1.2 Consideration of Level of Recreational Angling C3-2
C3-1.3 Consideration of Waterbody Type C3-3
C3-1.4 Angling and Flow Indices C3-4
C3-1.5 Waterbody Considerations C3-4
C3-1.6 Advantages and Disadvantages of EPA's Extrapolation Approach C3-5
C3-2 Results of National Benefits Extrapolation C3-5
C3-2.1 Case Study Baseline Losses C3-6
C3-2.2 Extrapolation of Baseline Losses to All Facilities Using Flow Index C3-7
C3-2.3 Extrapolation of Baseline Losses to All Facilities Using Angling Index C3-8
C3-2.4 Average of Flow-Based and Angling-Based Losses C3-9
C3-2.5 Best Estimates C3-10
References C3-12
Chapter C4: Benefits
C4-1 Options with Benefit Estimates C4-1
C4-2 Impingement Reductions and Benefits C4-2
C4-3 Entrainment Reductions and Benefits C4-3
C4-4 Certainty Levels Associated with the Benefits Estimates of Various Options C4-4
C4-5 Benefits Associated with Various Impingement and Entrainment Percentage Reductions C4-5
C4-6 Impingement and Entrainment Benefits Associated with The Proposed Option C4-5
PART D: NATIONAL BENEFIT-COST ANALYSIS
Chapter Dl: Comparison of National Costs and Benefits
Dl-l Social Costs Dl-2
Dl-2 Summary of National Benefits and Social Costs Dl-4
Glossary Dl-5
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
Chapter A1: Introduction and
Overview
INTRODUCTION CHARTER CQNTENTS
Al-l Scope of the Proposed Rule Al-1
Al-2 Definitions of Key Concepts Al-2
Al-3 Summary of the Proposed Rule Al-3
Al-3.1 Proposed Performance Standards Al-3
A1-4 Summary of Alternative Regulatory Options ... A1-6
Al-5 Compliance Responses of the Proposed Rule and
Alternative Options Al-8
Al-6 Organization of the EBA Report Al-10
References Al-12
EPA is proposing regulations implementing Section 316(b)
of the Clean Water Act (CWA) for existing facilities with a
design cooling water intake flow of 50 million gallons per
day (MOD) or greater (33 U.S.C. 1326(b)). The Proposed
Section 316(b) Phase II Existing Facilities Rule would
establish national technology-based performance
requirements applicable to the location, design, construction,
and capacity of cooling water intake structures (CWIS) at
existing facilities. The proposed national requirements
would establish the best technology available (BTA) to
minimize the adverse environmental impact (AEI) associated with the use of these structures. CWIS may cause AEI through
several means, including impingement (where fish and other aquatic life are trapped on equipment at the entrance to CWIS)
and entrainment (where aquatic organisms, eggs, and larvae are taken into the cooling system, passed through the heat
exchanger, and then discharged back into the source water body).
Al-1 SCOPE OF THE PROPOSED RULE
The proposed Phase II rule applies to existing power producing facilities that meet all of the following conditions:
They use a cooling water intake structure or structures, or obtain cooling water by any sort of contract or arrangement with an
independent supplier who has a cooling water intake structure; or their cooling water intake structure(s) withdraw(s) cooling
water from waters of the U.S., and at least twenty-five (25) percent of the water withdrawn is used for contact or non-contact
cooling purposes;
>• They have an NPDES permit or are required to obtain one; and
>• They have a design intake flow of 50 MOD or greater.
The proposed Phase II rule also covers substantial additions or modifications to operations undertaken at such facilities.
While all facilities that meet these criteria are subject to the regulation, this Economic and Benefit Analysis (EBA) focuses on
539 utility and non-utility steam electric power generating facilities identified in EPA's 2000 Section 316(b) Industry Survey
as being potentially covered by this proposed rule. These 539 facilities represent 550 facilities nation-wide.1
The proposed Phase II rule does not cover (1) new steam electric power generating facilities, (2) new manufacturing facilities,
(3) existing steam electric power generating facilities with a design intake flow of less than 50 MOD, and (4) existing
manufacturing facilities. The Final Section 316(b) New Facility Rule (Phase I), which EPA promulgated in November 2001,
covered new steam electric power generating facilities and new manufacturing facilities. Existing steam electric power
generating facilities with a design intake flow of less than 50 MOD and existing manufacturing facilities will be addressed by
a separate rule (Phase III).
1 EPA applied sample weights to the 539 facilities to account for non-sampled facilities and facilities that did not respond to the
survey. For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA, 2000).
Al-1
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
Al-2 DEFINITIONS OF KEY CONCEPTS
This EBA presents EPA's analyses of costs, benefits, and potential economic impacts as a result of the proposed Phase II rule.
In addition to important economic concepts, which will be presented in the following chapters, understanding this document
requires familiarity with a few key concepts applicable to CWA section 316(b) and this regulation. This section defines these
key concepts.
*• Capacity Utilization Rate: The ratio between the average annual net generation of the facility (in MWh) and the
total net capability of the facility (in MW) multiplied by the number of available hours during a year. The average
annual generation must be measured over a five year period (if available) of representative operating conditions.
*• Cooling Water Intake Structure (CWIS): The total physical structure and any associated constructed waterways
used to withdraw water from waters of the U.S. The CWIS extends from the point at which water is withdrawn from
the surface water source up to, and including, the intake pumps.
*• Design Intake Flow: The value assigned (during the facility's design) to the total volume of water withdrawn from a
source waterbody over a specific time period.
* Entrainment: The incorporation of all life stages of aquatic organisms with intake water flow entering and passing
through a CWIS and into a cooling water system (e.g., fish and shellfish).
*• Existing Facility: Existing facility means any facility that commenced construction before January 17, 2002; and
(1) any modification of such a facility;
(2) any addition of a unit at such a facility for purposes of the same industrial operation;
(3) any addition of a unit at such a facility for purposes of a different industrial operation, if the additional unit
uses an existing CWIS and the design capacity of the intake structure is not increased; or
(4) any facility constructed in place of such a facility, if the newly constructed facility uses an existing CWIS
whose design intake flow is not increased to accommodate the intake of additional cooling water.
*• Impingement: The entrapment of all life stages of aquatic organisms on the outer part of an intake structure or
against a screening device during periods of intake water withdrawal (e.g., fish, shellfish, turtles, birds, seals, etc.).
*• Phase IIExisting Facility: An existing facility, as defined above, that also meets the following requirements:
(1) is a point source that uses or proposes to use a CWIS; and
(2) both generates and transmits electric power, or generates electric power but sells it to another entity for
transmission; and
(3) has at least one CWIS that uses at least 25 percent of the water it withdraws for cooling purposes; and
(4) has a design intake flow of 50 MGD or more.
The category of facilities that would meet the proposed CWIS criteria for Phase II existing facilities are electric
power generation utilities and nonutility power producers, including cogeneration facilities.
Al-2
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
Al-3 SUMMARY OF THE PROPOSED RULE
The Proposed Section 316(b) Phase II Existing Facilities Rule would establish national standards applicable to the location,
design, construction, and capacity of CWIS at Phase II existing facilities to minimize AEI. The requirements of the proposed
Phase II rule reflect the BTA for minimizing AEI associated with the CWIS based primarily on source water body type and
the amount of cooling water withdrawn by a facility. A facility may choose one of three compliance alternatives for meeting
BTA requirements under this proposed rule:
*• Compliance Alternative 1 allows a facility to demonstrate that its existing CWIS design and construction
technologies, operational measures, or restoration measures currently meet the specified performance standards.
> Compliance Alternative 2 allows a facility to select and implement design and construction technologies,
operational measures, or restoration measures that satisfy the specified performance standards.
*• Compliance Alternative 3 allows a facility to demonstrate that it meets specified compliance cost criteria and obtain
a site-specific determination of BTA for minimizing AEI.
Al-3.1 Proposed Performance Standards
The proposed Phase II performance standards are based on several key factors, including CWIS intake capacity, facility
capacity utilization rate, source waterbody category, and percentage of the source water being withdrawn. The proposed rule
would establish performance standards for three groups of waterbody categories. These include (1) tidal rivers, estuaries,
oceans, and the Great Lakes; (2) lakes (other than the Great Lakes) and reservoirs; and (3) freshwater rivers or streams. The
performance standards include the following:
*• Capacity - Any Phase II facility that reduces its intake capacity to a level commensurate with that which can be
achieved by a closed cycle, recirculating cooling system is not subject to further requirements under the proposed
rule. This is applicable to facilities with CWIS located in any of the waterbody categories.
*• Capacity Utilization Rate - Any Phase II facility with a capacity utilization rate that is less than 15 percent must
reduce impingement mortality of all life stages of fish and shell fish by 80 to 95 percent from the calculation
baseline, regardless of proportional flow level of the facility.
> Source Waterbody Category/Proportion of Waterbody - These requirements vary according the combination of
waterbody category and percentage of the waterbody withdrawn:
*• Facilities with one or more CWIS located in an estuary, tidal river, ocean, or Great Lake must reduce
impingement mortality of all life stages of fish and shell fish by 80 to 95 percent from the calculation baseline,
and it must reduce entrainment of all life stages of fish and shellfish by 60 to 90 percent from the calculation
baseline;
>• Facilities with one or more CWIS located in a freshwater river or stream must reduce impingement mortality of
all life stages offish and shell fish by 80 to 95 percent from the calculation baseline and must reduce
entrainment of all life stages of fish and shellfish by 60 to 90 percent from the calculation baseline if they have a
design intake flow greater than 5 percent of mean annual flow;
*• Facilities with one or more CWIS located in a freshwater river or stream must reduce impingement mortality of
all life stages of fish and shell fish by 80 to 95 percent from the calculation baseline if they have a design intake
flow that is 5 percent or less of mean annual flow;
>• Facilities with one or more CWIS located in a lake or reservoir must reduce impingement mortality of all life
stages of fish and shell fish by 80 to 95 percent from the calculation baseline. In addition, if such facilities
propose to increase design intake flow they must not disrupt the natural thermal stratification or turnover
pattern.
Under compliance alternative 1, a Phase II facility could demonstrate present compliance with intake capacity requirements,
Al-3
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
impingement reduction, entrainment reduction, and/or thermal stratification requirements, as applicable. These facilities
could use existing CWIS design and construction technologies, operational measures, or restoration measures to demonstrate
such compliance.
Under compliance alternative 2, an existing facility would have to select and implement design and construction technologies,
operational measures, or restoration measures that satisfy the specified performance standards applicable to the facility.
Examples of technologies that minimize impingement and entrainment (I&E) and that facilities might install to meet the
performance standards of the proposed rule include technologies such as wet cooling towers, fine mesh screens, intake
traveling screens, and Gunderbooms that exclude smaller organisms from entering the CWIS; passive intake systems such as
wedge wire screens, perforated pipes, porous dikes, and artificial filter beds; and diversion and/or avoidance systems.
Examples of technologies that maximize survival of impinged organisms include fish handling systems such as bypass
systems, fish buckets, fish baskets, fish troughs, fish elevators, fish pumps, spray wash systems, and fish sills. Examples of
operational measures that minimize I&E include seasonal flow reductions to minimize intake flow during spawning or
migrating seasons. The calculation baseline against which compliance with the performance standards should be assessed is a
shoreline intake with the capacity to support once-through cooling and no impingement mortality or entrainment controls.
Under compliance alternative 3, a facility must demonstrate that it meets one of two cost tests, and then the Director must
make a site-specific determination of BTA for minimizing AEI. The applicant may demonstrate that the costs of compliance
with the performance standards applicable to the facility (considering the facility's source water body type and proportional
cooling water intake volume) would be significantly greater than (1) the costs considered by the Administrator in developing
the rule standards or (2) the benefits of complying with such standards. Facilities that request a site-specific determination of
BTA will have individual performance standards established by the Director at the time of permit issuance. The performance
standards requested may be less stringent than those specified in the proposed rule, but they may be no less stringent than
justified by the significantly greater cost.
Under all three compliance alternatives, the proposed Phase II rule allows the use of restoration measures to maintain the
level offish and shellfish in the water body, including the community structure and function, at a level comparable to that
which would be achieved by the implementation of design and construction technologies and operational measures. A facility
may opt to combine restoration measures with design and construction technologies and/or operational measures to achieve
the desired level offish and shellfish protection. Among other requirements, the permit applicant must submit a summary of
benefits, a narrative of the proposed restoration measures, and a plan for implementing and maintaining the efficacy of the
restoration effort to the Director as part of the application.
Figure Al-1 displays the framework for EPA's Proposed Section 316(b) Phase II Existing Facilities Rule.
Al-4
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§ 316(b) Phase II EBA, Part A: Background Information
Al: Introduction and Overview
Figure Al-1: Section 316(b) Phase II Existing Facilities Rule Framework
Facility is out of scope of this
rule.
No to
any one
Applicability Criteria [§125.91, 92, and 93]
•Are you an existing facility [per §125.93]?
• Do you both generate and transmit electric power, or
generate electric power but sell it to another entity for
transmission?
• Are you required to have an NPDES permit?
• Do you have at least one cooling water intake
structure that withdraws cooling water from waters of
the U.S. and uses at least 25% for cooling purposes?
• Do you have a design intake flow of 50 MGD or more?
Yes to all
Does your existing facility already meet the
performance standards in §125.94(b)?
OR
Does your existing facility reduce intake
capacity commensurate with a closed-
cycle, recirculating system [§125.94(b)]?
No
Yes
Facility has minimized adverse
environmental impact.
No
Performance Standards for Existing
Facilities [§125.94(b(]
Existing facilities that do not meet
performance standards in §125.94(b) and
do not qualify for a site-specific
determination of BTA must select and
implement D&C technologies, operational
measures, or restoration measures.
You must reduce impingement
mortality by 80 to 95% from the
calculation baseline for fish and
shellfish.
Yes
Does your facility have a utilization rate
less than 15 percent [§125.94(b)(2)]?
CWIS Located in a Freshwater River or
Stream [§125.94(b)(2) and (3)]
• If your facility's design intake flow is 5% or
less of the source water annual mean
flow, you must reduce impingement
mortality by 80 to 95% from the
calculation baseline for fish and shellfish.
• If your facility's design intake flow is
greater than 5% of the source water
annual mean flow, you must reduce
impingement mortality by 80 to 95% and
entrainment by 60 to 90% from the
calculation baseline for all life stages of
fish and shellfish.
No
CWIS Located in Lakes
(Other than One of the Great Lakes) or
Reservoirs [§125.94(b)(4)]
• If you propose to increase your facility's
design intake flow, your total design
intake flow must not disrupt the natural
thermal stratification or turnover pattern
of the source water body (unless
beneficial);
AND
•You must reduce impingement mortality
by 80 to 95% from the calculation
baseline for fish and shellfish.
Are the costs of implementing the
performance standards in §125.94(b) at
your facility significantly greater than the
costs considered in establishing them or
the benefits of complying with them?
Yes
Site-Specific Determination of Best
Technology Available [§125.94(c)]
All existing facilities may request and
receive alternative performance standards
less stringent than those specified in
§125.94(b) and (c) but they must be no
more stringent than justified by the
significantly greater cost.
CWIS Located in Estuaries, Tidal
Rivers, Oceans, or one of the Great
Lakes [§125.94(b)(3)]
You must reduce impingement mortality
by 80 to 95% and entrainment by 60 to
90% from the calculation baseline for all
life stages offish and shellfish.
CWIS = cooling water intake structure
MGD = million gallons per day
D&C = design and construction
Source: U.S. EPA analysis, 2002.
A1-5
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
A1-4 SUMMARY OF ALTERNATIVE RESULATORY OPTIONS
EPA also considered a number of other technology-based options for regulating Phase II facilities. As in the proposed option,
any technology-based options considered would allow for voluntary implementation of restoration measures by facilities that
choose to reduce their intake flow to a level commensurate with the performance requirements of the option. Thus, under
these options, facilities would be able to implement restoration measures that would result in increases in fish and shellfish if
a demonstration of comparable performance for species of concern is made. Similarly, most technology-based options
considered also would allow facilities to request alternative requirements that are less stringent than those specified, but only
if the Director determines that data specific to the facility indicate that compliance with the relevant requirement would result
in compliance costs significantly greater than (a) the costs EPA considered in establishing the requirement at issue or (b) the
benefits of the requirement. The alternative requirement could be no less stringent than justified by the significantly greater
cost. Finally, under the technology-based options considered, facilities that operate at less than 15 percent capacity utilization
would, as in the proposed option, only be required to have impingement control technologies.
Other regulatory options considered by EPA include:
*• (1) requiring Phase II facilities located on different categories of waterbodies to reduce intake capacity
commensurate with the use of closed-cycle, recirculating cooling systems based on location and the percentage of
the source waterbody they withdraw for cooling (Options 1 and 2);
*• (2) requiring all Phase II facilities to reduce I&E to levels established based on the use of design and construction
technologies (e.g., fine mesh screens, fish return systems) or operational measures (Option 3a);
>• (3) requiring all Phase II facilities to reduce intake capacity commensurate with the use of closed-cycle, recirculating
cooling systems (Option 4);
>• (4) requiring all Phase II facilities to reduce their intake capacity to a level commensurate with the use of a dry
cooling system (Option 5); and
*• (5) requiring all Phase II facilities located on certain types of water bodies to reduce intake capacity commensurate
with the use of closed-cycle recirculating cooling systems (Option 6).
Each of these alternative regulatory options is briefly described below.
a. Intake capacity commensurate with closed-cycle, recirculating cooling systems based on
waterbody type and proportion of waterbody flow (Options 1 and 2)
This option, referred to as the "waterbody/capacity-based option," would require facilities that withdraw very large amounts
of water from an estuary, tidal river, or ocean to reduce their intake capacity to a level commensurate with that which can be
attained by a closed-cycle, recirculating cooling system. Under this option, EPA would group waterbodies into five
categories: (1) freshwater rivers or streams, (2) lakes or reservoirs, (3) Great Lakes, (4) tidal rivers or estuaries, and (5)
oceans. The following compliance requirements would apply:
*• Two types of facility would have to meet standards for reducing impingement mortality and entrainment based on
the performance of wet cooling towers: (1) facilities with CWIS located in a tidal river or estuary, if the intake flow
is greater than one percent of the source water tidal excursion and (2) facilities with CWIS located in an ocean, if the
intake flow is greater than 500 MOD. In addition, these facilities must implement and/or maintain additional I&E
controls if the CWIS is located in a sensitive biological area.
*• Facilities with CWIS located in an estuary or tidal river or ocean that do not exceed the intake withdrawal threshold,
facilities with a CWIS located in a freshwater river or stream that exceed the intake withdrawal threshold for
freshwater rivers or streams (greater than 5 percent of the source water mean annual flow), and facilities with CWIS
located in one of the Great Lakes must implement and/or maintain both I&E controls.
>• Facilities with a CWIS located in a freshwater river or stream that do not exceed the intake withdrawal threshold and
all facilities with CWIS in a lake or reservoir, must implement and/or maintain impingement controls only. In
addition, facilities with CWIS located in a lake or reservoir must not disrupt the natural thermal stratification or
turnover pattern of the source waterbody unless such disruption is determined to be beneficial to fish and shellfish.
Facilities with recirculating cooling system based requirements would have the choice of complying with Track I or Track II
requirements. If a facility chose to comply with Track II, then the facility would have to demonstrate that alternative
technologies would reduce I&E to levels comparable to those that would be achieved with a closed-loop recirculating system
Al-6
-------
§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
(90 percent reduction). If such a facility chose to supplement its alternative technologies with restoration measures, it would
have to demonstrate the same or substantially similar level of protection.
EPA analyzed two different cases of the waterbody/capacity-based option: the first case assumes that all facilities with a
recirculating cooling system based requirements would comply with Track I and install a wet cooling tower (Option 1); the
second, more likely, case assumes that a percentage of the facilities with a recirculating cooling system based requirements
would comply with Track II and conduct a comprehensive waterbody characterization study and install technologies other
than wet cooling towers (Option 2). Under Option 1, 54 facilities are assumed to install a cooling tower; under Option 2, 33
facilities are assumed to install a cooling tower.
b. Impingement mortality and entrapment controls everywhere (Option 3a)
The impingement mortality and entrainment controls everywhere option would require the implementation of technologies
that reduce impingement mortality and entrainment at all Phase II facilities without regard to waterbody type and with no site-
specific compliance option available. EPA would specify a range of impingement mortality and entrainment reduction that is
the same as the performance requirements under the proposed rule (i.e., Phase II facilities would be required to reduce
impingement mortality by 80 to 95 percent for fish and shellfish, and to reduce entrainment by 60 to 90 percent for all life
stages offish and shellfish). However, unlike the proposed option, performance requirements under this alternative would
apply to all Phase II facilities regardless of the category of waterbody used for cooling water withdrawals. Like the proposed
option, the percent I&E reduction under this alternative would be relative to the calculation baseline. Thus, the baseline for
assessing performance would be an existing facility with a shoreline intake with the capacity to support once-through cooling
water systems and no impingement or entrainment controls. In addition, as under the proposed rule, a Phase II facility could
demonstrate either that it currently meets the performance requirements or that it would upgrade its facility to meet these
requirements.
EPA would set technology-based performance requirements under this alternative but would not mandate the use of any
specific technology. Unlike the proposed option, this alternative would not allow for the development of BTA on a site-
specific basis (except on a best professional judgment basis). This alternative would not base requirements on the percent of
source water withdrawn or restrict disruption of the natural thermal stratification of lakes or reservoirs. However, it would
impose entrainment performance requirements on Phase II facilities located on all waterbody types including freshwater
rivers or streams, and lakes or reservoirs.
Finally, under this alternative, restoration could be used, but only as a supplement to the use of design and construction
technologies or operational measures. This alternative would establish clear performance-based requirements that are simpler
and easier to implement than those proposed and are based on the use of available technologies to reduce AEI.
c. Intake capacity commensurate with closed-cycle, recirculating cooling systems for all
facilities (Option 4)
This option, referred to as the "all cooling towers option," would require all Phase II facilities with a design intake flow of 50
MOD or more to reduce the total design intake flow to a level commensurate with that which can be attained by a closed-
cycle recirculating cooling system. In addition, facilities in specified circumstances (e.g., located where additional protection
is needed due to concerns regarding threatened, endangered, or protected species or habitat; or migratory, sport, or
commercial species of concern) would have to select and implement design and construction technologies to minimize
impingement mortality and entrainment. This option does not distinguish between facilities on the basis of the waterbody
from which they withdraw cooling water. Rather, it would ensure that the same stringent controls are the nationally
applicable minimum for all waterbody types.
d. Flow reduction commensurate with the level achieved by dry cooling systems based on
waterbody type (Option 5)
Under this option, referred to as the "dry cooling option," two types of facilities would be required to reduce their intake
capacity to a zero or nearly zero intake flow, achievable with dry cooling systems: (1) facilities with CWIS located in a tidal
river or estuary, if the intake flow is greater than one percent of the source water tidal excursion and (2) facilities with CWIS
located in an ocean, if the intake flow is greater than 500 MOD. All other facilities have compliance requirements similar to
the waterbody/capacity-based option.
Al-7
-------
§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
e. Intake capacity commensurate with closed-cycle, recirculating cooling systems for all
facilities located on an estuary or tidal river or ocean (Option 6)
Under this option, all facilities located on an estuary or tidal river or ocean must reduce intake flow commensurate with a
level that can be achieved by a closed-cycle, recirculating system, regardless of proportional intake flow. Facilities with a
CWIS located in one of the Great Lakes must implement and/or maintain both I&E controls. Facilities with a cooling water
intake structure located in a freshwater river or stream that exceed the intake withdrawal threshold for freshwater rivers or
streams (greater than 5 percent of the source water mean annual flow) must implement and/or maintain I&E controls.
Facilities with a CWIS located in a freshwater river or stream that do not exceed the intake withdrawal threshold and all
facilities with CWIS in a lake or reservoir, must implement and/or maintain impingement controls only. In addition, facilities
with CWIS located in a lake or reservoir must not disrupt the natural thermal stratification or turnover pattern of the source
waterbody unless such disruption is determined to be beneficial to fish and shellfish.
While this option was considered in the development of the proposed Phase II regulation, EPA did not estimate costs or
economic impacts for this option. The remainder of the EBA will present benefits for this option, but will not discuss it in
any of the chapters in Part B: Costs and Economic Impacts.
Al-5 COMPLIANCE RESPONSES OF THE PROPOSED RULE AND ALTERNATIVE OPTIONS
Table Al-1 shows compliance response assumptions for the proposed rule and five alternative regulatory options based on
each facility's current technologies installed, capacity utilization, waterbody type, annual intake flow, and design intake flow
as a percent of source waterbody mean annual flow.
-------
§ 316(b) Phase II EBA, Part A: Background Information
Al: Introduction and Overview
Table Al-1: Number of Facilities by Compliance Assumption and Regulatory Option (based on 539 sample facilities)
Facility Compliance
Assumption
Cooling tower in
baseline (no action)
Waterbody/Capacity-
Based Option
(Allows two tracks)
Option 1
69
<15% capacity
utilization
Freshwater Lakes
Freshwater Streams and
Rivers a
Great Lakes
Estuaries, Tidal Rivers,
and Oceans
Total Impingement
Controls Only
53
94
94
0
0
2¥7
Freshwater Lakes
Freshwater Streams and
Rivers a
Great Lakes
Estuaries, Tidal Rivers,
and Oceans b
Total I&E Controls
0
107
13
58
178
Freshwater Lakes
Freshwater Streams and
Rivers
Great Lakes
Estuaries, Tidal Rivers,
and Oceans b
Total Flow Reduction
Technology c
Total
0
0
0
51
57
539
Option 2
69
53
94
94
0
0
241
0
107
13
78
198
0
0
0
31
31
539
Proposed
Rule
(Option 3)
69
Impinge
53
94
94
0
0
241
]
0
107
13
109
229
Flow Re
0
0
0
0
0
539
Impingement Mortality
and Entrainment
Controls Everywhere
(Option 3a)
69
ment Controls Only
53
0
0
0
0
53
[&E Controls
94
201
13
109
¥77
duction Technology
0
0
0
0
0
539
All Cooling
Towers
(Option 4)
69
53
0
0
0
0
53
0
0
0
0
0
94
201
13
109
¥77
539
Dry Cooling
(Option 5)
69
53
94
94
0
0
2¥7
0
107
13
58
178
0
0
0
51
57
539
Waterbody
Based
(Option 6)
69
53
94
94
0
0
2¥7
0
107
13
0
720
0
0
0
109
709
539
a Options 1, 2, 3, 5 and 6: A facility located on a freshwater river or stream with a design intake flow of <5% of the source water annual mean flow
will be required to install impingement controls only, while a facility with a design intake flow of >5% of the source water annual mean flow will
be required to install both I&E controls.
b Options 1, 2 and 5: A facility located on an estuary or tidal river with an intake flow < 1% of the source water tidal excursion or on an ocean with
an intake flow <500 MGD will be required to install I&E technologies. Option 1 assumes that all 51 facilities that do not meet that criteria will
install flow reduction technologies commensurate with a closed-cycle recirculating system. Option 2 assumes that 31 facilities will install flow
reduction commensurate with a closed-cycle recirculating system and the remaining 20 facilities will use track II (conduct a baseline
characterization study) and install I&E controls. Option 5 assumes that all 51 facilities that do not meet that criteria will install flow reduction
technologies commensurate with a dry cooling system.
0 Options 1, 2, 4, 5 and 6: In addition to flow reduction technologies, facilities in specified circumstances (e.g., located where additional protection is
needed due to concerns regarding threatened, endangered, or protected species or habitat; migratory, sport or commercial species of concern) would
have to select and implement design and construction technologies to minimize impingement mortality and entrainment.
Source: U.S. EPA analysis, 2002.
A1-9
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§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
Al-6 ORGANIZATION OF THE EBA REPORT
The Economic and Benefits Analysis for the Proposed Section 316(b) Phase II Existing Facilities Rule (EBA) assesses the
economic impacts and benefits of the proposed Phase II rule. The EBA consists of four parts. It is organized as follows:
PART A: BACKGROUND INFORMATION
*• Chapter Al: Introduction and Overview presents the scope, key definitions, and a summary of the proposed rule
and five alternative regulatory options.
> Chapter A2: The Need for Section 316(b) Regulation provides a brief discussion of the industry sectors and
facilities affected by this regulation, discusses the environmental impacts from operating CWIS, and explains the
need for this regulatory effort.
> Chapter A3: Profile of the Electric Power Industry presents a profile of the electric power market and the existing
utility and nonutility steam electric power generating facilities analyzed for this regulatory effort
PART B: COSTS AND ECONOMIC IMPACTS
> Chapter Bl: Summary of Compliance Costs summarizes the unit costs of compliance with the proposed rule and
alternative regulatory options, presents EPA's assessment of compliance years, and presents the national cost of the
proposed rule.
*• Chapter B2: Cost Impact Analysis presents an assessment of the magnitude of compliance costs with the proposed
Phase II rule, including a cost-to-revenue analysis at the facility and firm levels, a state-level analysis of compliance
costs per household, and an analysis of compliance costs relative to electricity price projections at the North
American Electric Reliability Council (NERC) level.
*• Chapter B3: Electricity Market Model Analysis presents an analysis of the proposed rule using an integrated
electricity market model. The chapter discusses potential energy effects of the proposed Phase II rule at the NERC
region and national levels, and presents facility-level impacts.
> Chapter B4: Regulatory Flexibility Analysis presents EPA's estimates of small business impacts from the proposed
Phase II rule.
*• Chapter B5: UMRA Analysis outlines the requirements for analysis under the Unfunded Mandates Reform Act and
presents the results of the analysis for this proposed rule.
> Chapter B6: Other Administrative Requirements presents several other analyses in support of the proposed Phase II
rule. These analyses address the requirements of Executive Orders and Acts applicable to this rule.
*• Chapter B7: Alternative Options - Costs and Economic Impacts describes the costs and economic impacts of four
alternative regulatory options considered by EPA
> Chapter B8: Alternative Options - Electricity Market Model Analysis presents an analysis of two alternative
regulatory options using an integrated electricity market model. The chapter discusses potential energy effects of the
waterbody/capacity-based option (Option 1) and the all cooling towers option (Option 4) at the NERC region and
national levels, and presents facility-level impacts.
PART C: NATIONAL BENEFITS
*• Chapter Cl: Introduction to the Case Studies provides an overview of why EPA chose a case study approach for
analyzing benefits, how and why the case study sites were selected, and the design of the analyses.
> Chapter C2: Summary of Case Study Results summarizes the findings from each case study analysis and presents
Al-10
-------
§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
EPA's estimate of I&E nation-wide based on extrapolation from case study results.
*• Chapter C3: National Extrapolation of Baseline Economic Losses details the methods used to extrapolate the
economic value of case study losses to obtain national loss estimates and presents EPA's best estimates of national
baseline economic losses.
*• Chapter C4: Benefits presents the expected national reductions in I&E under the proposed rule and five alternative
regulatory options and applies these reductions to the national baseline losses reported in Chapter C3 to obtain an
estimate of national benefits attributable to section 316(b) regulation.
PART D: NATIONAL BENEFIT-COST ANALYSIS
> Chapter Dl: Comparison of National Costs and Benefits summarizes total private costs, develops social costs, and
compares total social costs to total benefits at the national level. Results are presented for the proposed rule and five
alternative regulatory options.
Al-11
-------
§ 316(b) Phase II EBA, Part A: Background Information Al: Introduction and Overview
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling
Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
U.S. Environmental Protection Agency (U.S. EPA). 2002. Technical Development Document for the Proposed Section
316(b) Phase II Existing Facilities Rule. EPA-821-R-02-003. February 2002.
Al-12
-------
§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
Chapter A2: Need for the Regulation
INTRODUCTION
CHAPTER CONTENTS
Section 316(b) of the Clean Water Act (CWA) directs EPA to
A2-1 Overview of Regulated Facilities A2-1
,,,,,,,.,. . , •. r A2-1.1 Phasell Sector Information A2-1
assure that the location, design, construction, and capacity of .~ , ~ ™ TT r .,., T c .. . _ _
' & ' ' r j A2-1.2 Phase II Facility Information A2-2
A2-2 The Need for Section 316(b) Regulation A2-4
A2-2.1 Low Levels of Protection at Phase II
Facilities A2-5
A2-2.2 Reducing Adverse Environmental
Impacts A2-7
A2-2.3 Addressing Market Imperfections .... A2-8
A2-2.4 Reducing Differences Between the
States A2-10
cooling water intake structures reflect the best technology
available (BTA) for minimizing adverse environmental
impact (AEI). Based on this statutory language, section
316(b) is already in effect and should be implemented with
each NPDES permit issued to a directly discharging facility.
However, no national standard for BTA that will minimize
AEI from cooling water intake structures (CWIS) has been
established to date. As a result, many CWIS have been
constructed on sensitive aquatic systems with capacities and A2-2'5 Reducmg Transaction Costs A2-12
T\ PTPTPIIPPS A / 14
designs that cause damage to the waterbodies from which
they withdraw water. In addition, the absence of regulations
that establish standards for BTA has led to an inconsistent
application of section 316(b). In fact, only 145 out of 550 facilities with flows greater than 50 million gallons per day (MOD)
have indicated on EPA's 2000 Section 316(b) Industry Survey that they have ever performed a section 316(b) study (U.S.
EPA, 2000).
This chapter provides a brief overview of the facilities subject to this rule and their use of cooling water, and presents the
need for this regulation.
A2-1 OVERVIEW OF RESULATED FACILITIES
The Proposed Section 316(b) Phase II Existing Facilities Rule applies to existing power producing facilities with a design
intake flow of 50 MGD or greater. The Phase II rule also covers substantial additions or modifications to operations
undertaken at such facilities. The proposed Phase II rule does not cover (1) new steam electric power generating facilities, (2)
new manufacturing facilities, (3) existing steam electric power generating facilities with a design intake flow of less than 50
MGD, and (4) existing manufacturing facilities.1
The remainder of this section describes the industry sectors subject to the Phase II rule and the existing utility and nonutility
steam electric power generating facilities analyzed for this regulatory effort. Chapter A3: Profile of the Electric Power
Industry and Chapter B3: Electricity Market Model Analysis of this Economic and Benefits Analysis (EBA) present more
detailed information on the facilities subject to the Phase II rule and the market in which they operate.
A2-1.1 Phase II Sector Information
Past section 316(b) regulatory efforts and EPA's effluent guidelines program identified steam electric generators as the largest
industrial users of cooling water. The condensers that support the steam turbines in these facilities require substantial
amounts of cooling water. EPA estimates that steam electric utility power producers (SIC Codes 4911 and 4931) and steam
electric nonutility power producers (SIC Major Group 49) account for approximately 92.5 percent of total cooling water
1 New facilities were covered under the final section 316(b) New Facility Rule (Phase I), which EPA promulgated in November
2001. Existing steam electric power generating facilities with a design intake flow of less than 50 MGD and existing manufacturing
facilities will be addressed by a separate rule.
A2-1
-------
§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
intake in the United States (U.S. EPA, 2001). Beyond steam electric generators, other industrial facilities use cooling water
in their production processes (e.g., to cool equipment, for heat quenching, etc.).
EPA's 2000 Section 316(b) Industry Survey collected cooling water information for 676 power producers and 396 other
industrial facilities. These facilities withdraw 216 and 26.5 billion gallons per day (BGD) of cooling water, respectively. Of
the power producers, 539 meet the "in-scope" requirements of this proposed rule. These 539 facilities represent 550 facilities
in the industry.2 Based on the survey, the 550 Phase II facilities account for approximately 216 BGD, or 96.3 percent of all
estimated power producers. Industrial categories other than power producers are not covered by this proposed Phase II rule.
Table A2-1 summarizes cooling water use information of steam electric power generating facilities and major industrial
categories.
Table A2-1: Estimated Cooling Water Intake by Sector - EPA Survey
Sector"
Steam Electric Power Producers
Steam Electric Utility Power Producers
Steam Electric Nonutility Power Producers
Major Industrial Categories11
Total Steam Electric and Industrial
Estimated
Number of
Facilities
708
591
117
111,
1,481
Total Cooling
Water Intake
Average Flow
Billion
Gal./Yr.
81,753
72,665
9,088
13,752
95,505
Cooling Water Intake Average Flow Subject
to Phase II Rule
¥»•«• f^ in/ Percent of Total Steam
Billion Gal./Yr. „, . . , T , . . ,
Electric and Industrial
78,703 82.4%
71,471 74.8%
7,232 7.6%
0 0.0%
78,703 82.4%
a Estimates for each sector are based on facility categorization at the time of the survey; some utility facilities have since been sold
to non-utilities.
b Major industrial categories (major SIC codes) surveyed with EPA questionnaires: Paper and Allied Products (SIC Major Group
26), (2) Chemicals and Allied Products (SIC Major Group 28), (3) Petroleum and Coal Products (SIC Major Group 29), and (4)
Primary Metals Industries (SIC Major Group 33).
Source: U.S. EPA, 2000.
A2-1.2 Phase II Facility Information
The 550 steam electric power generating facilities subject to the proposed Phase II rule comprise a substantial portion of the
U.S. electric power market. As shown in Table A2-2, the 550 facilities represent 13 percent of all facilities in the U.S.
electric power market. In 2008, the Phase II facilities are projected to have a generating capacity of 416,000 MW (48 percent
of total), generate 2.3 billion MWh of electricity (56 percent of total), and realize $75 billion in revenues (49 percent of total).
2 EPA applied sample weights to the 539 facilities to account for non-sampled facilities and facilities that did not respond to the
survey. For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA, 2000).
A2-2
-------
§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
Table A2-2: Summary Economic Data for Electricity Market and Phase II
Economic Measure
Number of Facilities
Electric Generating Capacity (MW)
Net Generation (million MWh)
Revenues (in billions, $2001)
Industry Total"
4,091
875,000
4,100
$152
Facilities Subject to
Phase II Total
550
416,000
2,300
$75
Facilities
Phase II Ruleb
% of Industry Total
13%
48%
56%
49%
Industry Totals are based on ICF Consulting's Integrated Planning Model (IPM®), section 316(b) base case, 2008. The IPM
models 4,091 unique facilities. Industrial boilers are not modeled by the IPM. For a discussion of EPA's use of the IPM in
support of this proposed rule, see Chapter BS: Electricity Market Model Analysis.
b The IPM models 540 of the 550 Phase II facilities. Eleven of the 540 facilities are closures in the section 316(b) base case run for
2008. The Phase II totals for capacity, generation, and revenues include the activities of the 529 in-scope facilities that are
modeled by the IPM and are not closures in the base case.
Source: IPM analysis: model run for Section 316(b) base case, 2008.
Most of the analyses of economic impacts and energy effects presented in this Economic and Benefits Analysis present
results by geographic region (i.e., North American Electric Reliability Council, or "NERC," region). Analyzing results by
geographic region is of interest because regional concentrations of compliance costs could adversely impact electric power
system reliability and prices, if a large percentage of overall capacity is affected. Some analyses are also presented by plant
type. Analyzing results by plant type is of interest because a regulation that has disproportionate effects on particular types of
facilities could lead to shifts in technology selection, if the effects are substantial enough.
Table A2-3 presents the distribution of facilities subject to the Phase II rule by NERC region and plant type. The table shows
that the majority of facilities subject to the Phase II rule, 299, or 54.5 percent, are coal-fired steam-electric facilities. The
other major plant types are oil- or gas-fired steam-electric facilities (169, or 30.8 percent) and nuclear facilities (57, or 10.4
percent). The remaining 4.4 percent are combined-cycle or other steam facilities. On a regional level, the East Central Area
Reliability Council (ECAR) and the Southeastern Electric Reliability Council (SERC) account for the highest numbers of
Phase II facilities with 100 (18.3 percent) and 95 (17.3 percent), respectively.
A2-3
-------
§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
Table A2-3: Distribution of Phase II Facilities by NERC Region and Plant Type
NERC Region"
ASCC
ECAR
ERCOTb
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Percent of Phase II
Coal
1
91
9
7
0
17
41
34
17
55
19
7
299
54.5%
Combined
Cycle
0
0
1
5
0
2
0
0
4
1
0
3
16
2.9%
Nuclear
0
6
2
1
0
7
8
4
9
17
1
2
57
10.4%
Oil/Gas
0
3
39
17
3
15
2
6
28
22
12
21
169
30.8%
Other
Steam
0
0
0
0
0
2
0
0
5
0
0
1
8
1.5%
Total
1
100
51
30
3
44
51
44
62
95
32
34
Percent of
Phase II
0.2%
18.3%
9.3%
5.5%
0.5%
8.0%
9.3%
8.1%
11.4%
17.3%
5.8%
6.3%
» 1
a Key to 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 Interconnect Network; MAPP - Mid-Continent Area Power Pool;
NPCC - Northeast Power Coordinating Council; SERC - Southeastern Electric Reliability Council; SPP - Southwest Power Pool;
WSCC - Western Systems Coordinating Council.
b The plant type for one facility in ERCOT was not available. The total number of Phase II facilities presented in this table
therefore is 549, not 550.
Source: U.S. DOE 1999a; U.S. DOE 1999b
A2-2 THE NEED FOR SECTION 316(B) RESULATION
The withdrawal of cooling water removes trillions of aquatic organisms from waters of the U.S. each year, including plankton
(small aquatic animals, including fish eggs and larvae), fish, crustaceans, shellfish, sea turtles, marine mammals, and many
other forms of aquatic life. Most impacts are to early life stages of fish and shellfish.
Aquatic organisms drawn into CWIS are either impinged on components of the intake structure or entrained in the cooling
water system itself. Impingement takes place when organisms are trapped on the outer part of an intake structure or against a
screening device during periods of intake water withdrawal. Impingement is caused primarily by hydraulic forces in the
intake stream. Impingement can result in (1) starvation and exhaustion; (2) asphyxiation when the fish are forced against a
screen by velocity forces that prevent proper gill movement or when organisms are removed from the water for prolonged
periods; (3) descaling and abrasion by screen wash spray and other forms of physical damage.
Entrainment occurs when organisms are drawn into the intake water flow entering and passing through a CWIS and into a
cooling water system. Organisms that become entrained are those organisms that are small enough to pass through the intake
screens, primarily eggs and larval stages of fish and shellfish. As entrained organisms pass through a plant's cooling water
system, they are subject to mechanical, thermal, and or toxic stress. Sources of such stress include physical impacts in the
pumps and condenser tubing, pressure changes caused by diversion of the cooling water into the plant or by the hydraulic
A2-4
-------
§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
effects of the condensers, sheer stress, thermal shock in the condenser and discharge tunnel, and chemical toxemia induced by
antifcuring agents such as chlorine.
Rates of impingement and entrainment (I&E) depend on species characteristics, the environmental setting in which a facility
is located, and the location, design, and capacity of the facility's CWIS. Species that spawn in nearshore areas, have
planktonic eggs and larvae, and are small as adults experience the greatest impacts, since both new recruits and reproducing
adults are affected (e.g., bay anchovy in estuaries and oceans). In general, higher I&E is observed in estuaries and near
coastal waters because of the presence of spawning and nursery areas. By contrast the young of freshwater species are
generally epibenthic and/or hatch from attached egg masses rather than existing as free-floating individuals, and therefore
freshwater species may be less susceptible to entrainment.
The likelihood of I&E also depends on facility characteristics. If the quantity of water withdrawn is large relative to the flow
of the source waterbody, a larger number of organisms will be affected. Intakes located in nearshore areas tend to have
greater ecological impacts than intakes located offshore, since nearshore areas are usually more biologically productive and
have higher concentrations of aquatic organisms (see the Pilgrim-Seabrook comparison in Part G: New England Ocean of the
Case Study Analysis for the Proposed Section 316(b) Phase II Existing Facilities Rule. EPA estimates that CWIS used by
the 550 facilities subject to the proposed rule impinge and entrain billions of age 1 equivalent fish annually (see Table C2-10
in Chapter C2: Summary of Case Study Results of this EBA for further detail).
In addition to direct losses of aquatic organisms from I&E, there are a number of indirect, ecosystem-level effects that may
occur, including (1) disruption of aquatic food webs resulting from the loss of impinged and entrained organisms that provide
food for other species, (2) disruption of nutrient cycling and other biochemical processes, (3) alteration of species
composition and overall levels of biodiversity, and (4) degradation of the overall aquatic environment. In addition to the
impacts of a single CWIS on currents and other local habitat features, environmental degradation can result from the
cumulative impact of multiple intake structures operating in the same watershed or intakes located within an area where
intake effects interact with other environmental stressors.
Several factors drive the need for this final section 316(b) rule. Each of these factors is discussed in the following sections.
A2-2.1 Low Levels of Protection at Phase II Facilities
Facilities in the power producing industry use a wide variety of cooling water intake technologies to maximize cooling system
efficiency, minimize damage to their operating systems, and to reduce environmental impacts. The following subsections
present data on technologies that have been identified as effective in protecting aquatic organisms from I&E. EPA used
information from its 2000 Section 316(b) Industry Survey to characterize the 550 in-scope Phase II facilities with respect to
these technologies. Based on this information, EPA believes that many facilities subject to this proposed rule are not using
BTA to minimize AEI.
a. Closed-cycle cooling systems
Closed-cycle cooling systems (e.g., systems employing cooling towers) are the most effective means of protecting organisms
from I&E. Cooling towers reduce the number of organisms that come into contact with a CWIS because of the significant
reduction in the volume of intake water needed by a closed-cycle facilities. Reduced water intake results in a significant
reduction in damaged and killed organisms. Of the 550 in-scope Phase II facilities, 73 (13 percent) reported the use of
closed-cycle cooling systems.
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§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
Table A2-4: Estimated Number of Facilities by CWS Configuration and CWIS Technology
(Design Flow >= 50 M6D)
CWIS Technology
Intake screening technologies
Passive intake systems
Fish diversion or avoidance systems
Fish handling or return technologies
Other/none/unknown
Combination of technologies
Total
CWS Configuration
Once Through
f
26
42
17
53
213
65
416
%
6.3%
10.1%
4.1%
12.7%
51.2%
15.6%
100.0%
Recirculating
f
0
13
2
3
46
9
73
%
0.0%
17.8%
2.7%
4.1%
63.0%
12.3%
100.0%
Combination
f
5
9
2
7
20
7
50
%
10.0%
18.0%
4.0%
14.0%
40.0%
14.0%
100.0%
None/unknown
f
0
1
0
2
7
1
11
%
0.0%
9.1%
0.0%
18.2%
63.6%
9.1%
100.0%
Source: U.S. EPA, 2000.
b. Other CWIS technologies
Discussions with NPDES permitting authorities and utility officials identified fine mesh screens as an effective technology for
minimizing entrainment. They can, however, increase impingement. Data from the questionnaires indicate that of the 550 in-
scope Phase II facilities, seven (one percent) employed fine mesh screens on at least one CWIS. These seven plants
represented less than one percent of the cooling water withdrawn from surface waters by plants reporting data. These
findings indicate that, in general, BTA is not being used and further regulation is required.
Table A2-5: Estimated Number of Facilities by CWIS Technology
(Design Flow >= 50 M6D)
CWIS Technology
Intake screening technologies
Passive intake systems
Fish diversion or avoidance systems
Fish handling or return technologies
Other/none/unknown technology
Combination of technologies
Total
Number of
Facilities
31
65
21
65
286
82
550
Percent of Total
5.6%
11.8%
3.8%
11.8%
52.0%
14.9%
100.0%
Source: U.S. EPA, 2000.
c. Cooling system location
Another effective approach for minimizing AEI associated with CWIS is to locate the intake structures in areas with low
abundance of aquatic life and design the structures so that they do not provide attractive habitat for aquatic communities.
However, this approach is of little utility for existing facilities where options for relocating intake structures are infeasible.
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§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
Table A2-6 shows the estimated number of facilities by the source of water from which cooling water is withdrawn. The
table indicates that 135 steam electric power generation facilities are located on estuaries, tidal rivers, or oceans that are
considered to be areas of high productivity and abundance. In addition, estuaries are often nursery areas for many species.
The flow to these facilities totaled 32 percent of the total cooling water being withdrawn by all in-scope Phase II facilities.
However, the remaining 415 facilities (68 percent of flow) were reported as being located on fresh waterbodies (including
Great Lakes).
Table A2-6: Estimated Number of Facilities by Source
(Design Flow >= 50 M6D)
Source of Surface Water
Estuary /Tidal river
Freshwater stream/River
Great Lake
Lake/Reservoir
Ocean
Total"
Number of Facilities
112
263
16
135
23
550
of Surface Water
Percent of Total
20.4%
47.8%
2.9%
24.6%
4.3%
100.0%
a Individual numbers may not add up due to independent rounding.
Source: U.S. EPA, 2000.
A2-2.2 Reducing Adverse Environmental Impacts
Adverse environmental impacts occur when facilities impinge aquatic organisms on the screens of their CWIS, entrain them
within their cooling system, or otherwise negatively affect habitats that support aquatic species. Exposure of aquatic
organisms to I&E depends on the location, design, construction, capacity, and operation of a facility's CWIS (U.S. EPA,
1976; SAIC, 1994; SAIC, 1996). The regulatory goals of section 316(b) include the following:
*• ensure that the location, design, construction, and capacity of a facility's CWIS reflect best technology available for
minimizing adverse environmental impact;
>• protect individuals, populations, and communities of aquatic organisms from harm (reduced viability or increased
mortality) due to the physical and chemical stresses of I&E; and
>• protect aquatic organisms and habitat that are indirectly affected by CWIS because of trophic interactions with
species that are impinged or entrained.
Impingement occurs when fish are trapped against intake screens by the velocity of the intake flow. Organisms may die or be
injured as a result of:
>• starvation and exhaustion,
>• asphyxiation when velocity forces prevent proper gill movement,
>• abrasion by screen wash spray,
>• asphyxiation due to removal from water for prolonged periods, and
*• removal from the system by means other than returning them to their natural environment.
Small organisms are entrained when they pass through a plant's condenser cooling system. Injury and death can result from
the following:
>• physical impacts from pump and condenser tubing,
>• pressure changes caused by diversion of cooling water,
>• thermal shock experienced in condenser and discharge tunnels, and
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
>• chemical toxemia induced by the addition of anti-fouling agents such as chlorine.
Mortality of entrained organisms is usually extremely high.
Review of the available literature and section 316(b) demonstration studies has identified numerous documented cases of
impacts associated with I&E and the effects of I&E on individual organisms and on populations of aquatic organisms. For
example, specific losses attributed to individual steam electric generating plants include annual losses of 3 to 4 billion larvae,
equivalent to 23 million adult fish and shellfish,3 23 tons offish and shellfish of recreational, commercial, or forage value lost
each year,4 and 1 million fish lost during a three-week study period.5 The yearly loss of billions of individuals is not the only
problem. Often, there are impacts to populations as well. For example, studies of Hudson River fish populations predicted
reductions of up to 20 percent for striped bass, 25 percent for bay anchovy, and 43 percent for Atlantic torn cod, even without
assuming 100 percent mortality of entrained organisms.6 Estimates of lost midwater fish species due to direct entrainment by
CWIS at the San Onofre Nuclear Generating Station (SONGS) are between 16.5 to 45 tons per year.7 This loss represents a
41 percent mortality rate for fish (primarily northern anchovy, queenfish, and white croaker) entrained by intake water at
SONGS. In a normal year, approximately 350,000 juvenile white croaker are estimated to be killed through entrainment at
SONGS. This number represents 33,000 adult individuals or 3.5 tons of adult fish. Changes in densities of fish populations
within the vicinity of the plant, relative to control populations, were observed in species of queen fish and white croaker. The
density of queenfish and white croaker within three kilometers of SONGS decreased by 34 to 63 percent in shallow water
samples and 50 to 70 percent in deep water samples.
The main purpose of this regulation is to minimize losses such as those described above. See Part C: National Benefits and
Part D: Benefit-Cost Analysis of this EBA for information on the ability of the different options to reduce impingement and
entrainment. See also the Case Study Analysis for the Proposed Section 316(b) Phase II Existing Facilities Rule for detailed
information on baseline losses at case study facilities.
A2-2.3 Addressing Market Imperfections
The conceptual basis of environmental legislation in general, and the Clean Water Act and the section 316(b) regulation in
particular, is the need to correct imperfections in the markets that arise from uncompensated environmental externalities.
Facilities withdraw cooling water from a water of the U.S. to support electricity generation, steam generation, manufacturing,
and other business activities, and, in the process impinge and entrain organisms without accounting for the consequences of
these actions on the ecosystem or other parties who do not directly participate in the business transactions. The actions of
these section 316(b) facilities impose environmental harm or costs on the environment and on other parties (sometimes
referred to as third parties). These costs, however, are not recognized by the responsible entities in the conventional market-
based accounting framework. Because the responsible entities do not account for these costs to the ecosystem and society,
they are external to the market framework and the consequent production and pricing decisions of the responsible entities. In
addition, because no party is compensated for the adverse consequences of I&E, the externality is uncompensated.
Business decisions will yield a less than optimal allocation of economic resources to production activities, and, as a result, a
less than optimal mix and quantity of goods and services, when external costs are not accounted for in the production and
pricing decisions of the section 316(b) industries. In particular, the quantity of AEI caused by the business activities of the
responsible business entities will exceed optimal levels and society will not maximize total possible welfare. Adverse
distributional effects may be an additional effect of the uncompensated environmental externalities. If the distribution of I&E
and ensuing AEI is not random among the U.S. population but instead is concentrated among certain population subgroups
3 Brunswick Nuclear Steam Electric Generating Plant (U.S. EPA, Region IV, 1979).
4 Crystal River Power Plant (U.S. EPA, Region IV, 1986).
5 B.C. Cook Nuclear Power Plant (Thurber, 1985).
6 Bowline Point, Indian Point 2 & 3, and Roseton Steam Electric Generating Stations (ConEd, 2000).
7 San Onofre Nuclear Generating station (SAIC, 1993)
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
based on socio-economic or other demographic characteristics, then the uncompensated environmental externalities may
produce undesirable transfers of economic welfare among subgroups of the population.
The goal of environmental legislation and subsequent implementing actions, such as the section 316(b) regulation that is the
subject of this analysis, is to correct environmental externalities by requiring the responsible parties to reduce their actions
causing environmental damage. Congress, in enacting the authorizing legislation, and EPA, in promulgating the
implementing regulations, act on behalf of society to minimize environmental impacts (i.e., achieve a lower level of I&E and
associated environmental harm). These actions result in a supply of goods and services that more nearly approximates the
mix and level of goods and services that would occur if the industries impinging and entraining organisms fully accounted for
the costs of their AEI-generating activities.
Requiring facilities to minimize their environmental impacts by reducing levels of I&E (i.e., reducing environmental harm) is
one approach to addressing the problem of environmental externalities. This approach internalizes the external costs by
turning the societal cost of environmental harm into a direct business cost - the cost of achieving compliance with the
regulation - for the impinging and entraining entities. A facility causing AEI will either incur the costs of minimizing its
environmental impacts, or will determine that compliance is not in its best financial interest and will cease the AEI-generating
activities.
It is theoretically possible to correct the market imperfection by means other than direct regulation. Negotiation and/or
litigation, for example, could achieve an optimal allocation of economic resources and mix of production activities within the
economy. However, the transaction costs of assembling the affected parties and involving them in the negotiation/litigation
process as well as the public goods character of the improvement sought by negotiation or litigation will frequently render
this approach to addressing the market imperfection impractical. Although the environmental impacts associated with CWIS
have been documented since the first attempt at section 316(b) regulation in the late 1970s, implementation of section 316(b)
to date has failed to address the market imperfections associated with CWIS effectively.
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§ 316(b) Phase II EBA, Part A: Background Information
A2: Need for the Regulation
A2-2.4 Reducing Differences Between the States
NPDES permitting authorities have implemented the requirements of section 316(b) in widely varying ways. The language
used in the statutes or regulations vary from state to state almost as much as the interpretation. Most states do not address
section 316(b) at all.
Table A2-7. below illustrates a variety of ways in which states identify the section 316(b) requirements.
Table. A2-7: Selected NPDES State Statutory/Regulatory Provisions Addressing Impacts
from Cooling Water Intake Structures
NPDES State
Connecticut
New Jersey
New York
Maryland
Illinois
Iowa
California
Citation
RCSA § 22a, 430-4
NJAC§7:14A-11.6
6 NYCRR § 704.5
MRC § 26.08.03
35 111. Admin. Code
306.201 (1998)
567 IAC 62.4(455B)
Cal. Wat. Code
§ 13142.5(b)
Summary of Requirements
Provides for coordination with other Federal/State agencies with jurisdiction over
fish, wildlife, or public health, which may recommend conditions necessary to avoid
substantial impairment of fish, shellfish, or wildlife resources
Criteria applicable to intake structure shall be as set forth in 40 CFR Part 125, when
EPA adopts these criteria
The location, design, construction, and capacity of intake structures in connection
with point source thermal discharges shall reflect BTA for minimizing environmental
impact
Detailed regulatory provisions addressing BTA determinations
Requirement that new intake structures on waters designated for general use shall be
so designed as to minimize harm to fish and other aquatic organisms
Incorporates 40 CFR part 401, with cooling water intake structure provisions
designated "reserved"
Requirements that new or expanded coastal power plants or other industrial
installations using seawater for cooling shall use best available site, design
technology, and mitigation measures feasible to minimize intake and mortality of
marine life
Source: SAIC, 1994b.
Additionally, in discussions with state and EPA regional contacts, EPA has found that states differ in the manner in which
they implement their section 316(b) authority. Some states and regions review section 316(b) requirements each time an
NPDES permit is reissued. These permitting authorities may reevaluate the potential for impacts and/or the environment that
influences the potential for impacts at the facility. Other permitting authorities made initial determinations for facilities in the
1970s but have not revisited the determinations since.
Based on the above findings, EPA believes that approaches to implementing section 316(b) vary greatly. It is evident that
some authorities have regulations and other program mechanisms in place to ensure continued implementation of section
316(b) and evaluation of potential impacts from CWIS, while others do not. Furthermore, there appears to be no mechanism
to ensure consistency across all states. Section 316(b) determinations are currently made on a case-by-case basis, based on
permit writers' best professional judgment. Through discussions with some state permitting officials (e.g., in California,
Georgia, and New Jersey), EPA was asked to establish national standards in order to help ease the case-by-case burden on
permit writers and to promote national uniformity with respect to implementation of section 316(b).
When environmental policies are implemented differently by two or more states that share access to the same waterbody, a
conflict may occur between the states because environmental losses caused in one state may affect the biology, environmental
conditions, and benefits of another state. Differences of this type are most likely to occur when the regulations governing the
operation of CWIS are established at the state level or are implemented in fundamentally different ways by the states (i.e.,
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
more and less stringent due to policy or failure to implement). When this happens, the state with less stringent requirements
imposes "external costs" or damages on the other state.
A good example of a conflict between states is in Mount Hope Bay, an interstate water straddling the Massachusetts/Rhode
Island state line. Brayton Point Station in Somerset, Massachusetts is the largest fossil fuel-burning steam-electric generating
facility in New England. The facility may have caused or contributed to a documented collapse in fish populations in Mount
Hope Bay affecting Rhode Island as well as Massachusetts.
The plant uses a once-through-cooling water system and is allowed by its current NPDES permit to withdraw up to 1.452
billion gallons a day (BGD) of water from Mount Hope Bay for cooling and then to discharge the heated water back to the
Bay at temperatures up to 22°F above ambient water conditions. The current NPDES permit "expired" in June, 1998, but
remains in effect while EPA develops a new permit. EPA co-issues this permit with the Massachusetts DEP. EPA must also
coordinate closely with Rhode Island because its waters are also affected by the plant. The permit must ensure that both
Massachusetts and Rhode Island water quality standards are satisfied unless a variance authorizing excursions from those
standards is granted. Similarly, both states' Coastal Zone Management Programs must be satisfied, along with the federal
Essential Fish Habitat program and other federal requirements.
There has been a significant amount of controversy about the plant because of the documented collapse of fish populations in
Mount Hope Bay and the debate over the power plant's role in causing or contributing to the fishery decline. On October 9,
1996, Rhode Island Department of Environmental Management issued a report which documented an alarming, sharp decline
in abundance of finfish populations in Mount Hope Bay that appeared to occur about seventeen years ago with no subsequent
recovery in evidence. Additional review of the data has suggested that the fishery decline actually began, albeit at a gentler
pace, before the sharp decline evidenced around 1985. Adverse effects of plant cooling system operations on aquatic
organisms can be divided into the following major categories: (1) cooling water intake entrainment offish eggs and larvae
and other small organisms into the plant's cooling system; (2) cooling water intake impingement of larger organisms on the
intake screening systems; and (3) discharge-related effects from the impacts of the thermal effluent on the aquatic community
and its habitat. Entrainment and thermal discharge appear to be especially significant issues for this plant, with impingement
appearing to be a relatively less major problem.
In response to the developing controversy, federal and state regulatory agencies and former plant owner NEPCO entered into
a Memorandum of Agreement (MOA) in April, 1997, regarding plant operations. The MOA places annual and seasonal caps
on the level of heat discharged and the amount of cooling water withdrawn from the Bay. In the MOA the Company agreed
to limit its operations to levels below that authorized by the (still) current NPDES permit and the agencies agreed not to push
for an immediate modification of the permit. (NEPCO had threatened to appeal any immediate permit modification anyway.)
The intake volume and thermal discharge caps in the MOA represented a compromise between the levels initially sought by
the regulatory agencies and the levels the company claimed were justified. The MOA also indicated that a number of types of
research should be pursued to help with development of a new NPDES permit. When PG&E bought Brayton Point Station it
assumed responsibility for complying with the MOA (the MOA required that agreement to comply with the MOA be made a
condition of any sale of the plant). Since the 1997 MOA, the permittee and the regulatory agencies have been engaged in
extensive monitoring, modeling and study to determine the conditions for a new NPDES permit.
On October 2, 2001, PG&E publicly announced a proposed $250,000,000 environmental improvement plan for the facility
including new air pollution controls, ash recycling facilities, and a new cooling water system using mechanical draft wet
cooling tower that PG&E refers to as the Enhanced Multi-Mode System. The Company intends this plan to address
requirements under the new State air quality regulations, a State Administrative Consent Order addressing ash management
practices, and the new NPDES permit. PG&E states that this new system will reduce heat loadings into Mount Hope Bay,
and reduce cooling water withdrawals from Mount Hope Bay, to pre-1984 levels. The year 1984 is significant because it was
the year that Brayton Point was permitted to switch Unit 4 from a previously closed-cycle cooling system to a once-through
cooling system, and some data suggests that the steep decline in fish populations was coincidental with this modification. (As
noted above, there is also data suggesting that the decline had started earlier but accelerated after Unit 4 began once-through
cooling operations.)
EPA is working closely with Massachusetts and Rhode Island on the permit, and has also been coordinating with the National
Marine Fisheries Service. The permit will be jointly issued with the state in Massachusetts which does not have NPDES
delegation. EPA is also in close communication with the company regarding the issues, and the company has submitted a
substantial amount of information supporting its view of what limits should be in the new permit. EPA has also received
significant communications from interested environmental groups. In addition, there has been congressional interest in both
A2-11
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
Massachusetts and Rhode Island as well as statements of concern by the Governor of Rhode Island. Public interest in the
permit development is high. Over the past year serious concerns have been raised by groups including Save the Bay,
Conservation Law Foundation, the Rhode Island Salt Water Anglers, and the New England Fishery Management Council.
Also, the Rhode Island Attorney General has also been actively engaged in tracking the matter and has publicly threatened to
sue the company over damage to Rhode Island's natural resources. Finally, the permit issues have received substantial
attention in local major media outlets, including a recent front page story in the Boston Globe.
Options considered by EPA differ considerably in their ability to reduce implementation differences between two or more
states that share access to the same waterbody. The greater the level of benefits associated with a regulation, the lower the
level of I&E losses that can occur in one state and affect the biology, environmental conditions, and benefits of another state.
Thus the greater the benefits of a regulation, the fewer the "external costs" or damages that can be imposed by one state on
other states.
A2-2.5 Reducing Transaction Costs
Transaction costs associated with the implementation of a regulation include: (1) determining the desired level of
environmental quality and (2) determining how to achieve it.
Transaction costs associated with determining the desired level of environmental quality have to do with the supply and
demand for environmental quality.
The presence of uncertainties increases transaction costs. Some uncertainties relate to the supply of environmental quality
(e.g., the actual impact of various control technologies in terms of the effectiveness of I&E reductions); others relate to the
demand for environmental quality (e.g., the value of reduced I&E in terms of individual and population impacts). Reducing
uncertainties would reduce transaction costs. Standardizing the protocol for monitoring and reporting I&E impacts reduces
the uncertainty about how to measure the impact of controls, and provides for a uniform "language" for communicating these
impacts. A federal regulation that establishes methods for mitigating the impact of regulatory uncertainty and information
uncertainty produces a benefit in the form of reduced (transaction) costs.
There is another set of uncertainties that is independent of the desired level of environmental quality. These uncertainties fall
into the broad categories of "regulatory uncertainty" and "information uncertainty." The costs related to these uncertainties
lead to "transaction costs," which cause inefficiencies in decision-making related to achieving a given level of environmental
quality. Regulatory uncertainty refers to the uncertainty that facilities face when making business decisions in response to
regulatory requirements when those requirements are uncertain. For example, facilities are making business decisions today
based on their best guess about what future regulation will look like. The cost of this uncertainty comes in the form of
delayed business decisions and poor business decisions based on incorrect guesses about the future regulation. Information
uncertainty refers to the uncertainty related to the measurement and communication of the impact of controls on actual I&E,
as well as the impact of I&E on populations. The consequence of information uncertainty is poor decision-making by
stakeholders (suppliers and demanders of environmental quality) and a reduction in the cost-effectiveness of meeting a
desired level of environmental quality.
Transaction costs are incurred at several levels, including the states and Tribes authorized to implement the NPDES program;
the federal government; and facilities subject to section 316(b) regulation.
Section 316(b) requirements are implemented through NPDES permits. States and Tribes authorized to implement the
NPDES program do so through the issuance of permits to power producing facilities. Forty-four states and the Virgin Islands
are currently authorized pursuant to section 402(b) of the CWA to implement the NPDES program. In states not authorized
to implement the NPDES program, EPA issues NPDES permits. Under the CWA, states are not required to become
authorized to administer the NPDES program. Rather, such authorization is available to states if they operate their programs
in a manner consistent with section 402(b) and applicable regulations. Generally, these provisions require that state NPDES
programs include requirements that are as stringent as federal program requirements. States retain the ability to implement
requirements that are broader in scope or more stringent than federal requirements (See section 510 of the CWA).
Each state's, Tribe's, or region's burden associated with permitting activities depends on their personnel's background,
resources, and the number of regulated facilities under their authority. Developing a permit requires technical and clerical
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
staff to gather, prepare, and review various documents and supporting materials, verify data sources, plan responses,
determine specific permit requirements, write the actual permit, and confer with facilities and the interested public.
Where states and Tribal governments do not have NPDES permitting authority, the federal government implements section
316(b) regulations through its regional offices. The section 316(b) regulation is also necessary to reduce the burden on the
regions.
Uncertainty about what constitutes AEI, and the BTA that would minimize AEI, also increases transaction costs to facilities.
Without well-defined section 316(b) requirements, facilities have an incentive to delay or altogether avoid implementing I&E
technologies by trying to show that their CWIS do not have impacts at certain levels of biological organization, e.g.,
population or community levels. Some facilities thus spend large amounts of time and money on studies and analyses without
ever implementing technologies that would reduce I&E. Better definition of section 316(b) requirements could lead to a
better use of these resources by investing them in I&E reduction rather than studies and analyses.
The options considered by EPA differ considerably in their ability to reduce transactions costs. The greater the site specific
nature of the regulation the greater the transaction costs associated with the regulation. Options that are simpler, even though
they may involve higher technology and operation and maintenance costs, are likely to have much lower transaction costs.
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§ 316(b) Phase II EBA, Part A: Background Information A2: Need for the Regulation
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Consolidated Edison Company of New York (ConEd). 2000. Draft Environmental Impact Statement for the State Pollutant
Discharge Elimination System Permits for Bowline Point, Indian Point 2 & 3, andRoseton Steam Electric Generating
Stations.
Science Applications International Corporation (SAIC). 1993. Review of Southern California Edison, San Onofre Nuclear
Generating Station (SONGS) 316(b) Demonstration. July, 20, 1993.
Science Applications International Corporation (SAIC). 1994a. Background Paper Number 3: Cooling Water Intake
Technologies. Prepared for U.S. EPA Office of Wastewater Enforcement and Compliance, Permits Division by SAIC, Falls
Church, VA.
Science Applications International Corporation (SAIC). 1994b. Preliminary Regulatory Development, Section 316(b) of the
Clean Water Act, Background Paper Number 1: Legislative, Regulatory, and Legal History of Section 316(b) and
Information on Federal and State Implementation of Cooling Water Intake Structure Technology Requirements. Prepared for
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Science Applications International Corporation (SAIC). 1996. Background Paper Number 2: Cooling Water Use of Selected
U.S. Industries. Prepared for U.S. EPA Office of Wastewater Enforcement and Compliance, Permits Division by SAIC, Falls
Church, VA.
Thurber, Nancy J. and David J. Jude. 1985. Impingement Losses at the D.C. Cook Nuclear Power Plant during 1975-1982
with aDiscussion of Factors Responsible and Possible Impact on Local Populations, Special Report No. 115 of the Great
Lakes Research Division. Great Lakes and Marine Waters Center. The University of Michigan.
U.S. Department of Energy (U.S. DOE). 1999a. Form EIA-860A (1999). Annual Electric Generator Report-Utility.
U.S. Department of Energy (U.S. DOE). 1999b. Form EIA-860B (1999). Annual Electric Generator Report-Nonutility.
U.S. Environmental Protection Agency (U.S. EPA). 1976. Development Document for Best Technology Available for the
Location, Design, Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental
Impact. Office of Water and Hazardous Materials, Effluent Guidelines Division, U.S. EPA, Washington, DC.
U.S. Environmental Protection Agency (U.S. EPA) Region IV. 1979. Brunswick Nuclear Steam Electric Generating Plant of
Carolina Power and Light Company Located near Southport, North Carolina, Historical Summary and Review of Section
316(b) Issues. September 19, 1979.
U.S. Environmental Protection Agency (U.S. EPA) Region IV. 1986. Findings and Determination under 33 U.S.C. Section
1326, In the Matter of Florida Power Corporation Crystal River Power Plant Units 1, 2, and 3. NPDES Permit No.
FL0000159. December 2, 1986.
U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling
Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
U.S. Environmental Protection Agency (U.S. EPA). 2001. Economic Analysis of the Final Regulations Addressing Cooling
Water Intake Structures for New Facilities. EPA-821-R-01-035. November 2001.
A2-14
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Chapter A3: Profile of the Electric
Power Industry
INTRODUCTION
This profile compiles and analyzes economic and financial
data for the electric power generating industry. It provides
information on the structure and overall performance of
the industry and explains important trends that may
influence the nature and magnitude of economic impacts
from the Proposed Section 316(b) Phase II Existing
Facilities Rule.
The electric power industry is one of the most extensively
studied industries. The Energy Information
Administration (EIA), among others, publishes a multitude
of reports, documents, and studies on an annual basis.
This profile is not intended to duplicate those efforts.
Rather, this profile compiles, summarizes, and presents
those industry data that are important in the context of the
proposed Phase II rule. For more information on general
CHAPTER CONTENTS
A3-1 Industry Overview A3-1
A3-1.1 Industry Sectors A3-2
A3-1.2 Prime Movers A3-2
A3-1.3 Ownership A3-3
A3-2 Domestic Production A3-5
A3-2.1 Generating Capacity A3-6
A3-2.2 Electricity Generation A3-7
A3-2.3 Geographic Distribution A3-8
A3-3 Existing Plants with CWIS and NPDES Permit .... A3-11
A3-3.1 Existing Section 316(b) Utility Plants A3-13
A3-3.2 Existing Section 316(b) Nonutility Plants A3-18
A3-4 Industry Outlook A3-24
A3-4.1 Current Status of Industry Deregulation A3-24
A3-4.2 Energy Market Model Forecasts A3-25
Glossary A3-27
References A3-29
concepts, trends, and developments in the electric power
industry, the last section of this profile, "References," presents a select list of other publications on the industry.
The remainder of this profile is organized as follows:
>• Section A3-1 provides a brief overview of the industry, including descriptions of major industry sectors, types of
generating facilities, and the entities that own generating facilities.
*• Section A3-2 provides data on industry production and capacity.
*• Section A3-3 focuses on the in-scope section 316(b) facilities. This section provides information on the
geographical, physical, and financial characteristics of the in-scope phase II facilities.
>• Section A3 -4 provides a brief discussion of factors affecting the future of the electric power industry, including the
status of restructuring, and summarizes forecasts of market conditions through the year 2020.
A3-1 INDUSTRY OVERVIEW
This section provides a brief overview of the industry, including descriptions of major industry sectors, types of generating
facilities, and the entities that own generating facilities.
A3-1
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
A3-1.1 Industry Sectors
The electricity business is made up of three major functional service components or sectors: generation, transmission, and
distribution. These terms are defined as follows (Beamon, 1998; Joskow, 1997):1
*• The sector includes the power plants that produce, or "generate," electricity.2 Electric energy is
produced using a specific generating technology, e.g., internal combustion engines and turbines. Turbines can be
driven by wind, moving water (hydroelectric), or steam from fossil fuel-fired boilers or nuclear reactions. Other
methods of power generation include geothermal or photovoltaic (solar) technologies.
*• The sector can be thought of as the interstate highway system of the business - the large,
high-voltage power lines that deliver electricity from power plants to local areas. Electricity transmission involves
the "transportation" of electricity from power plants to distribution centers using a complex system. Transmission
requires: interconnecting and integrating a number of generating facilities into a stable, synchronized, alternating
current (AC) network; scheduling and dispatching all connected plants to balance the demand and supply of
electricity in real time; and managing the system for equipment failures, network constraints, and interaction with
other transmission networks.
>• The sector can be thought of as the local delivery system - the relatively low-voltage power lines that
bring power to homes and businesses. Electricity distribution relies on a system of wires and transformers along
streets and underground to provide electricity to residential, commercial, and industrial consumers. The distribution
system involves both the provision of the hardware (e.g., lines, poles, transformers) and a set of retailing functions,
such as metering, billing, and various demand management services.
Of the three industry sectors, only electricity generation uses cooling water and is subject to section 316(b). The remainder of
this profile will focus on the generation sector of the industry.
A3-1.2 Prime Movers
Electric power plants use a variety to generate electricity. The type of prime mover used at a given plant
is determined based on the type of load the plant is designed to serve, the availability of fuels, and energy requirements. Most
prime movers use fossil fuels (coal, petroleum, and natural gas) as an energy source and employ some type of turbine to
produce electricity. The six most common prime movers are (U.S. DOE, 2000a):
*• Steam turbine, or "steam electric" units require a fuel source to boil water and produce steam that
drives the turbine. Either the burning of fossil fuels or a nuclear reaction can be used to produce the heat and steam
necessary to generate electricity. These units are generally that are run continuously to serve the
minimum load required by the system. Steam electric units generate the majority of electricity produced at power
plants in the U.S.
> Gas turbine units burn a combination of natural gas and distillate oil in a high
pressure chamber to produce hot gases that are passed directly through the turbine. Units with this prime mover are
generally less than 100 megawatts in size, less efficient than steam turbines, and used for operation
serving the highest daily, weekly, or seasonal loads. Gas turbine units have quick startup times and can be installed
at a variety of site locations, making them ideal for peak, emergency, and reserve-power requirements.
*• Combined-cycle units utilize both steam and gas turbine prime mover technologies to
increase the efficiency of the gas turbine system. After combusting natural gas in gas turbine units, the hot gases
from the turbines are transported to a waste-heat recovery steam boiler where water is heated to produce steam for a
second steam turbine. The steam may be produced solely by recovery of gas turbine exhaust or with additional fuel
input to the steam boiler. Combined-cycle generating units are generally used for
1 Terms highlighted in bold and italic font are defined in the glossary at the end of this chapter.
2 The terms "plant" and "facility" are used interchangeably throughout this profile.
A3-2
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
> Internal combustion engines contain one or more cylinders in which fuel is
combusted to drive a generator. These units are generally about 5 megawatts in size, can be installed on short notice,
and can begin producing electricity almost instantaneously. Like gas turbines, internal combustion units are
generally used only for peak loads.
*• Units with water turbines, or "hydroelectric units," use either falling water or the force of a natural
river current to spin turbines and produce electricity. These units are used for all types of loads.
> Other methods of power generation include geothermal, solar, wind, and biomass prime
movers. The contribution of these prime movers is small relative to total power production in the U.S., but the role
of these prime movers may expand in the future because recent legislation includes incentives for their use.
Table A3-1 provides data on the number of existing utility and nonutility power plants by prime mover. This table includes
all plants that have at least one non-retired unit and that submitted Forms EIA-860A (Annual Electric Generator Report -
Utilities) or EIA-860B (Annual Electric Generator Report - Nonutilities) in 1999.3 For the purpose of this analysis, plants
were classified as "steam turbine" or "combined-cycle" if they have at least one generating unit of that type. Plants that do
not have any steam electric units, were classified under the prime mover type that accounts for the largest share of the plant's
total electricity generation.
Table A3-1: Number of Existing Utility and Nonutility Plants by Prime Mover, 1999
Prime Mover
Steam Turbine
Combined-Cycle
Gas Turbine
Internal Combustion
Hydroelectric
Other
Total
Utility"
Number of Plants
803
59
335
642
1,237
49
3,125
Nonutility"
Number of Plants
821
201
372
245
476
90
2,205
a See definition of utility and nonutility in Section A3-1.3.
Source: U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
Only prime movers with a steam electric generating cycle use substantial amounts of cooling water. These generators include
steam turbines and combined-cycle technologies. As a result, the analysis in support of the proposed Phase II rule focuses on
generating plants with a steam electric prime mover. This profile will, therefore, differentiate between steam electric and
other prime movers.
A3-1.3 Ownership
The U.S. electric power industry consists of two broad categories of firms that own and operate electric generating plants:
utilities and nonutilities. Generally, they can be defined as follows (U.S. DOE, 2000a):
*• A regulated entity providing electric power, traditionally vertically integrated. Utilities may or may not
generate electricity. "Transmission utility" refers to the regulated owner/operator of the transmission system only.
"Distribution utility" refers to the regulated owner/operator of the distribution system serving retail customers.
3 At the time of publication of this document, 1999 was the most recent year for which complete EIA data were available for existing
utility and nonutility plants. As of March 2002 EIA 860B data were not available for year 2000. As such, this profile is based on 1999
data.
A3-3
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
*• Nonutility: Entities that generate power for their own use and/or for sale to utilities and others. Nonutility power
producers include cogenerators, small power producers, and independent power producers. Nonutilities do not have
a designated franchised service area and do not transmit or distribute electricity.
Utilities can be further divided into three major ownership categories: investor-owned utilities, publicly-owned utilities, and
rural electric cooperatives. Each category is discussed below.
a. Investor-owned utilities
Investor-owned utilities (lOUs) are for-profit businesses that can take two basic organizational forms: the individual
corporation and the holding company. An individual corporation is a single utility company with its own investors; a holding
company is a business entity that owns one or more utility companies and may have other diversified holdings as well. Like
all businesses, the objective of an IOU is to produce a return for its investors. lOUs are entities with designated franchise
areas. They are required to charge reasonable and comparable prices to similar classifications of consumers and give
consumers access to services under similar conditions. Most lOUs engage in all three activities: generation, transmission, and
distribution. In 1999, lOUs operated 1,662 facilities, which accounted for approximately 58 percent of all U.S. electric
generation capacity (U.S. DOE, 1999a; U.S. DOE, 1999c; U.S. DOE, 1998c).
b. Publicly-owned utilities
Publicly-owned electric utilities can be municipalities, public power districts, state authorities, irrigation projects, and other
state agencies established to serve their local municipalities or nearby communities. Excess funds or "profits" from the
operation of these utilities are put toward community programs and local government budgets, increasing facility efficiency
and capacity, and reducing rates. This profile also includes federally-owned facilities in this category. Most municipal
utilities are nongenerators engaging solely in the purchase of wholesale electricity for resale and distribution. The larger
municipal utilities, as well as state and federal utilities, usually generate, transmit, and distribute electricity. In general,
publicly-owned utilities have access to tax-free financing and do not pay certain taxes or dividends, giving them some cost
advantages over lOUs. In 1999, publicly-owned utilities operated 1,250 facilities and accounted for approximately 16 percent
of all U.S. electric generation capacity (U.S. DOE, 1999a; U.S. DOE, 1999c; U.S. DOE, 1998c).
c. Rural electric cooperatives
Cooperative electric utilities ("coops") are member-owned entities created to provide electricity to those members. These
utilities, established under the Rural Electrification Act of 1936, provide electricity to small rural and farming communities
(usually fewer than 1,500 consumers). The National Rural Utilities Cooperative Finance Corporation, the Federal Financing
Bank, and the Bank of Cooperatives are important sources of financing for these utilities. Cooperatives operate in 34 states
and are incorporated under state laws. In 1999, rural electric cooperatives operated 213 generating facilities, and accounted
for approximately 3 percent of all U.S. electric generation capacity. (U.S. DOE, 1999a; U.S. DOE, 1999c; U.S. DOE, 1998c).
A3-4
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Figure A3-1 presents the number of generating facilities and their capacity in 1999, by type of ownership.4 The horizontal
axis also presents the percentage of the U.S. total that each type represents. This figure is based on data for all plants that
have at least one non-retired unit and that submitted Forms EIA-860A or EIA-860B in 1999. The graphic shows that
nonutilities account for the largest percentage of facilities (2,205, or about 41 percent), but only represent 23 percent of total
U.S. generating capacity. Investor-owned utilities operate the second largest number of facilities, 1,662, and generate 58
percent of total U.S. capacity.
Figure A3-1: Distribution of Facilities and Capacity by Ownership Type, 1999
Nonutilities
Cooperati\e
Utilities
ln\estor Owned
Publicly Owned
| Capacity
(GW)
D Number of
Facilities
0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0%
a In order to best understand the landscape of the electric power generating market EPA tracked
ownership changes from utilities to nonutilities, and vice versa, through January, 2002. These
changes have been incorporated into the analysis where possible.
Source: U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c; U.S. DOE 1998c.
Plants owned and operated by utilities and nonutilities may be affected differently by the proposed Phase II rule due to
differing competitive roles in the market. Much of the following discussion therefore differentiates between these two
groups.
A3-2 DOMESTIC PRODUCTION
This section presents an overview of U.S. generating capacity and electricity generation. Subsection A3-2.1 provides data on
capacity, and Subsection A3-2.2 provides data on generation. Subsection A3-2.3 presents an overview of the geographic
distribution of generation plants and capacity.
4 EPA tracked ownership changes from utilities to nonutilities, and vice versa, through January 2002. These changes are
incorporated into the profile. As such, the universe of facilities (and their corresponding characteristics) is based on EIA 1999 data,
adjusted to reflect EPA's most current knowledge.
A3-5
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
A3-2.1 Generating Capacity5
Utilities own and operate the majority of the
generating capacity in the United States (77 percent).
Nonutilities owned only 23 percent of the total
capacity in 1999 and produced roughly 21 percent of
the electricity in the country. Nonutility capacity and
generation have increased substantially in the past
few years, however, since passage of legislation
aimed at increasing competition in the industry.
Nonutility capacity has increased by 247 percent
between 1991 and 1998, compared with the decrease
in utility capacity of eight percent over the same time
period.6
Figure A3-2 shows the growth in utility and
nonutility capacity from 1991 to 1999. The growth in
nonutility capacity, combined with a slight decrease
in utility capacity, has resulted in a modest growth in
total generating capacity. The significant increase in
nonutility capacity, and decrease in utility capacity in
1999 is attributable to utilities being sold to nonutilities.
CAPACITY/CAPABILITY
The rating of a generating unit is a measure of its ability to produce
electricity. Generator ratings are expressed in megawatts (MW).
Capacity and capability are the two common measures:
Nameplate capacity is the full-load continuous output rating of the
generating unit under specified conditions, as designated by the
manufacturer.
Net capability is the steady hourly output that the generating unit is
expected to supply to the system load, as demonstrated by test
procedures. The capability of the generating unit in the summer is
generally less than in the winter due to high ambient-air and
cooling-water temperatures, which cause generating units to be less
efficient. The nameplate capacity of a generating unit is generally
greater than its net capability.
U.S. DOE,2000a
Figure A3-2: Generating Capability & Capacity, 1991 to 1999°
800 -i
700
600
500
400 -
300
200
100
X
-
u
99
L
1 1
M
y
99
L
2 1
^
Lk
993 1
^
Ik
994 1
^=
Lk
995 1
H
Lk
996 1
a
Lk
997 1
-j
I
9£
[
8 1
^
1
999
D Utility
Capability
• Nonutility
Capacity
Source: U.S. DOE, 2000c; U.S. DOE,1996b.
5 The numbers presented in this section are capability for utilities and capacity for nonutilities (see text box for the difference
between these two measures). For convenience purposes, this section will refer to both measures as"capacity."
6 More accurate data were available starting in 1991, therefore, 1991 was selected as the initial year for trends analysis.
A3-6
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
A3-2.2 Electricity Generation
Total net electricity generation in the U.S. for 1999
was 3,723 billion kWh. Utility-owned plants
accounted for 85 percent of this amount. Total net
generation has increased by 21 percent over the
nine-year period from 1991 to 1999. During this
period, nonutilities increased their electricity
generation by 131 percent. In comparison,
generation by utilities increased by only 12 percent
(U.S. DOE, 2000b; U.S. DOE, 2000c; U.S. DOE,
1995a; U.S. DOE, 1995b). This trend is expected to
continue with deregulation in the coming years, as
more facilities are purchased and built by nonutility
power producers.
Table A3-2 shows the change in net generation
between 1991 and 1999 by fuel source for utilities
and nonutilities.
MEASURES OF GENERATION
The production of electricity is referred to as generation and is measured
in kilowatthours (kWh). Generation can be measured as:
Gross generation: The total amount of power produced by an electric
power plant.
Net generation: Power available to the transmission system beyond
that needed to operate plant equipment. For example, around 7% of
electricity generated by steam electric units is used to operate equipment.
Electricity available to consumers: Power available for sale to
customers. Approximately 8 to 9 percent of net generation is lost during
the transmission and distribution process.
U.S. DOE,2000a
Table A3-2: Net Generation by Energy Source and Ownership Type, 1991 to 1999 (6Wh)
Energy
Source
Coal
Hydropower
Nuclear
Petroleum
Gas
Renewablesb
Total
Utilities
1991
1,551
280
613
111
264
10
2,830
1999
1,768
294
725
87
296
4
3,174
% Change
14%
5%
18%
-22%
12%
-63%
12%
Nonutilities3
1991
39
6
0
8
127
57
238
1999
126
22
9
21
296
76
549
% Change
219%
248%
0%
181%
132%
33%
131%
Total
1991
1,591
286
613
119
392
67
3,067
1999
1,893
315
734
108
592
80
3,723
% Change
19%
10%
20%
-9%
51%
19%
21%
a Nonutility generation was converted from gross to net generation based on prime mover-specific conversion factors (U.S. DOE,
2000c). As a result of this conversion, the total net generation estimates differ slightly from EIA published totals by fuel type.
b Renewables include solar, wind, wood, biomass, and geothermal energy sources.
Source: U.S. DOE, 2000b;U.S. DOE, 2000c; U.S. DOE, 1995a; U.S. DOE,1995b.
As shown in Table A3-2, nuclear generation grew the fastest among the utility fuel source categories, increasing by 18
percent between 1991 and 1999. Coal generation increased by 14 percent, while gas generation increased by 12 percent.
Utility generation from renewable energy sources decreased significantly (63 percent) between 1991 and 1999. A majority of
this decline (48 percent) occurred from 1998 to 1999. Nonutility generation has grown at a much higher rate between 1991
and 1999 with the passage of legislation aimed at increasing competition in the industry. Nonutility hydroelectric generation
grew the fastest among the energy source categories, increasing 248 percent between 1991 and 1999. Generation from coal-
fired facilities also increased substantially, with a 219 percent increase in generation between 1991 and 1999.
,4.3-7
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Figure A3-3 shows total net generation for the U.S. by primary fuel source for utilities and nonutilities. Electricity generation
from coal-fired plants accounts for 47 percent of total 1999 generation. Electric utilities generate 93 percent (1,768 billion
kWh) of the 1,893 billion kWh of electricity generated by coal-fired plants. This represents approximately 56 percent of total
utility generation. The remaining 7 percent (126 billion kWh) of coal-fired generation is provided by nonutilities, accounting
for 23 percent of total nonutility generation. The second largest source of electricity generation is nuclear power plants,
accounting for 20 percent of both total generation and total utility generation. Figure A3-3 shows that virtually 99.8 percent
of nuclear generation is owned and operated by utilities. Another significant source of electricity generation is gas-fired
power plants, which account for 54 percent of nonutility generation and 16 percent of total generation.
Figure A3-3: Percent of Electricity Generation by Primary Fuel Source, 1999
60.0%
50.0%
40.0%
30.0%
20.0%
10.0%
0.0%
ton-Utility
D Utility
Source: U.S. DOE,2000b; U.S. DOE,2000c.
The proposed Phase II rule will affect facilities differently based on the fuel sources and prime movers used to generate
electricity. As mentioned in Section A3-1.2 above, only prime movers with a steam electric generating cycle use substantial
amounts of cooling water.
A3-2.3 Geographic Distribution
Electricity is a commodity that cannot be stored or easily transported over long distances. As a result, the geographic
distribution of power plants is of primary importance to ensure a reliable supply of electricity to all customers. The U.S. bulk
power system is composed of three major networks, or power grids:
*• the Eastern Interconnected System, consisting of one third of the U.S., from the east coast to east of the Missouri
River;
*• the Western Interconnected System, west of the Missouri River, including the Southwest and areas west of the Rocky
Mountains; and
> the Texas Interconnected System, the smallest of the three, consisting of the majority of Texas.
The Texas system is not connected with the other two systems, while the other two have limited interconnection to each
other. The Eastern and Western systems are integrated or have links to the Canadian grid system. The Western and Texas
systems have links with Mexico.
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
These major networks contain extra-high voltage connections that allow for power transactions from one part of the network
to another. Wholesale transactions can take place within these networks to reduce power costs, increase supply options, and
ensure system reliability. Reliability refers to the ability of power systems to meet the demands of consumers at any given
time. Efforts to enhance reliability reduce the chances of power outages.
The North American Electric Reliability Council (NERC) is responsible for the overall reliability, planning, and coordination
of the power grids. This voluntary organization was formed in 1968 by electric utilities, following a 1965 blackout in the
Northeast. NERC is organized into nine regional councils that cover the 48 contiguous states, Hawaii, part of Alaska, and
portions of Canada and Mexico. These regional councils are responsible for the overall coordination of bulk power policies
that affect their regions' reliability and quality of service. Each NERC region deals with electricity reliability issues in its
region, based on available capacity and transmission constraints. The councils also aid in the exchange of information among
member utilities in each region and among regions. Service areas of the member utilities determine the boundaries of the
NERC regions. Though limited by the larger bulk power grids described in the previous section, NERC regions do not
necessarily follow any state boundaries. Figure A3-4 below provides a map of the NERC regions, which include:
>• 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 Interconnect Network
> MAPP - Mid-Continent Area Power Pool (U.S.)
> NPCC - Northeast Power Coordinating Council (U.S.)
>• SERC - Southeastern Electric Reliability Council
> SPP - Southwest Power Pool
> WSCC - Western Systems Coordinating Council (U.S.)
Alaska and Hawaii are not shown in Figure A3-4. Part of Alaska is covered by the Alaska Systems Coordinating Council
(ASCC), an affiliate NERC member. The state of Hawaii also has its own reliability authority (HI).
Figure A3-4: North American Electric Reliability Council (NERC) Regions
MAAC
FRCC
Source: EIA, 1996.
The proposed Phase II rule may affect plants located in different NERC regions differently. Economic characteristics of
existing facilities affected by the proposed Phase II rule are likely to vary across regions by fuel mix, and the costs of fuel,
A3-9
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
transportation, labor, and construction. Baseline differences in economic characteristics across regions may influence the
impact of the proposed Phase II rule on profitability, electricity prices, and other impact measures. However, as discussed in
Chapter B3: Electricity Market Model Analysis, the proposed Phase II rule will have little or no impact on electricity prices in
each region since the proposed Phase II rule is relatively inexpensive relative to the overall production costs in any region.
Table A3-3 shows the distribution of all existing utilities, utility-owned plants, and capacity by NERC region. The table
shows that while the Mid-Continent Area Power Pool (MAPP) has the largest number of utilities, 24 percent, these utilities
only represent five percent of total capacity. Conversely, only five percent of the nation's utilities are located in the
Southeastern Electric Reliability Council (SERC), yet these utilities are generally larger and account for 23 percent of the
industry's total generating capacity.
Table A3-3: Distribution of Existing Generation Utilities, Utility Plants, and Capacity by NERC Region, 1999
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Unknown
Total
Generation Utilities
Number % of Total
52 6%
100 11%
28 3%
18 2%
3 0%
21 2%
65 7%
212 24%
73 8%
43 5%
144 16%
129 14%
3 0%
891 100%
Utility Plants
Number % of Total
168 5%
301 10%
107 3%
62 2%
16 1%
93 3%
207 7%
406 13%
394 13%
333 11%
262 8%
773 25%
3 0%
3,125 100%
Capacity
Total MW % of Total
2,019 0%
112,439 16%
55,908 8%
38,155 5%
1,592 0%
23,649 3%
45,120 6%
36,094 5%
45,948 7%
164,235 23%
45,782 7%
131,644 19%
39 0%
702,624 100%
Source: U.S. DOE, 1999a; U.S. DOE, 1999c.
A3-10
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-4 shows the distribution of existing nonutility plants and capacity by NERC region. The table shows that the
Western Systems Coordinating Council (WSCC) has the largest number of nonutility plants, with 613. MAAC, which
contains only 7 percent of the total number of nonutility plants, accounts for the largest portion of capacity, with 43,547 MW
(21 percent).
Table A3 -4: Distribution of
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Unknown
Total
Nonutility Plants and Capacity
Nonutility Plants
Number
26
139
75
57
11
155
136
70
531
279
43
613
70
2,205
% of Total
1%
6%
3%
3%
0%
7%
6%
3%
24%
13%
2%
28%
3%
100%
by NERC Region, 1999
Capacity
Total MW
300
8,883
9,525
4,173
740
43,547
30,398
1,599
39,720
16,293
1,844
39,894
9,584
206,500
% of Total
0%
4%
5%
2%
0%
21%
15%
1%
19%
8%
1%
19%
5%
100%
Source: U.S. DOE, 1999a: U.S. DOE, 1999b: U.S. DOE, 1999c.
A3-3 EXISTING PLANTS WITH CWIS AND NPDES PERMIT
Section 316(b) of the Clean Water Act applies to a point source facility uses or proposes to use a cooling water intake
structure water that directly withdraws cooling water from a water of the United States. Among power plants, only those
facilities employing a steam electric generating technology require cooling water and are therefore of interest to this analysis.
Steam electric generating technologies include units with steam electric turbines and combined-cycle units with a steam
component.
The following sections describe existing utility and nonutility power plants that would be subject to the proposed Phase II
rule. The Proposed Section 316(b) Phase II Existing Facilities Rule applies to existing steam electric power generating
facilities that meet all of the following conditions:
* They meet the definition of an existing steam electric power generating facility as specified in § 125.93 of this rule;
* They use a cooling water intake structure or structures, or obtain cooling water by any sort of contract or
arrangement with an independent supplier who has a cooling water intake structure;
*• Their cooling water intake structure(s) withdraw(s) cooling water from waters of the U.S., and at least twenty-five
(25) percent of the water withdrawn is used for contact or non-contact cooling purposes;
*• They have an NPDES permit or are required to obtain one; and
*• They have a design intake flow of 50 MOD or greater.
A3-11
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
The proposed Phase II rule also covers substantial additions or modifications to operations undertaken at such facilities.
While all facilities that meet these criteria are subject to the regulation, this Economic and Benefit Analysis (EBA) focuses on
539 utility and non-utility steam electric power generating facilities identified in EPA's 2000 Section 316(b) Industry Survey
as being "in-scope" of this proposed rule. These 539 facilities represent 550 facilities nation-wide.7 The remainder of this
chapter will refer to these facilities as "existing section 316(b) plants."
Utilities and nonutilities are discussed in separate subsections because the data sources, definitions, and potential factors
influencing the magnitude of impacts are different for the two sectors. Each subsection presents the following information:
> Ownership type: This section discusses existing section 316(b) facilities with respect to the entity that owns them.
Utilities are classified into investor-owned utilities, rural electric cooperatives, municipalities, and other publicly-
owned utilities (see Section A3-1.3). This differentiation is important because EPA has separately considered
impacts on governments in its regulatory development (see Chapter B9: UMRA Analysis for the analysis of
government impacts of the proposed Phase II rule). The utility ownership categories do not apply to nonutilities.
The ownership type discussion for nonutilities differentiates between two types of plants: (1) plants that were
originally built by nonutility power producers ("original nonutility plants") and (2) plants that used to be owned by
utilities but that were sold to nonutilities as a result of industry deregulation ("former utility plants"). Differentiation
between these two types of nonutilities is important because of their different economic and operational
characteristics.
Ownership size: This section presents information on
the Small Business Administration (SBA) entity size of
the owners of existing section 316(b) facilities. EPA
has considered economic impacts on small entities
when developing this regulation (see Chapter B4:
Regulatory Flexibility Analysis for the small entity
analysis of new facilities subject to the proposed Phase
II rule).
Plant size: This section discusses the existing
section 316(b) facilities by the size of their generation
capacity. The size of a plant is important because it
partly determines its need for cooling water.
Geographic distribution: This section discusses plants
by NERC region. The geographic distribution of
facilities is important because a high concentration of
facilities with costs under a regulation could lead to
impacts on a regional level. Everything else being
equal, the higher the share of plants with costs, the
higher the likelihood that there may be economic
and/or system reliability impacts as a result of the
regulation.
Water body and cooling system type: This section
presents information on the type of water body from
which existing section 316(b) facilities draw their cooling water and the type of cooling system they operate.
Cooling systems can be either once-through or recirculating systems.8 Plants with once-through cooling water
systems withdraw between 70 and 98 percent more water than those with recirculating systems.
WATER USE BY STEAM ELECTRIC
POWER PLANTS
Steam electric generating plants are the single largest
industrial users of water in the United States. In 1995:
*• steam electric plants withdrew an estimated 190
billion gallons per day, accounting for 39 percent of
freshwater use and 47 percent of combined fresh
and saline water withdrawals for offstream uses
(uses that temporarily or permanently remove water
from its source);
*• fossil-fuel steam plants accounted for 71 percent of
the total water use by the power industry;
*• nuclear steam plants and geothermal plants
accounted for 29 percent and less than 1 percent,
respectively;
*• surface water was the source for more than 99
percent of total power industry withdrawals;
*• approximately 69 percent of water intake by the
power industry was from freshwater sources, 31
percent was from saline sources.
USGS, 1995
7 EPA applied sample weights to the 539 facilities to account for non-sampled facilities and facilities that did not respond to the
survey. For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA 2000).
8 Once-through cooling systems withdraw water from the water body, run the water through condensers, and discharge the water after
a single use. Recirculating systems, on the other hand, reuse water withdrawn from the source. These systems take new water into the
system only to replenish losses from evaporation or other processes during the cooling process. Recirculating systems use cooling towers
or ponds to cool water before passing it through condensers again.
A3-12
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
A3-3.1 Existing Section 316(b) Utility Plants
EPA identified steam electric prime movers that require cooling water using information from the EIA data collection U.S.
DOE, 1999a.9 These prime movers include:
>• Atmospheric Fluidized Bed Combustion (AB)
>• Combined-Cycle Steam Turbine with Supplementary Firing (CA)
> Combined Cycle - Total Unit (CC)
*• Steam Turbine - Common Header (CH)
> Combined-Cycle - Single Shaft (CS)
> Combined-Cycle Steam Turbine - Waste Heat Boiler Only (CW)
*• Steam Turbine - Geothermal (GE)
>• Integrated Coal Gasification Combined-Cycle (IG)
>• Steam Turbine - Boiling Water Nuclear Reactor (NB)
>• Steam Turbine - Graphite Nuclear Reactor (NG)
>• Steam Turbine - High Temperature Gas-Cooled Nuclear Reactor (NH)
*• Steam Turbine - Pressurized Water Nuclear Reactor (NP)
> Steam Turbine - Solar (SS)
> Steam Turbine - Boiler (ST)
Using this list of steam electric prime movers, and U.S. DOE, 1999a information on the reported operating status of units,
EPA identified 862 facilities that have at least one generating unit with a steam electric prime mover. Additional information
from the section 316(b) Industry Surveys was used to determine that 416 of the 862 facilities operate a CWIS and hold an
NPDES permit. Table A3-5 provides information on the number of utilities, utility plants, and generating units, and the
generating capacity in 1999. The table provides information for the industry as a whole, for the steam electric part of the
industry, and for the part of the industry potentially affected by the proposed Phase II rule.
Table A3-5: Number of Existing Utilities, Utility Plants, Units, and Capacity, 1999
Utilities
Plants
Units
Nameplate Capacity (MW)
Total"
891
3,125
10,460
702,624
Steam Electricb
Number % of Total
315 35%
862 28%
2,226 21%
533,503 76%
Steam Electric with CWIS and
NPDES Permit0
Number % of Total
148 17%
416 13%
1,220 12%
344,849 49%
a Includes only generating capacity not permanently shut down or sold to nonutilities.
b Utilities and plants are listed as steam electric if they have at least one steam electric unit.
c The number of plants, units, and capacity was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
Table A3-5 shows that the while the 862 steam electric plants account for only 28 percent of all plants, these plants account
for 76 percent of all capacity. The 416 in-scope plants represent 13 percent of all plants, are owned by 17 percent of all
utilities, and account for approximately 49 percent of reported utility generation capacity. The remainder of this section will
focus on the 416 utility plants.
9 U.S. DOE, 1999a (Annual Electric Generator Report) collects data used to create an annual inventory of utilities. The data
collected includes: type of prime mover; nameplate rating; energy source; year of initial commercial operation; operating status; cooling
water source, and NERC region.
A3-13
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
a. Ownership type
Table A3-6 shows the distribution of the 148 utilities that own the 416 existing section 316(b) plants, as well as the total
generating capacity of these entities, by type of ownership. The table also shows the total number of plants, utilities, and
capacity by type of ownership. Utilities can be divided into three major ownership categories: investor-owned utilities,
publicly-owned utilities (including municipalities, political subdivision, and federal and state-owned utilities), and rural
electric cooperatives. Table A3-6 shows that approximately 19 percent of plants operated by investor-owned utilities have a
CWIS and an NPDES permit. These 313 facilities account for 75 percent of all existing plants with a CWIS and an NPDES
permit (313 divided by 416). The percentage of all plants that have a CWIS and an NPDES permit is lower for the other
ownership types: 12 percent for rural electric cooperatives, six percent for municipalities, and seven percent for other publicly
owned utilities.
Table A3-6: Existing Utilities, Plants, and Capacity by Ownership Type, 1999°
Ownership
Type
Investor-Owned
Coop
Municipal
Other Public
Total
Utilities
Total
Number of
Utilities
177
71
578
65
891
Utilities with Plants
with CWIS and
NPDES
Number
oo
OO
14
38
8
148
%of
Total
50%
20%
7%
12%
17%
Plants
Total
Number
of
Plants
1,662
213
867
383
3,125
Plants with CWIS
and NPDESb
Number
313
25
50
27
416
%of
Total
19%
12%
6%
7%
13%
Capacity (MW)
Total
Capacity
527,948
28,151
42,904
103,621
702,624
Capacity with CWIS
and NPDESb
MW
287,774
8,582
15,870
32,623
344,850
%of
Total
55%
30%
37%
31%
68%
a Numbers may not add up to totals due to independent rounding.
b The number of plants and capacity was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
A3-14
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
b. Ownership size
EPA used the Small Business Administration (SB A) small entity size standards for SIC code 4911 (electric output of four
million megawatt hours or less per year) to make the small entity determination.10 Table A3-7 provides information on the
total number of utilities and utility plants owned by small entities by type of ownership. The table shows that 26 of the 148
utilities with existing section 316(b) plants, or 18 percent, may be small. The size distribution varies considerably by
ownership type: only 13 percent of all other public utilities and zero percent of all investor-owned utilities with existing
section 316(b) plants may be small, compared to 43 percent of all coop and 50 percent of all municipalities. The same is true
on the plant level: none of the 313 existing section 316(b) plants operated by an investor-owned utility, and four percent of
the other publicly owned utilities are owned by a small entity. The corresponding percentages for municipalities and electric
cooperatives are 38 percent and 24 percent, respectively.11
Table A3-7 also shows the percentage of all small utilities and all plants owned by small utilities that comprise the
"section 316(b)" part of the industry. Twenty-six, or four percent, of all 697 small utilities operate existing section 316(b)
plants. At the plant level, between one percent (other public) and four percent (Coop) of small utility plants have CWIS and
NPDES permits.
Table A3-7: Existing Small Utilities and Utility Plants by Ownership Type, 1999
Ownership
Type
Total
Total
Investor-Owned
Coop
Municipal
Other Public
Total
177
71
578
65
891
Investor-Owned
Coop
Municipal
Other Public
Total
1,662
213
867
383
3,125
Small
47
54
557
39
697
211
154
781
136
1,282
Unknown
11
1
11
9
32
26
0
9
71
106
%
Small
With CWIS and NPDES Permit ab
Total
Utilities
27%
76%
96%
60%
78%
88
14
38
148
Plants
13%
72%
90%
36%
41%
313
25
50
27
416
Small
0
6
19
1
26
0
6
19
1
26
Unknown
0
0
2
0
2
0
0
2
0
2
% Small
Small with
CWIS and
NPDES/ Total
Small
0%
43%
50%
13%
18%
0%
11%
3%
3%
4%
0%
24%
38%
4%
11%
0%
4%
2%
1%
2%
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. SBA, 2000; U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c; U.S. DOE 1999d.
10 SBA defines "small business" as a firm with an annual electricity output of four million MWh or less and "small governmental
jurisdictions" as governments of cities, counties, towns, school districts, or special districts with a population of less than 50,000 people.
Information on the population of all municipal utilities was not readily available for all municipalities. EPA therefore used the small
business standard for all utilities.
11 Note that for investor-owned utilities, the small business determination is generally made at the holding company level. Holding
company information was not available for all investor-owned utilities. The small business determination was therefore made at the utility
level. This approach will overstate the number of investor-owned utilities and their plants that are classified as small.
A3-15
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
c. Plant size
EPA also analyzed the steam electric facilities with a CWIS and an NPDES permit with respect to their generating capacity.
Figure A3-5 presents the distribution of existing utility plants with a CWIS and an NPDES permit by plant size. Of the 416
plants, 189 (45 percent) have a total nameplate capacity of 500 megawatts or less, and 280 (67 percent) have a total capacity
of 1,000 megawatts or less.
Figure A3-5: Number of Existing Phase II Facilities by Plant Size (in MW), 1999
a.b
180
160
140
120
100
80
60
40
20
!JT
61
-36-
m
4 2 0
V
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a: U.S. DOE, 1999c.
A3-16
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
d. Geographic distribution
Table A3-8 shows the distribution of existing section 316(b) utility plants by NERC region. The table shows that there are
considerable differences between the regions in terms of both the number of existing utility plants with a CWIS and an
NPDES permit, and the percentage of all plants that they represent. Excluding Alaska, which only has one utility plant with a
CWIS and an NPDES permit, the percentage of existing section 316(b) facilities ranges from two percent in the Western
Systems Coordinating Council (WSCC) to 49 percent in the Electric Reliability Council of Texas (ERCOT). The
Southeastern Electric Reliability Council (SERC) has the highest absolute number of existing section 316(b) facilities with
94, or 23 percent of all facilities, followed by the East Central Area Reliability Coordination Agreement (ECAR) with 90
facilities, or 22 percent of all facilities.
Table A3-8: Existing Utility Plants by NERC Region, 1999
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Unknown
Total
Total Number of Plants
168
301
107
62
16
93
207
406
394
333
262
773
3
3,125
Plants with CWIS and NPDES Permitab
Number
1
90
52
29
3
3
33
43
17
94
32
18
0
416
% of Total
1%
30%
49%
47%
19%
3%
16%
11%
4%
28%
12%
2%
0%
13%
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a: U.S. DOE, 1999c.
A3-17
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
e. Water body and cooling system type
Table A3-9 shows that most of the existing utility plants with a CWIS and an NPDES permit draw water from a freshwater
river (204, or 49 percent). The next most frequent water body types are lakes or reservoirs with 138 plants (33 percent) and
estuaries or tidal rivers with 47 plants (11 percent). The table also shows that most of these plants, 314 or 75 percent, employ
a once-through cooling system. Of the plants that withdraw from an estuary, the most sensitive type of water body, only nine
percent use a recirculating system while 85 percent have a once-through system.
Table A3-9: Number of Existing Utility Plants by Water Body Type and Cooling System Type"
Water
Body Type
Estuary/
Tidal River
Ocean
Lake/
Reservoir
Freshwater
River
Multiple
Freshwater
Other/
Unknown
Total
Cooling System Type
Recirculating
No.
4
0
29
36
0
1
70
%of
Total
9%
0%
21%
18%
0%
50%
17%
Once-Through
No.
40
15
103
149
6
1
314
%of
Total
85%
100%
75%
73%
60%
50%
75%
Combination
No.
1
0
A
Q
O
-3
0
16
%of
Total
2%
0%
3%
4%
30%
0%
4%
Other
No.
^
0
2
10
1
0
15
%of
Total
4%
0%
1%
5%
10%
0%
4%
Unknown
No.
0
0
0
1
0
0
1
%of
Total
0%
0%
0%
0%
0%
0%
0%
Total b
47
15
138
204
10
2
416
a The number of plants was sample weighted to account for survey non-respondents.
b Numbers may not add up to totals due to independent rounding.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
A3-3.2 Existing Section 316(b) Nonutility Plants
EPA identified nonutility steam electric prime movers that require cooling water using information from the EIA data
collection Forms EIA-860B12 and the section 316(b) Industry Survey. These prime movers include:
* Geothermal Binary (GB)
*• Steam Turbine - Fluidized Bed Combustion (SF)
> Solar - Photovoltaic (SO)
> Steam Turbine (ST)
In addition, prime movers that are part of a combined-cycle unit were classified as steam electric.
U.S. DOE, 1998b includes two types of nonutilities: facilities whose primary business activity is the generation of electricity,
and manufacturing facilities that operate industrial boilers in addition to their primary manufacturing processes. The
discussion of existing section 316(b) nonutilities focuses on those nonutility facilities that generate electricity as their primary
line of business.
12 U.S. DOE, 1998b (Annual Nonutility Electric Generator Report) is the equivalent of U.S. DOE, 1998a for utilities. It is the annual
inventory of nonutility plants and collects data on the type of prime mover, nameplate rating, energy source, year of initial commercial
operation, and operating status.
A3-18
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Using the identified list of steam electric prime movers, and U.S. DOE, 1999b information on the reported operating status of
generating units, EPA identified 559 facilities that have at least one generating unit with a steam electric prime mover.
Additional information from the section 316(b) Industry Survey determined that 134 of the 559 facilities operate a CWIS and
hold an NPDES permit. Table A3-10 provides information on the number of parent entities, nonutility plants, and generating
units, and their generating capacity in 1999. The table provides information for the industry as a whole, for the steam electric
part of the industry, and for the "section 316(b)" part of the industry.
Table A3-10: Number of Nonutilities, Nonutility Plants, Units, and Capacity, 1999
Parent Entities
Nonutility Plants
Nonutility Units
Nameplate Capacity (MW)
Total
1,509
2,205
5,958
206,500
Total Steam Electric
Nonutilities "
441
559
1,255
153,032
Nonutilities with CWIS and NPDES Permitab
Number % of Steam Electric
47 11%
134 24%
343 27%
107,054 70%
a Includes only nonutility plants generating electricity as their primary line of business.
b The number of plants, units, and capacity was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
a. Ownership type
Nonutility power producers that generate electricity as their main line of business fall into two different categories: "original
nonutility plants" and "former utility plants."
*** Original nonutility plants
For the purposes of this analysis, original nonutility plants are those that were originally built by a nonutility. These plants
primarily include facilities qualifying under the Public Utility Regulatory Policies Act of 1978 (PURPA), cogeneration
facilities, independent power producers, and exempt wholesale generators under the Energy Policy Act of 1992 (EPACT).
EPA identified original nonutility plants with a CWIS and an NPDES permit through the section 316(b) Industry Survey.
This profile further differentiates original nonutility plants by their primary Standard Industrial Classification (SIC) code, as
reported in the section 316(b) Industry Survey. Reported SIC codes include:
*• 4911 - Electric Services
*• 4931 - Electric and Other Services Combined
*• 4939 - Combination Utilities, Not Elsewhere Classified
> 4953 - Refuse Systems
»** Former utility plants
Former utility plants are those that used to be owned by a utility power producer but have been sold to a nonutility as a result
of industry deregulation. These were identified from U.S. DOE, 1999a, by theirplant code, section 316(b) Industry Survey,
and research conducted through January 2002.13
Table A3-11 shows that original nonutilities account for the vast majority of plants (1,894 out of 2,205, or 86 percent). Only
311 out of the 2,205 nonutility plants, or 14 percent, were formerly owned by utilities. However, these 311 facilities account
for about 63 percent of all nonutility generating capacity (130,526 MW divided by 206,499 MW). One-hundred thirty-four of
13 Plants formerly owned by a regulated utility have an identification code number that is less than 10,000 whereas nonutilities have a
code number greater than 10,000. When utility plants are sold to nonutilities, they retain their original plant code. EPA tracked ownership
changes from utilities to nonutilities, and vice versa, through January 2002. These changes are incorporated into the profile. As such, the
universe of facilities (and their corresponding characteristics) is based on EIA 1999 data, adjusted to reflect EPA's most current
knowledge.
A3-19
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
the 2,205 nonutility plants operate a CWIS and hold anNPDES permit. Most of these section 316(b) facilities (120, or 91
percent) are former utility plants, and account for almost 99 percent of all section 316(b) nonutility capacity (105,672 MW
divided by 107,054 MW). The table also shows that only one percent of all original nonutility plants have a CWIS and an
NPDES permit,14 compared to 49 percent of all former utility plants.
Table A3-11: Existing Nonutility Firms, Plants, and
SIC Code
Firms
Firms with Plants with
Total CWIS and NPDESb
Number '
of Firms" Number 0/oofTota,
Capacity by SIC Code, 1998°
Plants
Total
Number
of Plants
Plants with CWIS
and NPDESb
Number
%of
Total
Capacity (MW)
Capacity with CWIS
Total and NPDES"
Capacity
MW
%of
Total
Original Nonutilities
4911
4931
4939
4953
Other SIC
2
2
1,428 1
3
3
1%
1,894
2
2
1
5
3
1%
193
189
75,973 505
219
252
1%
Former Utility Plants
n/a
Total
81 36 44%
1,509 47 3%
311
2,205
120
134
39%
6%
130,526 105,672
206,499 107,030
81%
52%
a Numbers may not add up to totals due to independent rounding.
b The number of plants and capacity was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
14 This percentage understates the true share of section 316(b) nonutility plants because the total number of plants includes industrial
boilers while the number of section 316(b) nonutilities does not.
A3-20
-------
§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
b. Ownership size
EPA used the Small Business Administration (SB A) small entity size standards to determine the number of existing
section 316(b) nonutility plants owned by small firms. The thresholds used by EPA to determine if a domestic parent entity is
small depend on the entity type. Since multiple entity types were analyzed, multiple data sources were needed to determine
the entity sizes. EPA found that none of the parent entities of the 134 nonutility plants were small. For a detailed discussion
of the identification and size determination of the parent entities please see Chapter B4: Regulatory Flexibility Analysis.
c. Plant size
EPA also analyzed the steam electric nonutilities with a CWIS and an NPDES permit with respect to their generating
capacity. Figure A3-6 shows that the original nonutility plants are much smaller than the former utility plants. Of the 14
original utility plants, 3 (25 percent) have a total nameplate capacity of 50 MW or less, and 8 (58 percent) have a capacity of
100 MW or less. No original nonutility plant has a capacity of more than 500 MW. In contrast, only 18 (15 percent) former
utility plants are smaller than 250 MW while 83 (69 percent) are larger than 500 MW and 44 (37 percent) are larger than
1,000 MW.
Figure A3-6: Number of Existing Nonutility Plants with CWIS and NPDES
Permit by Generating Capacity (in MW), 1998° b
45 -,
40 -
35
30
25
20
15 -
10 -
5 -
oo
S^
20
mTf
i® ^ T
12
|s
.M
LL
* ^
0
mr
f=
44
0
/ /
D Forrrer Utilities
• Original
Nonutilities
a Numbers may not add up to totals due to independent rounding.
a The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
A3-21
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
d. Geographic distribution
Table A3-12 shows the distribution of existing section 316(b) nonutility plants by NERC region. The table shows that the
Northeast Power Coordinating Council (NPCC) has the highest absolute number of existing section 316(b) nonutility plants
with 45 (9 percent) of the 134 plants with a CWIS and an NPDES permit, followed by the Mid-Atlantic Area Council
(MAAC) with 41 plants. MAAC also has the largest percentage of plants with a CWIS and an NPDES permit compared to
all nonutility plants within the region, at 26 percent.15
Table A3-12: Nonutility Plants by NERC Region,
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Not Available
Total
Total Number
of Plants
26
139
75
57
11
155
136
70
531
279
43
613
70
2,205
1998
Plants with CWIS & NPDES Permitab
Number
0
10
0
1
0
41
18
1
45
1
0
16
0
134
% of Total
0%
7%
0%
2%
0%
26%
13%
2%
9%
0%
0%
3%
0%
6%
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
15 As explained earlier, the total number of plants includes industrial boilers while the number of plants with a CWIS and an NPDES
permit does not. Therefore, the percentages are likely higher than presented.
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§ 316(b) Phase II EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
e. Water body and cooling system type
Table A3-13 shows the distribution of existing section 316(b) nonutility plants by type of water body and cooling system.
The table shows that for both original and former nonutilities, a majority of plants with a CWIS and an NPDES permit draw
water from either a freshwater river, or an estuary or tidal river. Out of the 14 total original nonutilities, seven (50 percent)
pull from a freshwater river, and six (42 percent) pull from an estuary or tidal river. Out of the 120 former utilities, 53 (44
percent) pull from a freshwater river, and 47 (39 percent) pull from an estuary or tidal river.
The table also shows that most of the nonutilities employ a once-through system: 13 out of 14 plants (92 percent) for original
nonutilities and 101 out of 120 (84 percent) for former nonutility plants. Of the plants that withdraw from an estuary/tidal
river, the most sensitive type of waterbody, only two use a recirculating system, while 50 (94 percent) operate a once-through
system.
Table A3-13: Number of Nonutility Plants by Water Body Type and Cooling System Type"
Water Body
Type
Cooling System Type
Recirculating
AT %0f
No. _ . ,
Total
Once-Through
AT %0f
No. _ . ,
Total
Combination
AT %0f
No. _ . ,
Total
Other
AT %0f
No. _ . ,
Total
Total b
Original Nonutilities
Estuary/
Tidal River
Ocean
Lake/
Reservoir
Freshwater
River
Other/
Unknown
Total
0 0%
0 0%
0 0%
0 0%
0 0%
0 0%
6 100%
0 0%
0 0%
7 100%
0 0%
13 92%
0 0%
0 0%
1 100%
0 0%
0 0%
1 8%
0 0%
0 0%
0 0%
0 0%
0 0%
0 0%
6
0
1
7
0
14
Former Utility Plants
Estuary/
Tidal River
Ocean
Lake/
Reservoir
Freshwater
River
Other/
Unknown
Total
2 4%
0 0%
2 19%
13 29%
0 0%
17 14%
50 94%
9 100%
9 81%
32 71%
1 100%
101 84%
1 2%
0 0%
0 0%
0 0%
0 0%
1 1%
0 0%
0 0%
0 0%
1 2%
0 0%
1 1%
53
9
11
46
1
120
a The number of plants was sample weighted to account for survey non-respondents.
b Numbers may not add up to totals due to independent rounding.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
A3-23
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
A3-4 INDUSTRY OUTLOOK
This section discusses industry trends that are currently affecting the structure of the electric power industry and may
therefore affect the magnitude of impacts from the proposed section 316(b) Phase II Rule. The most important change in the
electric power industry is deregulation - the transition from a highly regulated monopolistic to a less regulated, more
competitive industry. Subsection 3.4.1 discusses the current status of deregulation. Subsection 3.4.2 presents a summary of
forecasts from the Annual Energy Outlook 2002.
A3-4.1 Current Status of Industry Deregulation
The electric power industry is evolving from a highly regulated, monopolistic industry with traditionally-structured electric
utilities to a less regulated, more competitive industry.16 The industry has traditionally been regulated based on the premise
that the supply of electricity is a natural monopoly, where a single supplier could provide electric services at a lower total cost
than could be provided by several competing suppliers. Today, the relationship between electricity consumers and suppliers
is undergoing substantial change. Some states have implemented plans that will change the procurement and pricing of
electricity significantly, and many more plan to do so during the first few years of the 21st century (Beamon, 1998).
a. Key changes in the industry's structure
Industry deregulation already has changed and continues to fundamentally change the structure of the electric power industry.
Some of the key changes include:
*• Provision of services: Under the traditional regulatory system, the generation, transmission, and distribution of
electric power were handled by vertically-integrated utilities. Since the mid-1990s, federal and state policies have
led to increased competition in the generation sector of the industry. Increased competition has resulted in a
separation of power generation, transmission, and retail distribution services. Utilities that provide transmission and
distribution services will continue to be regulated and will be required to divest of their generation assets. Entities
that generate electricity will no longer be subject to geographic or rate regulation.
*• Relationship between electricity providers and consumers: Under traditional regulation, utilities were granted a
geographic franchise area and provided electric service to all customers in that area at a rate approved by the
regulatory commission. A consumer's electric supply choice was limited to the utility franchised to serve their area.
Similarly, electricity suppliers were not free to pursue customers outside their designated service territories.
Although most consumers will continue to receive power through their local distribution company (LDC), retail
competition will allow them to select the company that generates the electricity they purchase.
*• Electricity prices: Under the traditional system, state and federal authorities regulated all aspects of utilities'
business operations, including their prices. Electricity prices were determined administratively for each utility,
based on the average cost of producing and delivering power to customers and a reasonable rate of return. As a
result of deregulation, competitive market forces will set generation prices. Buyers and sellers of power will
negotiate through power pools or one-on-one to set the price of electricity. As in all competitive markets, prices will
reflect the interaction of supply and demand for electricity. During most time periods, the price of electricity will be
set by the generating unit with the highest operating costs needed to meet spot market generation demand (i.e., the
"marginal cost" of production) (Beamon, 1998).
b. New industry participants
The Energy Policy Act of 1992 (EPACT) provides for open access to transmission systems, to allow nonutility generators to
enter the wholesale market more easily. In response to these requirements, utilities are proposing to form Independent
System Operators (ISOs) to operate the transmission grid, regional transmission groups, and open access same-time
information systems (OASIS) to inform competitors of available capacity on their transmission systems. The advent of open
transmission access has fostered the development of power marketers and power brokers as new participants in the electric
power industry. Power marketers buy and sell wholesale electricity and fall under the jurisdiction of the Federal Energy
16 Several key pieces of federal legislation have made the changes in the industry's structure possible. The
of 1978 opened up competition in the generation market by creating a class of nonutility
electricity-generating companies referred to as "qualifying facilities." The (EPACT) of 1992 removed constraints
on ownership of electric generation facilities, and encouraged increased competition in the wholesale electric power business (Beamon,
1998).
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
Regulatory Commission (FERC), since they take ownership of electricity and are engaged in interstate trade. Power
marketers generally do not own generation or transmission facilities or sell power to retail customers. A growing number of
power marketers have filed with the FERC and have had rates approved. Power brokers, on the other hand, arrange the sale
and purchase of electric energy, transmission, and other services between buyers and sellers, but do not take title to any of the
power sold.
c. State activities
Many states have taken steps to promote competition in their electricity markets. The status of these efforts varies across
states. Some states are just beginning to study what a competitive electricity market might mean; others are beginning pilot
programs; still others have designed restructured electricity markets and passed enabling legislation. However, the difficult
transition to a competitive electricity market in California, characterized by price spikes and rolling black-outs, has affected
restructuring in that state and several others. Since those difficulties in 2000, a total of seven states (Arkansas, Montana,
Nevada, New Mexico, Oklahoma, Oregon, and West Virginia) have delayed the restructuring process pending further review
of the issues while California has suspended direct retail access. As of March 2002, the following states have either enacted
restructuring legislation or issued a regulatory order to implement retail access (U.S. DOE, 2002):
*• Arizona
*• Connecticut
*• Delaware
>• District of Columbia
> Illinois
> Maine
>• Maryland
*• Massachusetts
*• Michigan
*• New Hampshire
*• New Jersey
> New York
> Ohio
> Pennsylvania
>• Rhode Island
*• Texas
*• Virginia
Even in states where consumer choice is available, important aspects of implementation may still be undecided. Key aspects
of implementing restructuring include treatment of stranded costs, pricing of transmission and distribution services, and the
design market structures required to ensure that the benefits of competition flow to all consumers (Beamon, 1998).
A3-A.2 Energy Market Model Forecasts
This section discusses forecasts of electric energy supply, demand, and prices based on data and modeling by the EIA and
presented in the Annual Energy Outlook 2002 (U.S. DOE, 2001)]. The EIA models future market conditions through the year
2020, based on a range of assumptions regarding overall economic growth, global fuel prices, and legislation and regulations
affecting energy markets. The projections are based on the results from EIA's National Energy Modeling System (NEMS)
using assumptions reflecting economic conditions as of July 2001. EPA used ICF Consulting's Integrated Planning Model
(IPM®), an integrated energy market model, to conduct the economic analyses supporting the proposed section 316(b) Phase
II Rule (see Chapter B3: Electricity Market Model Analysis). The IPM generates baseline and post compliance estimates of
each of the measures discussed below. For purposes of comparison, this section presents a discussion of EIA's reference
case results.
a. Electricity demand
The AEO2002 projects electricity demand to grow by approximately 1.8 percent annually between 2000 and 2020. This
growth is driven by an estimated 2.3 percent annual increase in the demand for electricity from the commercial sector
associated with a projected annual growth in commercial floor space. Residential demand is expected to increase by 1.7
percent annually as a result of an increase in the number of U.S. households of 1 percent per year between 2000 and 2020.
EIA expects electricity demand from the industrial sector to increase by 1.4 percent annually over the same forecast period,
largely in response to an increase in industrial output of 2.6 per year.
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
b. Capacity retirements
The AOE2002 projects total nuclear capacity to decline by an estimated 10 percent (or 10 gigawatts) between 2000 and 2020
due to nuclear power plant retirement. These closures are primarily assumed to be the result of the high costs of maintaining
the performance of nuclear units compared with the cost of constructing the least cost alternative. EIA also expects total
fossil fuel-fired generation capacity to decline due to retirements. EIA forecasrs that total fossil-steam capacity will decrease
by an estimated 7 percent (or 37 gigawatts) over the same time period including 20 gigawatts of oil and natural gas fired
steam capacity.
c. Capacity additions
Additional generation capacity will be needed to meet the estimated growth in electricity demand and offset the retirement of
existing capacity. EIA expects utilities to employ other options, such as life extensions and repowering, to power imports
from Canada and Mexico, and purchases from cogenerators before building new capacity. EIA forecasts that utilities will
choose technologies for new generation capacity that seek to minimize cost while meeting environmental and emission
constraints. Of the new capacity forecasted to come on-line between 2000 and 2020, 88 percent is projected to be combined-
cycle technology or combustion turbine technology, including distributed generation capacity. This additional capacity is
expected to be fueled by natural gas and to supply primarily peak and intermediate capacity. Approximately nine percent of
the additional capacity forecasted to come on line between 2000 and 2020 is expected to be provided by new coal-fired
plants, while the remaining three percent is forecasted to come from renewable technologies.
d. Electricity generation
The AEO2002 projects increased electricity generation from both natural gas and coal-fired plants to meet growing demand
and to offset lost capacity due to plant retirements. The forecast projects that coal-fired plants will remain the largest source
of generation throughout the forecast period. Although coal-fired generation is predicted to increase steadily between 2000
and 2020, its share of total generation is expected to decrease from 52 percent to an estimated 46 percent. This decrease in
the share of coal generation is in favor of less capital-intensive and more efficient natural gas generation technologies.
Investment in existing nuclear plants is expected to hold nuclear generation at current levels until 2006, after which it is
forecast to decline as older units are retired. The share of total generation associated with gas-fired technologies is projected
to increase from approximately 16 percent in 2001 to an estimated 32 percent in 2020, replacing nuclear power as the second
largest source of electricity generation. Generation from oil-fired plants is expected to remain fairly small throughout the
forecast period.
z. Electricity prices
EIA expects the average price of electricity, as well as the price paid by customers in each sector (residential, commercial,
and industrial), to decrease between 2000 and 2020 as a result of competition among electricity suppliers. Specific market
restructuring plans differ from state to state. Some states have begun deregulating their electricity markets; EIA expects most
states to phase in increased customer access to electricity suppliers. Increases in the cost of fuels like natural gas and oil are
not expected to increase electricity prices; these increases are expected to be offset by reductions in the price of other fuels
and shifts to more efficient generating technologies.
A3-26
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
GLOSSARY
E •.•; • / , A baseload generating unit is normally used to satisfy all or part of the minimum or base load of the system and,
as a consequence, produces electricity at an essentially constant rate and runs continuously. Baseload units are generally the
newest, largest, and most efficient of the three types of units.
(http://www.eia.doe.gov/cneaf/electricitv/page/prim2/chapter2.html')
i^ «;K/;;j;'d Cw: ;; ; <:,r •;•.•' :•]••••: An electric generating technology in which electricity is produced from otherwise lost waste
heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to heat
recovery steam generator for utilization by a steam turbine in the production of electricity. This process increases the
efficiency of the electric generating unit.
•'/ ; - ••". The portion of an electric system that is dedicated to delivering electric energy to an end user.
• ••'>>,' : .',-. ';:'', ,,;.;•, Power available for sale to customers. Approximately 8 to 9 percent of net
generation is lost during the transmission and distribution process.
• "' •/••• '•'•••';,'.'.:''.\ ."'" In 1992 the EP ACT removed constraints on ownership of electric generation facilities and
encouraged increased competition on the wholesale electric power business.
S ;; •'..:•, ?f;K/u>:?TS'i Tvrt :•/'•*•••. A gas turbine typically consisting of an axial-flow air compressor and one or more combustion
chambers, where liquid or gaseous fuel is burned and the hot gases are passed to the turbine. The hot gases expand to drive
the generator and are then used to run the compressor.
;:,;;f,'.; f /;' The process of producing electric energy by transforming other forms of energy. Generation is also the amount
of electric energy produced, expressed in watthours (Wh).
!- ;>: ;>:??;.; 'v'. The total amount of electric energy produced by the generating units at a generating station or stations,
measured at the generator terminals.
fi';?:.'.':•,•••.:•!.!;>•'>" Intermediate-load generating units meet system requirements that are greater than baseload but less than
peakload. Intermediate-load units are used during the transition between baseload and peak load requirements.
(http://www.eia.doe.gov/cneaf/electricity/page/prim2/chapter2.html)
/;•,•••?a-.-:•;•:••.- C'.;,-p-/'Ji'::--.f.-V«; '"::', A';-. An internal combustion engine has one or more cylinders in which the process of
combustion takes place, converting energy released from the rapid burning of a fuel-air mixture into mechanical energy.
Diesel or gas-fired engines are the principal fuel types used in these generators.
K;fov;-: '.f>',i-".i.'V.;.v (>H-V;!j. One thousand ••/• {;;' •.•,.''.• • •', •<.
rV.•:/•• >; v ;; I-. OH;-; y ;•;;/;.>;,••/,:;>;; minus plant use from all plants owned by the same utility.
?V; i;';;'/,",; • A corporation, person, agency, authority, or other legal entity or instrumentality that owns electric generating
capacity and is not an electric utility. Nonutility power producers include qualifying cogenerators, qualifying small power
producers, and other nonutility generators (including independent power producers) without a designated franchised service
area that do not file forms listed in the Code of Federal Regulations, Title 18, Part 141.
(http://www.eia.doe.gov/emeu/iea/glossary.html)
A3-27
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
O'1'•>•>•; •""; :>":•'!.' '[''!'.:•'•.•••'•'•• Methods of power generation other than :^"-in' >•,.<• -^^'c, ,.:-^'ii ;<••>•;'/ • ' vc.ic, ..;:;••: •' u/.-.'^.'c.'•;.'.'i;.'•
f;'-•.'.;"'a1, ; .'ir, ••-•:•,.,< -:n> ,•;;.,::"•:{•;;•«' ,••;!;.•.• .•!,•, and •.. ,;;!<•;' fi.•"!".•.'.•}>•. Other prime movers include: geothermal, solar, wind, and
biomass.
.'"'' •; . A peakload generating unit, normally the least efficient of the three unit types, is used to meet requirements
during the periods of greatest, or peak, load on the system.
(http://www.eia.doe.gov/cneaf/electricity/page/prim2/chapter2.html)
•''•''''•'•.' := ,;.;.!':! Business entities engaged in buying, selling, and marketing electricity. Power marketers do not usually
own generating or transmission facilities. Power marketers, as opposed to brokers, take ownership of the electricity and are
involved in interstate trade. These entities file with the Federal Energy Regulatory Commission for status as a power
marketer, (http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
; '••'.-. An entity that arranges the sale and purchase of electric energy, transmission, and other services between
buyers and sellers, but does not take title to any of the power sold.
(http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
.r>.-.'/.",';.' '!"• ••',••*•••.••••. The engine, turbine, water wheel or similar machine that drives an electric generator. Also, for reporting
purposes, a device that directly converts energy to electricity, e.g., photovoltaic, solar, and fuel cell(s).
'"'?.,•;;//;• :.!!•::!:/ ?•:'';.'•/,..••',;.',.;: v '\;;;':..;.->:; /"u. •' ;7!';.';r'jr!>:,; In 1978 PURPA opened up competition in the electricity generation
market by creating a class of nonutility electricity-generating companies referred to as "qualifying facilities."
';,;^ •• / ' I'v Electric system reliability has two components: adequacy and security. Adequacy is the ability of the electric
system to supply customers at all times, taking into account scheduled and unscheduled outages of system facilities. Security
is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of
system facilities, (http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
''••• A generating unit in which the prime mover is a steam turbine. The turbines convert thermal energy (steam
or hot water) produced by generators or boilers to mechanical energy or shaft torque. This mechanical energy is used to
power electric generators, including combined-cycle electric generating units, that convert the mechanical energy to
electricity.
:i '•':•:• '••;'! •••;';": SM'> The difference between revenues under competition and costs of providing service, including the
inherited fixed costs from the previous regulated market, (http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
' ! " !.',-.!.•;: < The movement or transfer of electric energy over an interconnected group of lines and associated equipment
between points of supply and points at which it is transformed for delivery to consumers, or is delivered to other electric
systems. Transmission is considered to end when the energy is transformed for distribution to the consumer.
••".•.'•. A corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or operates facilities
within the United States, its territories, or Puerto Rico for the generation, transmission, distribution, or sale of electric energy
primarily for use by the public and files forms listed in the Code of Federal Regulations, Title 18, Part 141. Facilities that
qualify as cogenerators or small power producers under the Public Utility Regulatory Policies Act (PURPA) are not
considered electric utilities, (http://www.eia.doe.gov/emeu/iea/glossary.html)
1/1 .'*'•' ' !-'•"''•!.'" ••. A unit in which the turbine generator is driven by falling water.
! V •/ The electrical unit of power. The rate of energy transfer equivalent to 1 ampere flowing under the pressure of 1 volt at
unity power factor. (Does not appear in text)
l-V,;.'.'' .'•;•..-: •..; ;Vi-''-.> An electrical energy unit of measure equal to 1 watt of power supplied to, or take from, an electric circuit
steadily for 1 hour. (Does not appear in text)
A3-28
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
REFERENCES
Beamon, J. Alan. 1998. Competitive Electricity Prices: An Update.
At: http://www.eia.doe.gov/oiaf/archive/issues98/cep.htnil.
Joskow, Paul L. 1997. "Restructuring, Competition and Regulatory Reform in the U.S. Electricity Sector," Journal of
Economic Perspectives, Volume 11, Number 3 - Summer 1997 - Pages 119-138.
U.S. Department of Energy (U.S. DOE). 2002. Energy Information Administration (EIA). Status of State Electric Industry
Restructuring Activity as of March 2002. At: http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html
U.S. Department of Energy (U.S. DOE). 2001. Energy Information Administration (EIA). Annual Energy Outlook 2002
With Projections to 2020. DOE/EIA-0383(2002). December 2001.
U.S. Department of Energy (U.S. DOE). 2000a. Energy Information Administration (EIA). Electric Power Industry
Overview. At: http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html.
U.S. Department of Energy (U. S. DOE). 2000b. Energy Information Administration (EIA). Electric Power Annual 1999
Volume I. DOE/EIA-0348(99)/1.
U.S. Department of Energy (U. S. DOE). 2000c. Energy Information Administration (EIA). Electric Power Annual 1999
Volume II. DOE/EIA-0348(99)/2.
U.S. Department of Energy (U.S. DOE). 1999a. Form EIA-860A (1999). Annual Electric Generator Report - Utility.
U.S. Department of Energy (U.S. DOE). 1999b. Form EIA-860B (1999). Annual Electric Generator Report-Nonutility.
U.S. Department of Energy (U.S. DOE). 1999c. Form EIA-861 (1999). Annual Electric Utility Data.
U.S. Department of Energy (U.S. DOE). 1999d. Form EIA-759 (1999). Monthly Power Plant Report.
U.S. Department of Energy (U.S. DOE). 1998a. Energy Information Administration (EIA). Electric Power Annual 1997
Volume I. DOE/EIA-0348(97/1).
U.S. Department of Energy (U.S. DOE). 1998b. Energy Information Administration (EIA). Electric Power Annual 1997
Volume II. DOE/EIA-0348(97/1).
U.S. Department of Energy (U.S. DOE). 1998c. Form EIA-861 (1998). Annual Electric Utility Data.
U.S. Department of Energy (U.S. DOE). 1996a. Energy Information Administration (EIA). Electric Power Annual 1995
Volume I. DOE/EIA-0348(95)/1.
U.S. Department of Energy (U.S. DOE). 1996b. Energy Information Administration (EIA). Electric Power Annual 1995
Volume II. DOE/EIA-0348(95)/2.
U.S. Department of Energy (U. S. DOE). 1996c. Energy Information Administration (EIA). Impacts of Electric Power
Industry Restructuring on the Coal Industry. At: http://www.eia.doe.gov/cneaf/electricity/chg_str_fuel/html/chapterl.html.
U.S. Department of Energy (U.S. DOE). 1995a. Energy Information Administration (EIA). Electric Power Annual 1994
Volume 1. DOE/EIA-0348(94/1).
U.S. Department of Energy (U.S. DOE). 1995b. Energy Information Administration (EIA). Electric Power Annual 1994
Volume II. DOE/EIA-0348(94/1).
U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling
Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
A3-29
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§ 316(b) Phase II EBA, Part A: Background Information A3: Profile of the Electric Power Industry
U.S. Geological Survey (USGS). 1995. Estimated Use of Water in the United States in 1995.
At: http://water.usgs.gov/watuse/pdfl995/html/.
U.S. Small Business Administration (U.S. SBA). 2000. Small Business Size Standards. 13 CFR section 121.201.
A3-30
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
Chapter Bl: Summary of Compliance
Costs
INTRODUCTION CHARTER CQNTENTS
This chapter presents the estimated costs to facilities of
complying with the Proposed Section 316(b) Phase II
Existing Facilities Rule. EPA developed unit costs of
complying with the various requirements of the proposed
rule and the alternative regulatory options, including costs of
section 316(b) technologies, energy costs, and administrative
costs. Unit costs were then assigned to the 550 in-scope
facilities, based on the facilities' modeled compliance
responses, and aggregated to the national level.
Bl-1 Unit Costs Bl-1
Bl-1.1 Technology Costs Bl-2
Bl-1.2 Energy Costs Bl-6
Bl-1.3 Administrative Costs Bl-9
Bl-2 Assigning Compliance Years to Facilities .... Bl-13
Bl-3 Total Private Compliance Costs Bl-14
Bl-3.1 Methodology Bl-14
Bl-3.2 Total Private Costs of the Proposed Rule Bl-16
Bl-4 Uncertainties and Limitations Bl-17
References Bl-18
Appendix to Chapter Bl Bl-20
Chapter Al: Introduction and Overview summarizes the
requirements of the proposed Phase II rule and five
alternative regulatory options considered by EPA. EPA costed four of these options. This chapter discusses the unit costs for
the proposed rule and the alternative regulatory options, the compliance years of Phase II facilities, and the total private
industry costs of the proposed rule. Compliance years for the alternative options are presented in the appendix to this chapter;
costs for the alternative options are presented in Chapter B7: Alternative Options - Costs and Economic Impacts.
Bl-1 UNIT COSTS
Unit costs are estimated costs of certain activities or actions, expressed on a uniform basis (i.e., using the same units), that a
facility may take to meet the regulatory requirements. Unit costs are developed to facilitate comparison of the costs of
different actions. For this analysis, the unit basis is dollars per gallon per minute ($/gpm) of cooling water intake flow. All
capital and operating and maintenance (O&M) costs were estimated in these units. These unit costs are the building blocks
for developing costs at the facility and national levels.
EPA developed cost estimates for a number of alternative regulatory options, based on a variety of technologies for
impingement mortality and entrainment reduction. For each regulatory option, individual facilities will incur only a subset of
the unit costs, depending on the extent to which their current technologies already comply with the requirements of that
regulatory option and on the compliance response they select. The unit costs presented in this section are engineering cost
estimates, expressed in 2001 dollars. More detail on the development of these unit costs is provided in the Technical
Development Document for the Proposed Section 316(b) Phase II Existing Facilities Rule, hereafter referred to as the "Phase
II Technical Development Document' (EPA, 2002a).
To characterize the existing facilities' current technologies, EPA compiled facility-level, cooling system, and intake structure
data for the 225 in-scope 316(b) Detailed Questionnaire (DQ) respondents and, to the extent possible, for the 314 in-scope
316(b) Short Technical Questionnaire (STQ) respondents. The Agency then used this tabulation of data to make
determinations about costing decisions that hinged on the cooling systems and intake technologies in place. Where the STQ
responses did not provide sufficient information to make the necessary costing decisions, EPA applied the concept of data
projection to the DQ facilities to estimate the missing data pieces for the STQ facilities, as described in the Phase II Technical
Development Document.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
Bl -1.1 Technology Costs
Existing facilities that do not currently comply with the Proposed Section 316(b) Phase II Existing Facilities Rule would have
to implement one or more technologies to reduce impingement mortality and entrainment. The specific technologies vary for
the different alternative regulatory options considered by EPA, but overall these technologies reduce impingement and
entrainment (I&E) through one of two general methods:
*• implementing design and construction technologies to reduce impingement mortality and entrainment, and
*• converting cooling systems from once-through to recirculating operation to reduce the design intake flow.
EPA developed distinct sets of cooling water intake structure compliance costs for existing facility model plants expected to
(1) upgrade intake technologies only, (2) upgrade cooling systems and intake structure technologies, and (3) upgrade cooling
systems only. The remainder of Section B 1-1.1 discusses specific section 316(b) technologies and their respective costs.
a. Intake technologies
All of the regulatory options (with the exception of the dry cooling option) considered by EPA would require some existing
facilities to upgrade their cooling water intake structure technologies. Upgrades to intake structure technologies at existing
facilities may include retrofitting of impingement technologies, entrainment technologies, or both. In some cases, retrofitting
of intake structure technologies may also necessitate modifying the intake structures themselves. For example, retrofitting an
intake to entrainment-reducing fine-mesh screens (which would have reduced open cross-sectional area as compared to
coarse-mesh screens) may also necessitate expanding, fanning, or adding additional bays to an existing intake structure in
order to maintain the required intake flow rate.
*** Fine-Mesh Traveling Screen
For those model facilities projected to install or upgrade entrainment technologies without flow reduction, EPA based the
CWIS technology costs on unit costs developed for fine-mesh traveling screens. Fine-mesh screens are typically mounted on
conventional traveling screens and are used to exclude eggs, larvae, and juvenile forms of fish from intakes. Fine-mesh
screens generally include those with mesh sizes of 5 mm or less. A detailed explanation of the development of "greenfield"
facility traveling screen unit costs can be found in the Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities. The "greenfield" capital costs for fine-mesh traveling
screens were then inflated by the "retrofit" capital cost factor of 30 percent. A 10 percent contingency factor and a 5 percent
allowance were also applied to account for uncertainties inherent in intake modifications at existing facilities. Therefore, the
Agency views the retrofit capital costs developed for upgrading intake screens to be appropriate for existing model plants.
For those plants projected to only incur entrainment related costs of cooling water intake structure upgrades, the Agency
estimated that intake fanning/expansion would be necessary for the majority of plants projected to install entrainment-
reducing fine-mesh screens. Therefore, the Agency developed capital costs that incorporated the costs of expanding/fanning
or adding an additional bay to an existing intake structure to provide an increase in screen area of 50 percent, in order to
accommodate the fine-mesh screens. Because fine-mesh screens have reduced open cross-sectional area when compared to
coarse-mesh screens, the Agency considers the intake expansion/fanning costs to be appropriate in these cases. Even though
there is no set of velocity-based requirements for this proposal, the Agency projected that the model plants expected to
upgrade their intake screens from coarse to fine-mesh would reduce their through-screen velocity from the median facility
value of 1.5 feet/second to 1.0 foot/second as a result of this rule. The Agency used costs developed for fine-mesh screens
with a through-screen velocity of 1.0 foot/second to size the intake for the full design intake flow. The O&M costs of these
screens were calculated based on the same principle. The Agency applied a capital cost inflation factor of 30 percent (55
percent for nuclear facilities), in addition to the 30 percent "retrofit" factor, to account for the expansion/fanning of the intake
structure, but did not estimate further O&M costs for this one-time activity.
For those plants projected to incur costs of flow reduction and entrainment-reducing fine-mesh screens, the Agency
considered the existing intake structures to be of a size too large for a realistic screen retrofit. Therefore, in these cases, the
Agency estimated that one-half of the intake bay(s) would be blocked/closed and the retrofitted fine-mesh intake screens
would apply to only one-half of the size of the original intake. The Agency considers this a reasonable approach to
estimating realistic scenarios where the average plant uses multiple intake bays. In the Agency's view, the plant, when
presented an equal opportunity option, would use the potential cost-saving option of installing the fine-mesh screens on only
the maximum intake area necessary. The O&M costs were also developed using this size of an intake.
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»** Fish Handling and Return System
For those model plants projected to install or upgrade impingement control or survival technologies, EPA based the CWIS
technology costs on unit costs developed for fish handling and return systems. Conventional vertical traveling screens
contain a series of wire-mesh screen panels that are mounted end to end on a band to form a vertical loop. As water flows
through the panels, debris and fish that are larger than the screen openings are caught on the screen or at the base of each
panel in a basket. As the screen rotates, each panel in turn reaches a top area where a high-pressure jet spray wash pushes
debris and fish from the basket into a trash trough for disposal. As the screen rotates over time, the clean panels move down,
back into the water to screen the intake flow.
Conventional traveling screens can be operated intermittently or continuously. However, when these screens are fitted with
fish baskets (also called modified conventional traveling screens or Ristroph screens), the screens must be operated
continuously so that fish that are collected in the fish baskets can be released to a bypass/return using a low pressure spray
wash when the basket reaches the top of the screen. A detailed explanation of the development of "greenfield" unit costs for
fish handling and return systems can be found in the Technical Development Document for the Final Regulations Addressing
Cooling Water Intake Structures for New Facilities. The "greenfield" capital costs for fish handling and return systems were
then inflated by the "retrofit" capital cost factor of 30 percent. A 10 percent contingency factor and a 5 percent allowance
were also applied to account for uncertainties inherent in intake modifications at existing facilities.
For those model plants projected only to incur costs of adding fish handling/return systems to existing screens, EPA
developed costs by estimating the size of coarse-mesh, 1.0 foot/second screens. The median through-screen velocity for all
316(b) survey respondents was 1.5 feet/second. The Agency thus determined that use of a 1.0 foot/sec metric to size the fish
handling/return systems was a conservative assumption (that is, would most likely result in an overestimate of fish
handling/return system costs) for the variety of plants projected to incur their capital and O&M costs as a result of the
proposed rule.
*** Fine-Mesh Traveling Screens with Fish Handling and Return Systems
For those plants projected to install or upgrade both impingement and entrainment technologies, EPA based the CWIS
technology costs on unit costs for fine-mesh traveling screens with fish handling and return systems, which were developed as
noted above.
For those plants projected to incur costs of both impingement and entrainment technologies, but not flow reduction, EPA
developed capital costs that incorporated the costs of expanding/fanning or adding an additional bay to an existing intake
structure to provide an increase in screen area of 50 percent, in order to accommodate the fine-mesh screens. The Agency
used costs developed for fine-mesh screens with a through-screen velocity of 1.0 feet/second to size the intake for the full
design intake flow. The O&M costs of these screens were calculated based on the same principle. Capital and O&M costs
for the fish handling and return systems were also based on the size of the larger screens. The Agency applied a capital cost
inflation factor of 15 percent (30 percent for nuclear facilities), in addition to the 30 percent "retrofit" factor, to account for
the expansion/fanning of the intake structure, but did not estimate further O&M costs for this one-time activity.
For those plants projected to incur costs of flow reduction and both impingement and entrainment technologies, EPA
estimated CWIS technology costs based on the assumption that one-half of the intake bay(s) would be blocked/closed.
Therefore, the installed capital costs and O&M costs of the intake screens and fish handling/return systems were
approximately one-half of those for a full-size screen replacement.
b. Wet cooling towers
Certain of the alternative regulatory options considered by EPA would require some existing facilities to reduce their flow to
a level commensurate with a closed-cycle recirculating system. Facilities are not required to install wet cooling towers to
reduce their flow to that level. While that level can be achieved by purchasing water from another source or using gray water,
EPA has assumed for costing purposes that the facility would recycle their water. Switching an existing facility to a
recirculating system involves retrofitting the facility to convert the cooling system from once-through to recirculating
operation. Cooling towers are by far the most common type of recirculating system; however, if enough land is available,
cooling ponds offer another, and potentially less expensive, approach. For the regulatory options that involved switching to
recirculating systems, EPA therefore assumed that all facilities switching to recirculating systems would use cooling towers.
The methodology for estimating costs of these cooling system conversions is based on a set of common principles:
>• recirculating systems can be connected to the existing condensers and operated successfully under certain (but not
all) conditions,
>• condenser flows generally do not change due to the conversions,
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
>• portions of the existing condenser conduit systems can be used for the recirculating tower systems,
>• the existing intake structures can be used for supplying make-up water to the recirculating towers,
>• tower structures can be constructed on-site before connection to the existing conduit system, and
*• modification and branching is generally necessary for connecting the recirculating system to the existing conduits
and for providing make-up water to the towers.
* Wet Tower Costs
Based on the principles outlined above, EPA developed capital cost estimates for cooling system conversions using those
developed for new "greenfield" facilities under the 316(b) Phase I Rule for New Facilities. For most model facilities that
were projected to install cooling towers, EPA based the cooling tower capital costs on unit costs developed for redwood
mechanical draft cooling towers with splash fill, which represents a median tower cost. However, EPA determined that
redwood tower unit costs were not appropriate for nuclear facilities. EPA thus based cooling tower capital costs for nuclear
facilities on unit costs developed for concrete mechanical draft cooling towers. A detailed explanation of the development of
"greenfield" facility cooling tower unit costs can be found in the Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities.
EPA then inflated these capital cost estimates by applying a "retrofit" factor to account for activities outside the scope of the
"greenfield" cost estimates. These activities relate to the "retrofit," or upgrade, of existing cooling water systems. Retrofit
activities associated with installation of recirculating wet cooling systems may include (but are not necessarily limited to)
branching or diversion of cooling water delivery systems, reinforcement of retrofitted conduit system connections, partial or
full demolition of conduit systems and/or structures, additional excavation activities, expedited construction schedules, and
administrative and construction-related safety precautions. The Agency estimated that a capital cost inflation factor of 20
percent applied to the costs developed for new "greenfield" projects would account for the cooling system retrofit activities
described above.
In addition to the 20 percent "retrofit" factor, EPA also used a 10 percent contingency factor for existing facilities. To
account for variations in capital construction costs for different locations within the United States, EPA adjusted the capital
cost estimates for the existing facilities using state-specific cost factors, which ranged from 0.739 for South Carolina to 1.245
for Alaska. The applicable state cost factors were multiplied by the model-facility cost estimates to obtain location-specific
model facility capital costs. The Agency derived the state-specific capital cost factors from the "location cost factor
database" in R.S. Means Cost Works 2001 (R.S. Means, 2001). The Agency used the weighted-average factor category for
total costs (including material and installation). The RS Means database provides cost factors (by 3-digit Zip code) for
numerous locations within each state. The Agency selected the median of the cost factors for all locations reported within
each state as the state-specific capital cost factor. Additional detail on the development of the retrofit, contingency, and state-
specific cost factors used by EPA can be found in the Phase II Technical Development Document.
EPA estimated that O&M costs of wet cooling tower systems for conversion projects would be the same as those developed
for new "greenfield" facilities during the 316(b) Phase I Rule for New Facilities. Detail on O&M costs of wet cooling tower
systems can be found in the Technical Development Document for the Final Regulations Addressing Cooling Water Intake
Structures for New Facilities. The Agency notes that recirculating pumping costs included in these O&M costs will roughly
equal those of the baseline once-through system, which the Agency deducts from annual costs of cooling system conversion
projects. In the end, the O&M costs of cooling tower pumping will roughly cancel between those included within the cooling
tower recurring annual costs and those deducted as recurring annual costs of an abandoned system. In EPA's view, this
methodology presents a realistic estimate of the actual O&M costs of cooling tower conversion projects.
»** Intake Piping Modification Costs
Conversions from once-through to recirculating cooling systems do not necessarily require construction of new intake
structures to provide make-up water to the cooling tower systems. Installation of a fully recirculating cooling system reduces
intake flow by upwards of approximately 92 percent as compared to a once-through system. The intake structure designed for
a once-through cooling system is oversized for moving flows reduced to this level. Based on example cases, EPA anticipates
that most existing facilities will be able to continue to use their baseline intake structures and portions of the associated intake
piping systems after converting to recirculating cooling systems. A branch from the original intake conduit system would be
needed to provide make-up flow to the cooling tower via a separate pump system. Thus, for purposes of capital cost
development, EPA excluded the itemized costs of make-up water pumps in favor of the larger recirculating cooling water
pumps inherent in the Agency's cooling tower cost estimates. However, the Agency included capital costs for the conduit
system required to bring make-up water to the cooling tower and basin and to discharge blowdown. The Agency estimated
that a range of 2000 feet to 4000 feet (depending on intake flow) of concrete-lined steel piping would be used for cooling
tower make-up water and blowdown.
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The Agency included these costs to account for conversion cases in which significant distances may exist between intake
locations and cooling tower sites. While this was not necessarily true for the example cases reviewed by EPA, the Agency
views these costs as appropriate for a variety of hypothetical cases. For instance, the Agency is aware of concerns from some
existing facilities regarding the need to maintain a reasonably high velocity within the intake structure conduit system to
minimize deposition and/or biological growth. By including the make-up water piping capital costs, the Agency's estimates
address these concerns by accounting for construction of relatively small-sized intake piping within existing large-sized,
once-through intake conduits, closure of a portion of intake bays and/or conduits to maintain in-conduit velocity, and/or
branching from the existing intake conduit systems.
As with the wet cooling tower cost estimates, these piping capital costs were further inflated by a "retrofit" factor. The
Agency uses a factor of 30 percent to account for construction techniques and situations outside the scope of a typical
"greenfield" cost estimate. In addition, EPA applied a 10 percent contingency factor and a 5 percent allowance to account for
uncertainties inherent in intake modifications at existing facilities.
»** Intake Pumping Costs
The Agency did not include the costs of installing pumps for supplying make-up water to the cooling towers. The Agency
developed costs for variable-speed pumps for make-up water intakes in its cost development for new facilities, but excluded
them from the costs of cooling system conversions. The Agency estimated, based on a set of example cases, that existing
intake structures could be reused for the recirculating cooling systems and that a portion of the existing pumping system
would be reused.
The Agency used estimates of O&M costs of once-through cooling based on a methodology similar to that used to develop
costs for the 316(b) Phase I Rule for New Facilities.
It should be noted that the O&M costs associated with a wet cooling tower do not include consideration of the effects on
turbine efficiency resulting from the differences in turbine exhaust pressure caused by changes in the cooling system (see
discussion in Section Bl-1.2 below).
c. Condensers
For the regulatory options that include wet cooling towers, EPA included costs for premature condenser refurbishments for a
portion of the model plants projected to incur costs of cooling tower conversions. The Agency projected premature condenser
refurbishments, in part, to alleviate potential condenser tube failures related to cooling tower conversions, such as that
experienced at one of the example case facilities. EPA consulted with condenser manufacturing representatives for advice on
probable causes for condenser failures due to cooling system conversions, motivations for condenser replacements or
refurbishments, useful lives of condensers, and appropriate tube materials for recirculating cooling systems for a variety of
water types. The Agency learned from condenser vendors that plants would likely elect to upgrade condenser tube materials
to increase the efficiency of the recirculating cooling system. In addition, for plants using brackish or saline cooling water,
the Agency judged that the material of the tubes would need to withstand corrosive effects of chemical addition and increased
salt content of the cooling water (due to concentration in a recirculating system). Hence, the Agency developed a baseline
standard of condenser tube material and based on that determined which model plants would most likely upgrade condenser
tube materials.
EPA judged that the minimum standard material would be copper-nickel alloy (of any mixture) for brackish water (i.e., for
facilities with intakes withdrawing water from estuaries/tidal rivers) and stainless steel (of any type) for saline water (i.e., for
facilities with intakes withdrawing water from oceans). The Agency then consulted the 1994 UDI database to determine the
condenser tube material for the existing plants projected to incur cooling tower conversion costs. For the units at each plant
with condenser tube materials judged to be of a quality below that of the minimum standards, the Agency estimated that the
plant would refurbish the condenser (thereby upgrading the condenser tubes) as a result of the cooling system conversion.
The Agency projected that tube material for the upgrades would be stainless steel for all model plants receiving upgrade
refurbishments. At some plants, EPA projected that only a portion of the site's condensers would require refurbishment.
EPA contacted condenser vendors to obtain cost estimates for refurbishing existing condensers and for full condenser
replacements. Using the vendor information, EPA developed unit cost estimates (on a flow basis) for several types of
condenser tube materials - copper-nickel alloy, stainless steel, and titanium - as detailed in the Phase II Technical
Development Document. The capital cost estimates for condenser refurbishing were lower than those for full replacements,
and the Agency determined that, given equal opportunity, facilities would make the economic decision to refurbish existing
condensers rather than replace the shell and the tubes. The condenser refurbishing costs developed by the Agency account for
the tube materials, full labor, overhead, and potential bracing of the shell due to buoyancy changes (related to differences in
replacement tube material and, hence, densities).
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Power plants will refurbish or replace condensers on a periodic basis. Condenser vendors estimated the average useful life of
condenser tubes as 20 years. In order to determine remaining useful life of the condensers at the model plants, the Agency
calculated a condenser replacement/refurbishing schedule based on the 20-year useful life estimate and the age of the
generating units at the plants. The average useful life remaining for a condenser at the model plants was approximately 9.5
years (in 2001). The Agency rounded this to 10 years and used this figure to represent lost operating years as a result of
premature condenser refurbishments. EPA estimated that the baseline condenser material for any plant upgrading a condenser
would be copper-nickel alloy. Therefore, plants upgrading condensers in order to install recirculating cooling would incur the
costs of the full condenser refurbishment/upgrade to stainless steel. However, 10 years later, they would save the costs of
replacing the original condenser, with a new condenser made of the same, lesser material (e.g., copper-nickel alloy). Both the
cost of condenser replacement and the savings associated with not having to replace the original condenser 10 years later, are
accounted for in EPA's cost analysis.
d. Dry cooling
One of the alternative regulatory options considered by EPA would require some existing facilities to switch to dry cooling
(air cooled condensers). EPA developed capital cost estimates for dry cooling system conversions using those developed for
new "greenfield" facilities under the 316(b) Phase I Rule for New Facilities. A detailed explanation of the development of
"greenfield" facility dry cooling unit costs can be found in the Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities.
The capital cost equations were based on equivalent cooling water flow rates (gpm), using the once-through design intake
cooling flow as the independent variable. EPA inflated the "greenfield" capital cost estimates by applying a "retrofit" factor
of 5 percent, a contingency factor of 10 percent, and a 5 percent allowance to account for activities outside the scope of the
"greenfield" cost estimates. Intake pumping was assumed to decrease to zero or near zero. Therefore, no costs were included
for intake or piping modifications. In addition, it should be noted that the dry cooling capital costs do not include any
consideration for replacement or modification of the steam turbines. The Agency developed dry cooling costs for new
"greenfield" facilities based on the installation of direct dry cooling systems. Since direct dry cooling systems would require
existing facilities to replace their steam-turbines, EPA assumed that indirect dry cooling systems would be used instead.
Therefore, the Agency has developed facility-level dry cooling costs for indirect systems by using data from direct dry
cooling systems.
EPA revised the O&M costs for dry cooling using a different basis than was used for the New Facility Rule compliance cost
estimates. Rather than base the technology costs on factors applied to the capital costs as previously done, EPA based the
O&M unit costs on energy requirements and cost information obtained from facility personnel and vendors. A detailed
explanation of the development of the dry cooling O&M costs can be found in the Phase II Technical Development
Document. It should be noted that these dry cooling O&M costs do not consider the effects on turbine efficiency resulting
from the differences in turbine exhaust pressure caused by changes in the cooling system (see discussion in Section B 1-1.2
below). As noted above, the Agency estimates that if dry cooling were used at existing facilities, the indirect dry cooling
system would be employed. The Agency developed the size and energy requirements of its new "greenfield" dry cooling
systems based on the more efficient (and, therefore, smaller) direct dry cooling systems.
Bl-1.2 Energy Costs
Converting a cooling system from a once-through system to a recirculating system with a wet cooling tower or to a dry
cooling system could affect a plant's operation in two ways. The first potential effect is an "energy penalty" from the
operation of the recirculating or dry cooling system. Energy penalty estimates reflect the long-term reduction in available
capacity due to the ongoing operation of the new system. The second potential effect is a one-time, temporary outage of the
plant when the new system is connected to the plant's existing cooling system. Both effects are discussed in the subsections
below. The third subsection discusses EPA's monetary valuation of the energy penalty and the cost of downtime.
a. Energy penalty
The energy penalty is the long-term reduction in available capacity as a result of operating a recirculating or dry cooling
system and is expressed as a percent of generating capacity. The energy penalty consists of two components: (1) a reduction
in unit efficiency due to increased turbine back-pressure and (2) an increase in auxiliary power requirements to operate the
new system (e.g., for pumping and fanning). EPA estimated energy penalties for different types of generators (nuclear,
combined-cycle, and fossil fuel) and different geographic regions (northeast, south, mid-west, and U.S. average). The
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Bl: Summary of Compliance Costs
estimated mean annual energy penalty for a recirculating system with wet cooling towers is 1.70 percent for nuclear units,
1.65 percent for fossil fuel units (including coal, oil, and natural gas), and 0.40 percent for combined-cycle units. The
estimated mean annual energy penalty for a dry cooling system is 8.53 percent for nuclear units, 8.58 percent for fossil fuel
units (including coal, oil, and natural gas), and 2.09 percent for combined-cycle units. EPA also considered the energy
requirements of other compliance technologies, such as rotating screens, but found them insignificant and thus excluded them
from this analysis.
As described in Section B1-1 above, EPA's estimates of O&M costs already include the second portion of the energy penalty,
the increase in auxiliary power requirements. Therefore, to avoid double-counting these costs, only the turbine back-pressure
part of the energy penalty was applied to the national cost estimate.
Table Bl-1 below presents EPA's estimate of the energy penalty for wet cooling towers and dry cooling systems by facility
type and geographic region.
Table Bl-1: Annual Energy Penalty (% of Plant Capacity) by Facility Type and Geographic Region
Region
Nuclear
Turbine
Northeast (MA)
South (FL)
Midwest (IL)
West (WA)
U.S. Average
0.73%
1.03%
0.96%
0.67%
0.85%
Northeast (MA)
South (FL)
Midwest (IL)
West (WA)
U.S. Average
4.96%
9.63%
5.35%
4.60%
6.13%
Aux.
Power
Recir
0.85%
0.85%
0.85%
0.85%
0.85%
2.40%
2.40%
2.40%
2.40%
2.40%
Total
Fossil Fuel
Turbine
dilating Systems with
1.58%
1.88%
1.82%
1.52%
1.70%
0.88%
0.93%
1.00%
0.74%
0.89%
Dry Cooling S
7.36%
12.0%
7.75%
7.00%
8.53%
4.69%
10.06%
5.26%
4.50%
6.13%
Aux.
Power
Wet Cooli
0.77%
0.77%
0.77%
0.77%
0.77%
ystems
2.45%
2.45%
2.45%
2.45%
2.45%
Total
Combined-Cycle
Turbine
rig Towers
1.65%
1.69%
1.77%
1.51%
1.65%
0.14%
0.18%
0.16%
0.11%
0.15%
7.14%
12.5%
7.71%
6.95%
8.58%
0.98%
2.14%
1.06%
0.90%
1.27%
Aux.
Power
0.26%
0.26%
0.26%
0.26%
0.26%
0.82%
0.82%
0.82%
0.82%
0.82%
Total
0.39%
0.44%
0.41%
0.37%
0.40%
1.80%
2.96%
1.88%
1.72%
2.09%
Source: Phase II Technical Development Document (U.S. EPA, 2002a).
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b. Connection outage
The second energy effect associated with the conversion to a recirculating or a dry cooling system is a one-time, temporary
outage of the plant when the new system is connected to the plant's existing cooling system. EPA estimates that the average
construction and installation outage would be one month. This is the net outage attributable to the installation. EPA assumes
that plants would minimize the disruption to their operations by installing the new system during times of scheduled
maintenance outages. Scheduled maintenance outages can range from several weeks to several months, depending on the
type of facility and the specific maintenance requirements.1 Therefore, by scheduling the connection of the new system
during maintenance periods, facilities could minimize the net impact to approximately one month but have several months to
complete the connection.
c. Monetary valuation of energy cost
The energy penalty and the connection outage represent a cost to the facilities that incur them. For the energy penalty, this
cost manifests itself as a reduction in revenues (the same amount of fuel is required to produce less electricity available for
sale). For the connection outage, this cost is a loss in revenues offset by a simultaneous reduction in fuel costs (while the
plant is out of service, it loses revenues but also does not incur variable costs of production).
EPA calculated facility-level baseline revenues using estimates of facility-specific average annual electricity sales and
wholesale electricity prices:
> Facility Average Annual Electricity Sales (MWh): EPA calculated electricity sales for a "typical" operating year for
each in-scope facility. This estimate is based on net generation data for each facility, adjusted to reflect that not all
net generation will be sold for revenue. EPA calculated the average annual net generation for each in-scope facility
over the five-year period 1995 to 1999 and excluded from this average "outlier" years, i.e., years of unusually low
levels of generation. This analysis defines outlier years as net generation of 70 percent or more below the facility's
average 1995 to 1999 net generation.2 To derive electricity sales for a "typical" operating year, EPA adjusted the
average net generation estimate to account for generation that is (1) lost due to transmission or distribution
inefficiencies, (2) furnished without charge, or (3) used by the utility's own electricity department. The electricity
sales adjustment is based on the average (1995 to 1999) percent of utility-level energy disposition that is sold. This
percentage was calculated for each facility's owner.3 For facilities without available utility-level energy disposition
information, EPA used the 1995 to 1999 average for all in-scope facilities for which this information was available
(95 percent of total energy sold, based on 531 facilities).
*• Wholesale Electricity Price: EPA used utility-level revenues and electricity sales from Form EIA-861 to calculate
the utility-specific wholesale price of electricity. EPA calculated each utility's average wholesale price of electricity
by dividing revenues from sales for resale by the quantity of sales for resale.4 EPA used revenue from sales for
resale instead of average revenue per unit sale by the total company for this calculation since sales for resale
represents the value of electricity at the generator busbar and does not include the price of additional value-added
services provided by the company as it delivers generated electricity to its customers. Thus, the average price
received for sales for resale is approximately a wholesale electricity price as received by the company. EPA
estimated this price for each year between 1995 and 1999 and adjusted the values to constant year-2001 dollars using
the electric power producer price index (PPI).
EPA estimated fuel cost per MWh of generation for each facility costed with a cooling tower under one of the regulatory
options considered based on annual data forms for utility-owned power plants (FERC Form 1 for investor-owned utilities,
Form EIA-412 for public electric utilities, and Form RUS 12 for rural electric cooperatives) compiled in OPRI's DataPik
Electric Generating Plant Database (as of February 2000 and May 2001).
1 For a detailed discussion of scheduled maintenance outages, see the Phase II Technical Development Document.
2 Annual net generation is based on the U.S. Department of Energy's (U.S. DOE) Form EIA-906 (formerly known as Forms EIA-759
and EIA-900). When data were not available from EIA Form-906, EPA used a compilation of annual data forms for utility-owned power
plants (FERC Form 1 for investor-owned utilities, Form EIA-412 for public electric utilities, and Form RUS 12 for rural electric
cooperatives; compiled in OPRI's DataPik Electric Generating Plant Database, as of February 2000 and May 2001).
3 EPA used utility-level energy disposition information from the U.S. DOE's Form EIA-861.
4 When the wholesale price could not be calculated, EPA calculated a price based on all utility-level revenues and electricity sales
(including both electricity sales to ultimate consumers and electricity sales for resale).
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
»** Energy Penalty
To estimate the monetary value of the energy penalty, EPA calculated the loss in electricity sales by multiplying the facility's
average annual electricity sales by the energy penalty percentages in Table B1-1 above. The penalty estimate used in this
calculation is the turbine part of the penalty and is based on each facility's type and geographic region. EPA multiplied the
loss in electricity sales by each facility's electricity price estimate to calculate the annual revenue loss from the energy
penalty.
The following formulas were used to calculate this revenue loss:
Annual Revenue Loss = Annual Loss of Electricity Sales x Electricity Price
where:
Annual Loss of Electricity Sales = Annual Electricity Sales x Energy Penalty
»** Connection outage
The average cost of the connection outage is the revenue loss during the downtime less the fuel expenses that would normally
be incurred during that period. EPA calculated the revenue loss due to the connection outage by dividing the facility's
average annual sales by twelve and multiplying this value by the facility's electricity price estimate. EPA calculated the fuel
cost by dividing the facility's average annual net generation by twelve and multiplying this value by each facility's fuel cost
per MWh of generation.
The following formulas were used to calculate the net loss due to downtime:
Cost of Connection Outage = Revenue Loss - Fuel Costs
where:
Revenue Loss = Average Annual Electricity Sales x Electricity Price
12
and
i-. ; ^-r . Average Annual Net Generation ,-, , ,-, . imn y/--
Fuel Costs = s x Fuel Cost per MWh of Generation
This approach may overstate the cost of the connection outage because it uses average electricity sales and prices. If
downtime is scheduled during off-peak times, both the loss in electricity sales and the price per MWh could be lower. In
addition, variable production costs other than fuel costs may be avoided during downtime. By only including fuel costs, EPA
again may have overestimated the cost of the connection outage.
Bl-1.3 Administrative Costs
Compliance with the proposed Phase II rule would require facilities to carry out certain administrative functions. These are
either one-time requirements (compilation of information for the initial post-promulgation NPDES permit) or recurring
requirements (compilation of information for subsequent NPDES permit renewals; and monitoring, record keeping, and
reporting). This section describes each of these administrative requirements and their estimated costs.
a. Initial post-promulgation NPDES permit application
The proposed rule would require existing facilities to submit information regarding the location, construction, design, and
capacity of their existing or proposed cooling water intake structures, technologies, and operational measures as part of their
initial post-promulgation NPDES permit applications. Some of these activities would be required regardless under the current
case-by-case cooling water intake structure permitting procedures, so to some extent the permitting costs of this proposed rule
are over-costed. Ideally, these costs would be estimated on only an incremental basis. Activities and costs associated with
the initial permit renewal application include:
* start-up activities: reading and understanding the rule; mobilizing and planning; and training staff;
Bl-9
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
*• permit application activities: developing drawings that show the physical characteristics of the source water;
developing a description of the CWIS configuration; developing a facility water balance diagram; developing a
narrative of operational characteristics; developing a description of the existing cooling water system; submitting
materials for review by the Director; and keeping records;
*• source water baseline biological characterization data: identifying available data and documenting efforts;
compiling and analyzing existing data; submitting materials for review by the Director; and keeping records;
> proposal for collection of information for comprehensive demonstration study: developing a proposal for the
collection of information; developing a description of the proposed and/or implemented technologies, operational
measures, and restoration measures to be evaluated; developing a description of historical studies that will be used;
developing a summary of public participation and consultation with fish and wildlife agencies; developing a
sampling plan; submitting data and plans for review; revising plans based on state review; and keeping records;
> source waterbody flow in formation: determining the annual mean flow of the waterbody for freshwater
rivers/streams; developing a description of the thermal stratification of the waterbody for lakes/reservoirs; preparing
supporting documentation and engineering calculations; submitting data for review; and keeping records;
*• impingement mortality and entrainment characterization study: performing biological sampling; developing a
taxonomic identification and characterization of species offish and shellfish and their life stages; documenting
impingement mortality and entrainment of all life stages offish and shellfish; identifying protected species;
submitting the study for review; and keeping records;
> impingement mortality and entrainment characterization study capital and O&M costs: contract laboratory
analysis of samples;
*• design and construction technology plan: calculating facility capacity utilization rate; describing in-place or
selected technologies and operational measures; documenting efficacy of the technologies; performing design
calculations and preparing drawings and estimates; submitting the plan for review; and keeping records;
> evaluation of potential cooling water intake structure effects: calculating the baseline upon which to assess total
reduction in impingement mortality and entrainment; calculating reduction in impingement mortality and
entrainment that would be achieved by the technologies and operational measures selected; demonstrating that the
location, design, construction and capacity of the intake reflects the best technology available (BTA) for minimizing
adverse environmental impact; performing impingement and entrainment pilot studies; submitting data and analysis
for review; and keeping records;
*• impingement and entrainment pilot study capital and O&M costs: purchasing, installing and operating pilot study
technology; laboratory analysis of samples;
> information to support site-specific determination of best technology available (BTA) for minimizing adverse
environmental impact: performing a comprehensive cost evaluation study; developing a monetized valuation of the
benefits of reducing impingement and entrainment; performing engineering calculations and drawings; submitting
results for review; and keeping records;
*• site-specific technology plan: describing selected technologies, operational measures and restoration measures;
documenting efficacy of the proposed and/or implemented technologies or operational measures; developing site-
specific evaluation of suitability of technologies or operational measures; performing design calculations and
preparing drawings and estimates; submitting the plan for review; and keeping records;
*• verification monitoring plan: developing a narrative description of the frequency of monitoring, parameters to be
monitored, and the basis for determining the parameters and frequency and duration of monitoring; and keeping
records;
> remote monitoring device capital and O&M costs: installation of remote monitoring devices.
Table B1 -2 below lists the estimated maximum costs of each of the initial post-promulgation NPDES permit application
activities described above. The specific activities that a facility will have to undertake depend on the facility's source water
body type, whether it exceeds capacity utilization rate and proportional flow thresholds, and whether it chooses to meet the
proposed rule's performance standards or to make a site-specific determination of BTA. Certain activities are expected to be
more costly for marine facilities than for freshwater facilities. Some activities will apply to all facilities, while other activities
will apply only if the facility exceeds the capacity utilization rate or proportional flow thresholds or chooses to make a site-
specific determination of BTA. The maximum cost a facility that implements all the activities would incur for its initial post-
promulgation NPDES permit application is estimated to be approximately $1.4 million.
Bl-10
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-2: Cost of Initial Post-Promulgation NPDES Permit Application Activities ($2001)
Activity
Start-up activities
Permit application activities3
Source water baseline biological characterization
data3
Proposal for collection of information for
comprehensive demonstration study
Source waterbody flow information3
Impingement mortality and entrainment
characterization studyb
Impingement mortality and entrainment
characterization capital and O&M costsb
Design and construction technology plan3
Evaluation of potential cooling water intake structure
effects3
Impingement and entrainment pilot study capital and
O&M costs3
Information to support site-specific determination of
BTA3
Site-specific technology plan3
Verification monitoring plan3
Remote monitoring device capital and O&M costs3
Total Initial Post-Promulgation NPDES Permit
Application Cost
Estimated Maximum Cost
per Permit
Freshwater
River/
Stream
$2,014
$9,571
$11,372
$12,407
$3,370
$243,483
$118,500
$5,310
$122,246
$321,600
$32,823
$7,038
$6,489
$280,000
$1,176,223
Lake
$2,014
$9,571
$11,372
$12,407
$3,894
$243,483
$118,500
$3,807
$76,893
$280,000
$32,823
$7,038
$6,489
$280,000
$1,088,291
Great Lake
$2,014
$9,571
$11,372
$12,407
$0
$302,061
$118,500
$5,310
$145,338
$280,000
$32,823
$7,038
$6,489
$280,000
$1,212,923
Estuary/
Tidal River
$2,014
$9,571
$11,372
$12,407
$0
$302,061
$199,230
$5,310
$145,338
$350,210
$32,823
$7,038
$6,489
$280,000
$1,363,863
Ocean
$2,014
$9,571
$11,372
$12,407
$0
$302,061
$199,230
$5,310
$145,338
$350,210
$32,823
$7,038
$6,489
$280,000
$1,363,863
3 The costs for these activities are incurred in the year prior to the permit application.
b The costs for these activities are incurred in the three years prior to the permit application.
Source: U.S. EPA, 2002b.
b. Subsequent NPDES permit renewals
Each existing facility will have to apply for NPDES permit renewal every five years. Subsequent permit renewal applications
will require collecting and submitting the same type of information as required for the initial permit renewal application.
EPA expects that facilities can use some of the information from the initial permit renewal. Building upon existing
information is expected to require less effort than developing the data the first time especially in situations where conditions
have not changed.
Table B1-3 lists the maximum estimated costs of each of the NPDES repermit application activities. The specific activities
that a facility will have to undertake depend on the facility's source water body type, whether it exceeds the capacity
utilization rate and proportional flow thresholds, and whether it chooses to meet the proposed rule's performance standards or
to make a site-specific determination of BTA. Certain activities are expected to be more costly for facilities located on a
Bl-11
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Great Lake, estuary, tidal river, or ocean than for freshwater facilities. The maximum cost a facility that implements all the
activities would incur for its NPDES repermit application is estimated to be $53,000.
Table Bl-3: Cost of NPDES Repermit Application Activities ($2001)
Activity
Start-up activities2
Permit application activities3
Source water baseline biological characterization data3
Proposal for collection of information for comprehensive
demonstration study3
Source waterbody flow information3
Impingement mortality and entrainment characterization
study3
Design and construction technology plan3
Evaluation of potential CWIS effects3
Information to support site-specific determination of BTA3
Site-specific technology plan3
Total NPDES Repermit Application Cost
Estimated Maximum Cost
per Permit
Freshwater
River/
Stream
$542
$6,265
$4,076
$4,579
$1,981
$14,733
$2,797
$7,138
$8,011
$2,623
$52,745
Lake
$542
$6,265
$4,076
$4,579
$2,138
$14,733
$2,011
$7,138
$8,011
$2,623
$52,116
Great
Lake
$542
$6,265
$4,076
$4,579
$0
$15,023
$2,797
$7,138
$8,011
$2,623
$51,054
Estuary/
Tidal
River
$542
$6,265
$4,076
$4,579
$0
$15,023
$2,797
$7,138
$8,011
$2,623
$51,054
Ocean
$542
$6,265
$4,076
$4,579
$0
$15,023
$2,797
$7,138
$8,011
$2,623
$51,054
3 The costs for these activities are incurred in the year prior to the application for a permit renewal.
Source: U.S. EPA, 2002b.
c. Monitoring, record keeping, and reporting
All existing facilities subject to the proposed rule will be required to monitor to show compliance with the requirements set
forth in the proposed rule. Facilities must keep records of their monitoring activities and report the results in a yearly status
report. Monitoring, record keeping, and reporting activities and costs include:
*• impingement sampling: collecting monthly samples for at least two years after the initial permit issuance;
enumerating organisms; and keeping records;
* entrainment sampling: collecting biweekly samples during the primary period of reproduction, larval recruitment,
and peak abundance for at least two years after the initial permit issuance; enumerating organisms; and keeping
records;
*• entrainment sampling capital and O&M costs: contract laboratory analysis of entrainment samples;
> visual or remote inspections: conducting weekly visual inspections or employing remote monitoring devices to
ensure that design and construction technologies continue to function as designed; and keeping records;
*• verification study: conducting technology performance monitoring; submitting monitoring results and study
analysis; and keeping records;
*• yearly status report activities: detailing biological monitoring results; reporting on visual or remote inspection;
compiling and submitting the report; and keeping records.
Table B1-4 lists the estimated costs of each of the monitoring, record keeping, and reporting activities described above.
Certain activities are expected to be more costly for marine facilities than for freshwater facilities. The maximum cost a
facility will incur for its monitoring, record keeping, and reporting activities is estimated to be $ 110,000.
Bl-12
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-4: Cost of Annual Monitoring, Record Keeping, and Reporting Activities ($2001)
Activity
Impingement sampling
Entrainment sampling
Entrainment sampling capital and O&M costs
Visual or remote inspections
Remote monitoring capital and O&M costs
Verification study
Yearly status report activities
Total Monitoring, Record Keeping, and Reporting
Cost
Estimated Cost
Freshwater
River/
Stream
$16,985
$37,369
$8,300
$9,094
$250
$6,427
$15,656
$94,081
Lake
$16,985
$37,369
$8,300
$9,094
$250
$6,427
$15,656
$94,081
Great
Lake
$21,623
$46,044
$10,640
$9,094
$250
$6,427
$15,656
$109,734
Estuary/
Tidal
River
$21,623
$46,044
$10,640
$9,094
$250
$6,427
$15,656
$109,734
Ocean
$21,623
$46,044
$10,640
$9,094
$250
$6,427
$15,656
$109,734
Source: U.S. EPA, 2002b.
Bl -2 ASSISNINS COMPLIANCE YEARS TO FACILITIES
This section discusses the methodology used to estimate the compliance years of facilities subject to Phase II regulations.
The estimated compliance years of facilities are important for two reasons: (1) they determine by how much compliance costs
are discounted in the national cost estimate and (2) for options that include cooling tower requirements, a high concentration
of facilities estimated to be out of service for cooling tower connection in the same region and at the same time could lead to
temporary energy effects in that region.
Facilities not costed with a cooling tower have to come into compliance with the proposed Phase II rule during the year their
first post-promulgation NPDES permit is issued. Since NPDES permits are renewed every five years, all facilities not costed
with cooling towers will come into compliance between 2004 and 2008. Table Bl-5 below presents the distribution of Phase
II facilities by North American Electric Reliability Council (NERC) region and compliance year. The NERC regions
presented in the table are:
> ASCC - Alaska
>• 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 Interconnect Network
*• MAPP - Mid-Continent Area Power Pool
>• NPCC - Northeast Power Coordinating Council
>• SERC - Southeastern Electric Reliability Council
> SPP - Southwest Power Pool
>• WSCC - Western Systems Coordinating Council
Bl-13
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-5: Weighted Number of Phase II Facilities by NERC Region and Compliance Year
Comp-
liance
Year
2004
2005
2006
2007
2008
Total
NERC Region
ASCC
0
1
0
0
0
1
ECAR
14
20
30
21
15
100
ERCOT
18
4
8
7
15
52
FRCC
8
10
2
3
7
30
HI ! MAAC
3J 6
OJ 11
OJ 16
OJ 6
OJ 5
3! 44
MAIN
10
16
13
5
7
51
MAPP ! NPCC
6J 10
6J 11
16 1 18
6J 12
10 1 12
44! 62
SERC
13
20
21
28
13
95
SPP
5
10
3
5
9
32
WSCC
5
16
7
2
4
34
Total
99
125
133
94
97
550
Source: U.S. EPA analysis, 2002.
The appendix to this chapter presents EPA's methodology for assigning compliance years to facilities costed with cooling
towers, and the compliance year assignment for regulatory options that include cooling tower requirements for some or all
facilities.
Bl-3 TOTAL PRIVATE COMPLIANCE COSTS
EPA estimated the total private pre-tax compliance costs for the proposed Phase II rule and the alternative regulatory options
based on the unit costs discussed in Section B1-1 and the compliance years discussed in Section B1-2. Technology
compliance costs were developed in 1999 dollars and converted to year-2001 dollars using the construction cost index (CCI).
Administrative costs were developed in 2001 dollars.
Bl-3.1 Methodology
The private cost of the Phase II rule represents the total compliance costs of the 550 in-scope section 316(b) Phase II
facilities. Under the proposed rule, facilities are expected to comply over a five-year period between 2004 and 2008; under
policy options that include a cooling tower requirement, the compliance period is between 2004 and 2012. EPA estimated the
total private cost of the rule by calculating the present value of each facility's one-time costs as of 2004. To derive the
constant annual value of the one-time costs, EPA annualized the costs of each compliance technology over its expected useful
life, using a seven percent discount rate. EPA then added the annualized one-time costs to the annual costs to derive each
facility' s total annual cost of complying with the Phase II rule. EPA estimated the post-tax value of private compliance costs
by applying state-specific corporate income tax rates to privately-owned facilities (government-owned entities and
cooperatives are not subject to income taxes).
a. Present value of compliance costs
EPA calculated the present value of the one-time capital, downtime, and initial permit costs using a seven percent discount
rate. The following assumptions were made regarding the timing of these one-time costs:
*• Cooling Tower Capital Costs: This cost is incurred over a two-year period. EPA assumed that in the first year,
engineering work would be completed and in the second year, the facility would install the cooling tower. The first
year of this cost is the year before the facility installs a cooling tower.
> Other Capital Costs: For facilities that do not require cooling towers, this cost is incurred in the year that the
facility's first post-promulgation permit is issued. For facilities requiring cooling towers, this cost is incurred in the
year that the facility installs the cooling tower.
> Condenser Improved Material Costs: This cost is incurred by facilities that require cooling towers to comply with
the regulation. This cost is incurred in the year that the facility installs a cooling tower.
Bl-14
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
> Condenser Existing Material Costs: This is a cost that would have been incurred by the facility ten years after
installing their cooling tower if the facility had not upgraded to an improved condenser material.
*• Cost of Connection Outage: EPA estimates that the average outage to construct and install a cooling tower would be
one month. A more detailed description of this cost is presented in SectionBl-1.2 above. This cost is incurred in
the year that the facility installs the cooling tower.
*• Baseline Characterization Study: This is a three-year study required for facilities with a cooling tower requirement
under the waterbody /capacity -based option that decide to take Track II. The cost of this study is incurred over three
years. The first year of costs is in the year that the facility's first post-promulgation permit is issued.
The following formula was used to calculate the net present value of the one-time costs as of 2004 :5
Cost .
Present Value = - — -
* (1 + r)2004-<
where:
Costxt = Costs in category x and year t
x = Cost category
r = Discount rate (7% in this analysis)
t = Year in which cost is incurred (2004 to 2012)
b. Annualization of compliance costs
Annualized compliance costs include all capital costs, O&M costs, administrative costs, energy penalty costs, and plant
outage costs of compliance with the proposed Phase II rule and alternative regulatory options. O&M costs include the cost of
auxiliary power requirements as a result of the operation of recirculating cooling towers. To derive the constant annual value
of the capital costs and the value of the cooling tower construction and/or connection plant outage, EPA annualized them over
30 years, using a seven percent discount rate. The costs of condenser upgrades were annualized over 20 years. Other capital
costs, which include fine-mesh traveling screens with and without fish handling as well as fish handling and return systems,
were annualized over 10 years. EPA calculated the annualized capital costs using the following formula:
r X (\
Annualized Capital Cost = Total Capital Costs x - L
(1 + r)" - 1
where:
r = Discount rate (7% in this analysis)
n = Amortization period (useful life of equipment; 30 years for cooling tower equipment; 20 years for
condensers; 10 years for other flow reduction and I&E technologies)
EPA then added the annualized capital and outage costs to annual O&M, administrative costs and energy penalty costs to
derive each facility's total annual cost of complying with the proposed Phase II rule.
c. Consideration of taxes
Compliance costs associated with the section 3 16(b) regulation reduce the income of facilities subject to the rule. As a result,
the tax liability of these facilities decreases. The net cost of the rule to facilities is therefore the compliance costs of the rule
less the tax savings that result from these compliance costs. EPA estimated the tax savings by developing a total tax rate that
integrates the federal corporate income tax rate (35 percent) and state-specific state corporate income tax rates. The total
effective tax rate was calculated as follows:
Total Tax Rate = State Tax Rate + Federal Tax Rate - (State Tax Rate * Federal Tax Rate)
Calculation of the present value assumes that the cost is incurred at the end of the year.
Bl-15
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
The amount by which a facility's annual tax liability would be reduced is the annualized compliance cost of the rule
multiplied by the total tax rate.6
Bl-3.2 Total Private Costs of the Proposed Rule
EPA estimates that the total annual facility compliance cost of the proposed Phase II rule for the 550 in-scope facilities is
$182 million annually. Table Bl-6 presents annualized facility compliance costs by cost category and NERC region. The
annualized cost by NERC region ranges from approximately $200,000 for facilities located in ASCC to $33 million for
facilities located in ECAR.7
Table Bl-6: Private (Post-Tax) Annualized Facility Compliance Costs by NERC Region (in millions, $2001)
NERC
Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
One-Time Costs
Capital
Technology
$0.0
$15.2
$4.6
$7.2
$1.2
$9.3
$6.4
$2.0
$13.3
$14.7
$1.3
$8.2
$83.5
Connection
Outage
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Initial
Permit
Application
$0.1
$6.5
$3.7
$2.5
$0.2
$2.9
$3.3
$3.1
$4.3
$6.4
$2.2
$2.6
$37.8
Recurring Costs
O&M
$0.0
$3.6
$1.2
$1.8
$0.2
$1.8
$1.4
$0.4
$2.7
$3.9
$0.4
$1.5
$19.0
Monitoring,
Record Keeping
& Reporting
$0.1
$5.9
$3.4
$2.1
$0.2
$2.5
$3.0
$2.9
$3.7
$5.9
$2.1
$2.2
$34.1
Energy
Penalty
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Permit
Renewal
$0.0
$1.4
$0.8
$0.5
$0.0
$0.6
$0.7
$0.7
$0.8
$1.4
$0.5
$0.5
$8.0
Total
$0.2
$32.6
$13.8
$14.1
$1.9
$17.1
$14.8
$9.1
$24.9
$32.3
$6.4
$15.1
$182.4
Source: U.S. EPA analysis, 2002.
Table B1-7 presents total annual facility compliance costs by cost category and steam plant type. The annual compliance
costs range from approximately $2 million for waste facilities to $91 million for coal facilities.
6 This calculation is a conservative approximation of the actual tax effect of the compliance costs. For capital costs, it assumes that
the total annualized cost, which includes imputed interest and principal charge components, is subject to a tax benefit. In effect, the
schedule of principal charges over time in the annualized cost value is treated, for tax purposes, as though it were the depreciation schedule
over time. In fact, the actual tax depreciation schedule that would be available to a company would be accelerated in comparison to the
principal charge schedule embedded in the annualized cost calculation. As a result, explicit accounting for the deprecation schedule would
yield a slightly higher present value of tax benefits than is reflected in the analysis presented here.
7 See definitions of NERC regions in section Bl-2.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-7: Private (Post-Tax) Annualized Facility Compliance Costs by Steam Plant Type (in millions, $2001)
Steam Plant
Type
Coal
Combined Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
One-Time Costs
Capital
Technology
$38.8
$1.7
$15.4
$27.2
$0.3
$0.0
$83.5
Connection
Outage
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Initial
Permit
Application
$20.1
$1.2
$3.7
$12.2
$0.6
$0.1
$37.8
Recurring Costs
O&M
$9.4
$0.5
$3.0
$6.0
$0.1
$0.0
$19.0
Monitoring,
Record Keeping
& Reporting
$18.3
$1.0
$3.3
$10.9
$0.5
$0.1
$34.1
Energy
Penalty
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Permit
Renewal
$4.3
$0.2
$0.8
$2.5
$0.1
$0.0
$8.0
Total
$90.9
$4.6
$26.2
$58.9
$1.6
$0.1
$182.4
Source: U.S. EPA analysis, 2002.
The total costs of the alternative regulatory options are presented in Chapter B7: Alternative Options - Costs and Economic
Impacts.
Bl -4 UNCERTAINTIES AND LIMITATIONS
EPA's estimates of the compliance costs associated with the proposed Section 316(b) Existing Facilities Rule are subject to
limitations because of uncertainties about the number and characteristics of the existing facilities that will be subject to the
rule. Projecting the number of existing facilities that meet the design intake flow threshold is subject to uncertainties
associated with the quality of data reported by the facilities in their DQ and STQ surveys, and with the accuracy of the design
flow estimates for the STQ facilities. Characterizing the cooling systems and intake technologies in use at existing facilities
is also subject to uncertainties associated with the quality of data reported by the facilities in their surveys and with the
projected technologies for the STQ facilities. The estimated national facility compliance costs may be over- or understated if
the projected number of Phase II existing facilities is incorrect or if the characteristics of the Phase II existing facilities are
different from those assumed in the analysis.
There is additional uncertainty about the valuation of the energy penalty and the connection outage. EPA's analysis used
historical information on electricity generation, electricity sales, electricity prices, and fuel costs, which may not be
representative of conditions at the time when facilities comply with Phase II regulation.
Limitations in EPA's ability to consider a full range of compliance responses may result in an overestimate of facility
compliance costs. The Agency was not able to consider certain compliance responses, including the costs of using alternative
sources of cooling water, the costs of some methods of changing the cooling system design, and the costs of restoration.
Costs will be overstated if these excluded compliance responses are less expensive than the projected compliance response for
some facilities.
Alternative less stringent requirements based on both costs and benefits are allowed under the proposed rule. There is some
uncertainty in predicting compliance responses because the number of facilities requesting alternative less stringent
requirements based on costs and benefits is unknown.
Bl-17
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
REFERENCES
Corporate Service Center, Inc. Accessed March 31, 2002. Federal Tax Rates.
www.corporateservicecenter.com/corp/federal tax rates.htm
Federal Tax Administration. Accessed February 23, 2002. Range of State Corporate Income Tax Rates (For tax year 2002).
www.taxadmin.org/fta/rate/corp inc.html
Personal correspondence between Timothy Connor, U.S. Environmental Protection Agency (U.S. EPA), and Ed Parsons, U.S.
Department of Energy (U.S. DOE), National Energy Technology Lab. February 2002.
R.S. Means. 2001. R.S. Means Cost Works Database, 2001.
U.S. Environmental Protection Agency (U.S. EPA). 2001. Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities. EPA-821-R-01-036. November 2001.
U.S. Environmental Protection Agency (U.S. EPA). 2002a. Technical Development Document for the Proposed Section
316(b) Phase II Existing Facilities Rule. EPA-821-R-02-003. February 2002.
U.S. Environmental Protection Agency (U.S. EPA). 2002b. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Proposed Rule. ICR Number 2060.01. February 2002.
Bl-18
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
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Bl-19
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter Bl
Appendix to Chapter Bl
APPENDIX CONTENTS
Bl-A.l Assignment of Compliance Years for Cooling Tower
Options Bl-20
Bl-A.1.1 Methodology Bl-20
B1 -A. 1.2 Summary of Cooling Tower Facilities by
Compliance Year Bl-21
Bl-A.l ASSISNMENT OF COMPLIANCE
YEARS FOR COOLINS TOWER OPTIONS
This section discusses the methodology used to estimate the
compliance years of facilities subject to alternative
regulatory options that include cooling towers as compliance
requirements for some facilities. Under the
waterbody/capacity-based option (Option 1), facilities that
withdraw cooling water from oceans or estuaries and have
certain intake flow characteristics are required to reduce flow to a level commensurate with that of wet cooling towers; EPA
costed 54 facilities with cooling towers under this option. The all cooling towers option (Option 4) requires that all facilities
that do not currently have a cooling tower to install one; EPA costed 426 facilities with cooling towers under this option. Due
to the longer lead-time required to design and install cooling towers, facilities that install cooling towers have a longer time
frame within which to comply with a policy option. Facilities not costed with a cooling tower have the same compliance
years as described in Section B1-2 of this chapter.
Bl-A.1.1 Methodology
Under a regulatory option that would require facilities to reduce their flow to a level commensurate to a closed-cycle
recirculating system, a facility installing a cooling tower would have to comply by the end of the first permit issued after the
Phase II promulgation date (August 28, 2003). Facilities that got their last NPDES permit in 1999 would receive their first
post-promulgation permit in 2004 and would have until the end of that permit term, 2008, to comply with the rule.8 Similarly,
facilities that get a new permit in 2003 would receive their first post-promulgation permit in 2008 and have until the end of
that permit term, 2012, to comply with the rule. Therefore, for facilities costed with a cooling tower, the latest possible year
of compliance with the proposed rule ranges from 2008 to 2012. Since facilities have the option to comply earlier, the
potential compliance period for facilities costed with a cooling tower would be between 2004 and 2012. This analysis
assumes that each facility costed with a cooling tower would comply during the five-year term of its first post-promulgation
permit.
At a large electric generating plant, a cooling tower takes approximately two years to design, construct, and then connect
(U.S. EPA-U.S. DOE personal correspondence, 2002). In the first year, engineers prepare for the construction of a cooling
tower. In the second year, the cooling tower is installed. A facility that is issued its first post-promulgation permit in 2004
could do the preparation work in that year and install their cooling tower in 2005. Therefore, the compliance period for
facilities costed with a cooling tower is 2005 to 2012. EPA obtained NPDES permit information from its Permit Compliance
System (PCS) database, using NPDES permit ID's from the 1994 UDI database or Envirofacts.9
Table B 1-A-l below presents the five-year compliance period for facilities costed with a cooling tower, based on the year of
their last NPDES permit.
8 The dates used for this analysis are based on a five-year permit term. For the purpose of analysis simplicity, we assume that each
facility's permit period will begin on January 1st and end on December 31st.
9 NPDES permit IDs could not be identified for eight facilities. EPA randomly assigned these facilities to a compliance year.
Bl-20
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter Bl
Table Bl-A-1: Compliance
Year of Last
NPDES Permit
1999
2000
2001
2002
2003
Schedule for Facilities Costed
with Cooling Towers
Compliance Period
Year of First Post-
Promulgation Permit
2004
2005
2006
2007
2008
First Year of Cooling
Tower Installation
2005
2005
2006
2007
2008
Last Year of Cooling Tower Installation
2008
2009
2010
2011
2012
Source: U.S. EPA analysis, 2002.
The following subsections explain how a specific compliance year was identified from the five-year compliance period
available to each facility.
a. Nuclear facilities
Periodic in-service inspections (ISIs) are typically performed at nuclear power plants at five- and ten-year intervals. Five-
year ISIs are scheduled for the 5th, 15th, 25th, and 35th years of a plant's operation, and ten-year ISIs are performed in the 10th,
20th, and 30th years. Each of these outages typically requires two to four months of downtime for the plant. EPA assumed
that all nuclear facilities costed with cooling towers will install them at times that coincide with their ISIs. This analysis used
Forms EIA-860A and EIA-860B to identify the year that each non-retired nuclear unit began operation. When a facility has
more than one unit, it was assumed that the ISIs would occur during five-year intervals from the time that the earliest unit
began operation. The compliance year used in the analysis is therefore a five-year multiple of the first year of operation of
each nuclear facility. The compliance year is additionally constrained by the NPDES permitting schedule, as described
above. For example, for a facility which has two active generating units that began operation in 1983 and 1984, EPA
assumed that the facility is on an inspection schedule which began in 1983, with inspections occurring in five-year intervals.
The facility's current NPDES permit expires in 2005. Therefore, this analysis assumes that the facility would install a cooling
tower in 2008, which is 25 years after the facility began operation and occurs during its first post-promulgation permit period
(2005 to 2009).
b. Other facilities
Information on routine maintenance shut-downs is not available for non-nuclear facilities, so the algorithm used to determine
the compliance year of nuclear facilities could not be used for non-nuclear facilities. Instead, EPA used NPDES permit
expiration dates to estimate compliance years. EPA assigned the non-nuclear cooling tower facilities to compliance years so
that the capacity and steam electric generating capacity that would be out of service at one time in any NERC region was
evenly distributed over the compliance period (2005-2012). In doing so, EPA also took into account the nuclear capacity that
would be out of service.
The methodology used to assign compliance years to facilities may not accurately predict the actual shut-down time for any
given facility, but it is unbiased and provides a reasonable estimate of national costs.
Bl-A.1.2 Summary of Cooling Tower Facilities by Compliance Year
a. Waterbody/capacity-based option
This option would require existing facilities located on estuaries and tidal rivers to reduce intake capacity commensurate with
the use of a closed-cycle recirculating cooling system. EPA analyzed two different cases of the waterbody/capacity based
option: the first case assumes that all 54 facilities with recirculating cooling system-based requirements would comply with
Track I and install a wet cooling tower (Option 1); the second, more likely, case assumes that 21 of the 54 facilities with
recirculating cooling system-based requirements would comply with Track II. These 21 facilities would conduct a
comprehensive waterbody characterization study and install technologies other than wet cooling towers (Option 2). The
following tables and discussion present only the Option 1 analysis. The 33 facilities assumed to install a wet cooling tower
under Option 2 are a subset of the 54 facilities analyzed with the wet cooling tower technology in Option 1 and the
compliance results for the Option 2 case are less than those presented for the Option 1 case.
Bl-21
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter Bl
The 54 facilities that were costed with a cooling tower in Option 1 account for 62,500 MW of baseline steam capacity. The
following three tables present the distribution of capacity costed with a cooling tower by (1) NERC region and steam plant
type, (2) NERC region and estimated compliance year, and (3) steam plant type and estimated compliance year.
Table Bl-A-2: Weighted Baseline Steam Capacity (MW) by NERC Region and Steam Plant Type
NERC Region
ERCOT
FRCC
HI
MAAC
NPCC
SERC
WSCC
Total
Steam Plant Type
Coal
0
6,651
0
4,346
2,927
2,612
0
16,537
Combined-
Cycle
0
0
0
219
600
0
0
819
Nuclear
0
1,700
0
4,211
3,076
3,485
4,555
17,027
Oil
0
3,132
1,085
1,769
4,842
0
0
10,827
Other Steam
3,902
0
0
0
3,529
2,051
7,807
17,289
Total
3,902
11,483
1,085
10,544
14,974
8,148
12,362
62,497
Source: U.S. EPA analysis, 2002.
Table Bl-A-3: Weighted Baseline Steam Capacity (MW) by NERC Region and Compliance Year
Compliance
Year
2005
2006
2007
2008
2009
2010
2011
2012
Total
NERC Region
ERCOT
0
0
0
0
426
514
647
2,315
3,902
FRCC
1,112
1,700
1,320
3,333
0
0
1,998
2,019
11,483
HI
610
0
475
0
0
0
0
0
1,085
MAAC
1,829
1,229
2,382
1,767
768
1,059
801
710
10,544
NPCC
0
0
1,695
812
2,051
1,790
1,800
0
8,148
SERC
2,301
3,426
1,295
2,254
1,447
1,639
0
0
12,362
WSCC
1,656
2,396
1,317
625
2,591
3,326
1,124
1,940
14,974
Total
7,508
8,751
8,483
8,791
7,283
8,327
6,370
6,984
62,497
Source: U.S. EPA analysis, 2002.
Bl-22
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter Bl
Table Bl-A-4: Weighted Baseline Steam Capacity (MW)
by Steam Plant Type and Compliance Year
Compliance Year
2005
2006
2007
2008
2009
2010
2011
2012
Total
Steam Plant Type
Coal
987
1,229
1,320
5,694
768
0
4,599
1,940
16,537
Combined-Cycle
0
0
0
819
0
0
0
0
819
Nuclear
4,129
1,700
4,898
2,254
0
3,032
1,013
0
17,027
Oil
1,722
1,516
475
0
1,242
3,142
0
2,730
10,827
Other Steam
669
4,306
1,790
25
5,273
2,152
758
2,315
17,289
Total
7,508
8,751
8,483
8,791
7,283
8,327
6,370
6,985
62,497
Source: U.S. EPA analysis, 2002.
b. All cooling towers option
To comply with the all cooling towers option, EPA estimated that 426 facilities would need to install cooling towers. These
facilities account for 353,750 MW of baseline steam capacity. The following three tables present the distribution of capacity
costed with a cooling tower by (1) NERC region and steam plant type, (2) NERC region and estimated compliance year, and
(3) steam plant type and estimated compliance year.
Bl-23
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter Bl
Table Bl-A-5: Weighted Baseline Steam Capacity (MW)
by NERC Region and Steam Plant Type
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Steam Plant Type
Coal
28
55,762
7,237
7,666
0
8,685
25,661
12,702
7,867
57,496
6,456
2,183
191,742
Combined- Cycle
0
0
110
3,402
0
219
0
0
1,105
127
0
344
5,306
Nuclear
0
3,503
2,430
1,700
0
7,155
4,921
3,075
10,430
23,699
0
4,555
61,468
Oil
0
1,953
22,940
10,252
1,189
6,664
0
197
20,104
16,050
2,149
13,186
94,685
Other Steam
0
0
0
0
0
262
0
0
282
0
0
0
543
Total
28
61,218
32,717
23,021
1,189
22,985
30,581
15,973
39,787
97,373
8,605
20,267
353,745
Source: U.S. EPA analysis, 2002.
Comp-
liance
Year
2005
2006
2007
2008
2009
2010
2011
2012
Total
Table Bl-A-6: Weighted Baseline
ASCC j ECAR j ERCOT j FRCC
0; 7,090 ! 5,559 ! 3,245
28; 6,832; 4,789; 1,842
0; 8,439 ! 3,179; 1,551
0; 6,423; 3,708; 3,414
0; 6,078 ! 3,238 ! 2,250
0; 8,480; 2,998; 2,852
0; 8,573 ! 3,442= 3,361
0; 9,304; 5,803; 4,504
28 ! 61,218 ! 32,717 ! 23,021
Steam Capacity (MW) by NER<
NERC Region
HI j MAAC j MAIN j MAPP
714 ! 2,312 i 6,588 i 948
0; 2,425; 5,159; 2,233
475 i 5,295 i 4,1 37 i 784
Oi 2,603 i 3,004 i 2,995
0; 4,279 i 4,265 i 2,634
0; 4,105; 2,085; 2,055
0; 1,256 ! 1,605 ! 1,431
0; 710; 3,737; 2,893
1,189 ! 22,985 ! 30,581 ! 15,973
: Region
NPCC
3,711
4,262
3,337
4,332
8,574
7,205
4,461
3,905
39,787
and Compliance Year
SERC j SPP j WSCC
9,288 ! 1,309; 3,497
12,312; 816; 3,937
12,736 i 386 i 3,866
14,026 i 562 i 3,824
10,763 i 654 i 2,373
13,738; 2,044; 1,639
1 5,987 i l,220i 25
8,523; 1,613; 1,105
97,373 ! 8,605 ! 20,267
Total
44,263
44,636
44,186
44,892
45,109
47,200
41,362
42,098
353,745
Source: U.S. EPA analysis, 2002.
Bl-24
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter Bl
Table Bl-A-7: Weighted Baseline Steam Capacity (MW)
by Steam Plant Type and Compliance Year
Compliance Year
2005
2006
2007
2008
2009
2010
2011
2012
Total
Steam Plant Type
Coal
25,795
27,043
22,078
23,793
14,851
20,501
29,028
28,651
191,742
Combined-Cycle
127
0
1,430
1,162
218
0
382
1,986
5,306
Nuclear
9,416
7,229
8,069
7,383
16,045
9,872
3,454
0
61,468
Oil
8,924
10,364
12,354
12,444
13,925
16,827
8,386
11,460
94,685
Other Steam
0
0
254
110
68
0
111
0
543
Total
44,263
44,636
44,186
44,892
45,109
47,200
41,362
42,098
353,745
Source: U.S. EPA analysis, 2002.
c. Dry cooling
Compliance year assignments for the dry cooling option (Option 5) are identical to those for facilities in the
waterbody/capacity-based option (Option 1), assuming that all facilities will go track 1 and install cooling towers.
Bl-25
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter Bl
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Bl-26
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B2: Cost Impact Analysis
Chapter B2: Cost Impact Analysis
INTRODUCTION
CHAPTER CONTENTS
B2-1 Cost-to-Revenue Measure B2-1
B2-1.1 Facility Analysis B2-2
B2-1.2 Firm Analysis B2-3
B2-2 Cost Per Household B2-4
B2-3 Electricity Price Analysis B2-6
References B2-8
This chapter presents an assessment of the magnitude of
compliance costs associated with the Proposed Section
316(b) Phase II Existing Facilities Rule, including a cost-
to-revenue analysis at the facility and firm levels, a state-
level analysis of compliance costs per household, and an
analysis of compliance costs relative to electricity price
projections at the North American Electric Reliability "^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^™
Council (NERC) level. Later chapters consider the
potential energy effects of the proposed rule on regional energy markets and facilities subject to Phase II regulation (Chapter
B3: Electricity Market Model Analysis), impacts on small entities (Chapter B4: Regulatory Flexibility Analysis), and impacts
on governments (Chapter B5: UMRA Analysis). Chapter B7: Alternative Options - Costs and Economic Impacts evaluates
the magnitude of four other regulatory alternatives considered by EPA.
Based on the analyses presented in this chapter, EPA concludes that compliance with this proposed rule is both economically
practicable and achievable.1
B2-1 COST-TO-REVENUE MEASURE
The "cost-to-revenue measure" is used to assess the magnitude of compliance costs relative to revenues. This test is
commonly used to evaluate the economic practicability of regulatory requirements. The cost-to-revenue measure is a useful
test because it compares the cost of reducing adverse environmental impact from the operation of the facility's cooling water
intake structure (CWIS) with the economic value (i.e., revenue) of the facility's economic activities. EPA conducted this test
at the facility and firm levels.
Depending on the policy option analyzed, annualized compliance costs include all capital costs, O&M costs, administrative
costs, energy penalty costs, and plant outage costs of compliance with the proposed Phase II rule. O&M costs include the
cost of auxiliary power requirements as a result of the operation of recirculating cooling towers. To derive the constant
annual value of the capital costs and the value of the cooling tower construction and/or connection plant outage, EPA
annualized them over 30 years, using a seven percent discount rate. The costs of condenser upgrades were annualized over
20 years. Other capital costs, which include fine-mesh traveling screens with and without fish handling as well as fish
handling and return systems, were annualized over 10 years. EPA then added the annualized capital and connection outage
costs to annual O&M costs, administrative costs, and the cost of the energy penalty to derive each facility's total annual cost
of complying with the Phase II rule.2 For a detailed analysis of the compliance cost components developed for this analysis,
see Chapter Bl: Summary of Compliance Costs and the § 316(b) Technical Development Document.
EPA compared the annualized compliance costs to the estimated facility and firm revenues to determine the economic
practicability of the proposed Phase II rule on both the facility and firm levels. This analysis uses impact thresholds of one
and three percent.
1 It should be noted that the following measures are intended to give an indication of the magnitude of compliance costs. These
measures are not used to predict closures or other types of economic impacts on facilities subject to the proposed Phase II rule. EPA did
not rely on any one of these measures to assess the magnitude of costs.
2 This annualization methodology is different from that conducted for the national cost estimate presented in Chapter Bl: Overview
of Costs and Economic Impacts. For the national cost estimate, the present value was determined as of the first year the Phase II rule will
take effect (2004). In contrast, for the impact analysis, the present value was determined as of the first year of compliance of each facility
(2004 to 2012).
B2-1
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
B2-1.1 Facility Analysis
To estimate the impact on facilities due to the proposed Phase II rule, EPA compared the annualized post-tax compliance
costs of the proposed rule as a percentage of annual revenues for each of the 550 in-scope facilities. EPA used facility-
specific revenue projections from ICF Consulting's Integrated Planning Model (IPM®) for 2008 for this analysis. The IPM
did not provide revenues for 21 of the 550 in-scope facilities. Eleven of these facilities are estimated to be baseline closures
and 10 facilities were not modeled by the IPM. In addition, 9 facilities were projected by IPM 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 19 non-baseline closure facilities with missing
information. The revenues for one of these facilities remained unknown.
Table B2-1 below presents the results of the facility-level cost-to-revenue measure conducted for the 550 electric generating
facilities subject to the Phase II rule, by facility ownership type and fuel type. For each facility type the table presents (1) the
total number of facilities; (2) the number of facilities with a cost-to-revenue ratio of less than 0.5 percent, between 0.5 and
one percent, between one and three percent, and greater than three percent; and (3) the minimum and maximum ratio.
Table B2-1: Facility-Level Cost-to-Revenue Measure
Facility Type
Total
Number
of
Facilities
Investor-Owned Utility
Federal Utility
State-Owned Utility
Political Subdivision
Municipality & Municipal
Marketing Authority
Rural Electric
Cooperative
Nonutility (former utility)
Nonutility (original)
Total3
313
13
6
8
50
25
120
14
550
Coal
Combined-Cycle
Nuclear
Oil
Other Steam
Unknown
Total3
299
16
57
169
8
1
550
Number of Facilities with a Ratio of
<0.5%
218
12
o
J
4
13
10
69
2
331
218
6
47
60
-
-
331
0.5 -1%
By Own
39
1
2
6
4
24
2
78
By F
44
3
2
26
2
-
78
1 - 3%
ership Ty
37
-
1
2
16
6
15
5
82
uel Type
26
3
-
48
5
-
82
>3%
pe
12
-
-
1
15
5
8
5
46
10
3
-
31
1
-
46
Baseline
Closure
6
-
-
1
-
-
4
-
11
-
-
8
3
-
-
11
n/a
Minimum
Ratio
1
-
-
-
-
-
-
-
1
0.02%
0.07%
0.09%
0.07%
0.09%
0.09%
0.02%
0.29%
0.02%
-
-
-
-
-
1
1
0.02%
0.04%
0.02%
0.05%
0.51%
n/a
0.02%
Maximum
Ratio
15.8%
0.5%
1.9%
28.0%
34.3%
9.0%
6.4%
12.1%
32.3%
12.1%
11.5%
0.8%
34.3%
4.5%
n/a
32.3%
a Individual numbers may not add up due to independent rounding.
Source: IPM analysis: model run for Section 316(b) base case; U.S. EPA analysis, 2002.
B2-2
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
Table B2-1 shows that the vast majority of facilities subject to the proposed Phase II rule incur very low compliance costs
when compared to facility-level revenues. Out of the 550 facilities subject to the proposed Phase II rule, 409, or
approximately 74 percent, incur annualized costs of less than 1 percent of revenues. Of these, 331, or approximately 60
percent, incur annualized costs of less than 0.5 percent of revenues. Eighty-two facilities, or 15 percent would incur costs of
between 1 and 3 percent of revenues, and 46 facilities, or 8 percent, would incur costs of greater than 3 percent. EPA
estimates that eleven facilities would be baseline closures, and for one facility, revenues are unknown. Based on these
results, EPA concludes that the proposed Phase II rule would be economically practicable at the facility level.
B2-1.2 Firm Analysis
The facility-level analysis above showed that compliance costs are low compared to facility-level revenues. However,
impacts experienced at the firm-level may be significant for firms that own multiple facilities subject to the proposed Phase II
rule. EPA therefore also analyzed the economic practicability of the proposed Phase II rule at the firm level.
To evaluate the economic practicability of this rule on the firms owning the in-scope facilities, EPA first identified the
domestic parent entity of each in-scope Phase II facility. For a detailed description of how EPA identified the domestic
parent entity of each in-scope facility, see Chapter B4: Regulatory Flexibility Analysis. From this analysis, EPA identified
the 131 unique domestic parent entities owning facilities subject to the proposed Phase II regulation. EPA obtained the sales
revenues for the 131 domestic parent entities from publicly available data sources (the 1999 Forms EIA-860A, EIA-860B,
and EIA-861; and the Dun and Bradstreet database) as well as EPA's 2000 Section 316(b) Industry Survey. The firm-level
analysis is based on the aggregated post-tax compliance costs for each facility owned by the 131 parent entities to the firm's
total sales revenue. EPA identified 70 entities, out of the 131 unique domestic parent entities, that own more than one facility
subject to the proposed Phase II rule.
Table B2-2 below summarizes the results of the cost-to-revenue measure conducted for the 131 entities owning in-scope
electric generating facilities by the parent entity type. For each entity type the table presents (1) the total number of facilities
owned; (2) the total number of firms; (3) the number of firms with a cost-to-revenue ratio of less than 0.5 percent, between
0.5 and one percent, between one and three percent, greater than three percent; and (4) the minimum and maximum ratio.
Table B2-2: Firm-Level Cost -to -Revenue Measure by Entity Type
Entity Type
Municipality &
Municipal Marketing
Authority
Political Subdivision
Rural Electric
Cooperative
State
Federal
Private
Total3
Total
Number of
Facilities
50
8
25
7
13
446
550
Total
Number
of Firms
37
4
15
4
1
70
131
Number of Firms with a Ratio of
<0.5%
18
3
12
2
1
68
104
0.5-
1%
8
-
2
2
-
-
12
1 - 3%
8
1
1
-
-
-
10
>3%
3
-
-
-
-
-
3
Baseline
Closure
-
-
-
-
-
2
2
Minimum
Ratio
0.05%
0.03%
0.06%
0.10%
0.16%
0.00%
0.00%
Maximum
Ratio
5.29%
1.22%
1.41%
0.84%
0.16%
0.44%
5.29%
a Individual numbers may not add up to totals due to independent rounding.
Source: IPM analysis: model run for Section 316(b) base case; EPA analysis, 2002.
B2-3
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B2: Cost Impact Analysis
EPA estimates that the compliance costs will comprise a very low percentage of firm-level revenues. Of the 131 unique
entities with facilities subject to the proposed Phase II rule, 116, or approximately 89 percent, incur annualized costs of less
than 1 percent of revenues. Of these, 104, or approximately 79 percent, incur annualized costs of less than 0.5 percent of
revenues. Ten entities would incur costs of between 1 and 3 percent of revenues, and only three entities would incur costs of
greater than 3 percent. EPA estimates that two entities only own facilities projected to be baseline closures. For both entities,
the compliance costs incurred would have been less than 0.5 percent of revenues. Overall, the estimated annualized
compliance costs represent between 0.002 and 5.3 percent of the entities' annual sales revenue. Based on the results from this
analysis, EPA concludes that the proposed Phase II rule would be economically practicable at the firm level.
B2-2 COST PER HOUSEHOLD
EPA also conducted an analysis that evaluates the potential cost per household3, 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 NERC
region, using two data inputs: (1) the average annual compliance cost per megawatt hour (MWh) of sales and (2) the average
annual MWh of electricity sales per household. Both data elements were calculated by NERC region using the following
approach.
Average annual compliance cost per MWh of sales: EPA compiled data on total electricity sales (including residential,
commercial, industrial, public street highway and lighting, and other sales) from the 2000 Form EIA-861 database. Utility-
level sales were aggregated by NERC region to derive each region's total electricity sales in 2000. In addition, EPA
aggregated the national pre-tax compliance costs by the NERC region in which the 550 Phase II facilities are located. The
average compliance cost per MWh of electricity sales is calculated by dividing total electricity sales by total pre-tax
compliance costs for each region.
Average annual electricity sales per household: Form EIA-861 differentiates electricity sales by customer type and also
presents the number of customers that account for the sales. The average annual electricity sales per household is therefore
calculated by dividing the MWh of residential sales by the number of households. This calculation was again done by NERC
region.
EPA calculated the annual cost of the proposed rule per household by multiplying the average annual compliance cost per
MWh of sales by the average annual electricity sales per household. This analysis assumes that power generators pass costs
on to consumers, on a dollar-to-dollar basis, and that each sector (i.e., residential, industrial, commercial, public street
highway and lighting, and other) bears an equal burden of compliance costs per MWh of electricity.
Table B2-3 shows the results of this analysis: the cost per residential consumer would range from $0.33 per year in ASCC to
$2.55 per year in HI. Regions with electricity use higher than the average (ERCOT, FRCC, SERC, and SPP) are regions with
warm climates where air conditioning use is high.
3 The number of residential consumers reported in Form EIA-861 is based on the number of utility meters. This is a proxy for the
number of households but can differ slightly due to bulk metering in some multi-family housing.
B2-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
Table B2-3
NERC
Region a
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
U.S.
Total
Electricity
Sales ( MWh)
5,309,970
522,187,334
285,347,453
182,848,371
9,271,676
229,193,120
247,759,377
139,246,194
256,382,568
764,593,949
171,473,599
599,645,124
3,413,258,735
Annual Compliance Cost per Residential Consumer by NERC Region in 2000
Total
National
Pre-Tax
Compliance
Cost
$215,459
$51,335,018
$19,569,370
$20,999,501
$3,108,587
$28,742,057
$23,384,949
$12,444,394
$41,090,108
$45,131,984
$8,952,539
$23,714,787
$278,688,755
Annualized
Pre-Tax
Compliance
Cost (S /
MWh Sales)
$0.04
$0.10
$0.07
$0.11
$0.34
$0.13
$0.09
$0.09
$0.16
$0.06
$0.05
$0.04
$0.08
Residential
Electricity
Sales (MWh)
1,854,968
158,037,771
103,478,697
92,391,451
2,627,203
82,890,271
72,946,752
47,997,755
85,806,190
282,503,216
59,902,473
201,895,024
1,192,331,771
Number of
Households
230,534
15,626,013
7,021,590
6,721,120
344,882
8,982,600
8,188,189
4,848,274
12,650,908
20,192,159
4,909,350
22,010,686
111,726,305
Annual
Residential
Sales/
Consumer
(MWh)
8.05
10.11
14.74
13.75
7.62
9.23
8.91
9.90
6.78
13.99
12.20
9.17
10.67
Annual
Compliance
Cost/
Residential
Consumer
$0.33
$0.99
$1.01
$1.58
$2.55
$1.16
$0.84
$0.88
$1.09
$0.83
$0.64
$0.36
$0.87
a Key to 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 Interconnect Network; MAPP - Mid-Continent Area Power Pool;
NPCC - Northeast Power Coordinating Council; SERC - Southeastern Electric Reliability Council; SPP - Southwest Power Pool;
WSCC - Western Systems Coordinating Council.
Source: U.S. DOE, 2000; EPA analysis, 2002.
B2-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
B2-3 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 the proposed rule, (2) total electricity sales, based
on the Annual Energy Outlook (AEO) 2002 , and (3) prices by consumer type (residential, commercial, industrial, and
transportation), also from the AEO 2002. All three data elements were calculated by NERC region.4
Table B2-4 shows the annualized costs of complying with the proposed Phase II rule, total electricity sales (MWh), and the
cost in cents per kilowatt hour (KWh) of total electricity sales by NERC region. The costs range from 0.004 cents per KWh
sales in WSCC to 0.017 cents per KWh sales in NPCC.
Table E
NERC Region
ASCC
ECAR
ERCOT
HI
MAAC
MAIN
MAPP
NPCC
FRCC
SERC
SPP
WSCC
U.S.
$2-4: Compliance Cos1
Annualized Pre-Tax
Compliance Costs
(National; $2001)
$215,459
$51,335,018
$19,569,370
$3,108,587
$28,742,057
$23,384,949
$12,444,394
$41,090,108
$20,999,501
$45,131,984
$8,952,539
$23,714,787
$278,688,755
1- per KWh of Sales by
Total Electricity Sales
(MWh; 2000)
—
517,730,286
269,072,083
246,302,490
231,949,219
153,681,396
243,035,378
182,241,013
759,772,644
171,100,266
627,001,373
3,418,263,184
MERC Region
Annualized Pre-Tax
Compliance Cost (Cents
/ KWh Sales)
—
0.010
0.007
—
0.012
0.010
0.008
0.017
0.012
0.006
0.005
0.004
0.008
Source: U.S. DOE, 2001; U.S. EPA analysis, 2002.
To determine potential effects on electricity prices as a result of the proposed rule, EPA compared the compliance cost per
KWh of sales, presented in Table B2-4, to baseline electricity prices. Table B2-5 shows the annualized pre-tax compliance
cost in cents per KWh of electricity sales and the AEO projected electricity prices for each consumer type. In addition, the
table presents the price increase by consumer type that would result from the proposed Phase II rule. The largest potential
increase in electricity prices would be 0.31 percent cents per KWh for an industrial facility in NPCC. The average increase in
electricity prices would only be between 0.09 percent for households (0.008 / 8.81) and 0.17 percent for industrial customers
(0.008/4.88).
This analysis assumes that power generators fully recover compliance costs from consumers and that each sector (i.e.,
residential, commercial, industrial, and transportation) bears an equal burden of compliance costs per MWh of purchased
electricity.
4 The Annual Energy Outlook does not include two NERC regions, ASCC and HI.
B2-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
Table B2-5: Estimated Price Increase as a Percent of 2000 Prices by Consumer Type and NERC Region"
Region
ECAR
ERCOT
MAAC
MAIN
MAPP
NPCC
FRCC
SERC
SPP
WSCC
U.S.
Annualized
Pre-Tax
Compliance
Cost (Cents /
KWh Sales)
0.010
0.007
0.012
0.010
0.008
0.017
0.012
0.006
0.005
0.004
0.008
Residential
Price
8.04
8.35
10.43
9.09
8.27
11.42
8.30
7.33
7.14
9.17
8.81
% Change
0.12%
0.09%
0.11%
0.11%
0.10%
0.15%
0.14%
0.08%
0.07%
0.04%
0.09%
Commercial
Price
7.43
7.40
9.19
7.60
6.82
8.40
7.17
6.52
6.08
8.03
8.00
% Change
0.13%
0.10%
0.13%
0.13%
0.12%
0.20%
0.16%
0.09%
0.09%
0.05%
0.10%
Industrial
Price
4.63
4.35
7.09
5.03
4.62
5.52
5.31
4.20
4.03
5.08
4.88
% Change
0.21%
0.17%
0.16%
0.20%
0.18%
0.31%
0.22%
0.14%
0.13%
0.07%
0.17%
Transportation
Price
7.08
6.54
9.13
7.55
6.76
8.33
6.49
5.63
5.14
6.83
7.88
% Change
0.14%
0.11%
0.13%
0.13%
0.12%
0.20%
0.18%
0.11%
0.10%
0.06%
0.10%
All Sectors
Average
Price
6.44
6.80
9.11
7.13
6.43
8.93
7.60
6.08
5.86
7.58
7.31
% Change
0.15%
0.11%
0.13%
0.14%
0.13%
0.19%
0.15%
0.10%
0.09%
0.05%
0.11%
a Prices are in cents per KWh.
Source: EPA analysis, 2002.
B2-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B2: Cost Impact Analysis
REFERENCES
U.S. Department of Energy (U.S. DOE). 2001. Energy Information Administration (EIA). Annual Energy Outlook 2002
With Projections to 2020. DOE/EIA-0383(2002). December 2001.
U.S. Department of Energy (U.S. DOE). 2000. FormEIA-861. Annual Electric Utility Report for the Reporting Period
2000.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Chapter B3: Electricity Market
Model Analysis
INTRODUCTION
The proposed section 316(b) Phase II Existing Facilities
Rule applies to a subset of facilities within the electric
power generation industry. The proposed rule applies to
steam electric generating units that use cooling water
withdrawn directly from waters of the U.S. Generating
units with a non-steam prime mover and those steam units
that use cooling water from a source other than a water of
the U.S. are not subject to this rule. In addition, this rule
only applies to plants with a design intake flow of at least
50 million gallons per day (MOD). However, due to
interdependencies within the electric power market,
impacts on in-scope facilities may result in indirect
impacts throughout the industry. Direct impacts on plants
subject to the rule may include changes in generation,
profitability, and capacity utilization. Potential indirect
impacts on the electric power industry may include
changes to the generation and revenue of facilities and
firms not subject to the rule, changes to bulk system reliability
and demand for electricity.
CHAPTER CONTENTS
B3-1 Summary Comparison of Energy Market Models. B3-1
B3-2 Integrated Planning Model Overview B3-3
B3-2.1 Modeling Methodology B3-3
B3-2.2 Specifications for the Section 316(b) Analysis . B3-6
B3-2.3 Model Inputs B3-7
B3-2.4 Model Outputs B3-8
B3-3 Economic Impact Analysis Methodology B3-9
B3-3.1 Market-level Impact Measures B3-9
B3-3.2 Facility-level Impact Measures B3-10
B3-4 Analysis Results for the Proposed Rule B3-11
B3-4.1 Market Analysis B3-13
B3-4.2 Analysis of Phase II Facilities B3-15
B3-5 Summary of Findings B3-17
B3-6 Uncertainties and Limitations B3-17
References B3-19
Appendix to Chapter B3 B3-20
and regional and national impacts such as changes in the price
EPA used ICF Consulting's Integrated Planning Model (IPM®), an integrated energy market model, to conduct the economic
analyses supporting the proposed section 316(b) Phase II Rule. The model addresses the interdependencies within the electric
power market and accounts for both direct and indirect impacts of regulatory actions. EPA used the model to analyze two
potential effects of the proposed rule and other regulatory options: (1) potential energy effects at the national and regional
levels, as required by Executive Order 13211 ("Actions Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use"); and (2) potential economic impacts on in-scope facilities.
The remainder of this chapter presents an overview of the IPM and the results of the IPM analysis for the proposed rule.
Chapter B8: Alternative Options - Electricity Market Model Analysis presents the IPM analysis for two alternative regulatory
options considered by EPA.
B3-1 SUMMARY COMPARISON OF ENERGY MARKET MODELS
EPA conducted research to identify models suitable for analysis of environmental policies that affect the electric power
industry. Through a review of forecasting studies and interviews with industry personnel, EPA identified three potential
models and considered each for the analyses in support of the proposed Phase II Rule: (1) the Department of Energy's
National Energy Modeling System (NEMS), (2) the Department of Energy's Policy Office Electricity Modeling System
(POEMS), and (3) ICF Consulting's Integrated Planning Model (IPM). These models are widely used in the analysis of
various issues related to public policies affecting the electric power generation industry and have been reviewed.1
The three models considered by EPA were developed to meet the specific needs of different users; they therefore differ in
terms of structure and functionality. EPA established a set of modeling and logistical criteria to select the model that is best
1 EPA also considered other models that are more commonly used for private sector analyses but decided to focus its model selection
process on models developed for public policy analyses.
B3-1
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
suited for the analysis of the proposed rule and alternative regulatory options. Modeling criteria refer to the models' technical
capabilities that are required to provide the outputs necessary for the analysis of the proposed rule. They include the
following:
*• Redefining model plants - The energy market models considered by EPA aggregate similar generating units into
model plants to reduce the amount of time required to run the model. However, such an aggregation is usable only if
the aggregated units are similar in the base case and also have similar compliance requirements under the analyzed
policy cases. The Phase II compliance requirements of in-scope facilities are based on the location, design,
construction, and capacity of their cooling water intake structures (CWIS). In contrast, the existing aggregation of
these models is based on factors including unit age, unit type, fuel type, capacity, and operating costs. Therefore, the
model used for the Phase II analysis had to be able to accommodate a different aggregation scheme for model plants
or even to run all in-scope facilities as separate model plants.
> Predicting the economic retirement of generating capacity - Compliance with the proposed Phase II Rule may
increase the capital and operating costs of some facilities to a point where it is no longer economically profitable to
operate the facility, or one or more of its generating units. The economically sound decision for a firm owning such
a facility or unit would be to retire the facility or unit rather than comply with the regulation. Therefore, the model
needed to have the ability to project early retirements as a result of compliance with the proposed rule and the
market's response to such closures, including increased capacity additions or increased market prices. In addition, to
support EPA's economic impact analysis, the model had to be able to map early retirements to specific facilities or
units.
> Representing the impact of structural changes to the industry from deregulation - Assumptions regarding
deregulation of the electric utility industry could impact a model's ability to accurately depict the profit maximizing
decisions of firms. Deregulation of the wholesale market for electricity is expected to reduce wholesale prices as
competition in markets increases. These changes may impact decisions regarding the retirement of existing
generating units, investment in new generating units, and technology and fuel choices for new generation capacity.
Therefore, it was necessary for the market model to reflect the most recent trends in the deregulation of wholesale
energy markets.
EPA also considered a number of logistical criteria to determine the most appropriate model for the analyses of the proposed
Phase II Rule. While a given model may be desirable from an analytical perspective, its use may be restricted due to other
limitations unrelated to the model's capabilities. The logistical criteria used to evaluate each model refer to administrative
issues and include the following:
> Availability of the model - Due to the tight regulatory schedule of the Phase II Rule, the model selected for this
analysis had to be accessible at the time data inputs were available, and had to be able to turn around the analyses in
a relatively short period of time. Some of the models considered for this analysis are used to conduct analyses in
support of annual reports. Such requirements may limit access to the model and the staff required to execute the
model, and therefore prevent the use of the model for this analysis.
*• Sufficient documentation of methods and assumptions - Sufficient documentation of the model structure and
assumptions was required to allow for the necessary review of results and procedure. While it may not be possible
to disclose specific details of the structure and function of a model, a general discussion of the mechanics of the
model, its assumptions, inputs, and results was required to make a model useable for this analysis.
*• Cost - EPA considered the cost of using each model together with each model's ability to satisfy the other modeling
and logistical criteria in determining the most appropriate model for the analysis of this rule. The model had to be
sufficiently robust with respect to the other criteria while remaining within the budget constraints for this analysis.
EPA assessed each market model with respect to the aforementioned modeling and logistical criteria and determined that the
IPM was best suited for the Phase II analysis.2 A principal strength of the IPM as compared to other models is the ability to
evaluate impacts to specific facilities subject to this rule. Another important advantage of the IPM model is that it has a
history of prior use by EPA. The Agency has successfully used the IPM in support of a number of major air rules. Finally,
the IPM model has been reviewed and approved by the Office of Management and Budget (OMB).
2 Please see Section B3-A.1 of the appendix to this chapter for a comparison of the three electricity market models considered for this
analysis.
B3-2
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
B3-2 INTESRATED PlANNINS MODEL OVERVIEW
This section presents a general overview of the capabilities of the IPM, including a discussion of the modeling methodology,
the specification of the model for the section 316(b) analysis, and model inputs and outputs.
B3-2.1 Modeling Methodology
a. General framework
The IPM is an engineering-economic optimization model of the electric power industry, which generates least-cost resource
dispatch decisions based on user-specified constraints such as environmental, demand, and other operational constraints. The
model can be used to analyze a wide range of electric power market issues at the plant, regional, and national levels. In the
past, applications of the IPM have included capacity planning, environmental policy analysis and compliance planning,
wholesale price forecasting, and asset valuation.3
The IPM uses a long-term dynamic linear programming framework that simulates the dispatch of generating capacity to
achieve a demand - supply equilibrium on a seasonal basis and by region. The model seeks the optimal solution to an
"objective function," which is a linear equation equal to the present value of the sum of all capital costs, fixed and variable
operation and maintenance (O&M) costs, and fuel costs. The objective function is minimized subject to a series of user-
defined supply and demand, or system operating, constraints. Supply-side constraints include capacity constraints,
availability of generation resources, plant minimum operating constraints, transmission constraints, and environmental
constraints. Demand-side constraints include reserve margin constraints and minimum system-wide load requirements. The
optimal solution to the objective function is the least-cost mix of resources required to satisfy system wide electricity demand
on a seasonal basis by region. In addition to existing capacity, the model also considers new resource investment options,
including capacity expansion or repowering at existing plants as well as investment in new plants. The model selects new
investments while considering interactions with fuel markets, capacity markets, power plant cost and performance
characteristics, forecasts of electricity demand, reliability criteria, and other constraints. The resulting system dispatch is
optimized given the resource mix, unit operating characteristics, and fuel and other costs, to achieve the most efficient use of
existing and new resources available to meet demand. The model is dynamic in that it is capable of using forecasts of future
conditions to make decisions for the present.4
b. Model plants
The model is supported by a database of boilers and electric generation units which includes all existing utility-owned
generation units as well as those located at plants owned by independent power producers and cogeneration facilities that
contribute capacity to the electric transmission grid. Individual generators are aggregated into model plants with similar
O&M costs and specific operating characteristics including seasonal capacities, heat rates, maintenance schedules, outage
rates, fuels, and transmission and distribution loss characteristics.
The number and aggregation scheme of model plants can be adjusted to meet the specific needs of each analysis. The EPA
Base Case 2000 contains 1,390 model plants.5
3 The EPA Base Case 2000 is the latest EPA specification of the U.S. power market using the IPM. Past applications of the IPM for
EPA analyses have used a predecessor EPA base case specification. Section B3-A.2 of the appendix to this chapter contains a summary of
the major differences between the EPA Base Case 2000 and the previous EPA base case specification.
4 EPA used the IPM to forecast operational changes, including changes in capacity, generation, revenues, electricity prices, and plant
closures, resulting from the rule. In other policy analyses, the IPM is generally also used to determine the compliance response for each
model facility. This process involves selecting the optimal response from a menu of compliance options that will result in the least-cost
system dispatch and new resource investment decision. Compliance options specified by IPM may include fuel switching, repowering,
pollution control retrofit, co-firing multiple fuels, dispatch adjustments, and economic retirement. EPA did not use this capability to
choose the compliance responses of the facilities subject to section 316(b) regulation. Rather EPA exogenously estimated a compliance
response using the costs of technologies capable of meeting the percentage reductions required under the regulation. In the post-
compliance analysis, these compliance costs were added as model inputs to the base case operating and capital costs.
5 Since the EPA Base Case 2000 model plants were initially created to support air policy analyses, the original configuration was not
appropriate for the section 316(b) analysis. As a result, in support of this economic analysis, the facilities subject to the Phase II Rule were
disaggregated from the IPM model plants and "run" as individual units along with the other model plants.
B3-3
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
c. IPM regions
The IPM divides the U.S. electric power market into 26 regions in the contiguous U.S. It does not include generators located
in Alaska or Hawaii. The 26 regions map into North American Reliability Council (NERC) regions and sub-regions. The
IPM models electric demand, generation, transmission, and distribution within each region and across the transmission grid
that connects regions. For the analyses presented in this chapter, IPM regions were aggregated back into NERC regions.
Figure B3-1 provides a map of the regions included in the IPM. Table B3-1 presents the crosswalk between NERC regions
and IPM regions.
Figure B3-1: Regional Representation of U.S. Power System as Modeled in IPM
NENG
WUMS DSNYU
MECS
Source: U.S. EPA, 2002.
B3-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-1: Crosswalk between NERC Regions and IPM Regions
NERC Region
ASCC - Alaska
ECAR - East Central Area Reliability Coordination Agreement
ERCOT - Electric Reliability Council of Texas
FRCC - Florida Reliability Coordinating Council
HI - Hawaii
MACC - Mid Atlantic Area Council
MAIN - Mid- America Interconnect Network
MAPP - Mid-Continent Area Power Pool
NPCC - Northeast Power Coordination Council
SERC - Southeastern Electricity Reliability Council
SPP - Southwest Power Pool
WSCC - Western Systems Coordinating Council
IPM Regions
Not Included
ECAO, MECS
ERCT
FRCC
Not Included
MACE, MACS, MACW
MANO, WUMS
MAPP
DSNY, LILC, NENG, NYC, UPNY
ENTG, SOU, TVA, VACA
SPPN, SPPS
AZNM, CALI, NWPE, PNW, RMPA
Source: U.S. EPA, 2002.
d. Model run years
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 this analysis: 2008, 2010, and2013.6 Model run year 2008 was selected based on the assumption that all in-
scope facilities will be required to comply with the requirements of the proposed rule during the first five years after
promulgation in 2003, i.e., 2004 to 2008. Therefore, 2008 represents the long-term, post-compliance state of the industry.
Run year 2013 was selected based on the assumption that facilities costed with a cooling tower (a requirement for some
facilities under the two alternative options analyzed with the IPM) would have to comply by the end of the permit term of the
first permit issued after promulgation, i.e., 2004 to 2012. As installation of a cooling tower may require the temporary shut-
down of the facility (this analysis assumes one month of shut-down time), 2013 would represent the first full, post-
compliance year for options requiring cooling towers. Run year 2010 was selected as an additional year during which
facilities costed with a cooling tower may experience temporary connection outages during cooling tower installation and
connection. (For a description of the assignment of compliance years, see Chapter Bl: Summary of Compliance Costs).
The model assumes that capital investment decisions are only implemented during run years. Each model run year is mapped
to several calendar years such that changes in variable costs, available capacity, and demand for electricity in the years
between the run years are partially captured in the results for each model run year. Table B3-2 below identifies the model run
years specified for the analysis of the proposed rule and other regulatory options, and the calendar years mapped to each.
6 The IPM developed output for a total of five model run years 2008, 2010, 2013, 2020, and 2026. 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 was not used in this analysis.
B3-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-2:
Run Year
2008
2010
2013
2020
2026
Model Run Year Mapping
Mapped Years
2005-2009
2010-2012
2013-2015
2016-2022
2023-2030
Source: IPM model specification for the Section 316(b) Base Case.
EPA mainly relied on data for 2008 in the analyses of the proposed rule (presented in this chapter) and on data for 2013 in the
analyses of the alternative regulatory options (presented in Chapter B7: Alternative Regulatory Options).
B3-2.2 Specifications for the Section 316(b) Analysis
The analysis of the proposed Phase II Rule and the other regulatory options analyzed with the IPM required changes in the
original specification of the IPM model. Specifically, the base case configuration of the model plants and model run years
were revised according to the requirements of this analysis. Both modifications to the existing model specifications are
discussed below.
*• Changes in the Aggregation of Model Plants: As noted above, the IPM aggregates individual boilers and generators
with similar cost and operational characteristics into model plants. Since the IPM model plants were initially created
to support air policy analyses, the original configuration was not appropriate for the section 316(b) analysis. As a
result, the steam electric generators at facilities subject to the Phase II Rule were disaggregated from the existing
IPM model plants and "run" as individual facilities along with the other existing model plants. This change
increased the total number of model plants from 1,390 to 1,777.
*• Use of Different Model Run Years: The original specification of the EPA Base Case 2000 of the IPM uses five
model run years chosen based on the requirements of various air policy analyses. As EPA assumed that all facilities
subject to the proposed rule and other regulatory options would come into compliance within the first permitting
cycle after promulgation in 2003 (i.e., 2004 to 2012), the run years specified for the EPA Base Case 2000 are not of
primary interest to this analysis. Therefore, EPA selected different run years for the section 316(b) analysis in order
to obtain model output throughout the compliance period (see discussion of run year selection in section B3-2.1.d
above). The change in run years and run year mappings are summarized below.
Table B3-3: Modification of Model Run Years
EPA Base Case 2000 Specification
Run Year
2005
2010
2015
2020
2026
Run Year Mapping
2005-2007
2008-2012
2013-2017
2018-2022
2023-2030
Section 316(b)
Run Year
2008
2010
2013
2020
2026
Base Case Specification
Run Year Mapping
2005-2009
2010-2012
2013-2015
2016-2022
2023-2030
Source: IPM model specifications for the EPA Base Case 2000 and the Section 316(b) Base Case.
EPA compared the base case results generated from the two different specifications of the IPM model. The base case results
could only be compared for those run years that are common to both base cases, 2010 and 2020. This comparison identified
little or no difference in the base case results:
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
>• Base case total production costs (capital, O&M, and fuel) using the revised section 316(b) specifications are higher
by 0.4% and 0.1% in the years 2010 and 2020, respectively.
>• Early retirements of base case oil and gas steam capacity under the section 316(b) specifications increased by 390
MW. Early retirements of base case nuclear capacity decreased by 429 MW. There is no difference in the early
retirement of coal capacity.
*• The change in model specifications results in virtually no change in base case coal and gas fuel use.
B3-2.3 Model Inputs
Compliance costs and compliance-related capacity reductions are the primary model inputs in the analysis of section 316(b)
regulations. EPA determined compliance costs for each of the 530 facilities subject to the proposed rule and modeled by the
IPM.7 For each facility, compliance costs consist of capital costs (including new wet tower capital costs, intake piping
modification capital costs, and condenser upgrade costs for facilities costed with flow reduction technologies), fixed O&M
costs, variable O&M costs, and permitting costs (for information on the costing methodology, see the § 316(b) Technical
Development Document).8
Capital cost inputs into the IPM are expressed in terms of dollars per KW of capacity. The capital costs of compliance reflect
the up-front cost of construction, equipment, and capital associated with the installation of required compliance technologies.
While IPM uses a single up-front cost as a model input, the model translates this cost into a series of annual payments using a
discount rate of 5.34 percent and a capital charge rate of 12 percent for the duration of the book life of the investment
(assumed to be 30 years) or the years remaining in the modeling horizon, whichever is shorter.9 The net present value of this
stream of annual capital payments is the model input included as part of the objective function for which the model seeks the
least cost solution.
Fixed O&M cost inputs into the IPM are expressed in terms of dollars per KW of capacity per year. Variable O&M cost
inputs are expressed in dollars per MWh of generation.
Capacity reductions consist of an energy penalty and a one-time generator down-time and, for purposes of this analysis, were
only applied to facilities costed with flow reduction technologies. Energy penalty estimates reflect the long-term reduction in
capacity due to the on-going operation of compliance technologies and are expressed in terms of a percentage change in
capacity. The energy penalty consists of two components: (1) a reduction in unit efficiency due to increased turbine back-
pressure and (2) an increase in auxiliary power requirements to operate the cooling tower (e.g., for pumping and fanning). As
discussed in Chapter Bl: Summary of Compliance Costs, EPA's estimate of O&M compliance costs already includes the
auxiliary power requirement component of the energy penalty. However, to fully capture the effect of the energy penalty in
the market model analysis, the both components of energy penalty needed to be applied. To avoid double-counting of the
auxiliary power requirements, EPA reduced the O&M compliance cost input into the IPM by the estimated value of the
auxiliary power penalty, using the valuation methodology described in Chapter Bl. Generator down-time estimates reflect
the amount of time generators are off-line while compliance technologies are constructed and/or installed and are expressed in
weeks. In contrast to the energy penalty, the generator down-time is a one-time event that occurs during the year when a
facility complies with the policy option (for a discussion of how EPA estimated compliance years, see Chapter Bl: Summary
of Compliance Costs). Capacity reductions were only assigned to facilities costed with flow reduction technologies.
Therefore, no facilities experience a capacity reduction (energy penalty or one-time shut down) under the proposed rule.
7 Of the 539 surveyed facilities subject to the section 316(b) Phase II Rule, nine are not modeled in the IPM. Three facilities are in
Hawaii, one is in Alaska. Neither state is represented in the IPM. One facility is identified as an "Unspecified Resource" and does not
report on any EIA forms. Four facilities are on-site facilities that do not provide electricity to the grid. The 530 in-scope facilities
modeled by the IPM were weighted to account for facilities not sampled and facilities that did not respond to the EPA's industry survey
and thus represent a total of 540 facilities industry-wide. The results for Phase II facilities in the remainder of this chapter, except where
noted, are based on the 540 weighted facilities.
8 No facilities under the proposed rule were costed with flow reduction technologies. However, 51 facilities were costed with flow
reduction technology under the "Closed-loop, Recirculating Wet Cooling based on Waterbody type and Intake Capacity" Option
(waterbody/capacity-based option) and 417 facilities were costed with flow reduction technology under the "Closed-loop, Recirculating
Wet Cooling Everywhere" Option (all cooling towers option) (see discussion in Chapter B7: Alternative Regulatory Options).
9 The capital charge rate is a function of capital structure (debt/equity shares of an investment), pre-tax debt rate (or interest cost),
debt life, post-tax return on equity, corporate income tax, depreciation schedule, book life of the investment, and other costs including
property tax and insurance. The discount rate is a function of capital structure, pre-tax debt rate, and post-tax return on equity.
B3-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
The IPM operates at the boiler level. It was therefore necessary to distribute facility-level costs across affected boilers. EPA
used the following methodology:
*• Steam electric generators operating at each of the 530 modeled section 316(b) facilities were identified using data
from Forms EIA-860A and 860B (1998 and 1999).
*• Generator-specific design intake flows were obtained from Form EIA-767 (1998).10
*• Facility-level compliance costs were distributed across each facility's steam generators. For facilities with available
intake flow data, this distribution was based on each generator's proportion of total design intake volume; for
facilities without available intake flow, this distribution was based on each generator's proportion of total steam
electric capacity.
>• Generator-level compliance costs were aggregated to the boiler level based on the EPA's Base Case 2000 cross-walk
between boilers and generators.
B3-2.4 Model Outputs
The IPM generates a series of outputs on different levels of aggregation (boiler, model plant, region, and nation). The
economic analysis for the Phase II Rule used a subset of the available IPM output. For each model run (base case and each
analyzed policy option) and for each model run year (2008, 2010, 2013, and 2020) the following model outputs were
generated:
*• Capacity - Capacity is a measure of the ability to generate electricity. This output measure reflects the summer net
dependable capacity of all generating units at the plant. The model differentiates between existing capacity, new
capacity additions, and existing capacity that has been repowered.11
*• Generation - The amount of electricity produced by each plant that is available for dispatch to the transmission
grid ("net generation")..
*• Energy Revenue - Revenues from the sale of electricity to the grid.
*• Capacity Revenue - Revenues received by facilities operating in hours where the price of energy exceeds the
variable production costs of generation for the next unit to be dispatched at that price in order to maintain reliable
energy supply in the short run. At these peak hours, the price of energy includes a premium which reflects the cost
of the required reserve margin and serves to stimulate investment in the additional capacity required to maintain a
long run equilibrium in the supply and demand for capacity.
*• Fuel Costs - The cost of fuel consumed in the generation of electricity.
> Variable Operation and Maintenance Costs - Non-fuel O&M costs that vary with the level of generation, e.g.,
cost of consumables, including water, lubricants, and electricity.
*• Fixed Operation and Maintenance Costs - O&M costs that do not vary with the level of generation, e.g., labor
costs and capital expenditures for maintenance.
*• Capital Costs - The cost of construction, equipment, and capital. In the base case, capital costs at existing facilities
are associated with investment in new equipment, e.g., the replacement of a boiler or condenser, or the repowering of
the plant. In the post-compliance cases, this cost includes retrofitting existing plants with compliance technologies
to meet the requirements of the proposed rule and the alternative regulatory options.
*• Energy Price - The average annual price received for the sale of electricity.
*• Capacity Price - The premium over energy prices received by facilities operating in peak hours during which
system load approaches available capacity. The capacity price is the premium required to stimulate new market
10 This information is provided in Schedule IV - Generator Information, Question 3.A (Design flow rate for the condenser at 100%
load). Design intake flow data at the generator level is not available for nonutilities nor for those utility owned plants with a steam
generating capacity less than 100MW. Generator-level design intake flow data were not available for 50 of the 530 modeled facilities.
11 Repowering in the IPM consists of converting of oil/gas capacity to combined-cycle capacity.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
entrants to construct additional capacity, cover costs, and earn a return on their investment. This price manifests as
short term price spikes during peak hours and, in long-run equilibrium, need be only so large as is required to justify
investment in new capacity.
*• Early Retirements - The IPM models two types of plant closures: closures of nuclear plants as a result of license
expiration and economic closures as a result of negative net present value of future operation.12 This analysis only
considers economic closures in assessing the impacts of the proposed rule and other regulatory options. However,
cases where a nuclear facility decides to renew its license in the base case but does not renew its license in the post-
compliance case for a given policy option are also considered economic closures and an impact of that policy option.
B3-3 ECONOMIC IMPACT ANALYSIS METHODOLOSY
The IPM was used to identify changes to economic and operational characteristics such as capacity, generation, revenue, cost
of generation, and electricity prices associated with the proposed Phase II Rule and alternative regulatory options. EPA
identified changes resulting from each policy option by comparing it to the base case (i.e., the model run in the absence of
section 316(b) Phase II regulations).13 The outputs presented in the previous section were used to estimate the economic
impacts of each regulatory option. EPA developed impact measures at two analytic levels: (1) the market as a whole and (2)
the subset of in-scope Phase II facilities. Both analyses were conducted by NERC region. In both cases, the impacts of each
option are defined as the difference between the model output for the base case scenario and the post-compliance scenario.
The following subsections describe the impact measures used for the two levels of analysis.
B3-3.1 Market-level Impact Measures
The market-level analysis evaluates regional changes as a result of the proposed rule and the alternative regulatory options.
Seven main measures are analyzed:
*• (1) Changes in available capacity: This measure analyzes changes in the capacity available to generate electricity.
A long-term reduction in availability may be the result of the energy penalty associated with the installation of
recirculating systems, and of partial or full closures of plants subject to the rule. In the short term, temporary plant
shut-downs for the installation of cooling towers may lead to reductions in available capacity. When analyzing
changes in available capacity, EPA distinguished between existing capacity, new capacity additions, and repowering
additions.
*• (2) Changes in generation: This measure considers the amount of electricity generated. At a regional level, long-
term changes in generation may be the result of plant closures, energy penalties, or a change in the amount of
electricity traded between regions. In the short term, temporary plant shut-downs to install recirculating systems
may lead to reductions in generation. At the national level, the demand for electricity does not change between the
base case and the analyzed policy options (generation within the regions is allowed to vary). However, demand for
electricity does vary across the modeling horizon according to the model's underlying electricity demand growth
assumptions.
> (3) Changes in revenues: This measure considers the revenues realized by all facilities in the market. A change in
revenues could be the result of a change in generation and/or the price of electricity.
*• (4) Changes in variable production costs: This measure considers the regional change in average variable
production cost per MWh. Variable production costs include fuel costs and other variable O&M costs but exclude
12 Nuclear plants are evaluated for economic viability at the end of their license term. Nuclear units that, at age 30, did not make a
major maintenance investment, are provided with a 10-year life extension, if they are economically viable. These same units may
subsequently undertake a 20-year re-licensing option at age 40. Nuclear units that already had made a maintenance investment are
provided with a 20-year re-licensing option at age 40, if they are economically viable. All nuclear units are ultimately retired at age 60.
13 EPA conducted model runs based on different electricity demand assumptions: (1) a case using EPA's electricity demand
assumptions and (2) a case using Annual Energy Outlook (AEO) electricity demand assumptions. The analyses presented in this chapter
are based on EPA's electricity demand assumptions. The appendix to Chapter B7: Alternative Regulatory Options presents a discussion of
the two different assumptions, the results of one alternative regulatory option using the AEO electricity demand assumptions, and a
comparison of the differences in results between the AEO assumptions and the EPA assumptions.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
fixed O&M costs and capital costs. Production cost per MWh is a primary determinant of how often a power plant's
units are dispatched.
*• (5) Changes in fuel costs: This measure considers a subset of the production costs included in the previous measure:
fuel costs. Fuel costs generally account for the single largest share of production costs.
> (6) Changes in the price of electricity: This measure considers changes in regional prices as a result of the proposed
rule. In the long term, electricity prices may change as a result of increased production costs of the Phase II
facilities. In the short-term, price increases may be higher if large power plants have to temporarily shut down to
construct and/or install recirculating systems. This analysis considers changes in both energy prices and capacity
prices.
* (7) Plant closures: Only plants that are projected to remain operational in the base case but are closures in the post-
compliance case are considered a closure as the result of the rule. An option may result in partial (i.e., unit) or full
plant closures. An option may also result in avoided closures if a facility's compliance costs are low relative to other
affected facilities. An avoided closure is a facility that would close in the base case but operates in the post-
compliance case. At the market-level, the closure analysis considers the amount of capacity retired early, but not the
number of retired facilities.
B3-3.2 Facility-level Impact Measures (In-scope Facilities Only)
EPA used the IPM results to analyze impacts on Phase II facilities at two levels: (1) potential changes in the economic and
operational characteristics of the group of Phase II facilities and (2) potential changes to individual facilities within the group
of Phase II facilities.
a. Group of Phase II facilities
The analysis of the group of Phase II facilities is largely similar to the market-level analysis described in SectionB3-3.1
above, except that the base case and policy option totals only include the economic activities of the steam-electric generating
units of the 540 in-scope Phase II facilities represented by the model. In addition, a few measures differ: (1) new capacity
additions and prices are not relevant at the facility level, (2) repowering changes were not explicitly analyzed at the facility
level, and (3) an additional measure, facilities that are not dispatched, is analyzed in this section but was not relevant at the
market level. The following are the measures evaluated for the group of Phase II facilities:
> (1) Changes in available capacity: This measure considers the capacity available at the 540 Phase II facilities. A
long-term reduction in availability may be the result of the energy penalty associated with the installation of
recirculating systems, and of partial or full closures of plants subject to the rule. In the short term, temporary plant
shut-downs for the installation of cooling towers may lead to reductions in available capacity.
*• (2) Changes in generation: This measure considers the generation at the 540 Phase II facilities. Long-term changes
in generation may be the result of plant closures, energy penalties, or a less frequent dispatch of a plant due to higher
production cost as a result of the policy option. In the short term, temporary plant shut-downs may lead to
reductions in generation at some of the 540 Phase II facilities. For some Phase II facilities, the proposed rule may
lead to an increase in generation if their compliance costs are low relative to other affected facilities.
*• (3) Changes in revenues: This measure considers the revenues realized by the 540 Phase II facilities. A change in
revenues could be the result of a change in generation and/or the price of electricity. For some modeled 316(b)
facilities, the proposed rule may lead to an increase in revenues if their generation increases as a result of the rule, or
if the rule leads to an increase in electricity prices.
*• (4) Changes in variable production costs: This measure considers the plant-level change in the average annual
variable production cost per MWh. Variable production costs include fuel costs and other variable O&M costs but
exclude fixed O&M costs and capital costs.
* (5) Changes in fuel costs: This measure considers a subset of the production costs included in the previous measure:
fuel costs. Fuel costs generally account for the single largest share of production costs.
*• (6) Plant closures: Only plants that are projected to remain operational in the base case but are closures in the post-
compliance case are considered a closure as the result of the rule. An option may result in partial (i.e., unit) or full
plant closures. An option may also result in avoided closures if a facility's compliance costs are low relative to other
B3-10
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
affected facilities. An avoided closure is a facility that would close in the base case but operate in the post-
compliance case. At the facility-level, both the number of closure facilities and their capacity are analyzed.
*• (7) Non-dispatch facilities: This measures identifies Phase II facilities that do not generate electricity but are earning
capacity revenues. These are facilities that do not retire but are also not dispatched. These facilities provide a
portion of the spinning reserves necessary for system reliability. An increase in production costs may lead additional
facilities to become non-dispatch facilities. Conversely, compliance costs that are relatively lower than those of
other competing facilities may cause a non-dispatch facility in the base case to be dispatched under a policy option.
b. Individual Phase II facilities
To assess potential distributional impacts among individual Phase II facilities, EPA analyzed facility-specific changes to a
number of key measures. For each measure, EPA determined the number of Phase II facilities that experience an increase or
a reduction, respectively, within two ranges: 0 to 1 percent, and 1 percent or more.14 EPA conducted this analysis for the
following measures:
* (1) Changes in capacity utilization: Capacity utilization is defined as a unit's actual generation divided by its
potential generation, if it ran 100 percent of the time (i.e., generation / (capacity * 365 days * 24 hours)). This
measure indicates how frequently a unit is dispatched and earns energy revenues for its owner.
*• (2) Changes in generation: See explanation in subsection a. above.
> (3) Changes in revenues: See explanation in subsection a. above.
> (4) Changes in variable production costs: See explanation in subsection a. above.
*• (5) Changes in fuel costs: See explanation in subsection a. above.
> (6) Changes in operating income: Operating income is defined as revenues minus production cost. Operating
income is an indicator of profitability and represents the amount of money available to cover the firm's non-
production costs. Operating income of Phase II facilities may decrease as a result of reductions in revenues and/or
increases in production costs.
B3-4 ANALYSIS RESULTS FOR THE PROPOSED RULE
EPA was not able to execute the market model analysis with an analytic option that completely matches the proposed rule's
specifications. Due to the lead time required to run an integrated electricity market model, EPA first completed an electricity
market model analysis of two options with costs higher than those of the proposed option: (1) the waterbody/capacity-based
option and (2) the all cooling towers option (the results of these two options are presented in Chapter B7: Alternative
Regulatory Options). Both of the analyzed options are more stringent in aggregate than the proposed rule and provide a
ceiling on the proposed rule's potential economic impacts. Because of limited time after the final definition of the proposed
rule, EPA was unable to rerun the IPM model. As a result, EPA adopted a two-step approach for the analysis of potential
impacts from the proposed Phase II Rule that uses the model outputs from the waterbody/capacity-based option:
*• First, EPA identified that for certain regional electricity markets that do not have any facilities costed with a closed-
cycle recirculating cooling water system, the waterbody/capacity-based option, as analyzed, matches the technology
compliance requirements of the proposed rule.15 These are the North American Electric Reliability Council (NERC)
regions that do not border oceans and estuaries: ECAR, MAIN, MAPP, SPP. Accordingly, EPA was able to
14 For the two alternative options analyzed in Chapter B7: Alternative Regulatory Options, EPA used three ranges: 0 to 1 percent, 1
to 3 percent, and 3 percent or more.
15 While the compliance requirements are identical under the proposed rule and the alternative waterbody/capacity-based option,
permitting costs associated with the proposed rule are higher than those for the alternative option analyzed using the IPM. The cost
differential averages approximately 30 percent of total compliance costs associated with the alternative option. Despite the higher
permitting costs, EPA concludes that the results of the alternative analysis are representative of impacts that could be expected under the
proposed rule.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
interpret the results of the IPM analysis for the waterbody/capacity-based option for these four NERC regions as
representative of the proposed rule in these regions.
Second, EPA determined that while the waterbody/capacity-based option, as analyzed in the IPM, matches the
technology specifications of the proposed rule for the four regions discussed above, this is not the case for the other
six NERC regions: ERCOT, FRCC, MAAC, NPCC, SERC, and WSCC. Under the waterbody/capacity-based
option, some facilities in these regions were costed with more stringent and costly compliance requirements,
including recirculating wet cooling towers, than would be required by the proposed rule. As a result, the IPM
waterbody/capacity-based option overstates the impacts of the expected rule in these remaining six regions. To
provide an alternative approach to estimating the rule's impacts in these regions, EPA compared the four NERC
regions explicitly analyzed in the IPM analysis and the other six NERC regions in terms of characteristics relevant to
the determination of the rule's impacts. EPA found no material differences between the two groups of regions in(l)
the percentage of total base case capacity subject to the proposed rule, (2) the average annualized compliance costs
of the proposed rule per MWh of generation, and (3) the distribution of compliance requirements of the proposed
rule (see Table B3-4 below). EPA therefore concludes that the results for the four regions would be representative
of the other NERC regions as well.
Table B3-4: Comparison of Compliance Requirements by NERC Region - 2008
NERC
Region
Percent of
Total
Capacity
Subject to
the Rule
ECAR
MAIN
MAPP
SPP
Average
66.5%
60.9%
42.1%
40.7%
57.1%
ERCOT
FRCC
MAAC
NPCC
SERC
WSCC
Average
Average of
All NERC
Regions
57.8%
49.8%
50.7%
49.6%
53.8%
18.3%
43.6%
47.7%
Total
Annualized
Compliance
Cost per
MWh
Generation
($2001)
$0.05
$0.04
$0.04
$0.03
$0.04
$0.04
$0.07
$0.06
$0.08
$0.03
$0.02
$0.04
$0.04
Percentage of In -Scope Facilities Subject to Each Compliance Requirement
Number of
Phase II
Facilities
Four Analyzed
99
49
42
32
Other Six N
51
30
43
54
95
33
Fine Mesh
Traveling
Screen w/
Fish
Handling
NERC Regions
32.4%
30.6%
9.5%
12.6%
24.8%
IERC Regions
2.0%
40.0%
26.2%
22.1%
16.8%
52.9%
22.8%
23.6%
Fine-Mesh
Traveling
Screen
7.1%
6.1%
7.1%
0.0%
5.8%
11.8%
13.3%
19.1%
34.2%
7.4%
3.0%
14.6%
10.9%
Fish
Handling
and Return
System
23.9%
22.7%
28.5%
46.9%
27.8%
60.8%
16.7%
28.8%
16.5%
31.6%
16.6%
30.3%
29.3%
None
36.6%
40.7%
54.8%
40.5%
41.5%
25.5%
30.0%
25.9%
27.1%
44.2%
27.5%
32.3%
0.3619367
Source: U.S. EPA, 2000; U.S. EPA analysis, 2002.
Table B3-4 indicates that, on average, the percentage of capacity subject to the proposed rule is slightly higher in the four
analyzed NERC regions compared to the other six regions. Everything else being equal, the higher the percentage of capacity
subject to the rule, the greater the likelihood that the rule would affect production costs and electricity prices at a regional
level. In addition, the average annualized compliance costs per MWh of generation for the four NERC regions, 4 cents per
MWh, is identical to that of the other six NERC regions. Again, everything else being equal, the higher the compliance cost
per MWh, the greater the likelihood that the rule would affect production costs and electricity prices at a regional level.
Finally, the distribution of compliance requirements is similar for the two groups of regions. The four analyzed regions have
B3-12
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
a slightly higher percentage of in-scope facilities costed with the most costly compliance technology, fine mesh traveling
screens with fish handling systems, than the other six regions. Conversely, the six regions have a higher percentage of
facilities costed with fine mesh screens, the second most costly compliance technology. The six regions also have a lower
percentage of facilities that are costed with no compliance technologies. Everything else being equal, the more facilities
costed with costly compliance technology, the higher the impacts that could be expected for Phase II facilities as a group and
for individual Phase II facilities.
Based on this comparison and the limited amount of electricity exchanges between regions modeled in IPM,16 EPA concluded
that the analysis of impacts under the proposed rule for the four NERC regions is representative of likely impacts in the other
six NERC regions.
The remainder of this section presents the results of the economic impact analysis of the proposed rule for the four NERC
regions for which the technology requirements under the waterbody/capacity-based option are identical to those of the
proposed rule: ECAR, MAIN, MAPP, SPP. The analysis is based on IPM output for the base case and proposed rule for
model run year 2008. Results are presented at the market level and the Phase II facility level.
B3-4.1 Market Analysis
This section presents the results of the IPM analysis for all facilities modeled by the IPM. The results in this section include
facilities that are in-scope and facilities that are out-of-scope of the proposed Phase II Rule. As stated above, EPA concluded
that results for the four NERC regions presented below are representative of likely impacts in the other six NERC regions.
Table B3-5 presents the market-level impact measures discussed in section B3-3.1 above: (1) Capacity changes, (2)
generation changes, (3) revenue changes, (4) variable production cost changes, (5) fuel cost changes, (6) electricity price
changes, and (7) plant closures. For each measure, the table presents the results for the base case and the proposed rule, the
absolute difference between the two cases, and the percentage difference.
Table B3-5: Market Level Impacts of the Proposed Rule (Four NERC Regions; 2008)
Economic Measures3
Base Case
East Central Area Reliability Coordinati
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(2) Total Generation (GWh)
(3) Total Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Energy Prices ($2001/MWh)
(6b) Capacity Prices ($2001/KW/yr)
(7) Closures - Capacity
118,390
110,080
8,310
0
649,140
$23,830
$12.53
$10.11
$22.58
$77.67
0
Proposed Rule
on Agreement (E
118,570
110,080
8,490
0
649,140
$23,850
$12.53
$10.11
$22.56
$77.86
0
Difference
•CAR)
180
0
180
0
0
$20
$0.00
$0.00
($0.02)
$0.19
0
% Change
0.2%
0.0%
2.2%
0.0%
0.0%
0.1%
0.0%
0.0%
-0.1%
0.2%
0.0%
16 Significant amounts of electricity exchanged between regions could limit the findings from the NERC region comparison, because
the four analyzed regions may have benefitted from the higher compliance costs of the other six regions in the analyzed regulatory
alternative. However, base case transmission from the four analyzed regions to the other six regions range from 3.5 to 6.7 percent of total
generation, while transmission from the other six regions to the four analyzed ones ranges from 0 to 0.2 percent. In the post-compliance
case, the change in transmissions of all regions is 0.2 percent or less.
B3-13
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-5: Market Level Impacts of the Proposed Rule (Four NERC Regions; 2008)
Economic Measures3
Base Case
Mid-America Interconnected Ne
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(2) Total Generation (GWh)
(3) Total Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Energy Prices ($2001/MWh)
(6b) Capacity Prices ($2001/KW/yr)
(7) Closures - Capacity
60,230
53,690
6,540
0
284,920
$11,120
$12.29
$10.25
$22.54
$78.15
0
Mid-Continent Area Power P
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(2) Total Generation (GWh)
(3) Total Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Energy Prices ($2001/MWh)
(6b) Capacity Prices ($2001/KW/yr)
(7) Closures - Capacity
35,470
32,710
2,760
0
179,110
$6,710
$11.67
$9.64
$22.25
$77.79
0
Southwest Power Pool (
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(2) Total Generation (GWh)
(3) Total Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Energy Prices ($2001/MWh)
(6b) Capacity Prices ($2001/KW/yr)
(7) Closures - Capacity
49,110
48,950
160
0
217,670
$8,440
$14.43
$12.52
$25.00
$61.24
0
Proposed Rule
twork (MAIN)
60,210
53,680
6,530
0
284,860
$11,120
$12.29
$10.25
$22.55
$78.18
0
Dol (MAPP)
35,470
32,710
2,760
0
179,170
$6,700
$11.68
$9.65
$22.20
$77.74
0
SPP)
49,110
48,950
160
0
217,750
$8,440
$14.43
$12.52
$24.99
$61.24
0
Difference
-20
-10
-10
0
-60
$0
$0.00
$0.00
$0.01
$0.02
0
0
0
0
0
60
($10)
$0.01
$0.01
($0.05)
($0.05)
0
0
0
0
0
80
$0
$0.01
$0.01
($0.01)
$0.00
0
% Change
0.0%
0.0%
-0.2%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
-0.1%
0.0%
0.1%
-0.2%
-0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.1%
0.0%
0.0%
0.0%
a Total capacity, existing capacity, total generation, and total revenues have been rounded to nearest 10.
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
B3-14
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
The results presented in Table B3-5 show that the proposed rule would not lead to significant changes in any of the analyzed
economic measures in any of the four regions. This finding is not surprising as the requirements of the proposed Phase II
Rule are very inexpensive compared to the overall production costs in the regions (Table B3-4 indicates that the average cost
of compliance per MWh of generation for these four regions is $0.04 as compared to an average variable production cost of
$12.73). ECAR is projected to install 180 MW, or 2.2 percent, more new capacity under the proposed rule. However, this
additional capacity represents only 0.2 percent of total capacity in the region. All other measures in all other regions change
by 0.2 percent or less as a result of the proposed rule, with a majority having zero change. Based on these results, EPA
concludes that there would be no energy effects from the proposed Phase II Existing Facilities Rule in these regions.
B3-4.2 Analysis of Phase II Facilities
This section presents the results of the IPM analysis for the Phase II facilities that are modeled by the IPM. Of the 540 Phase
II facilities, 226 are located in the four analyzed regions. Three of these 226 facilities are identified by the IPM as baseline
closures (two are located in MAIN, one is located in MAPP) and are therefore not represented in these results. Except where
noted, the results in this section therefore reflect the 223 non-closure Phase II facilities modeled by the IPM.
EPA used the IPM results to analyze two potential facility-level impacts of the proposed section 316(b) Phase II Rule: (1)
potential changes in the economic and operational characteristics of the group of Phase II facilities and (2) potential changes
to individual facilities within the group of Phase II facilities. It should be noted that the results of both analyses only include
the steam electric components of the Phase II facilities and thus do not provide complete measures for in-scope facilities that
also operate non-steam electric generation, which are not subject to this rule.
a. Group of Phase II facilities
The analysis of performed for the group of Phase II facilities is similar to the market level analysis described above but is
limited to facilities subject to the requirements of the section 316(b) rule. Table B3-6 presents the impact measures for the
group of Phase II facilities discussed in section B3-3.2 above: (1) Capacity changes, (2) generation changes, (3) revenue
changes, (4) variable production cost changes, (5) fuel cost changes, (6) plant closures, and (7) non-dispatch facilities. For
each measure, the table presents the results for the base case and the proposed rule, the absolute difference between the two
cases, and the percentage difference.
Table B3-6: Impacts on the Phase II Facilities of the Proposed Rule (Four NERC Regions; 2008)
Economic Measures3
Base Case
East Central Area Reliability Coor
(1) Total Capacity (MW)
(2) Total Generation (GWh)
(3) Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Closures - Number of Facilities
(6b) Closures - Capacity
(7a) Non-Dispatched Facilities - Number
(7b) Non-Dispatched Facilities - Capacity
78,710
515,020
$17,650
$12.34
$9.94
0
0
2
191
Proposed Rule
dination Agreemen
78,710
515,030
$17,650
$12.34
$9.94
0
0
2
191
Difference
t (ECAR)
0.00
10.00
$0.00
$0.00
$0.00
0.00
0.00
0.00
0.00
% Change
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
B3-15
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-6: Impacts on the Phase II Facilities of the Proposed Rule (Four NERC Regions; 2008)
Economic Measures3
Base Case
Mid-America Interconnect
(1) Total Capacity (MW)
(2) Total Generation (GWh)
(3) Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Closures - Number of Facilities
(6b) Closures - Capacity
(7a) Non-Dispatched Facilities - Number
(7b) Non-Dispatched Facilities - Capacity
36,700
226,360
$7,890
$11.74
$9.55
0
0
2
2,757
Mid-Continent Area PC
(1) Total Capacity (MW)
(2) Total Generation (GWh)
(3) Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Closures - Number of Facilities
(6b) Closures - Capacity
(7a) Non-Dispatched Facilities - Number
(7b) Non-Dispatched Facilities - Capacity
14,920
103,430
$3,420
$11.78
$9.84
0
0
6
326
Southwest Power
(1) Total Capacity (MW)
(2) Total Generation (GWh)
(3) Revenues (Million, $2001)
(4) Variable Production Costs ($2001/MWh)
(5) Fuel Costs ($2001/MWh)
(6a) Closures - Number of Facilities
(6b) Closures - Capacity
(7a) Non-Dispatched Facilities - Number
(7b) Non-Dispatched Facilities - Capacity
19,990
112,250
$3,930
$13.32
$11.07
0
0
8
1,857
Proposed Rule
ed Network (MAI
36,700
226,350
$7,890
$11.74
$9.55
0
0
2
2,757
wer Pool (MAPP)
14,920
103,470
$3,420
$11.78
$9.85
0
0
6
326
Pool (SPP)
19,990
112,350
$3,930
$13.34
$11.09
0
0
8
1,857
Difference
*V
0.00
-10.00
$0.00
$0.00
$0.00
0.00
0.00
0.00
0.00
0.00
40.00
$0.00
$0.00
$0.00
0.00
0.00
0.00
0.00
0.00
100.00
$0.00
$0.01
$0.01
0.00
0.00
0.00
0.00
% Change
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
0.1%
0.1%
0.0%
0.0%
0.0%
0.0%
a Total capacity, total generation, and revenues have been rounded to the closest 10.
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody'/Capacity-Based Option.
The results presented in Table B3-6 show that the proposed rule would not lead to significant changes in the performance of
the 223 Phase II facilities as evaluated by the seven measures. The rule would cause no early plant closures and would not
increase the number of Phase II facilities that are not dispatched. In all analyzed NERC regions, except for SPP, none of the
measures experiences any change as a result of the rule. In SPP, generation, variable productions costs, and fuel costs change
minimally, 0.1 percent.
B3-16
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
b. Individual Phase II facilities
The analysis in the previous section showed that the group of Phase II facilities as a whole would not experience economic
impacts under the proposed rule. However, it is possible that there would be shifts in economic performance among
individual facilities subject to this rule. To examine the range of possible impacts to individual Phase II facilities, EPA
analyzed facility-specific changes in (1) capacity utilization, (2) generation, (3) revenues, (4) variable production costs, (5)
fuel costs, and (6) operating income. Table B3-7 presents the 223 Phase II facilities located in the four analyzed NERC
regions by category of change for each economic measure.
Table B3-7: Number of Individual Phase II Facilities with Operational Changes (Four NERC Regions; 2008)
Economic Measures3
(1) Change in Capacity Utilization
(2) Change in Generation
(3) Change in Revenues
(4) Change in Variable Production Costs
(5) Change in Fuel Costs
(6) Change in Operating Income
Reduction
0-1%
2
i~t
56
0
2
66
>1%
0
0
0
0
0
0
Increase
0-1%
2
i
44
27
43
58
>1%
1
2
2
0
2
1
No Change
218
218
121
178
158
98
a For all measures, the percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent.
b Of the 223 Phase II facilities located in the four NERC regions, 18 facilities had zero generation and zero fuel costs in either the
base case or post-compliance scenario. It was therefore not possible to calculate the change in variable production costs or the
change in fuel costs per MWh for these facilities. As a result, the number of facilities adds up to 205 instead of 223 for these two
measures.
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B3-7 shows that most of the Phase II facilities in the four analyzed NERC regions experience very little changes in
economic activity as a result of this rule. No facility experiences a decrease in generation, capacity utilization, revenues, or
operating income, or an increase in production costs of more than one percent. These findings, together with the findings
from the comparison of compliance costs and requirements across all regions above, further confirm EPA's conclusion that
the proposed rule would not result in economic impacts to Phase II facilities located in the four analyzed NERC regions.
B3-5 SUMMARY OF FINDINSS
Based on the results presented in sections B3-4.1 and B3-4.2, EPA concludes the proposed rule will have little or no impact
on the electricity markets in any of the four analyzed regions, the group of Phase II facilities, or individual Phase II facilities.
The analyses at the market and the Phase II facility level have shown that the rule would lead to no significant changes in any
of the economic measures examined by EPA.
Given EPA's earlier noted finding of no material differences in important characteristics relevant to rule impacts between the
four analyzed NERC regions and the other six NERC regions, EPA concludes that the finding of no significant impact for
these four regions could be extended to the remaining six regions. As a result, EPA concludes that the proposed rule will not
pose significant impacts in any NERC region.
B3-6 UNCERTAINTIES AND LIMITATIONS
There are uncertainties associated with EPA's analysis of the electric power market and the economic impacts of the proposed
Phase II Rule and alternative regulatory options. These uncertainties stem from two main issues: (1) the specification of the
policy options analyzed by the IPM and (2) modeling limitations of the IPM.
B3-17
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
Specification of policy options: Due to limited time after the final definition of the proposed option, EPA was not able to use
the IPM to analyze a regulatory option that completely matches the proposed rule's specifications. Rather, EPA employed a
methodology that used the results of a previously completed analysis of the waterbody/capacity-based option, an option with
more costly and stringent compliance requirements, to assess the impacts of the proposed rule. The following limitations
result from the use of these results to represent the impacts associated with the proposed rule:
> Extrapolation of results from four regions to the national level: EPA identified four regional electricity markets
(NERC regions) for which the compliance technology requirements under the waterbody/capacity-based option
match those of the proposed rule. EPA assumed that the results of the IPM analysis of the more stringent option are
representative of the proposed rule in these regions. The six NERC regions for which the compliance technology
requirements under the proposed rule are different from the waterbody/capacity-based option were subsequently
compared to the four NERC regions with regard to characteristics relevant to the determination of impacts. This
comparison revealed no material differences between the two groups of regions. Based on this comparison, EPA
concluded that the results for the four regions would be representative of potential impacts for all regions. While
EPA recognizes that using the results from four regional markets to represent national impacts introduces some
uncertainty, EPA believes this approach to be reasonable given the similarities revealed by the comparison of NERC
regions.
*• Difference in permitting costs in four regional markets: While the compliance technology requirements in the four
analyzed NERC regions are identical under the proposed rule and the waterbody/capacity-based option, permitting
costs associated with the proposed rule are higher than those for the alternative option. The cost differential
averages approximately 30 percent of total compliance costs associated with the alternative option. As a result,
EPA's analysis may underestimate facility and market level impacts associated with the proposed rule. However,
given the very low absolute costs of the proposed rule, EPA concludes that the results of the alternative analysis are
representative of impacts that could be expected under the proposed rule.
Modeling limitations of the IPM: Additional uncertainty is introduced by the IPM modeling framework. Specifically, the
IPM assumes that demand at the national level and imports from Canada and Mexico would not change between the base case
and the analyzed policy options (generation within the regions is allowed to vary). Under the EPA Base Case 2000
specification, the demand for electricity is based on the AEO 2001 forecast adjusted to account for demand reductions
resulting from implementation of the Climate Change Action Plan (CCAP). The IPM model, as specified for this analysis,
does not capture changes in demand that may result from electricity price increases associated with the proposed rule and
alternative regulatory options. While this constraint may overestimate total demand in policy options that have high
compliance cost and that may therefore lead to significant price increases, EPA believes that it does not affect the results
analyzed in support of the proposed rule. As described in Section B3-4 above, the price increases associated with the
proposed rule are minimal. EPA therefore concludes that the assumption of inelastic demand-responses to changes in prices
is reasonable. In addition, all things being equal, holding generation fixed would result in conservative estimates of
production costs and electricity prices because more costly facilities remain economically viable longer to serve load that
does not decrease in response to higher prices. Similarly, holding international imports fixed would provide a conservative
estimate of production costs and electricity prices, because imports are not subject to the rule and may therefore become more
competitive relative to domestic capacity, displacing some of the more expensive domestic generating units. However, EPA
concludes that fixed imports do not materially affect the results of the analyses. Only four of the ten NERC regions import
electricity (ECAR, MAPP, NPCC, and WSCC) and the level of imports compared to domestic generation in each of these
regions is very small (0.03 percent in ECAR, 2.4 percent in MAPP, 5.6 percent in NPCC, and 1.5 in WSCC).
B3-18
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling
Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
U.S. Environmental Protection Agency (U.S. EPA). 2002. Documentation of EPA Modeling Applications (V.2.1) Using the
Integrated Planning Model. EPA 430/R-02-004. March 2002.
B3-19
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3
Appendix to Chapter B3
INTRODUCTION CHApTER CoNTENTS
This appendix presents additional, more detailed
information on EPA's research to identify models suitable
for analysis of environmental policies that affect the
electric power industry. In addition, this appendix
presents a comparison of the specifications of the EPA
Base Case 2000 and its predecessor Base Case specifications.
B3-A. 1 Summary Comparison of Energy Market Models B3-21
B3-A.2 Differences Between EPA Base Case 2000 and
Previous Model Specifications B3-26
B3-A.1 SUMMARY COMPARISON OF ENERSY MARKET MODELS
EPA performed research to identify electricity market models that could potentially be used in the analysis of impacts
associated with the proposed section 316(b) Phase II regulation and other regulatory options. This research included
reviewing available forecast studies and interviewing persons knowledgeable in the area of electricity market forecasting.
EPA focused on identifying models that are widely used for public policy analyses, peer reviewed, of national scope, and
have the capabilities needed to perform regulatory impact scenario analyses of the type required for the section 316(b) Phase
II economic analyses. Based on this research, EPA identified three models that were potentially suitable for the analysis of
the proposed section 316(b) Phase II regulations:
*• (1) The Department of Energy's National Energy Modeling System (NEMS),
*• (2) The Department of Energy's The Policy Office Electricity Modeling System (POEMS), and
> (3) ICF Consulting's Integrated Planning Model (IPM®).
Each of these models was developed to meet the specific needs of different end users and therefore differ in terms of
structure, inputs, outputs, and capability. Table B3-A-1 below presents a detailed comparison of the three models. The
comparison comprises:
*• General features, including a description of each model, their general applications, and their environmental
applications.
> Modeling features, including each model's treatment of existing environmental regulations, of industry
restructuring, and of economic plant retirements; their regional capabilities; their plant/unit detail and data sources;
their general data inputs and outputs; and their data inputs and outputs required for the section 316(b) analysis.
*• Logistical considerations, including each model's costs, computational requirements, accessability and response
time; their documentation and issues regarding disclosure of inputs or results; and general notes and references.
B3-20
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Comparison of Electricity Market Models
Model
DOE/EIA: NEMS
DOE/OP: POEMS
(OnLocation, Inc.)
EPA/Office of Air Policy (GAP):
IPM (ICF Consulting Inc.)
General Features
Description
Modular structured model of
national energy supply and
demand, includes macroeconomic,
international, supply and demand
modules, as well as an electricity
market module (EMM) that can be
run independently. The EMM
represents generation, transmission
and prices of electricity.
Based on forecasts of fuel prices,
variable O&M, and electricity
demand, determines plant dispatch
to achieve the least cost supply of
electric power.
POEMS is a model integration
system that allows the substitution of
the TRADELEC model for the EMM
in NEMS. TRADELEC allows for a
greater level of detail about the
electricity sector than the EMM.
Designed to examine the effect of
market structure transformation of
the electricity sector. It solves for
the trade of the commodity as a
function of relative prices,
transmission constraints and cost of
market entry by maximizing
economic gains achieved through
commodity trading.
A production cost model based on
linear programming approach,
solves for least cost dispatch.
Simulates system dispatch and
operations, estimates marginal
generation costs on an hourly basis.
Minimizes present worth of total
system cost subject to various
constraints.
General
Applications
Used to produce annual forecasts
of energy supply, demand, and
prices through 2020 for the Annual
Energy Outlook. Can also be used
to analyze effects of proposed
regulations. EIA performs studies
for Congress, DOE, other
agencies.
Used by DOE's policy office to
study the impacts of electricity
market transformation/ deregulation
through 2010. Supports the
administration's 1999 bill on industry
deregulation, the Comprehensive
Electricity Competition Act (CECA).
Primary model used by EPA Air
Program offices to evaluate policy
and regulatory impacts through
2030. EPA Office of Policy also
used this model for GCC and retail
deregulation analysis. Used by over
50 private sector clients to develop
compliance plans, price forecasts,
market analysis, and asset valuation.
Environmental
Applications
Includes a Carbon Emission
submodule. Can also calculate
emissions. Produced "Analysis of
Carbon Mitigation Cases" for
EPA.
DOE application generally not
designed to perform environmental
regulatory analysis. Examines a
renewable portfolio standard.
EPA/ARD concluded that air
emission estimates are low relative to
IPM and other models. However,
DOE contractor has performed
analyses of environmental policies
for private clients.
Analyzes environmental regulations
by simultaneously selecting optimal
compliance strategies for all
generating units. Can calculate
emissions, and simulate trading
scenarios. Used for ozone (NOX),
SO2, and mercury emissions control
scenarios; implementation of
NAAQS for ozone and PM;
alternative NO,, emissions trading
and rate-based programs for OTAG,
CAAA Title IV NO^ Rule; NOX
control options; RIA for the NO,,
SIP call; and GCC scenarios.
Possible to accommodate other
environmental regulations.
B3-21
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Comparison of Electricity Market Models
Model
DOE/EIA: NEMS
DOE/OP: POEMS
(OnLocation, Inc.)
EPA/Office of Air Policy (GAP):
IPM (ICF Consulting Inc.)
Modeling Features
Treatment of
Environmental
Regulations
Reference case represents all
existing regulations and legislation
in effect as of July 1,1998,
including impacts of the Climate
Change Action Plan and the NO,,
SIP call. EMM can analyze
seasonal environmental controls to
the extent that they match up with
the seasonal representations in the
model (non-sequential months are
grouped according to similar load
characteristics).
Assumes existing regulations and
legislation remain in place and
facilities comply with existing
regulations in the least cost way.
Most recent reference case analysis
includes NOX SIP call. Assesses a
renewable portfolio in the
competition case. Does not include
other proposed or anticipated
environmental regulatory scenarios
in DOE analysis.
The base case includes current
federal and state air quality
requirements, including future
implementation of SO2 and NOX
requirements of Title IV of the
CAA, the NOX SIP call as
implemented through a cap and
trade program. Base case also
includes assumptions regarding
demand reductions associated with
the Climate Change Action Plan.
Treatment of
Restructuring
All regions assumed to have
wholesale competition. Only
states with enacted legislation are
treated as competitive for retail
markets in base case. Has a
competitive pricing scenario that
assumes full retail competition.
Designed to compare competitive
wholesale and cost-of-service retail
market structures to fully competitive
market structure at the wholesale and
retail levels. Compares prices and
determines "stranded assets" at the
firm level. Pricing modeled for 114
power control areas, assumes profit
maximizing behavior.
EPA uses assumptions in IPM that
reflect wholesale competition
occurring throughout the electric
power industry. Work for private
clients uses different assumptions.
Treatment of
Economic Plant
Retirements
Uses assumptions about licencing
and needs for new major capital
expenses to forecast nuclear
retirements. For fossil steam,
model checks yearly to compare
revenues at market price with
future O&M and fuel costs to
forecast economic retirements.
Results appear to have second
highest forecast of fossil steam
retirements compared to other
models.
Uses same method as NEMS for
forecasting "forced" retirements of
nuclear assets due to operating
constraints such as licences.
Economic retirements based on lack
of ability to cover short term going
forward costs and the cost of capacity
replacement in the long term.
Results appear to have highest
forecast of fossil steam retirements
compared to other models.
Uses assumptions about licencing in
forecasting nuclear retirements.
The IPM model retires capacity
when unit level operating costs
reach a level that total electric
system costs are minimized by
shutting down the existing unit.
Regional
Capabilities
Model runs analysis for 15 supply
regions.
Analyzes 114 power control areas
connected by 680 transmission links.
Analyzes 26 supply regions that can
be mapped to NERC regions.
Plant/Unit
Detail
Groups all plants into 36 capacity
types based on fuel type, burner
technology, emission control
technology, etc. within a region.
Units or plants can be grouped
differently according to §316(b)
characteristics.
Units are grouped according to
demand and supply regions, fuel
type, prime mover, in-service period,
similar heat rates. There are 6,000
unit groupings, an average of 55 per
power control area. Plants can be re-
grouped for §316(b).
Groups approximately 12,000
generating units into model plants.
Grouped by region, state,
technology, boiler configuration,
location, fuel, heat rate, emission
rate, pollution control, coal demand
region. Plants can be re-grouped
for§316(b).
B3-22
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Comparison of Electricity Market Models
Model
DOE/EIA: NEMS
DOE/OP: POEMS
(OnLocation, Inc.)
EPA/Office of Air Policy (GAP):
IPM (ICF Consulting Inc.)
Modeling Features (cont.)
Plant/Unit Data
Sources
Form EIA-860A (all utility plants);
Form EIA-867 (nonutility plants
<1MW); Form EIA-767 (steam
plants <10MW); Form EIA-759
(monthly operating data for utility
plants).
Model includes "virtually all"
currently existing generating units,
including utility, exempt wholesale
generators (EWGs), and
cogenerators.
Over 12,000 generating units are
represented in this model. Includes
all utility units included in Form
EIA-860 database. Plus IPPs and
cogenerating units that sell firm
power to the wholesale market.
Also draws from other EIA Forms,
Annual Energy Outlook (AEO),
UDI, and other public and private
databases. In addition, ICF has
developed a database of industrial
steam boilers with over 250
MMBtu/hr capacity in 22 eastern
states.
General Data
Inputs
Demand, financial data, tax
assumptions, EIA and FERC data
on capital costs, O&M costs,
operating parameters, emission
rates, existing facilities, new
technologies, transmission
constraints, and other inputs from
other modules.
Inputs are similar to NEMS (for
demand, fuel price and
macroeconomic data), and EIA
reports. FERC filings for other
inputs such as capacity, operating
costs, performance, transmission,
imports, and financial parameters.
Some inputs are similar to NEMS,
including demand forecast, and cost
and performance of new and
existing units. Emission
constraints, repowering, and retrofit
options are EPA specified. Fuel
supply curves are used to model gas
and coal prices.
Data Inputs for
§316(b)EA
Would need to provide
information on additional capital
costs, O&M costs, study costs,
outage period for technology
installation, and changes in heat
rate and plant energy use
associated with each type of
technology as it applies to each
type of model plant.
Would need to provide information
on additional capital costs, O&M
costs, outage period for installation,
and changes in heat rate and plant
energy use associated with each type
of technology as it applies to each
plant grouping.
Would need to provide information
on additional capital costs, O&M
costs, outage period for installation,
and changes in heat rate and plant
energy use associated with each
type of technology as it applies to
each type of model plant.
General Data
Outputs
Retail price and price components,
fuel demand, capital requirements,
emissions, DSM options, capacity
additions, and retirements by
region and fuel type.
Dispatch, electricity trade, capacity
expansion, retirements, emissions,
and pricing (retail and wholesale) by
region, state, and fuel type.
Regional and plant emissions; fuel,
capital, and O&M costs;
environmental retrofits; capacity
builds; marginal energy costs; fuel
supply, demand, and prices
(primarily wholesale; one study
focused on retail market).
Data Outputs
for§316(b)
EBA
Results would include additional
economic retirements, changes in
generation, and changes in
revenues for each region and fuel
type. EMM cannot provide results
on a state-by-state basis.
By design, it is not possible to map
model plant results back to
specific plant/owner using current
modeling approach.
Results would include additional
economic retirements, changes in
generation, and changes in revenues
for each region andplant grouping.
Could map costs to units and owners
with some modification of structure.
Results would include additional
economic retirements, changes in
generation, and changes in revenues
for each region and model plant
type.
Currently has ability to map back to
specific unit and plant/owner.
While this process is automated, it
requires 2-3 days of manual
checking for every year modeled.
B3-23
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Comparison of Electricity Market Models
Model
DOE/EIA: NEMS
DOE/OP: POEMS
(OnLocation, Inc.)
EPA/Office of Air Policy (GAP):
IPM (ICF Consulting Inc.)
Logistical Considerations
Costs
(cost estimates
should be
considered very
preliminary)
No out-of-pocket costs expected.
Initial policy case using existing
scenario: $15-20k. Setting up new
base case scenario, performing
several runs, and producing briefing:
$40-60k. (Assumes plant re-
grouping cost is included in second
estimate only.)
Initial policy case: $20-30k.
Incremental cases $2-10k. Re-
grouping model plants would be
labor intensive and add costs to
analysis.
Computational
Requirements
Setting up a policy case may take
two months. The model run time
is two hours without iterating with
rest of NEMS, four hours for total
NEMS iteration. EIA runs NEMS
on RS6000 workstations.
Setting up and running policy case
could take from a few days to a few
weeks, depending on whether policy
case builds on an existing scenario
and the complexity of the policy
scenarios.
Depends on number of model plants
and number of years in analysis.
Base case approximately 4-6 hours.
Accessability
and Response
Time
Access and response time
dependent on agreement between
EIA and EPA and EIA's schedule.
Could be difficult to get results
turned around in time to meet
regulatory schedule, depending on
EIA's reporting schedule.
Access and response time potentially
dependent on agreement between
DOE and EPA and DOE's schedule.
Model run by a contractor. ARD has
impression that model has long set-
up time, model not set up to perform
many iterations quickly.
ICF is an EPA contractor. Assume
that access and response time will
be consistent with requirements of
analysis.
Documentation
and Disclosure
of
Inputs/Results
Documentation and results already
available to public. Presented by
year for fuel type and region.
Could make aggregated results
publicly available. EIA does not
release plant-specific results.
Documentation and results of
reference and competition cases are
available to public on DOE's web
page.
Documentation of the EPA Base
Case already available to public.
Assume disclosure would be similar
to that for NOX SIP call, etc.
EPA/ARD states that there is more
in public domain regarding IPM
than most models.
Notes
The NEMS code and data are
available to anyone for their own
use. Anyone wishing to use
NEMS is responsible for any code
conversions or setup on their own
systems. For example, FORTRAN
compilers differ between the
workstation and PC. Several
national laboratories and
consulting firms have used NEMS
or portions of it, but the time
investment is considerable. One
out-of-pocket expense is the
purchase of an Optimization
Modeling Library (OML) license.
OML is used to solve the
embedded linear programs in
NEMS. In order to modify or
execute one of the NEMS modules
that includes a linear program
(EMM is one of them), an OML
license is required.
DOE's contractor stated that they
may need to make some structural
changes to the modeling framework
to accommodate the requirements for
§316(b) analysis so that the model
can incorporate the effects of the
additional costs into the decision
process (either to continue running a
plant or to retire and replace the
plant).
OAP sensitive to other EPA offices
using another model or using IPM
with different assumptions. Willing
to coordinate and provide
background and technical support.
The EPA Base Case has received
some challenges over impacts of
Climate Change Action Plan on
end-use demand. However, has
cleared OMB review under other
regulatory proposals.
B3-24
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Comparison of Electricity Market Models
Model
DOE/EIA: NEMS
DOE/OP: POEMS
(OnLocation, Inc.)
EPA/Office of Air Policy (GAP):
IPM (ICF Consulting Inc.)
References
Annual Energy Outlook 1999,
Report#:DOE/EIA-0383(99);
Assumptions to the AEO99,
Report#:DOE/EIA-0554(99);
EMM/NEMS Model
Documentation Report,
Report#: DOE/EIA-M0689(99);
Personal communications with
EIA staff: Jeffrey Jones
(jeffrey.jones@eia.doe.gov) and
Susan Holte
(sholte@eia.doe.gov).
POEMS Model Documentation,
June 1998;
Supporting Analysis for the
Comprehensive Electricity
Competition Act (CECA), May,
1999, Report#: DOE/PO-0059;
The CECA: A Comparison of
Model Results, September, 1999,
Report#: SR/OAIF/99-04;
Personal communications with
DOE staff: John Conti
(john.conti@hq.doe.gov), EPA
staff: Sam Napolitano
(napolitano.sam@epa.gov), and
contractor: Lessly Goudarzi
(goudarzi@onlocationinc.com).
Analyzing Electric Power
Generation Under the CAA
(Appendix 2), March, 1998
(EPA/OAR/ARD);
Analysis of Emission Reduction
Options for the Electric Power
Industry (Chapter 2), March,
1999 (EPA/OAR/ARD);
IPM Demonstration, May, 1998
(slides by ICF);
Personal communications with
EPA staff: Sam Napolitano
(napolitano.sam@epa.gov), and
contractors: John Blaney
(blaneyj @icfkaiser. com).
Source: U.S. EPA analysis, 2002.
B3-A.2 DIFFERENCES BETWEEN THE EPA BASE CASE 2000 AND PREVIOUS MODEL
SPECIFICATIONS
Past applications by EPA of the IPM model have employed a predecessor base case specification. The previous specification
of the IPM model, EPA Base Case 1998, was recently updated to the current EPA Base Case 2000. The revised specification
used for the section 316(b) analysis uses more complete and current cost and performance data for new and existing facilities,
updated demand growth forecasts, and revised financial, fuel cost, and regulatory assumptions. The primary differences
between the IPM's EPA Base Case 2000 and its predecessor model specification are identified and discussed below. For
more a more detailed discussion of the specification of the EPA Base Case 2000 see Documentation of EPA Modeling
Applications (V. 2.1) Using the Integrated Planning Model (U.S. EPA, 2002).
*• The National Electric Energy Data System (NEEDS), the database containing location, operational, and emission
data for each of the existing and planned-committed generating units modeled in each IPM base case specification,
was updated using 1998 EIA data taken primarily from Form EIA-860A, Form EIA-860B, Form EIA-759, and Form
EIA-767. In addition, the update used data from the 1998 NERC Electric Supply and Demand database, second
quarter values from EPA's 2000 Continuous Emission Monitoring System database, and the EPA 1999 Information
Collection Request database.
>• The EPA Base Case 1998 demand growth assumptions were updated for the EPA Base Case 2000 specification.
The demand growth assumptions for the original specification were based on the 1997 NERC Electricity Supply and
Demand forecast for Net Energy for Load in early years, and on the Data Research Institute (DRI) 1995 forecast for
later years. These original forecasts were adjusted based on EPA's estimate of the demand reductions resulting from
implementation of the Climate Change Action Plan (CCAP). The EPA Base Case 1998 electricity demand growth
rate was 1.6 percent per year for 1997-2000, 1.8 percent peryearfor 2001-2010, and 1.3 percent per year for beyond
2010. EPA Base Case 2000 electricity demand growth is based on the AEO 2001 forecast. The AEO 2001 forecast
was also adjusted to account for impacts of initiatives created under the CCAP in the revised base case specification.
The EPA Base Case 2000 average annual growth rate in Net Energy for Load is 1.2 percent for 2000-2020.
*• Fuel Price assumptions were also updated under the EPA Base Case 2000 specification. Revised fuel price
forecasts/ supply curves for nuclear and biomass assumptions were taken from AEO2000 and AEO2001,
respectively, and natural gas information was derived from ICF's Gas Systems Analysis Model (GSAM).
>• The underlying assumptions affecting the retirement of fossil fired and nuclear capacity under the original
specification were revised for EPA Base Case 2000. Fossil power plants are given no fixed retirement date in EPA
Base Case 2000 as compared to EPA Base Case 1998 where they were assumed to have a finite lifetime. In the EPA
B3-25
-------
i 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3
Base Case 2000 retirement is determined endogenously based on economics. In addition, the option of re-licensing
nuclear units was introduced for EPA Base Case 2000, based on AEO2000 nuclear capacity factor forecast data.
Nuclear units that had not made a major maintenance investment, at age 30, are provided with a 10-year life
extension. These same units may subsequently undertake a 20-year re-licensing option at age 40. Nuclear units that
already had made a maintenance investment are provided with a 20-year re-licensing option at age 40. All nuclear
units are ultimately retired at age 60.
>• The cost and performance characteristics of new and existing units as well as environmental control technologies
such as SO2 scrubbers, selective catalytic reduction, and activated carbon injection were updated using more recent
data for the EPA Base Case 2000 specification. For example, the O&M costs for existing units were updated to
include the cost of capital additions. Further, the cost and performance assumptions for new units were updated
using information presented in AEO2000.
*• The financial assumptions for environmental control options and new units were revised based on recent market
activity. The capital charge rate and discount rate in EPA Base Case 1998 were 10.4% and 6%, respectively. For
the EPA Base Case 2000 specification the capital charge rate and discount rate were revised to 12% and 5.34%,
respectively, for retrofits; 12.9% and 6.14%, respectively, for new combined cycle units; and 13.4% and 6.74%,
respectively, for new combustion turbine units.
*• The EPA Base Case 2000 uses updated transmission assumptions. EPA Base Case 2000 organizes the United States
into 26 different power market regions for analyzing inter-regional electricity transfers across the interconnected
bulk power transmission grid as compared to 21 power market regions in EPA Base Case 1998. Assumptions
regarding transmission capabilities in the EPA Base Case 2000 were updated based on more recent NERC
documents.
>• The EPA Base Case 2000 is updated to account for additional environmental regulations. Specifically, EPA Base
Case 2000 accounts for EPA's NOX SIP Call regulation, a trading program covering all fossil units in 19 northeastern
states during the ozone season (May-September). In addition, state level environmental regulations in Texas,
Missouri, and Connecticut are also modeled.
*• The aggregation scheme for model plants was revised under EPA Base Case 2000. The group of coal fired model
plants was further disaggregated based on power plant firing type, fine paniculate controls, and post combustion
NOX controls.
B3-26
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Chapter B4: Regulatory Flexibility
Analysis
CHAPTER CONTENTS
B4-1 Number of In-Scope Facilities Owned by
Small Entities B4-2
B4-1.1 Identification of Domestic Parent
Entities B4-2
B4-1.2 Size Determination of Domestic Parent
Entities B4-3
B4-2 Percent of Small Entities Regulated B4-5
B4-3 Sales Test for Small Entities B4-6
B4-4 Summary B4-7
References B4-8
INTRODUCTION
The Regulatory Flexibility Act (RFA) requires EPA to
consider the economic impact a proposed rule would have on
small entities. The RFA requires an agency to prepare a
regulatory flexibility analysis for any notice-and-comment
rule it promulgates, unless the Agency certifies that the rule
"will not, if promulgated, have a significant economic impact
on a substantial number of small entities" (The Regulatory
Flexibility Act, 5 U.S.C. § 605(b)).
For the purposes of assessing the impacts of the Proposed
Section 316(b) Phase II Existing Facilities Rule on small
entities, EPA has defined a small entity as: (1) a small business according to the Small Business Administration (SBA) size
standards; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district
with a population of less than 50,000; or (3) a small organization that is a not-for-profit enterprise that is independently
owned and operated and is not dominant in its field. The SBA defines small businesses based on Standard Industrial
Classification (SIC) codes and size standards expressed by the number of employees, annual receipts, or total electric output
(13 CFR §121.20). The thresholds used in this analysis are four-digit SIC codes at the domestic parent entity-level.1
To evaluate the potential impact of this rule on small entities, EPA identified the domestic parent entity of each in-scope
Phase II facility and determined its size. EPA used a "sales test" to evaluate the potential severity of economic impact on
electric generators owned by small entities. The test calculates annualized post-tax compliance cost as a percentage of total
sales revenues and uses a threshold of three percent to identify facilities that would be significantly impacted as a result of the
proposed Phase II rule.
EPA's analysis showed that the proposed Phase II rule would not have a significant economic impact on a substantial number
of small entities (SISNOSE). This finding is based on: (1) the limited absolute number of small entities expected to incur
compliance costs; (2) the low percentage of all small entities in the entire electric generating industry expected to incur
compliance costs; and (3) the insignificant magnitude of compliance costs as a percentage of sales revenues.
1 The North American Industry Classification System (NAICS) replaced the Standard Industrial Classification (SIC) System as of
October 1, 2000. The data sources EPA used to identify the parent entities of the facilities subject to this rule did not provide NAICS
codes at the time of this analysis.
B4-1
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
B4-1 NUMBER OF IN-SCOPE FACILITIES OWNED BY SMALL ENTITIES
EPA's 2000 Section 316(b) Industry Survey identified 539 generating facilities expected to meet the in-scope requirements of
the Proposed Section 316(b) Phase II Existing Facilities Rule. As described in previous chapters of this document, these 539
facilities represent 550 facilities in the industry.2 It is impossible, however, to determine the parent entity of extrapolated
facilities. The remainder of this parent size analysis therefore discusses research done for the 539 surveyed facilities only.
Later steps of this RFA analysis extrapolate the small entity findings to the industry level.
The small entity determination for in-scope facilities was conducted in two steps:
*• Determine the domestic parent entity of the 539 in-scope facilities.
*• Determine the size of the entities owning the 539 facilities.
B4-1.1 Identification of Domestic Parent Entities
Each of the 539 Phase II facilities belongs to one of the following seven types of domestic parent entity: private, federal,
state, municipality, municipal marketing authority, political subdivision, or rural electric cooperative. In order to determine
the domestic parent entity for each of the 539 facilities, EPA used publicly available data from the Department of Energy's
(DOE) Energy Information Administration, 1999 Forms 860A and 860B. Information from the Section 316(b) Industry
Survey was also used for facilities owned by nonutilities. Due to the recent changes in the electric generating industry, EPA
used the Electric Power Monthly, a publication by the EIA, to identify in-scope facilities that have been sold to nonutilities
and their new owners. As of the January 2002 Electric Power Monthly publication, EPA identified 112 facilities that had
been sold to a nonutility since 1999. Of these 112 facilities, 105 were previously owned by a private utility, four were owned
by a rural electric cooperative, two were owned by a political subdivision, and one was owned by a municipality. For
facilities that have not been sold to a nonutility and that are not owned by a private entity, EPA assumed that the owner
presented in the 1999 Forms EIA-860A and EIA-860B is the facility's domestic parent entity. For all other facilities, EPA
conducted additional research to determine the domestic parent entity.
For facilities owned by a private entity, the immediate utility or nonutility owner is not necessarily the domestic parent firm.
Many privately-owned utilities and nonutilities are owned by holding companies. A holding company is defined by the U.S.
Census Bureau as being "primarily engaged in holding the securities of (or equity interests in) companies and enterprises for
the purpose of owning a controlling interest or influencing the management decisions of these firms" (U.S. DOC, 2002).
EPA used publicly available data and the Dun and Bradstreet (D&B) database to determine the domestic parent entity for all
facilities either owned by a private entity or sold since 1999. The following four publicly available data sources were
primarily used: the Security and Exchange Commission's (SEC) FreeEdgar database, the Hoover's Online website, Wright
Investors' Service, and ZapData, an internet service of Market Inc. EPA determined that 131 unique entities own the 539 in-
scope facilities.
2 EPA applied sample weights to the 539 facilities to account for non-sampled facilities and facilities that did not respond to the
survey. For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA, 1999a).
B4-2
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
B4-1.2 Size Determination of Domestic Parent Entities
The thresholds used by EPA to determine if a domestic parent entity is small depend on the entity type. Therefore, EPA used
multiple data sources to determine the entity sizes. The entity size thresholds and data sources EPA used are:
>• For private entities (including utilities and nonutilities), the small entity size is defined based on the parent entity's
SIC code and the related size standard set by the Small Business Administration (SBA). The SBA standards are
based on employment, sales revenue, or total electric output (in megawatt hours (MWh)), by four-digit SIC code.
EPA used publicly available data sources, including the SEC's FreeEdgar database, the Hoover's Online website,
Wright Investors' Service, and iMarket's ZapData, to obtain the information necessary to determine the entity size.
Table B4-1 presents the unique Phase II firm-level SIC codes and the corresponding SBA size standards that were
used to determine the size of privately-owned entities.
*• All federal and state governments are assumed to be large for the purpose of the RFA analysis (U.S. EPA, 1999).
> Municipalities, municipal marketing authorities, and political subdivisions are considered public sector entities.
Public sector entities are defined as small if they serve a population of less than 50,000. Population data for these
entities was obtained from the U.S. Census Bureau, Population Estimates Program.
>• The SBA threshold for SIC 4911 (4 million MWh of total electric output) was used for the size determination of
rural electric cooperatives. The size determination was based on 1999 Form EIA-861 data.
If the specific size standard information was not available for any of the 131 entities, EPA used the 4 million MWh total
electric output size standard to determine the entity size.
Table B4-1: Unique Phase II Non -Government Entity SIC Codes and
SIC Code
1311
3312
4911
4924
4931
4932
4939
4953
6512
8711
SIC Description
Crude Petroleum and Natural Gas
Steel Works, Blast Furnaces (Including Coke Ovens), and Rolling Mills
Electric Services
Natural Gas Distribution
Electric and Other Services Combined
Gas and Other Services Combined
Combination Utilities, NEC
Refuse Systems
Operators of Nonresidential Buildings
Engineering Services
SBA Size Standards
SBA Size Standard
500 Employees
1,000 Employees
4 million MWh
500 Employees
$5.0 Million
$5.0 Million
$5.0 Million
$10.0 Million
$5.0 Million
$6.0 Million
Source: U.S. SBA, 2000.
Based on these size thresholds, EPA determined that 26 out of the 131 unique entities owning the 539 in-scope facilities are
small entities. In addition to the 26 entities EPA identified as small, two entities were of an unknown size. EPA assumed
these two entities to be small. Therefore, out of the 131 unique entities, 28 were determined by EPA to be small. Nineteen of
the 28 small entities are municipalities, six are rural electric cooperatives, two are municipal marketing authorities, and one is
a political subdivision. None of the private entities owning in-scope facilities were found to be small entities. Table B4-2
presents the distribution of the unique entities by entity type and size.
B4-3
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-2: Phase II Unique Entities (by Entity Type and Size)
Entity Type
Private
Federal
State
Municipality
Municipal Marketing Authority
Political Subdivision
Rural Electric Cooperative
Small Entity Size
Standard
SIC Specific
Large
Large
Population of 50,000
Population of 50,000
Population of 50,000
4 million MWh
Total
Entity Size
Large Small Unknown
70
1
4
16 19
2
3 1
9 6
103 26 2
Total
70
1
4
35
2
4
15
131
Source: U.S. EPA analysis, 2002.
The distribution of the weighted in-scope facilities by their owner's type and size is displayed in Table B4-3. No small entity
owns more than one in-scope facility; therefore, the 28 small entities own 28 in-scope facilities.
Table B4-3: Phase II Facilities (by Entity Type and Size)
Entity Type
Private
Federal
State
Municipality
Municipal Marketing Authority
Political Subdivision
Rural Electric Cooperatives
Small Entity Size
Standard
SIC Specific
Large
Large
Population of 50,000
Population of 50,000
Population of 50,000
4 million MWh
Total a
Entity Size
Large Small
446
13
7
29 19
2
7 1
19 6
521 28
Total
446
13
7
48
2
8
25
550
a Individual numbers may not add up to total due to independent rounding.
Source: U.S. EPA analysis, 2002.
B4-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
B4-2 PERCENT OF SMALL ENTITIES REGULATED
In order to assess the impact of the proposed Phase II rule on the electric generating industry universe, EPA compared the
number of in-scope small entities to the number of small entities in the entire electric generating industry. As discussed
above, EPA identified 28 small entities (26 small and 2 unknown) subject to the proposed Phase II rule. Since only facilities
with design intake flows of 50 MOD or more are subject to the proposed rule, the low number of small entities owning in-
scope facilities is not unexpected. EPA identified 2,160 small entities within the entire electric power industry from the
methods discussed below. Overall, only a small percentage of all small entities in the entire electric power industry, 1.3
percent, is subject to the proposed Phase II rule.
Based on Form EIA-861, 3,315 unique utilities operated in the United States in 1999.3 It was not feasible to conduct the same
research for all 3,315 utilities that was done for the 131 entities owning in-scope facilities (i.e., determining the holding
companies and their SIC code and size standard information for private entities, and the population size for public sector
entities). EPA therefore determined the industry-wide number of small entities based on the electricity sales threshold of 4
million MWh, using the 1999 Form EIA-861. However, EPA's analysis of the 131 entities that own in-scope facilities
showed that the small entity determination based on the 4 million MWh threshold is not always the same as that based on the
SIC code or population thresholds. EPA therefore made the following adjustments to the industry-wide numbers of small
private entities, and municipalities:
> Private entities: EPA identified five privately-owned in-scope utilities that would qualify as small entities based on
the 4 million MWh total electric output threshold. However, EPA's holding company research showed that all five
small utilities would be considered large at the holding company level. EPA therefore assumed that industry-wide,
all privately-owned utilities are large entities.
> Municipalities: EPA's research of entities owning in-scope facilities showed that 33 municipalities, municipal
marketing authorities, and political subdivisions would be small based on the 4 million MWH size standard. Of
these 33 entities, however, 39.4 percent, or 13 would be considered large when using the population threshold. EPA
therefore reduced the number of small entity municipalities, municipal marketing authorities, and subdivisions
within Form EIA-861 by a factor of 39.4 percent.
3 It should be noted that the total number of small entities in the industry used in this analysis is based on utilities only. Information
on the entity size of nonutilities is not readily available. The total number of small entities in the industry may therefore be understated,
and, as a result, the percentage of small entities subject to the proposed Phase II rule may be overstated.
B4-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-4 presents the adjusted industry-wide number of small entities, the number of small entities that own in-scope
facilities, and the percent of all small entities that is subject to the proposed Phase II rule.
Table B4-4: Number of Small Entities (Industry Total and Entities with In-Scope Facilities)
Type of Entity
Municipality
Municipal Marketing Authority
Political Subdivision
Power Marketers
Rural Electric Cooperatives
All Firm Types
Total Number of
Small Entities
1,110
13
63
97
877
2,160
Number of Small
Entities with In-Scope
Facilities
19
2
1
0
6
28
Percent of Small Entities
Subject to the Proposed
Phase II Rule
1.7%
15.4%
1.6%
0.0%
0.7%
1.3%
Source: U.S. DOE, 1999c; U.S. EPA, 2000; D&BDatabase,2002.
B4-3 SALES TEST FOR SMALL ENTITIES
The final step in the RFA analysis consists of analyzing the cost-to-revenue ratio of each small entity subject to this proposed
rule (also referred to as the "sales test"). The analysis is based on the ratio of estimated annualized post-tax compliance costs
to annual revenues of the entity. EPA used a threshold of three percent to determine entities that would experience a
significant economic impact as a result of the proposed Phase II regulation.
None of the 28 facilities EPA determined to be owned by a small entity has more than one owner. Also, none of the 28 small
entities owns more than one in-scope facility. Therefore, no small entity is expected to incur compliance costs for more than
one facility under the proposed rule.
The estimated annualized post-tax compliance costs include all technology costs, operation and maintenance costs, and
permitting costs associated with the proposed Phase II rule. A detailed summary of how these costs were developed is
presented in Chapter Bl: Summary of Compliance Costs. For the 28 small entities, EPA calculated the average revenues over
a three year period (1996 through 1998), using data from Form EIA-861.
The overall annualized compliance costs that facilities owned by small entities are estimated to incur represent between 0.1
and 5.3 percent of the entities' annual sales revenues. Table B4-5 presents the distribution of the entities' cost-to-revenue
ratios by small entity type. Of the 28 small entities, two would incur compliance costs of greater than three percent of
revenues. Nine entities would incur compliance costs of between one and three percent of revenues, while the remaining 17
entities would incur compliance costs of less than one percent of revenues.
B4-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-5: Impact Ratio Ranges by Small Entity Type
Type of Entity
Municipality
Municipal Marketing Authority
Political Subdivision
Rural Electric Cooperative
Total
Impact Ratio Ranges
0.4 to 5. 3%
0.1 to 0.1%
1.2 to 1.2%
0.2 to 0.5%
0.1 to 5.3%
0-1% 1-3% >3%
982
200
0 1 0
600
17 9 2
Total
19
2
1
6
28
Source: U.S. EPA analysis, 2002.
EPA has determined that, overall, the impacts faced by small entities as a result of the proposed Phase II rule are very low.
Of the 28 entities owning in-scope facilities, only 2, approximately seven percent, would incur compliance costs of greater
than three percent of revenues. Moreover, these two entities represent only 1.5 percent of all 131 entities owning in-scope
facilities.
B4-4 SUMMARY
Under the Proposed section 316(b) Phase II Existing Facilities Rule, only 28 of 550 in-scope facilities would be owned by a
small entity. The absolute number of small entities potentially subject to this regulation, 28, is low. Additionally, only a
small percentage, 1.3 percent, of all small entities in the electric power industry is subject to this rule. Finally, the costs
incurred by the 28 small entities are low representing between 0.1 and 5.3 percent of the entities' annual sales revenue. EPA
therefore finds that this proposed rule would not have a significant economic impact on a substantial number of small entities
(SISNOSE).
The RFA analysis in support of this proposed Phase II rule is summarized in Table B4-6.
Type of Entity
Municipality
Municipal Marketing Authority
Political Subdivision
Power Marketers
Rural Electric Cooperative
Total
Table B4-6:
Total Number
of Small
Entities
1,110
13
63
97
877
2,160
Summary of RFA
Number of Small
Entities with
In-scope facilities
19
2
1
0
6
28
Analysis
Percent of Small
Entities In-Scope
of Rule
1.7%
15.4%
1.6%
0.0%
0.7%
1.3%
Annual Compliance
Costs/ Annual Sales
Revenue
0.4 to 5. 3%
0.1 to 0.1%
1.2 to 1.2%
n/a
0.2 to 0.5%
0.1 to 5.3%
Source: U.S. EPA analysis, 2002.
B4-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
REFERENCES
Dun and Bradstreet (D&B). 2002. Data extracted from D&B Webspectrum January 2002.
Hoover's Online. Various company capsule's. Accessed between 1999 and 2002. www.hoovers.com.
iMarket Inc., ZapData service. Various company profile's. Accessed between 1999 and 2002. www.zapdata.com.
Regulatory Flexibility Act. Pub. L. 96-354, Sept. 19, 1980, 94 Stat. 1164 (Title 5, Sec. 601 et seq.).
Security and Exchange Commission (SEC). FreeEdgar Database. Accessed between 1999 and 2002. www.freeedgar.com.
U.S. Department of Commerce (U.S. DOC). 2002. Bureau of the Census. 1997NAICS Definitions: 551 Management of
Companies and Enterprises.
U.S. Department of Commerce (U.S. DOC). 1990-1999. Bureau of the Census. Population Estimates Program. "Population
Estimates for Places: Annual Time Series" eire.census.gov/popest/estimates.php
U.S. Department of Energy (U.S. DOE). 1999a. Form EIA-860A (1999). Annual Electric Generator Report - Utility.
U.S. Department of Energy (U.S. DOE). 1999b. Form EIA-860B (1999). Annual Electric Generator Report - Nonutility.
U.S. Department of Energy (U.S. DOE). 1999c. Form EIA-861. Annual Electric Utility Report for the Reporting Period
1999.
U.S. Department of Energy (U.S. DOE). 1999-2001. Energy Information Administration. Electric Power Monthly. January
2000, January 2001, January 2002.
U.S. Environmental Protection Agency (U.S. EPA). 2000. Detailed Industry Questionnaire: Phase II Cooling Water Intake
Structures.
U.S. Environmental Protection Agency (U.S. EPA). 1999a. Information Collection Request (ICR), Detailed Industry
Questionnaires: Phase II Cooling Water Intake Structures & Watershed Case Study Short Questionnaire. August 1999.
U.S. Environmental Protection Agency (U.S. EPA). 1999b. Revised Interim Guidance for EPA Rulewriters: Regulatory
Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act. March 29, 1999.
U.S. Small Business Administration (U.S. SBA). 2000. Small Business Size Standards. 13 CFR §121.201.
Wright's Investor Service. Various company profile's. Accessed between 1999 and 2002. profiles.wisi.com.
B4-8
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Chapter B5: UMRA Analysis
INTRODUCTION
Title II of the Unfunded Mandates Reform Act of 1995, Pub.
L. 104-4, establishes requirements for Federal agencies to
assess the effects of their regulatory actions on state, local,
and Tribal governments and the private sector. Under section
202 of UMRA, EPA generally must prepare a written
statement, including a cost-benefit analysis, for proposed and
final rules with "Federal mandates" that might result in
expenditures to state, local, and Tribal governments, in the
aggregate, or to the private sector, of $100 million or more in
any one year.
CHAPTER CONTENTS
B5-1 Analysis of Impacts on Government
Entities B5-1
B5-1.1 Compliance Costs for
Government-Owned Facilities B5-2
B5-1.2 Administrative Costs B5-2
B5-1.3 Impacts on Small Governments B5-6
B5-2 Compliance Costs for the Private Sector B5-7
B5-3 Summary of UMRA Analysis B5-8
References B5-9
Before promulgating a regulation for which a written statement is needed, section 205 of UMRA generally requires EPA to
identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective, or least
burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are
inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most
cost-effective, or least burdensome alternative if the Administrator publishes with the proposed rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory requirements that might significantly or uniquely affect
small governments, including Tribal governments, it must have developed under section 203 of the UMRA a small
government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of
affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with
significant intergovernmental mandates, and informing, educating, and advising small governments on compliance with
regulatory requirements.
EPA estimates that facilities subject to the proposed Phase II rule would incur annualized post-tax compliance costs of $182.4
million ($2001). Of this total, $153.0 million is incurred by private sector facilities, $19.6 million is incurred by facilities
owned by state and local governments, and $9.8 million is incurred by facilities owned by the federal government.1
Permitting authorities incur an additional $3.6 million to administer the rule, including labor costs to write permits and to
conduct compliance monitoring and enforcement activities. EPA estimates that the highest undiscounted cost incurred by the
private sector in any one year is approximately $480 million in 2005. The highest undiscounted cost incurred by the state and
local governments in any one year is approximately $42 million in 2005 (including facility compliance costs and state
implementation cost). Thus, EPA has determined that this rule contains a Federal mandate that may result in expenditures of
$100 million or more for state, local, and Tribal governments, in the aggregate, or the private sector in any one year.
Accordingly, EPA has prepared under §202 of the UMRA a written statement which is summarized below.
B5-1 ANALYSIS OF IMPACTS ON GOVERNMENT ENTITIES
Governments may incur two types of costs as a result of this proposed rule:
*• direct costs to comply with the rule for facilities owned by government entities, and
*• administrative costs to implement the regulation.
Both types of costs incurred by governments are discussed below.
1 The costs incurred by the federal government are not part of the unfunded mandates analyses and are therefore not included in the
remainder of this chapter. The federal government owns 13 of the 550 Phase II facilities.
B5-1
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
B5-1.1 Compliance Costs for Government-Owned Facilities
Of the 550 existing in-scope facilities subject to the proposed rule, 65 are owned by a state or local government. These 65
facilities are owned by 45 government entities. None of the Phase II facilities are owned by a Tribal government. Table B5-1
presents the number of government entities that own facilities subject to the proposed rule and the number of in-scope
facilities by ownership type. Of the 65 facilities that are owned by government entities, 48 are owned by municipalities, two
are owned by municipal marketing authorities, seven are owned by state governments, and eight are owned by political
subdivisions.
Table B5-1 also presents the total annualized compliance costs of the 65 facilities by owner type, the average annualized cost
per facility, and the maximum undiscounted cost by the 65 government-owned facilities in any one year. The total annualized
compliance costs incurred by the 65 government-owned Phase II facilities is $19.6 million, or approximately $301,300 per
facility.2 The seven state-owned facilities account for the largest average annualized compliance cost, with approximately
$445,000 per facility. The maximum undiscounted cost by the 65 facilities is $36.3 million, estimated to be incurred in 2005.
The 48 facilities owned by municipalities incur the largest share of this cost, with $27.4 million.
Table B5-1: Number of Government Entities and Government -Owned Facilities
Ownership Type
Municipality
Municipal Marketing Authority
State Government
Political Subdivision
Total
Number of
Government
Entities
35
2
4
4
45
Number of
Facilities
48
2
7
8
65
Total Annualized
Compliance Costs
(in millions, $2001)
$14.1
$0.4
$3.1
$2.0
$19.6
Average
Compliance
Cost
(per facility)
$293,100
$206,300
$445,200
$248,500
$301,300
Maximum
One- Year Facility
Compliance Costs
(in millions, $2001)
$27.4
$0.5
$4.7
$3.8
$36.3
Source: U.S. EPA analysis, 2002.
B5-1.2 Administrative Costs
The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination System (NPDES)
permit program. Forty-four states and one territory currently have NPDES permitting authority under Section 402(c) of the
Clean Water Act (CWA). EPA estimates that states and territories will incur three types of costs associated with
implementing the requirements of the proposed rule: (1) start-up activities; (2) permitting activities associated with the initial
NPDES permit containing the new section 316(b) requirements and subsequent permit renewals; and (3) annual activities.3
EPA estimates that the total costs for these activities will be $3.62 million, annualized over 30 years at a seven percent rate.
Table B5-2 below presents the annualized costs of the three major administrative activities.
2 Chapter Bl: Summary of Compliance Costs of this Economic and Benefits Analysis (EBA) presents information on the unit costs
used to estimate facility compliance costs and the assumptions used to calculated annualized costs.
3 The costs associated with implementing the requirement of the proposed Phase II rule are documented in EPA's Information
Collection Request (U.S. EPA, 2002).
B5-2
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-2: Annual ized Government Administrative Costs
(in millions, $2001)
Activity
Start-Up Activities
Permitting Activities
Annual Activities
Total
Cost
$0.02
$2.66
$0.94
$3.62
Source: U.S. EPA analysis, 2002.
The start-up costs are incurred only once by each of the 45 permitting authorities. The first permit containing the new section
316(b) requirements, permit renewals, and annual activities are incurred on a per-permit basis. Based on the specific
permitting requirements of each in-scope facility, EPA calculated total government costs of implementing the proposed Phase
II rule by aggregating the unit costs for the first post-promulgation permit, and the repermitting and annual activities. The
maximum one-year undiscounted implementation cost incurred by the government is $6.4 million, in 2006.
The incremental administrative burden on states will also depend on the extent of each state's current practices for regulating
cooling water intake structures (CWIS). States that currently require relatively modest analysis, monitoring, and reporting of
impacts from CWIS in NPDES permits may require more permitting resources to implement the proposed Phase II rule than
are required under their current programs. Conversely, states that currently require very detailed analysis may require fewer
permitting resources to implement the proposed rule than are currently required.
The following subsections present more detail on the three types of implementation costs.
a. Start-up activities
Forty-four states and one territory with NPDES permitting authority are expected to undertake start-up activities to prepare
for administering the proposed rule. Start-up activities include reading and understanding the rule, mobilization and planning
of the resources required to address the rule's requirements, and training technical staff on how to review materials submitted
by facilities and make determinations on the proposed Phase II rule requirements for each facility's NPDES permit. In
addition, permitting authorities are expected to incur other direct costs, e.g., for copying and the purchase of supplies. Table
B5-3 shows the total start-up costs EPA estimated permitting authorities to incur. Each permitting authority will incur start-
up costs of $3,546 as a result of the proposed Phase II rule. EPA assumes that the initial start-up activities will be incurred by
all permitting authorities at the end of 2003, the year of promulgation of the Final Section 316(b) Phase II Existing Facilities
Rule.
Table B5-3: Government Costs of Start-Up Activities
(per Regulatory Authority)
Start-Up Activity
Read and Understand Rule
Mobilization/Planning
Training
Other Direct Costs
Total
Start-Up Costs
$877
$1,526
$1,093
$50
$3,546
Source: U.S. EPA analysis, 2002.
B5-3
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B5: UMRA Analysis
b. Initial post-promulgation permitting and repermitting activities
The permitting authorities will be required to implement the section 316(b) Phase II rule by adding compliance requirements
to each facility's NPDES permit. Permitting activities include incorporating section 316(b) requirements into the first post-
promulgation permit and making modifications, if necessary, to each subsequent permit. The first permit containing the new
section 316(b) requirements will be issued between 2004 and 2008.4 Repermitting activities will take place every five years
after initial permitting.
The proposed Phase II rule requires facilities to submit the same type of information for their initial post-promulgation permit
and for each permit renewal application. Therefore, the type of administrative activities are similar for the initial post-
promulgation and each subsequent permit. EPA identified the following major activities associated with state permitting
activities: reviewing submitted documents and supporting materials, verifying data sources, consulting with facilities and the
interested public, determining specific permit requirements, and issuing the permit. Table B5-4 below presents the state
permitting activities and associated costs on a per permit basis. The permitting costs do not vary by type of facility to be
permitted. The burden of repermitting is expected to be smaller than for the initial post-promulgation permit because the
permitting authority is already familiar with the facility's case and the type of information the facility will provide.
Two of the permitting activities presented within Table B5-4 pertain only to facilities opting for a site-specific determination
of best technology available (BTA). An authorized state is able to permit a facility to opt for alternative regulatory
requirements if it can demonstrate that the alternative requirements will result in environmental performance within a
watershed that is comparable to the reductions in impingement mortality and entrainment comparable to those otherwise
achieved under the proposed Phase II rule. EPA estimates that 10 regulatory permitting authorities would incur permitting
costs associated with site-specific determinations.
4 For an explanation of how the compliance years were assigned to facilities subject to the proposed Phase II rule, see Chapter El:
Summary of Compliance Costs of this EBA.
B5-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-4: Government Permitting Costs (per Permit)
Activity
Review Source Water Physical Data
Review CWIS Data
Review Source Water Baseline Biological Characterization Data
Review Proposal for Collection of Information for Comprehensive
Demonstration Study
Review Source Water Body Flow Information
Review Design and Construction Technology Plan
Review Impingement Mortality & Entrainment Characterization Study
Review Evaluation of Potential CWIS Effects
Review Restoration Measures3
Review Information to Support Site-Specific Determination of BTAb
Determine Monitoring Frequency
Determine Record Keeping and Reporting Frequency
Establish Requirements for Site-Specific Technology11
Considering Public Comments
Issuing Permits
Permit Record Keeping
Other Direct Costs
Total0
Site Specific Costs
Post-Promulgation Permit
$261
$782
$1,462
$1,170
$261
$1,297
$19,230
$1,170
$2,066
$41,320
$261
$261
$1,042
$1,170
$238
$117
$300
$72,405
$42,362
Repermitting
$102
$232
$439
$366
$102
$369
$5,769
$366
$620
$12,396
$102
$102
$289
$366
$57
$22
$300
$21,996
$12,685
a Assumed to apply to only 10 percent of facilities.
b Cost incurred only for facilities conducting site-specific demonstrations.
c Individual numbers may not add up to total due to independent rounding.
Source: U.S. EPA analysis, 2002.
Initial post-promulgation permits that require all of the components listed in the table above are expected to impose a per
permit cost per of $72,405 on the permitting authority. A majority of the initial permitting costs result from the facility option
for a site-specific determination of BTA. For the initial post-promulgation permit, the state administrative costs associated
with the site-specific determination are estimated to be $42,362, or approximately 59 percent of the total permitting costs.
Permitting authorities would incur a maximum permit cost of $30,043 for facilities that do not conduct a site specific
determination for their initial post-promulgation permit.
The maximum state administrative cost for a permit renewal is $21,996. For facilities that do not conduct a site specific
determination, the cost per permit imposed on the permitting authority is reduced by $12,685, resulting in a maximum permit
cost of $9,311.
B5-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
c. Annual activities
In addition to the start-up and permitting activities previously discussed, permitting authorities will have to carry out certain
annual activities to ensure the continued implementation of the requirements of the proposed Phase II rule. These annual
activities include reviewing yearly status reports, tracking compliance, determination on monitoring frequency reduction, and
record keeping.
Table B5-5 below shows the annual activities that will be necessary for each permit, beginning in the year after the first post-
promulgation permit, and the estimated costs of each activity. A total cost of $1,712 is estimated for each permit per year.
Table B5-5: Government Costs for Annual
Annual Activity
Review of Yearly Status Report
Compliance Tracking
Determination on Monitoring Frequency Reduction
Record Keeping
Other Direct Costs
Total
Activities (per Permit)
Annual Costs
$610
$521
$407
$124
$50
$1,712
Source: U.S. EPA analysis, 2002.
B5-1.3 Impacts on Small Governments
EPA's analysis also considered whether the proposed rule may significantly or uniquely affect small governments (i.e.,
governments with a population of less than 50,000). Table B5-6 presents by ownership size: (1) the number of entities
owning facilities subject to the regulation; (2) the number of facilities; (3) compliance costs; and (4) the estimated average
compliance cost per facility. EPA identified 22 facilities (of the 65 government-owned facilities) subject to the proposed rule
that are owned by small governments.5
Table B5-6 shows that the estimated annualized compliance cost for all government-owned facilities is $19.6 million. The 43
facilities owned by large governments would incur costs of $13.6 million; the 22 facilities owned by small governments
would incur costs of $6 million.
5 Chapter B4: Regulatory Flexibility Analysis of this EBA provides more information on EPA's determination of the size of entities
owning the 550 in-scope facilities.
B5-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-6: Number of Regulated Facilities and Compliance Costs by Entity Size
Ownership Size
Facilities Owned by
Small Governments
Facilities Owned by
Large Governments
All Government-Owned
Facilities
All Privately-Owned
Facilities
Number of
Number of Facilities
Entities Subject to
Regulation
22 22
23 43
45 65
85 471
Annualized
Compliance Costs
(in millions, $2001)
$6.0
$13.6
$19.6
$153.0
Average
Compliance
Cost per Facility
$272,200
$283,300
$301,400
$324,700
Maximum
One- Year Facility
Compliance Costs
(in millions, $2001)
$9.7
$26.6
$36.3
$479.0
Source: U.S. EPA analysis, 2002.
The total annualized compliance cost for the 22 facilities owned by small governments is $6.0 million, or approximately
$272,000 per facility. In comparison, the total annualized compliance cost for the 43 facilities owned by large governments is
$13.6 million, or approximately $283,000 per facility. For all of the 471 privately-owned facilities, the total annualized
compliance cost is $182.4 million, or approximately $331,600 per facility. These numbers support EPA's analysis in
showing that small governments would not be significantly or uniquely affected by the proposed Phase II rule. The per
facility average compliance cost incurred by facilities owned by small governments is less than the per facility compliance
costs incurred by facilities owned by large governments and privately-owned facilities subject to the proposed Phase II rule.
B5-2 COMPLIANCE COSTS FOR THE PRIVATE SECTOR
The private sector only incurs compliance costs associated with facilities subject to this proposed rule. These direct facility
costs already include the cost to facilities of obtaining their NPDES permits. Of the 550 in-scope facilities subject to the
proposed rule, EPA identified 471 to be owned by a private entity.
Compliance costs for individual facilities are presented in Chapter Bl: Summary of Compliance Costs of this EBA. Total
annualized (post-tax) compliance costs for the 471 privately-owned facilities are estimated to be $153.0 million, discounted at
seven percent. The maximum aggregate costs (undiscounted) for all 471 facilities in any one year is estimated to be $479.0
million, incurred in 2005.
B5-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
B5-3 SUMMARY OF UMRA ANALYSIS
EPA estimates that the Proposed Section 316(b) Existing Facilities Rule will result in expenditures of $100 million or greater
for state and local governments, in the aggregate, or for the private sector in any one year. Table B5-7 summarizes the costs
to comply with the rule for the 537 in-scope facilities (excluding the 13 facilities owned by the federal government) and the
costs to implement the rule, borne by the responsible regulatory authorities.
Table B5-7: Summary of UMRA Costs (in millions, $2001)
Sector
Government
Sector
Private Sector
Total Annualized Cost (Post-Tax)
_ .... Government
Facility T ,
_ ,. V, , Implementation
Compliance Costs r t
$19.6 $3.6
$153.0 n/a
Total
$23.2
$153.0
Maximum One- Year Cost
Facility Government
Compliance Implementation
Costs Costs
$36.3 $5.8
$479.0 n/a
Total
$42.2
$479.0
Source: U.S. EPA Analysis, 2002.
The total annualized (post-tax) costs of the Proposed Section 316(b) Phase II Existing Facilities Rule borne by governments is
approximately $23.2 million, consisting of $19.6 million in facility compliance costs and $3.6 million in government
implementation costs. The maximum one-year costs that will be incurred by government entities is expected to be $42.2
million ($36.3 million in facility compliance costs and $5.8 million in implementation costs), incurred in 2005. Total
annualized costs borne by the private sector is estimated by EPA to be $153 million. The maximum one-year cost to the
private sector is $479 million, incurred in 2005.
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B5: UMRA Analysis
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2002. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Proposed Rule. ICR Number 2060.01. February 2002.
B5-9
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B5: UMRA Analysis
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B5-10
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B6: Other Administrative Requirements
Chapter B6: Other Administrative
Requirements
INTRODUCTION
This chapter presents several other analyses in support of the
Proposed Phase II Existing Facilities Rule. These analyses
address the requirements of Executive Orders and Acts
applicable to this rule.
B6 -1 EXECUTIVE ORDER 12866:
RESULATORY PLANNING AND REVIEW
Under Executive Order 12866 (58 FR 51735, October 4,
1993), the Agency must determine whether the regulatory
action is "significant" and therefore subject to OMB review
and the requirements of the Executive Order. The order
defines a "significant regulatory action" as one that is likely
to result in a rule that may:
CHAPTER CONTENTS
B6-1 E.O. 12866: Regulatory Planning and Review B6-1
B6-2 E.O. 12898: Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income
Populations B6-1
B6-3 E.O. 13045: Protection of Children from Environmental
Health Risks and Safety Risks B6-3
B6-4 E.O. 13132: Federalism B6-4
B6-5 E.O. 13158: Marine Protected Areas B6-5
B6-6 E.O. 13175: Consultation with Tribal
Governments B6-6
B6-7 E.O. 13211: Energy Effects B6-6
B6-8 Paperwork Reduction Act of 1995 B6-7
B6-9 National Technology Transfer and
Advancement Act B6-7
References B6-8
> have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a
sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or
Tribal governments or communities; or
>• create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; or
>• materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations
of recipients thereof; or
> raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, EPA determined that this proposed rule is a "significant regulatory action."
As such, this action was submitted to OMB for review. Changes made in response to OMB suggestions or recommendations
are documented in the public record.
B6-2 EXECUTIVE ORDER 12898: FEDERAL ACTIONS TO ADDRESS ENVIRONMENTAL
JUSTICE IN MINORITY POPULATIONS AND LOW-INCOME POPULATIONS
Executive Order 12898 (59 FR 7629, February 11, 1994) requires that, to the greatest extent practicable and permitted by law,
each Federal agency must make achieving environmental justice part of its mission. E.O. 12898 provides that each Federal
agency must conduct its programs, policies, and activities that substantially affect human health or the environment in a
manner that ensures such programs, policies, and activities do not have the effect of (1) excluding persons (including
populations) from participation in, or (2) denying persons (including populations) the benefits of, or (3) subjecting persons
(including populations) to discrimination under such programs, policies, and activities because of their race, color, or national
origin.
B6-1
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B6: Other Administrative Requirements
Today's final rule would require that the location, design, construction, and capacity of cooling water intake structures
(CWIS) at Phase II existing facilities reflect the best technology available for minimizing adverse environmental impact. For
several reasons, EPA does not expect that this final rule would have an exclusionary effect, deny persons the benefits of the
participation in a program, or subject persons to discrimination because of their race, color, or national origin.
In fact, because EPA expects that this final rule would help to preserve the health of aquatic ecosystems located in reasonable
proximity to Phase II existing facilities, it believes that all populations, including minority and low-income populations,
would benefit from improved environmental conditions as a result of this rule. Under current conditions, EPA estimates
approximately 2.2 billion fish (expressed as age 1 equivalents) of recreational and commercial species are lost annually due to
impingement and entrainment at the 539 in-scope Phase II existing facilities. Under the proposed regulation, over 1.2 billion
individuals of these commercially and recreationally sought fish species (age 1 equivalents) will now survive to join the
fishery each year (435 million fish due to reduced impingement impacts, and 789 million fish due to reduced entrainment).
These additional 1.2 billion fish will provide increased opportunities for subsistence anglers to increase their catch, thereby
providing some benefit to low income households located near regulation-impacted waters.
The greatest benefits from this rule may be realized by populations that fish for subsistence purposes. While the extent of
subsistence fishing in the U.S. or in individual states and cities is not generally known, it is known that Native Americans and
low income Southeast Asians are the major population subgroups participating in subsistence fishing. However, Native
Americans fishing on reservations are not required to obtain a license, so records of the number of Native Americans fishing
on reservations are not available. Similarly, Southeast Asians often do not purchase licenses and therefore the extent of their
participation in subsistence fishing is unknown.
Due to the lack of data, EPA uses simplifying assumptions to estimate the number of subsistence fishermen. In some past
analyses, EPA assumed that subsistence fishermen constitute 5 percent of the total licensed population. This assumption is,
however, likely to understate the number of recreational fishers, because although fishing licenses may be sold to subsistence
fishermen, many of these individuals do not purchase fishing licenses. Therefore, in more recent analyses EPA has assumed
that the number of subsistence fishermen would constitute an additional 5 percent of the licensed fishing population. Using
this 10 percent assumption, the number of subsistence fishermen that may benefit from increased fish populations as a result
of this rule is substantial.
Based on estimates of the number of anglers calculated from the 1996 National Survey of Fishing, Hunting, and
Wildlife-Associated Recreation (U.S. DOI 1997), the average in-scope facility has a subsistence population of nearly 15,000
people living within 50 miles of the facility. EPA estimated average subsistence populations by waterbody type. The results
indicate that, although the estimated subsistence fishing population comprises a small percentage of the total population, a
significant number of persons may engage in subsistence fishing within the vicinity of in-scope facilities. The results of this
analysis are presented in Table B6-1.
Table B6-1: Estimated Subsistence Fishing Population Within 50-mile Radius of In-scope Facilities °
Waterbody Type
Estuary - NonGulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
All In-Scope Facilities
Number of In-Scope
Facilities
78
30
393
16
22
539
Average 2000
Population11
7,045,000
1,845,000
1,578,000
3,195,000
5,101,000
2,576,000
Average Estimated Subsistence
Fishing Population"
20,000
12,000
14,000
6,000
13,000
15,000
a Estimated as 10% of total estimated anglers living within 50 miles of an in-scope facility. Rounded to nearest thousand.
b Rounded to the nearest thousand.
Source: Angler estimates calculated from U.S. DOI, 1997; U.S. EPA analysis, 2002.
Because the estimates presented in Table B6-1 are estimates that are not based on actual subsistence fishing data, they may
tend to underestimate or overestimate the actual levels of subsistence fishing within a given waterbody type. As a secondary
B6-2
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B6: Other Administrative Requirements
analysis, EPA calculated the poverty rate and the percentage of the population classified as non-white, Native American, and
Asian for populations living within a 50-mile radius of each of the 53 9 in-scope facilities.
The results of this secondary analysis, presented in Table B6-2, show that the populations affected by the in-scope facilities
have poverty levels and racial compositions that are quite similar to the U.S. population as a whole. In-scope facilities
located on oceans and non-gulf estuaries do tend to have significant Asian populations. As such, in these areas persons that
rely on subsistence fishing may benefit greatly due to increases in fish populations resulting from changes mandated by the
rule. However, taken as a whole, a relatively small subset of the facilities are located near populations with poverty rates (24
of 539, or 4.5%), non-white populations (101 of 539, or 18.7%), Native American populations (30 of 539, or 5.6%), or Asian
populations (48 of 539, or 8.9%) that are significantly higher than U.S. average levels.
Table B6-2 Demographics of Populations within 50-Mile Radius of In-Scope Facilities
Waterbody Type
Estuary - NonGulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
All In-Scope
Facilities
U.S.
Number of
In-Scope
Facilities
78
30
393
16
22
539
—
Average
1998
Poverty
Rate
11.2%
13.4%
12.7%
11.1%
13.7%
12.5%
12.7%
Average 2000 Percent of
Population
Non-
white"
28.5%
24.0%
17.5%
19.5%
33.8%
20.2%
22.9%
Native
American1"
0.8%
0.8%
1.6%
1.6%
1.6%
1.4%
1.5%
Asian0
6.2%
2.5%
1.7%
2.3%
15.4%
3.0%
4.2%
Number of Facilities with Levels >= 1.5 Times
the U.S. Level
Poverty
Rate
0
0
22
0
2
24
—
Non-
White
Pop
38
6
44
3
10
101
—
Native
America
nPop
0
0
27
2
1
30
—
Asian Pop
33
0
1
0
14
48
a Non-white population defined as any person who did not indicate their race to be "White," either alone or in combination with one
or more of the other races listed.
b Defined as any person who indicated their race to be "Native American" or "Native Alaskan" either alone or in combination with
one or more of the other races listed
c Defined as any person who indicated their race to be "Asian" either alone or in combination with one or more of the other races
listed.
Source: Non-white, Native American, and Asian population estimates compiled from U.S. DOC, 2000; Average poverty rate compiled
from U.S. DOC, 1998.
Based on these results, EPA does not believe that this rule will have an exclusionary effect, deny persons the benefits of the
NPDES program, or subject persons to discrimination because of their race, color, or national origin. To the contrary, it will
increase the number offish and other aquatic organisms available for subsistence, commercial, and recreational anglers of all
races, color, and natural origin.
B6-3 EXECUTIVE ORDER 13045: PROTECTION OF CHILDREN FROM ENVIRONMENTAL
HEALTH RISKS AND SAFETY RISKS
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be "economically
significant" as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has
reason to believe might have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency
must evaluate the environmental health and safety effects of the planned rule on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. This
proposed rule is an economically significant rule as defined under Executive Order 12866. However, it does not concern an
B6-3
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
environmental health or safety risk that would have a disproportionate effect on children. Therefore, it is not subject to
Executive Order 13045.
B6-4 EXECUTIVE ORDER 13132: FEDERALISM
Executive Order 13132 (64 FR 43255, August 10, 1999) requires EPA to develop an accountable process to ensure
"meaningful and timely input by state and local officials in the development of regulatory policies that have federalism
implications." Policies that have federalism implications are defined in the Executive Order to include regulations that have
"substantial direct effects on the states, on the relationship between the national government and the states, or on the
distribution of power and responsibilities among the various levels of government."
Under section 6 of Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes
substantial direct compliance costs, and that is not required by statute unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by state and local governments or unless EPA consults with state and
local officials early in the process of developing the proposed regulation. EPA also may not issue a regulation that has
federalism implications and that preempts state law, unless the Agency consults with state and local officials early in the
process of developing the proposed regulation.
This proposed rule does not have federalism implications. It will not have substantial direct effects on the states, on the
relationship between the national government and the states, or on the distribution of power and responsibilities among the
various levels of government, as specified in Executive Order 13132. EPA expects an annual burden of 146,983 hours for
states to collectively administer this proposed rule. EPA has identified 65 Phase II existing facilities that are owned by state
or local government entities. The annual impacts on these facilities are not expected to exceed 2,252 burden hours and
$56,739 (non-labor costs) per facility.
The proposed national cooling water intake structure requirements would be implemented through permits issued under the
NPDES program. Forty-five states and territories are currently authorized pursuant to section 402(b) of the CWA to
implement the NPDES program. In states not authorized to implement the NPDES program, EPA issues NPDES permits.
Under the CWA, states are not required to become authorized to administer the NPDES program. Rather, such authorization
is available to states if they operate their programs in a manner consistent with section 402(b) and applicable regulations.
Generally, these provisions require that state NPDES programs include requirements that are as stringent as Federal program
requirements. States retain the ability to implement requirements that are broader in scope or more stringent than Federal
requirements. (See section 510 of the CWA.)
EPA does not expect the proposed Phase II regulation to have substantial direct effects on either authorized or nonauthorized
states or on local governments because it would not change how EPA and the states and local governments interact or their
respective authority or responsibilities for implementing the NPDES program. This proposed rule establishes national
requirements for Phase II existing facilities with cooling water intake structures. NPDES-authorized states that currently do
not comply with the final regulations based on this rule might need to amend their regulations or statutes to ensure that their
NPDES programs are consistent with Federal section 316(b) requirements. (See 40 CFR 123.62(e).) For purposes of this
proposed rule, the relationship and distribution of power and responsibilities between the Federal government and the state
and local governments are established under the CWA (e.g., sections 402(b) and 510); nothing in this proposed rule would
alter that. Thus, the requirements of section 6 of the Executive Order do not apply to this rule.
Although section 6 of Executive Order 13132 does not apply to this rule, EPA did consult with state governments and
representatives of local governments in developing definitions and concepts relevant to the section 316(b) regulation and this
proposed rule:
*• During the development of the proposed section 316(b) rule for new facilities, EPA conducted several outreach
activities through which state and local officials were informed about this proposal. These officials then provided
information and comments to the Agency. The outreach activities were intended to provide EPA with feedback on
issues such as adverse environmental impact, BTA, and the potential cost associated with various regulatory
alternatives.
*• EPA has made presentations on the section 316(b) rulemaking effort in general at eleven professional and industry
association meetings. EPA also conducted two public meetings in June and September of 1998 to discuss issues
related to the section 316(b) rulemaking effort. In September 1998 and April 1999, EPA staff participated in
technical workshops sponsored by the Electric Power Research Institute on issues relating to the definition and
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
assessment of adverse environmental impact. EPA staff have worked with numerous states such as New York, New
Jersey, California, Rhode Island, and Massachusetts and regions such as Region 1 and Region 9.
*• EPA met with the Association of State and Interstate Water Pollution Control Administrators (ASIWPCA) and, with
the assistance of ASIWPCA, conducted a conference call in which representatives from 17 states or interstate
organizations participated.
>• EPA met with OMB and utility representatives and other federal agencies (the Department of Energy, the Small
Business Administration, the Tennessee Valley Authority, the National Oceanic and Atmospheric Administration's
National Marine Fisheries Service and the Department of Interior's U.S. Fish and Wildlife Service).
*• EPA received more than 2000 comments on the Phase I proposed rule and Notice of Data Availability (NODA). In
some cases these comments have informed the development of the Phase II rule proposal. State and local
government representatives from the following states submitted comments: Alaska, California, Florida, Louisiana,
Maryland, Michigan, Nebraska, New Hampshire, New Jersey, New York, North Carolina, North Dakota, Ohio,
Pennsylvania, and Texas.
>• On May 23, 2001, EPA held a day-long forum to discuss specific issues associated with the development of
regulations under section 316(b). At the meeting, 17 experts from industry, public interest groups, states, and
academia reviewed and discussed the Agency's preliminary data on cooling water intake structure technologies that
are in place at existing facilities and the costs associated with the use of available technologies for reducing
impingement and entrainment. Over 120 people attended the meeting.
In the spirit of this Executive Order and consistent with EPA policy to promote communications between EPA and state and
local governments, the preamble to this proposed rule specifically solicited comment from state and local officials.
B6-5 EXECUTIVE ORDER 13158: MARINE PROTECTED AREAS
Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to "expeditiously propose new science-based regulations,
as necessary, to ensure appropriate levels of protection for the marine environment." EPA may take action to enhance or
expand protection of existing marine protected areas and to establish or recommend, as appropriate, new marine protected
areas. The purpose of the Executive Order is to protect the significant natural and cultural resources within the marine
environment, which means "those areas of coastal and ocean waters, the Great Lakes and their connecting waters, and
submerged lands thereunder, over which the United States exercises jurisdiction, consistent with international law." EPA
expects that the proposed Phase II Existing Facilities Rule will advance the objective of Executive Order 13158.
Marine protected areas include designated areas with varying levels of protection, from fishery closure areas, to aquatic
National Parks, Marine Sanctuaries, and Wildlife Refuges (NOAA, 2002). The Departments of Commerce and the Interior
have included sites that appear to meet the marine protected area definition in a nationwide inventory of marine protected
areas. This list has not been completed yet, but includes 32 national sites in the New England region, 31 in the Middle
Atlantic region, 43 sites in the South Atlantic region, and 46 in the U.S. Pacific Coast region. Examples of different types of
marine protected areas currently in the list include the Great Bay National Wildlife Refuge in New Hampshire, the Cape Cod
Bay Northern Right Whale Critical Habitat in Massachusetts, the Narragansett Bay National Estuarine Research Reserve in
Rhode Island, Everglades National Park and the Tortugas Shrimp Sanctuary in Florida, and the Point Reyes National
Seashore in California.
Marine protected areas can help address problems related to the depletion of marine resources by prohibiting, or severely
curtailing, activities that are permitted or regulated by law outside of marine protected areas. Such activities include oil
exploration, dredging, dumping, fishing, certain types of vessel traffic, and the focus of section 316(b) regulation, the
impingement and entrainment of aquatic organisms by cooling water intake structures.
Impingement and entrainment affects many kinds of aquatic organisms, including fish, shrimp, crabs, birds, sea turtles, and
marine mammals. Aquatic environments are harmed both directly and indirectly by impingement and entrainment of these
organisms. In addition to the harm that results from the direct removal of organisms by impingement and entrainment, there
are the indirect effects on aquatic food webs that result from the impingement and entrainment of organisms that serve as prey
for predator species. There are also cumulative impacts that result from multiple intake structures operating in the same local
area, or when multiple intakes affect individuals within the same population over a broad geographic range.
B6-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
Decreased numbers of aquatic organisms resulting from the direct and indirect effects of impingement and entrainment can
have a number of consequences for marine resources, including impairment of food webs, disruption of nutrient cycling and
energy transfer within aquatic ecosystems, loss of native species, and reduction of biodiversity. By reducing the impingement
and entrainment of aquatic organisms, the proposed Phase II Existing Facilities Rule will not only help protect individual
species but also the overall marine environment, thereby advancing the objective of Executive Order 13158 to protect marine
areas.
B6-6 EXECUTIVE ORDER 13175: CONSULTATION AND COORDINATION WITH INDIAN
TRIBAL GOVERNMENTS
Executive Order 13175 (65 FR 67249, November 6, 2000) requires EPA to develop an accountable process to ensure
"meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications."
"Policies that have tribal implications" is defined in the Executive Order to include regulations that have "substantial direct
effects on one or more Indian Tribes, on the relationship between the Federal government and the Indian Tribes, or on the
distribution of power and responsibilities between the Federal government and Indian Tribes." This proposed rule does not
have tribal implications. It will not have substantial direct effects on tribal governments, on the relationship between the
Federal government and Indian Tribes, or on the distribution of power and responsibilities between the Federal government
and Indian Tribes, as specified in Executive Order 13175. EPA's analyses show that no facility subject to this proposed rule
is owned by tribal governments. This proposed rule does not affect Tribes in any way in the foreseeable future. Accordingly,
the requirements of Executive Order 13175 do not apply to this rule.
B6-7 EXECUTIVE ORDER 13211: ACTIONS CONCERNING REGULATIONS THAT
SIGNIFICANTLY AFFECT ENERGY SUPPLY, DISTRIBUTION, OR USE
Executive Order 13211 (66 FR 28355; May 22, 2001) requires EPA to prepare a Statement of Energy Effects when
undertaking regulatory actions identified as "significant energy actions." Forthe purposes of Executive Order 13211,
"significant energy action" means:
"any action by an agency (normally published in the Federal Register) that promulgates or is
expected to lead to the promulgation of a final rule or regulation, including notices of inquiry,
advance notices of proposed rulemaking, and notices of proposed rulemaking:
(1) (i) that is a significant regulatory action under Executive Order 12866 or any successor
order, and
(ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy;
or
(2) that is designated by the Administrator of the Office of Information and Regulatory Affairs
(OIRA) as a significant energy action."
For those regulatory actions identified as "significant energy actions," a Statement of Energy Effects must include a detailed
statement relating to (1) any adverse effects on energy supply, distribution, or use (including a shortfall in supply, price
increases, and increased use of foreign supplies), and (2) reasonable alternatives to the action with adverse energy effects and
the expected effects of such alternatives on energy supply, distribution, and use.
This proposed rule does not qualify as a "significant energy action" as defined in Executive Order 13211 because it is not
likely to have a significant adverse effect on the supply, distribution, or use of energy. The proposed rule does not contain
any compliance requirements that would directly reduce the installed capacity or the electricity production of U.S. electric
power generators, for example through parasitic losses or auxiliary power requirements. In addition, based on the estimated
costs of compliance, EPA currently projects that the rule will not lead to any early capacity retirements at facilities subject to
this rule or at facilities that compete with them. As described in detail in Chapter C3: Electricity Market Model Analysis,
EPA estimates small effects of this rule on installed capacity, generation, production costs, and electricity prices. EPA
B6-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
therefore concludes that this proposed rule will have small energy effects at a national, regional, and facility-level. As a
result, EPA did not prepare a Statement of Energy Effects.1
For more detail on the potential energy effects of this proposed rule or the alternative regulatory options considered by EPA,
see Chapter C3: Electricity Market Model Analysis and Chapter C7: Alternative Regulatory Options.
B6-8 PAPERWORK REDUCTION ACT OF 1995
The Paperwork Reduction Act of 1995 (PRA) (superseding the PRA of 1980) is implemented by the Office of Management
and Budget (OMB) and requires that agencies submit a supporting statement to OMB for any information collection that
solicits the same data from more than nine parties. The PRA seeks to ensure that Federal agencies balance their need to
collect information with the paperwork burden imposed on the public by the collection.
The definition of "information collection" includes activities required by regulations, such as permit development,
monitoring, record keeping, and reporting. The term "burden" refers to the "time, effort, or financial resources" the public
expends to provide information to or for a Federal agency, or to otherwise fulfill statutory or regulatory requirements. PRA
paperwork burden is measured in terms of annual time and financial resources the public devotes to meet one-time and
recurring information requests (44 U.S.C. 3502(2); 5 C.F.R. 1320.3(b)).
Information collection activities may include:
*• reviewing instructions;
*• using technology to collect, process, and disclose information;
*• adjusting existing practices to comply with requirements;
*• searching data sources;
*• completing and reviewing the response; and
>• transmitting or disclosing information.
Agencies must provide information to OMB on the parties affected, the annual reporting burden, the annualized cost of
responding to the information collection, and whether the request significantly impacts a substantial number of small entities.
An agency may not conduct or sponsor, and a person is not required to respond to, an information collection unless it displays
a currently valid OMB control number.
EPA's estimate of the information collection requirements imposed by the proposed Phase II regulation are documented in the
Information Collection Request (ICR) which accompanies this regulation (U.S. EPA, 2002).
B6-9 NATIONAL TECHNOLOSY TRANSFER AND ADVANCEMENT ACT
Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995, Pub L. No. 104-113, Sec. 12(d)
directs EPA to use voluntary consensus standards in its regulatory activities unless doing so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications,
test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standard
bodies. The NTTAA directs EPA to provide Congress, through the Office of Management and Budget (OMB), explanations
when the Agency decides not to use available and applicable voluntary consensus standards.
This proposed rule does not involve such technical standards. Therefore, EPA is not considering the use of any voluntary
consensus standards.
1 EPA recognizes that some of the alternative regulatory options discussed in the preamble and analyzed in Chapter C7: Alternative
Regulatory Options would have larger effects and might well qualify as "significant energy actions" under Executive Order 13211. If EPA
decides to revise the proposed requirements for the final rule, it will reconsider its determination under Executive Order 13211 and prepare
a Statement of Energy Effects as appropriate.
B6-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
REFERENCES
Executive Office of the President. 2001. Executive Order 13211. "Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use." 66 FR 28355. May 22, 2001.
Executive Office of the President. 2000a. Executive Order 13175. "Consultation and Coordination with Indian Tribal
Governments." 65 FR 67249, November 6, 2000.
Executive Office of the President. 2000b. Executive Order 13158. "Marine Protected Areas." 65 FR 34909, May 31, 2000.
Executive Office of the President. 1999. Executive Order 13132. "Federalism." 64 FR 43255. August 10, 1999.
Executive Office of the President. 1997. Executive Order 13045. "Protection of Children from Environmental Health Risks
and Safety Risks." 62 FR 19885, April 23, 1997.
Executive Office of the President. 1994. Executive Order 12898. "Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations." 59 FR 7629, February 11, 1994.
Executive Office of the President. 1993. Executive Order 12866. "Regulatory Planning and Review." 58 FR 51735.
October 4, 1993.
National Oceanic and Atmospheric (NOAA) and U.S. Department of Commerce. 2002. Marine Protected Areas of the
United States, http://mpa.gov/welcome.html. Accessed 2/22/02.
Paperwork Reduction Act (PRA). 44 U.S.C. 3501 et seq.
U.S. Department of Commerce (U.S. DOC), Bureau of the Census. 2000. 2000 Census of Population and Housing.
U.S. Department of Commerce (U.S. DOC), Bureau of the Census. 1998. 1998 Small Area Income and Poverty Estimates.
U.S. Department of the Interior (U.S. DOI), Fish and Wildlife Service, and U.S. Department of Commerce, Bureau of the
Census. 1997. 1996 National Survey of Fishing, Hunting, and Wildlife-Associated Recreation.
U.S. Environmental Protection Agency (U.S. EPA). 2002. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Proposed Rule. ICR Number 2060.01. February 2002.
B6-8
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Chapter B7: Alternative Options -
Costs and Economic Impacts
CHAPTER CONTENTS
B7-1 Waterbody/Capacity-Based Option B7-2
B7-1.1 Compliance Costs B7-2
B7-1.2 Cost-to-Revenue Measure B7-4
B7-1.3 SBREFA Analysis B7-6
B7-2 Impingement Mortality and Entrainment Controls
Everywhere Option B7-6
B7-2.1 Compliance Costs B7-6
B7-2.2 Cost-to-Revenue Measure B7-8
B7-2.3 SBREFA Analysis B7-9
B7-3 All Cooling Towers Option B7-9
B7-3.1 Compliance Costs B7-9
B7-3.2 Cost-to-Revenue Measure B7-11
B7-3.3 SBREFA Analysis B7-12
B7-4 Dry Cooling Option B7-12
B7-4.1 Compliance Costs B7-12
B7-4.2 Cost-to-Revenue Measure B7-14
B7-4.3 SBREFA Analysis B7-15
INTRODUCTION
EPA considered the costs and economic impacts of four
alternative regulatory options that would establish best
technology available (BTA) for minimizing adverse
environmental impact (AEI):1
> (1) Waterbody/Capacity-Based Option
(Options 1 and 2): This option would require
Phase II facilities located on estuaries, tidal
rivers, and oceans to reduce intake capacity
commensurate with the use of closed-cycle,
recirculating cooling systems based on the
volume of cooling water they withdraw. EPA
analyzed two different cases of the
waterbody/capacity-based option: the first case
assumes that all facilities with recirculating
cooling system-based requirements would comply
with Track I and install a wet cooling tower
(Option 1); the second, more likely, case assumes
that a percentage of the facilities with recirculating cooling system-based requirements would comply with Track II
and conduct a comprehensive waterbody characterization study and install technologies other than wet cooling
towers (Option 2).
*• (2) Impingement Mortality and Entrainment Controls Everywhere Option (Option 3a): This option would
require all Phase II facilities to reduce impingement and entrainment to levels established based on the use of design
and construction technologies (e.g., fine-mesh screens, fish return systems) or operational measures.
*• (3) All Cooling Towers Option (Option 4): This option would require all Phase II facilities to reduce intake
capacity commensurate with the use of closed-cycle, recirculating cooling systems.
*• (4) Dry Cooling Option (Option 5): This option would require Phase II facilities located on estuaries, tidal rivers,
and oceans to reduce intake capacity commensurate with the use of a dry cooling system based on the volume of
cooling water they withdraw.
For each of these four alternative options, this chapter presents (1) the private annualized costs of compliance by NERC
region and plant type;2 (2) cost-to-revenue ratios at the facility and firm-levels; and (3) an analysis of potential impacts on
small entities. The methodologies used to develop the estimates presented in this chapter are the same as those discussed in
previous chapters of this EBA. Chapter Bl: Summary of Compliance Costs and the § 316(b) Technical Development
Document present EPA's detailed analysis of the compliance cost components and national cost estimation; Chapter B2: Cost
1 Chapter Al: Introduction and Overview of this Economic and Benefits Analysis (EBA) provides a more detailed discussion of the
requirements of these alternative regulatory options. EPA also considered another waterbody-based option (Option 6) in which all
facilities located on an estuary or tidal river or ocean must reduce intake flow commensurate with a level that can be achieved by a closed-
cycle, recirculating system, regardless of proportional intake flow. This option was not costed and is not discussed in this chapter.
2 For a count of Phase II facilities by NERC region and plant type, see Chapter A2: Need for the Regulation of this EBA.
B7-1
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B7: Alternative Options - Costs and Economic Impacts
Impact Analysis presents an assessment of the magnitude of compliance costs at the facility and firm-levels; and Chapter B4:
Regulatory Flexibility Analysis considers the potential impact of the proposed Phase II rule on small entities.
B7-1 WATERBODy/CAPAcrry-BASED OPTION (OPTIONS 1 AND 2)
The waterbody/capacity-based option would require facilities that withdraw very large amounts of water from an estuary, tidal
river, or ocean to reduce their intake capacity to a level commensurate with that which can be attained by a closed-cycle,
recirculating cooling system. EPA estimates that 54 facilities would be required to reduce intake flow to a level commensurate
with that which can be attained by a closed-cycle recirculating system to comply with this option.
The cost for facilities to meet these standards could potentially be substantial if they installed a cooling tower. Under this
option, EPA would provide an opportunity to seek alternative requirements to address locally significant air quality or energy
impacts. While EPA is not proposing this option, EPA is considering it for the final rule.3
EPA analyzed two different cases of the waterbody/capcity based option: the first case assumes that all 54 facilities with
recirculating cooling system-based requirements would comply with Track I and install a wet cooling tower; the second, more
likely, case assumes that 33 facilities would comply with Track I and install a wet cooling tower and the remaining 21 facilities
with flow reduction requirements would comply with Track II and conduct a comprehensive waterbody characterization study
and install technologies other than wet cooling towers.
B7-1.1 Compliance Costs
EPA estimates that the total annualized private post-tax cost of compliance for the waterbody/capacity-based option ranges
from approximately $379 million assuming 21 facilities comply with Track II (Option 2) to $595 million assuming all 54
facilities comply with Track I (Option 1).
Table B-2 presents the total annualized private costs by cost category and NERC region for both of the compliance responses
analyzed. The NERC regions with the highest compliance costs, FRCC (Florida Reliability Coordinating Council), MAAC
(Mid-Atlantic Area Council), NPCC (Northeast Power Coordinating Council), SERC (Southwestern Electric Reliability
Council), and WSCC(Western Systems Coordinating Council) all contain coastal states with facilities withdrawing cooling
water from estuaries, tidal rivers, or oceans.
Using the assumption that all 54 facilities with recirculating cooling system based requirements would comply with Track I
(Option 1), the annualized cost by NERC region ranges from approximately $90,000 for facilities located in ASCC (Alaska
Systems Coordinating Council) to $142 million for facilities located in NPCC (Northeast Power Coordinating Council). The
capital technology cost, which includes the cost of cooling towers, comprises $226 million of the total $595 million cost (or 38
percent). The annual energy penalty and one-time connection outage costs represent $68 million (or 11 percent) and $26
million (or 4 percent), respectively. Annual operating and maintenance costs represent $242 million (or 41 percent) of total
compliance costs. Permitting costs represent $34 million (or 6 percent) of total compliance costs.
Under the second, more likely, assumption that some facilities would comply with Track I and others with Track II (Option 2),
the annualized cost by NERC region ranges from approximately $76,000 for facilities located in ASCC (Alaska Systems
Coordinating Council) to $98 million for facilities located in NPCC (Northeast Power Coordinating Council). The capital
technology cost comprises $162 million of the total $379 million cost (or 43 percent). The annual energy penalty and one-time
connection outage costs represent $28 million (or 7 percent) and $22 million (or 6 percent), respectively. EPA estimates
operating and maintenance costs to be $146 million (or 39 percent) of total compliance costs. Permitting costs represent $32
million (or 8 percent) of total compliance costs.
3 EPA analyzed this option using the energy market model. For a detailed analysis, see Chapter B8: Alternative Options - Electricity
Market Model Analysis of this Economic and Benefits Analysis (EBA).
57-2
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Table B7-2: Private (Post-Tax) Annualized Compliance Costs by NERC Region (in millions, $2001)
Waterbody/Capacity- Based Option
NERC Region
One-Time Costs
Capital Connection
Technology Outage
Recurring Costs
O&M Jnely
Penalty
Permitting
Costs
Total
All Track I (Option 1)
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
$0.0 $0.0
$15.2 $0.0
$8.5 $0.4
$29.7 $5.4
$5.5 $1.1
$40.7 $3.2
$6.4 $0.0
$2.0 $0.0
$54.7 $4.6
$27.5 $3.5
$1.3 $0.0
$34.0 $7.3
$225.5 $25.5
$0.0 $0.0
$3.6 $0.0
$12.2 $2.7
$44.2 $15.3
$5.4 $2.5
$45.9 $9.1
$1.4 $0.0
$0.4 $0.0
$66.2 $12.7
$28.1 $10.5
$0.4 $0.0
$34.3 $15.1
$242.1 $67.9
$0.1
$5.9
$3.5
$2.1
$0.2
$2.5
$3.0
$3.0
$3.8
$5.9
$2.1
$2.3
$34.3
$0.1
$24.6
$27.2
$96.7
$14.8
$101.4
$10.8
$5.3
$141.9
$75.6
$3.8
$93.0
$595.3
Track I and II (Option 2)
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
$0.0 $0.0
$15.2 $0.0
$7.7 $0.3
$18.5 $0.9
$5.5 $1.1
$23.8 $1.1
$6.4 $0.0
$2.0 $0.0
$40.0 $2.5
$20.7 $1.6
$1.3 $0.0
$21.1 $3.5
$162.0 $11.0
$0.0 $0.0
$3.6 $0.0
$10.3 $2.0
$24.5 $3.7
$5.4 $2.5
$22.5 $3.1
$1.4 $0.0
$0.4 $0.0
$45.8 $6.2
$13.4 $3.8
$0.4 $0.0
$17.7 $7.0
$145.5 $28.4
$0.1
$5.0
$3.1
$2.2
$0.2
$2.6
$2.5
$2.5
$3.9
$5.4
$1.8
$2.5
$31.7
$0.1
$23.7
$23.3
$49.7
$14.7
$53.2
$10.3
$4.9
$98.4
$45.0
$3.5
$51.8
$378.6
Source: U.S. EPA analysis, 2002.
B7-3
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Table B7-3 presents total annual facility compliance costs by cost category and steam plant type. The annual compliance costs
under Option 1 range from $2 million for waste facilities to $232 million for oil and gas facilities. Under Option 2, total
annual compliance costs range from $2 million for waste facilities to $189 million for oil and gas facilities
Table B7-3: Annual ized Facility Compliance Costs by Steam Plant Type (in millions, $2001)
Waterbody/Capacity- Based Option
Steam Plant
Type
One-Time Costs
Capital
Technology
Coal
Combined Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
$65.3
$7.6
$67.7
$84.1
$0.7
$0.0
$225.5
Coal
Combined Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
$42.5
$7.6
$38.8
$72.4
$0.7
$0.0
$162.0
Connection
Outage
Recurring Costs
O&M
All Track I (Option 1
$5.3
$0.4
$14.3
$5.4
$0.0
$0.0
$25.5
$58.0
$10.7
$62.3
$110.1
$0.9
$0.0
$242.1
Track I and II (Option
$0.5
$0.4
$5.9
$4.0
$0.0
$0.0
$11.0
$16.9
$10.7
$29.7
$87.2
$0.9
$0.0
$145.5
Energy
Penalty
)
$17.6
$1.3
$27.4
$21.5
$0.2
$0.0
$67.9
2)
$2.1
$1.3
$10.2
$14.7
$0.2
$0.0
$28.4
Permitting
Costs
Total
$18.3
$1.0
$3.4
$11.0
$0.5
$0.1
$34.3
$164.6
$21.1
$175.2
$232.1
$2.3
$0.1
$595.3
$16.5
$0.9
$3.6
$10.3
$0.4
$0.0
$31.7
$78.5
$20.9
$88.2
$188.7
$2.2
$0.0
$378.6
Source: U.S. EPA analysis, 2002.
B7-1.2 Cost-to-Revenue Measure
a. Facility-level analysis
EPA estimates that the cost-to-revenue ratios at the facility-level for both analyzed cases of the waterbody/capacity-based
option are low, similar to the proposed rule. Table B7-4 presents the distribution of facilities by range of the cost-to-revenue
ratio, for both Option 1 and Option 2. Under both options, a vast majority of facilities incur compliance costs of less than one
percent revenues. EPA estimates that under Option 1, 416 facilities, or 76 percent, would incur compliance costs of less than
one percent of revenues; under Option 2, 444 facilities, or 81 percent, would incur compliance costs of less than one percent of
revenues. Under Option 1, 67 facilities, or 12 percent, would incur compliance costs of greater than 3 percent of revenues.
Fifty-one facilities, or 9 percent, would incur compliance costs of greater than 3 percent of revenues under Option 2. For both
options, nine facilities are projected to be baseline closures and the revenues for one facility were unknown.
B7-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Table B7-4: Facility- Level Cost-to-Revenue Measure
Waterbody/Capacity- Based Option
Annualized
Cost-to-Revenue Ratio
< 1.0%
1.0 - 3.0%
>3.0%
Baseline Closure
n/a
Total3
All Track
All Phase II
416
57
67
9
1
550
I (Option 1)
Percent of
Total Phase H
76%
10%
12%
2%
0%
100%
Track I and
All Phase II
444
44
51
9
1
550
H (Option 2)
Percent of
Total Phase H
81%
8%
9%
2%
0%
100%
a Individual numbers may not add up due to independent rounding.
Source: U.S. EPA analysis, 2002.
b. Firm-level analysis
Similar to the proposed rule, EPA estimates that the compliance costs for the waterbody/capacity-based option would also be
low compared to firm-level revenues. Table B7-5 below summarizes the results of the cost-to-revenue measures by the
domestic parent entity types. Under Option 1, 120 of the 131 unique parent entities that own the facilities subject to this rule
would incur compliance costs of less than 1 percent of revenues; six entities would incur compliance costs of between 1 and 3
percent of revenues; three entities would incur compliance costs of greater than 3 percent of revenues; and two entities are
projected to only own facilities that are baseline closures. Under Option 2,101 entities would incur compliance costs of less
than one percent of revenues; 14 entities would incur compliance costs of between 1 and 3 percent of revenues; and 14 entities
would incur compliance costs of greater than 3 percent of revenues. Similar to Option 1, EPA estimates that two entities only
own facilities that are baseline closures under Option 2.
Table B7-5: Firm-Level Cost-to-Revenue Measure
Waterbody/Capacity- Based Option
Annualized
Cost-to-Revenue Ratio
< 1.0%
1.0-3.0%
>3.0%
Baseline Closure
Total
All Track I (Option 1)
. „ _, TT Percent of
All Phase II ,_ , , _, „
Total Phase n
120 92%
6 5%
3 2%
2 2%
131 100%
Track I and
All Phase II
101
14
14
2
131
H (Option 2)
Percent of
Total Phase H
77%
11%
11%
2%
100%
Source: U.S. EPA analysis, 2002.
B7-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-1.3 SBREFA Analysis
The impacts on the small domestic parent entities would be very similar under both cases of the waterbody/capacity-based
option, as presented in Table B7-6. Of the 28 entities EPA identified as small, 24 entities are expected to incur compliance
costs of less than one percent of revenues under Option 1, and 25 entities under Option 2. EPA estimates that two entities
would incur compliance costs of greater than 3 percent of revenues under Option 1. The cost-to-revenue ranges from 0.05 to
4.2 under Option 1. Under Option 2, only one entity is estimated to incur compliance costs of greater than 3 percent of
revenues. The ratios range from 0.04 to 4.1 under this option.
Table B7-6: Impact Ratio Ranges by Small Entity Type
Waterbody/Capacity- Based Option
Type of Entity
Municipality
Municipal Marketing
Authority
Political Subdivision
Rural Electric
Cooperative
Total
All Track I (Option 1)
Impact
Ratio
Ranges
0.2-4.2%
0.05-0.1%
0.6-0.6%
0.1-0.4%
0.05-4.2%
0-1%
15
2
1
6
24
1-3%
2
-
-
-
2
>3%
2
-
-
-
2
Total
19
2
1
6
28
Track I and II (Option 2)
Impact
Ratio
Ranges
0.1-4.1%
0.04-0.1%
0.5-0.5%
0.1-0.4%
0.04-4.1%
0-1%
16
2
1
6
25
1-3%
2
-
-
-
2
>3%
1
-
-
-
1
Total
19
2
1
6
28
Source: U.S. EPA analysis, 2002.
B7-2 IMPINSEMENT MORTALITY AND ENTRAINMENT CONTROLS EVERYWHERE OPTION
(OPTION SA)
This option would require the implementation of technologies that reduce I&E at all Phase II facilities without regard to
waterbody type and with no site-specific compliance option available. EPA would set technology-based performance
requirements under this alternative but would not mandate the use of any specific technology. Unlike the proposed option,
this alternative would not allow for the development of BTA on a site-specific basis (except on a best professional judgment
basis). This alternative would not base requirements on the percent of source water withdrawn or restrict disruption of the
natural thermal stratification of lakes or reservoirs. However, it would impose entrainment performance requirements on
Phase II facilities located on freshwater rivers or streams, and lakes or reservoirs. Finally, under this alternative, restoration
could be used, but only as a supplement to the use of design and construction technologies or operational measures. This
alternative would establish clear performance-based requirements that are simpler and easier to implement than those
proposed and are based on the use of available technologies to reduce AEI.
B7-2.1 Compliance Costs
The estimated total annualized private post-tax cost of compliance for the impingement mortality and entrainment controls
everywhere option is approximately $195 million.
Table B7-7 presents the total annualized private compliance cost by cost category and NERC region. The annualized cost by
NERC region ranges from approximately $76,000 for facilities located in ASCC (Alaska Systems Coordinating Council) to
$45 million for facilities located in SERC (Southwestern Electric Reliability Council). The capital technology cost which
includes the cost of fine-mesh traveling screens and fish handling and return systems comprises $135 million of the total $195
million cost (or 70 percent). The costs of operating and maintenance and permitting are approximately $32 and $29 million,
respectively. The annual energy penalty and one-time connection outage costs are not applicable to this regulatory option
B7-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
because no facilities will be required to reduce intake capacity commensurate with the use of a closed-cycle recirculating
cooling system.
Table B7-7: Private (Post-Tax) Annualized Compliance Costs by NERC Region (in millions, $2001)
Impingement Mortality and Entrainment Controls Everywhere Option
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
One-Time Costs
Capital Connection
Technology Outage
$0.0 $0.0
$21.6 $0.0
$13.0 $0.0
$8.0 $0.0
$1.2 $0.0
$10.5 $0.0
$13.1 $0.0
$5.6 $0.0
$16.5 $0.0
$31.1 $0.0
$5.7 $0.0
$8.4 $0.0
$134.6 $0.0
Recurring Costs
O&M Jnerfhy
Penalty
$0.0 $0.0
$5.1 $0.0
$3.4 $0.0
$2.0 $0.0
$0.2 $0.0
$2.1 $0.0
$2.7 $0.0
$1.3 $0.0
$3.3 $0.0
$8.3 $0.0
$1.5 $0.0
$1.6 $0.0
$31.6 $0.0
Permitting
Costs
$0.1
$5.0
$3.0
$1.8
$0.2
$2.2
$2.5
$2.5
$3.2
$5.1
$1.8
$1.9
$29.2
Total
$0.1
$31.7
$19.3
$11.8
$1.6
$14.8
$18.3
$9.5
$23.0
$44.5
$8.9
$11.9
$195.4
Source: U.S. EPA analysis, 2002.
Table B7-8 presents total annual facility compliance costs by cost category and steam plant type. The annual compliance
costs range from $900,000 for waste facilities to $96 million for coal facilities.
Table B7-8: Annualized Facility Compliance Costs by Steam Plant Type (in millions, $2001)
Impingement Mortality and Entrainment Controls Everywhere Option
Steam Plant
Type
Coal
Combined-
Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
One-Time Costs
Capital Connection
Technology Outage
$64.6 $0.0
$2.2 $0.0
$28.3 $0.0
$39.1 $0.0
$0.3 $0.0
$0.0 $0.0
$134.6 $0.0
Recurring Costs
Permitting
O&M Jnerf Costs
Penalty
$16.0 $0.0 $15.6
$0.6 $0.0 $0.9
$5.8 $0.0 $2.9
$9.1 $0.0 $9.4
$0.1 $0.0 $0.4
$0.0 $0.0 $0.0
$31.6 $0.0 $29.2
Total
$96.2
$3.6
$37.1
$57.7
$0.9
$0.0
$195.4
Source: U.S. EPA analysis, 2002.
B7-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-2.2 Cost-to-Revenue Measure
a. Facility-level analysis
For the impingement mortality and entrainment controls everywhere option, EPA estimates that the compliance costs would
be low compared to facility-level revenues. As shown in Table B7-9, out of the 550 in-scope facilities, 441 would incur
annualized costs of less than one percent of revenues; 63 facilities would incur costs of between 1 and 3 percent; and 34
facilities would incur costs of greater than 3 percent. Eleven facilities are projected to be baseline closures, and for one
facility, revenues are unknown.
Table B7-9: Facility-Level Cost-to-Revenue Measure
Impingement Mortality and Entrainment Controls Everywhere Option
Annualized
Cost-to-Revenue Ratio
<1.0%
1.0-3.0%
> 3.0 %
Baseline Closure
n/a
Total3
All Phase H
441
63
34
11
1
550
Percent of Total Phase
n
80%
11%
6%
2%
0%
100%
a Individual numbers may not add up due to independent rounding.
Source: U.S. EPA analysis, 2002.
b. Firm-level analysis
Compliance costs for the impingement mortality and entrainment controls everywhere option would also be low compared to
firm-level revenues. Of the 131 unique parent entities that own the facilities subject to this rule, 102 entities would incur
compliance costs of less than 1 percent of revenues; 13 entities would incur compliance costs of between 1 and 3 percent of
revenues; and 14 entities would incur compliance costs of greater than 3 percent of revenues. Under the impingement
mortality and entrainment controls everywhere option, two entities own only facilities that are baseline closures. Table B7-10
summarizes these results.
Table B7-10: Firm-Level Cost-to-Revenue Measure
Impingement Mortality and Entrainment Controls Everywhere Option
Annualized
Cost-to-Revenue Ratio
< 1.0%
1.0-3.0%
> 3.0 %
Baseline Closure
Total
All Phase H
102
13
14
2
131
Percent of Total Phase
II
78%
10%
11%
2%
100%
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-2.3 SBREFA Analysis
Under the impingement mortality and entrainment controls everywhere option, the overall annualized compliance costs that
facilities owned by small entities are estimated to incur represent between 0.04 and 12.98 percent of the entities' annual sales
revenues. Table B7-11 presents the distribution of the entities' cost-to-revenue ratios by small entity type. Of the 28 small
entities, two would incur compliance costs of greater than three percent of revenues. Both of these entities are municipalities.
Five entities would incur compliance costs of between one and three percent of revenues, while the remaining 21 entities
would incur compliance costs of less than one percent of revenues.
Table B7-11: Impact Ratio Ranges by Small Entity Type
Impingement Mortality and Entrainment Controls Everywhere Option
Type of Entity
Municipality
Municipal Marketing Authority
Political Subdivision
Rural Electric Cooperative
Total
Impact Ratio Ranges
0.1-13%
0.04-0.3%
0.1-0.1%
0.1-0.6%
0.04-12.98%
0-1%
12
2
1
6
21
1-3%
5
-
-
-
5
>3%
2
-
-
-
2
Total
19
2
1
6
28
Source: U.S. EPA analysis, 2002.
B7-3 ALL COOLING TOWERS OPTION (OPTION 4)
This option would require all Phase II facilities having a design intake flow of 50 million gallons per day (MGD) or more to
reduce the total design intake flow to a level, at a minimum, commensurate with that which can be attained by a closed-cycle
recirculating cooling system. Of the 550 Phase II facilities, 124 already have a recirculating wet cooling system (e.g., wet
cooling towers or ponds). These facilities would meet the requirements under this option unless they are located in areas where
the director or fisheries managers determine that fisheries need additional protection. Therefore, under this option, 426 steam
electric power generating facilities would be required to meet performance standards for reducing impingement mortality and
entrainment based on a reduction in intake flow to a level commensurate with that which can be attained by a closed-cycle
recirculating system.
B7-3.1 Compliance Costs
EPA estimates that the total annualized private post-tax cost of compliance for the all cooling towers option is approximately
$2.32 billion. According to EPA's unit cost estimates, capital costs for individual high-flow plants to convert to wet towers
generally ranged from $130 million to $200 million, with annual operating costs in the range of $4 million to $20 million.
Table B7-12 presents private annualized facility compliance costs by cost category and NERC region. The annualized cost by
NERC region ranges from approximately $1 million for facilities located in ASCC (Alaska Systems Coordinating Council) to
$660 million for facilities located in SERC (Southwestern Electric Reliability Council). The largest cost component would be
the annual operating and maintenance expense which represents $1.1 billion (or 47 percent) of the total cost. EPA estimates the
capital technology cost to be $685 million (or 30 percent) of the total cost. The energy effects associated with the installation of
cooling towers would be $124 million (or 5 percent) for the connection outage and $362 million (or 16 percent) for the recurring
energy penalty. The permitting costs are estimated to be $29 million (or 1 percent) of the total cost. The permitting costs under
this regulatory option would be relatively low since the technology requirements would not include extensive site-specific
determinations on the part of complying facilities.
B7-9
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Table B7-12: Annual ized Facility Compliance Costs by NERC Region (in millions, $2001)
All Cooling Towers Option
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
One-Time Costs
Capital Connection
Technology Outage
$0.4 $0.0
$106.8 $13.4
$58.6 $11.5
$43.2 $7.4
$6.2 $1.1
$59.5 $6.7
$53.3 $6.0
$32.7 $4.8
$99.0 $10.7
$165.3 $51.9
$13.8 $1.3
$45.9 $8.8
$684.7 $123.8
Recurring Costs
O&M Jnerf
Penalty
$0.4 $0.1
$183.4 $52.0
$114.0 $34.4
$74.7 $23.4
$6.3 $2.6
$78.7 $19.2
$80.6 $20.5
$54.4 $15.0
$143.6 $30.8
$299.9 $137.8
$26.4 $5.8
$54.4 $20.4
$1,116.7 $361.9
Permitting
Costs
$0.1
$5.0
$3.0
$1.8
$0.2
$2.2
$2.5
$2.5
$3.2
$5.1
$1.8
$1.9
$29.2
Total
$1.0
$360.6
$221.5
$150.4
$16.5
$166.3
$162.8
$109.5
$287.3
$660.0
$49.1
$131.5
$2,316.4
Source: U.S. EPA analysis, 2002.
Table B7-13 presents total annual facility compliance costs by cost category and steam plant type. The annual compliance costs
range from $5 million for waste facilities to $1.2 billion for coal facilities.
Table B7-13: Annual ized Facility Compliance Costs by Steam Plant Type (in millions, $2001)
All Cooling Towers Option
Steam Plant
Type
Coal
Combined-Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
One-Time Costs
Capital Connection
Technology Outage
$319.7 $62.7
$10.5 $0.9
$166.8 $45.6
$184.9 $14.7
$1.5 $0.0
$1.3 $0.0
$684.7 $123.8
Recurring Costs
O&M Jner^
Penalty
$575.7 $200.6
$17.0 $1.8
$199.3 $94.4
$318.8 $64.6
$2.3 $0.5
$3.6 $0.0
$1,116.7 $361.9
Permitting
Costs
$15.6
$0.9
$2.9
$9.4
$0.4
$0.0
$29.2
Total
$1,174.3
$31.1
$509.0
$592.4
$4.7
$4.9
$2,316.4
Source: U.S. EPA analysis, 2002.
B7-10
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-3.2 Cost-to-Revenue Measure
a. Facility-level analysis
The facility-level costs-to-revenue analysis for the all cooling towers option is presented below. The all cooling towers option
results in high cost-to-revenue ratios at the facility level. This is not unexpected since under this option all in-scope facilities
are required to reduce their intake capacity with the use of closed-cycle recirculating cooling systems. As shown below in
Table B7-14, over 50 percent of the facilities would incur compliance costs of greater than 3 percent of revenues under this
option. Two-hundred forty-one facilities, or 44 percent, would incur compliance costs of less than 3 percent of revenues. Nine
facilities are projected to be baseline closures, and the revenues for one facility remain unknown.
Table B7-14: Facility-Level Cost-to-Revenue Measure
All Cooling Towers Option
Annualized
Cost-to-Revenue Ratio
< 1.0 %
1.0-3.0%
> 3.0 %
Baseline Closure
n/a
Total3
All Phase H
104
137
298
9
1
550
Percent of Total
Phase H
19%
25%
54%
2%
0%
100%
a Individual numbers may not add up due to independent
rounding.
Source: U.S. EPA analysis, 2002.
b. Firm-level analysis
Similar to the facility-level impacts, the cost-to-revenue ratios at the firm-level would also be high under the all cooling towers
option. Thirty-six of the 131 unique domestic-parent entities would incur compliance costs of greater than 3 percent of
revenues. The remaining 93 entities would incur compliance costs of less than 3 percent of revenues. Two of the entities own
only facilities that are baseline closures under the all cooling towers option.
Table B7-15: Firm-Level Cost-to-Revenue Measure
All Cooling Towers Option
Annualized
Cost-to-Revenue Ratio
< 1.0 %
1.0-3.0%
> 3.0 %
Baseline Closure
Total
All Phase H
73
20
36
2
131
Percent of Total
Phase H
56%
15%
27%
2%
100%
Source: U.S. EPA analysis, 2002.
B7-11
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-3.3 SBREFA Analysis
Under the all cooling towers option, EPA estimates that the 28 small entities would incur compliance costs of 0.05 percent to
33.63 percent of revenues. Over 46 percent, or 13 entities, would incur compliance costs of greater than 3 percent of revenues
under the all cooling towers option. Eleven of these entities are municipalities. Table B7-16 presents the distribution of small
entities by their entity type and estimated impact ratios under the all cooling towers option.
Table B7-16: Impact Ratio Ranges by Small Entity Type
All Cooling Towers Option
Type of Entity
Municipality
Municipal Marketing
Authority
Political Subdivision
Rural Electric Cooperative
Total
Impact Ratio
Ranges
0.2-33.6%
0.1-2.4%
0.5-0.5%
0.1-5.9%
0.05-33.63%
0-1%
4
1
1
1
7
1-3%
4
1
3
8
>3%
11
-
-
2
13
Total
19
2
1
6
28
Source: U.S. EPA analysis, 2002.
B7-4 DRY COOLING OPTION (OPTION 5)
The dry cooling option requires all facilities that would install a cooling tower under the waterbody/capacity-based option to
reduce their intake capacity to a level commensurate with the use of a dry cooling system.
B7-4.1 Compliance Costs
EPA estimates that the total annualized private post-tax cost of compliance with the dry cooling option is approximately $1.25
billion.
Table B7-17 presents private annualized facility compliance costs by cost category and NERC region for the dry cooling option.
The annualized cost by NERC region ranges from approximately $0.1 million for facilities located in ASCC (Alaska Systems
Coordinating Council) to $269 million for facilities located in FRCC (Florida Reliability Coordinating Council). The largest
cost component would be the annual energy penalty associated with the dry cooling technology, which represents $554 million
(or 44 percent) of the total cost. The dry cooling technology causes a reduction in unit efficiency due to increased turbine back-
pressure of between 1.0 and 10.1 percent depending on the geographic region and generator type (for more detailed information
on EPA's estimate of energy penalties see Chapter Bl: Summary of Compliance Costs). EPA estimates the annualized capital
technology cost and the annual operating and maintenance cost to be $490 million (or 39 percent) and $156 million (or 12
percent of total costs), respectively. The monthly connection outage and permitting costs are both estimated to be $26 million
(or 2 percent of the total compliance costs).
B7-12
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
Table B7-17: Annualized Facility Compliance Costs by NERC Region (in millions, $2001)
Dry Cooling Option
NERC Region
ASCC
ECAR
ERGOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
One-Time Costs
Capital Connection
Technology Outage
$0.0 $0.0
$15.2 $0.0
$17.2 $0.4
$73.9 $5.4
$14.3 $1.1
$94.6 $3.2
$6.4 $0.0
$2.0 $0.0
$134.4 $4.6
$51.1 $3.5
$1.3 $0.0
$80.0 $7.3
$490.4 $25.5
Recurring Costs
O&M Jnelf
Penalty
$0.0 $0.0
$3.6 $0.0
$7.9 $29.4
$27.0 $160.8
$3.3 $27.7
$29.7 $49.3
$1.4 $0.0
$0.4 $0.0
$41.0 $73.4
$19.5 $105.3
$0.4 $0.0
$22.2 $107.8
$156.3 $553.6
Permitting
Costs
$0.1
$5.0
$2.7
$1.5
$0.1
$1.7
$2.5
$2.5
$2.3
$4.8
$1.8
$1.4
$26.3
Total
$0.1
$23.7
$57.5
$268.5
$46.4
$178.5
$10.3
$4.9
$255.7
$184.2
$3.5
$218.6
$1,252.0
Source: U.S. EPA analysis, 2002.
Table B7-18 presents total annual facility compliance costs by cost category and steam plant type. The annual compliance costs
range from $3 million for waste facilities to $464 million for oil and gas facilities.
Table B7-18: Annualized Facility Compliance Costs by Steam Plant Type (in millions, $2001)
Dry Cooling Option
Steam Plant
Type
Coal
Combined-Cycle
Nuclear
Oil/Gas
Waste
Unspecified
Total
One-Time Costs
Capital Connection
Technology Outage
$118.8 $5.3
$18.2 $0.4
$144.4 $14.3
$207.6 $5.4
$1.4 $0.0
$0.0 $0.0
$490.4 $25.5
Recurring Costs
O&M Jnerf
Penalty
$38.4 $153.3
$6.5 $13.0
$43.7 $210.2
$67.0 $176.2
$0.7 $0.9
$0.0 $0.0
$156.3 $553.6
Permitting
Costs
$15.0
$0.7
$2.3
$7.9
$0.3
$0.0
$26.3
Total
$330.7
$38.9
$414.9
$464.1
$3.3
$0.0
$1,252.0
Source: U.S. EPA analysis, 2002.
B7-13
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-4.2 Cost-to-Revenue Measure
a. Facility-level analysis
The annualized cost-to-revenue ratios at the facility level for the dry cooling option are presented in Table B7-19. The ratios
are higher under the dry cooling option than for the proposed rule. Of the 550 in-scope facilities, 73 facilities are expected to
incur compliance costs of greater than 3 percent of revenues; 41 facilities would incur compliance costs of between 1 and 3
percent of revenues; and 425 facilities would incur compliance costs of less than one percent of revenues. Nine of the facilities
are expected to be baseline closures, and the revenues for one facility remain unknown.
Table B7-19: Facility-Level Cost-to-Revenue Measure
Dry Cooling Option
Annualized
Cost-to-Revenue Ratio
< 1%
1.0-3.0%
> 3.0 %
Baseline Closure
n/a
Total3
All Phase H
425
41
73
9
1
550
Percent of Total
Phase H
77%
7%
13%
2%
0%
100%
a Individual numbers may not add up due to independent rounding
Source: U.S. EPA analysis, 2002.
b. Firm-level analysis
Impacts incurred at the firm level are similar to the facility-level impacts for the dry cooling option. EPA estimates 17 of the
131 unique domestic parent entities, or 13 percent, would incur compliance costs of greater than 3 percent of revenues. The
remaining 112 entities would incur compliance costs of less than 3 percent of revenues under this option. Under the dry cooling
option, two entities own only baseline closure facilities.
Table B7-20: Firm-Level Cost-to-Revenue Measure
Dry Cooling Option
Annualized
Cost-to-Revenue Ratio
<1%
1.0-3.0%
> 3.0 %
Baseline Closure
Total
All Phase H
95
17
17
2
131
Percent of Total
Phase H
73%
13%
13%
2%
100%
Source: U.S. EPA analysis, 2002.
B7-14
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B7: Alternative Options - Costs and Economic Impacts
B7-4.3 SBREFA Analysis
Under the dry cooling option, EPA estimates that the impacts on small entities would be minimal. Only one of the 28 entities
determined to be small would incur compliance costs of greater than three percent of revenues. This one entity is a
municipality. The remaining 27 small entities would incur compliance costs of less than three percent of revenues under the dry
cooling option. The impact ratio ranges by small entity type for the dry cooling option are presented in Table B7-21.
Table B7-21: Impact Ratio Ranges by Small Entity Type Dry Cooling Option
Type of Entity
Municipality
Municipal Marketing Authority
Political Subdivision
Rural Electric Cooperative
Total
Impact Ratio Ranges
0.1-4.1%
0.04-0.1%
0.5-0.5%
0.1-0.4%
0.04-4.1%
0-1%
16
2
1
6
25
1-3%
2
-
-
-
2
>3%
1
-
-
-
1
Total
19
2
1
6
28
Source: U.S. EPA analysis, 2002.
B7-15
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B7: Alternative Options - Costs and Economic Impacts
THIS PAGE INTENTIONALLY LEFT BLANK
B7-16
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
Chapter B8: Alternative Options -
Electricity Market Model Analysis
INTRODUCTION
Chapter B7: Alternative Options - Costs and Economic
Impacts described the total costs and economic impacts of
four of the six alternative regulatory options considered by
EPA. This chapter presents EPA's electricity market
model analysis using ICF Consulting's Integrated Planning
Model (IPM®) for two of those alternative options: (1) the
waterbody/capacity-based option (Option 1), and (2) the
all cooling towers option (Option 4).
CHAPTER CONTENTS
B8-1 Overview of IPM Analysis of Alternative Options . B8-1
B8-2 Market Analysis Level B8-2
B8-3 Analysis of Phase II Facilities B8-12
B8-3.1 Group of Phase II Facilities B8-12
B8-3.2 Individual Phase II Facilities B8-20
B8-4 Uncertainties and Limitations B8-22
References B8-24
Appendix to Chapter B8 B8-26
B8-1 OVERVIEW OF IPM ANALYSIS OF ALTERNATIVE OPTIONS
EPA used the IPM, an integrated energy market model, to analyze two potential effects of the alternative regulatory options:
(1) potential energy effects at the national and regional levels, as required by Executive Order 13211 ("Actions Concerning
Regulations That Significantly Affect Energy Supply, Distribution, or Use"); and (2) potential economic impacts on in-scope
facilities.1 Both alternative options analyzed using the IPM have more stringent compliance technology requirements than the
proposed rule. Specifically, both options would require a subset of existing facilities to install recirculating wet cooling
towers.
Table B8-1 below presents the number and capacity of facilities in each NERC region that EPA estimated would install a
cooling tower under the waterbody/capacity-based option and the all cooling towers option, respectively. The table presents
the percentage of total pre-run capacity in each region that was costed with a cooling tower under the two alternative options.
Pre-run capacity is defined as the current operating, and planned-committed generating units, as identified by ICF. It is used
for this measure, rather than the base case capacity. Since the base case results reflect a post-compliance landscape in which
the effects of cooling tower installation are already modeled, the base case would no longer provide a useful measure of the
magnitude of capacity effected by the alternative options.2
1 Chapter B3: Electricity Market Model Analysis presents a detailed description of the IPM and a discussion of the methodology EPA
used to estimate economic impacts using the IPM.
2 Note that of the 539 surveyed facilities subject to the section 316(b) Phase II Rule, nine are not modeled in the IPM. Three facilities
are in Hawaii, one is in Alaska. Neither state is represented in the IPM. One facility is identified as an "Unspecified Resource" and does
not report on any EIA forms. Four facilities are on-site facilities that do not provide electricity to the grid. The 530 in-scope facilities
modeled by the IPM were weighted to account for facilities not sampled and facilities that did not respond to the EPA's industry survey
and thus represent a total of 540 facilities industry-wide. The results for Phase II facilities in the remainder of this chapter, except where
noted, are based on the 540 weighted facilities.
8-1
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
Table B8-1: Distribution of Cooling Towers in 2008 (MW; by NERC Region)0 b
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
National
Pre-Run
Capacity
124,220
79,590
53,680
67,350
67,520
39,120
81,070
205,310
51,340
172,790
941,990
Waterbody/Capacity-Based Option
f of Facilities
0
4
7
9
0
0
18
5
0
9
52
Pre - Run
Capacity
0
3,840
8,970
9,320
0
0
13,530
7,390
0
12,200
55,250
% of Pre-Run
Capacity
0.0%
4.8%
16.7%
13.8%
0.0%
0.0%
16.7%
3.6%
0.0%
7.1%
5.9%
All Cooling Towers Option
f of Facilities
77
35
23
26
40
39
58
76
18
24
416
Pre-Run
Capacity
54,200
30,650
18,320
19,480
27,350
14,790
35,840
84,590
7,450
19,470
312,140
% of Pre-Run
Capacity
43.6%
38.5%
34.1%
28.9%
40.5%
37.8%
44.2%
41.2%
14.5%
11.3%
33.1%
a Capacities have been rounded to the nearest 10, and percentages have been rounded to the nearest 10th.
b The number of facilities and pre-run capacity under each option have been weighted to account for facilities not sampled and
facilities that did not respond to the EPA's industry survey.
Source: IPM analysis: Section 316(b) Base Case 2000, EPA Analysis 2002.
Waterbody/capacity-based option: Overall, EPA estimates that 54 facilities would install a cooling tower under this option.
Two of these facilities are located in Hawaii, and are therefore not included in the IPM analysis. Table B8-1 shows that 52
facilities in six NERC regions are estimated to be required to install wet cooling towers under this option. In aggregate, these
facilities account for 55,250 MW of capacity or 5.9 percent of the total pre-run capacity. Three regions (FRCC, MAAC, and
NPCC) would be required to install cooling towers on more than 13 percent of total base case capacity.
All cooling towers option: Overall, EPA estimates that 426 facilities would install a cooling tower under this option. Ten of
these facilities are not modeled. In total, 416 facilities across all regions are estimated to install wet cooling towers under this
option, accounting for 312,140 MW of capacity or 33.1 percent of total pre-run capacity. EPA estimates that at least 10
percent of capacity in each region would install cooling towers under this option, and four of the 10 regions would install
cooling towers on more than 40 percent of total base case capacity. ECAR would install cooling towers on the largest
number of facilities (77), and the second largest percentage of capacity (43.6 percent).
B8-2 MARKET ANALYSIS
This section presents the results of the IPM analysis for all facilities modeled by the IPM. The results in this section include
facilities that are in-scope and facilities that are out-of-scope of the proposed Phase II rule. Market level impacts associated
with each of the alternative options are assessed using the following seven impact measures: (1) plant closures, (2) capacity
changes, (3) generation changes, (4) revenue changes, (5) variable production cost changes, (6) fuel cost changes, and (7)
electricity price changes.3 These measures were developed for model run year 2013.4 A detailed description of each of the
impact measures discussed below is presented in Section B3-3.1 of Chapter B3: Electricity Market Mode I Analysis.
3 All of the information presented in section B8-2 is unweighted.
4 The IPM model simulates electricity market function for a period of 25 years. Model output is provided for five user-specified
model run years. EPA selected three run years to provide output across the ten year compliance period for the rule. Analyses of regulatory
options are based on output for model run years that reflect a scenario in which all facilities are operating in their post-compliance
condition. Options requiring the installation of cooling towers are analyzed using output from model run year 2013.
8-2
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
a. Market plant closures
Table B8-2 presents total base case capacity as well as the capacity of plant closures and the percentage of total base case
capacity closed under the two alternative options by NERC region.
Table B8-2: National Capacity of Closure Units by 2013 (MW; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Capacity
122,080
80,230
52,850
65,270
61,380
36,660
74,080
205,210
51,380
173,600
922,740
Waterbody/Capacity-Based Option
Closure Capacity ! % of Base Case
o! 0.0%
o! 0.0%
o! 0.0%
o! 0.0%
o! 0.0%
o! 0.0%
840! 1.1%
o! 0.0%
o! 0.0%
2,170 ! 1.3%
3,010! 0.3%
All Cooling Towers Option
Closure Capacity ! % of Base Case
no! 0.1%
460 ! 0.6%
90 ! 0.2%
(40)! -0.1%
o! 0.0%
o! 0.0%
800! 1.1%
(170)! -0.1%
20! 0.0%
2,370 ! 1.4%
3,640! 0.4%
a Capacities have been rounded to the nearest 10 and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In aggregate, 0.3 percent of total base case capacity closes as a result of this option.
Two regions, NPCC and WSCC, experience closures of existing capacity. Of the 840 MW of capacity that closes in NPCC
(1.1 percent of total base case capacity), 440 MW is oil/gas fired capacity while the remaining 400 MW is nuclear capacity.
In WSCC 2,170 MW of capacity, or 1.3% of the total capacity in the region closes. The vast majority of this capacity, 99
percent (2,150 MW), represents nuclear capacity.
All cooling towers option: Overall, 0.4 percent of total base case capacity closes under this option. Six regions experience
closures of existing capacity. Of the 3,640 MW of total capacity that closes under this option, 2,370 MW (65 percent) occur
in WSCC. This closure represents 1.4 percent of total base case capacity in WSCC. Conversely, two regions, MAAC and
SERC, experience avoided closures as a result of this option. In these regions, facilities that would have closed in the
absence of section 316(b) regulation remain open under this option. This could occur as a result of increases in electricity
prices, which could increase the number of plants that can profitably supply generation, or if a facility's compliance costs are
low relative to other affected facilities.
8-3
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
b. Market capacity
*** Total domestic capacity
Table B8-3 presents the total domestic capacity under the base case and the two alternative regulatory options by NERC
region. The total domestic capacity shows the effects of closures, additions, repowerings, and energy penalties. The change
in capacity associated with each option is expressed as a percentage of total base case capacity.
Table B8-3: National Domestic Capacity in 2013 (MW; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Capacity
122,080
80,230
52,850
65,270
61,380
36,660
74,080
205,210
51,380
173,600
922,740
Waterbody/Capacity-Based Option
Capacity % Change
122,260 0.1%
80,160 -0.1%
52,710 -0.3%
65,170 -0.2%
61,380 0.0%
36,640 -0.1%
73,840 -0.3%
204,970 -0.1%
51,360 0.0%
173,450 -0.1%
921,940 -0.1%
All Cooling Towers Option
Capacity % Change
121,330 -0.6%
79,820 -0.5%
52,580 -0.5%
65,050 -0.3%
61,100 -0.5%
36,410 -0.7%
73,650 -0.6%
204,820 -0.2%
51,320 -0.1%
173,280 -0.2%
919,360 -0.4%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: Overall, there is a reduction in total available capacity of approximately 800 MW, or 0.1
percent of total base case capacity. Therefore, this option would be considered a significant energy action under Executive
Order 13211, and EPA would be required to prepare a Statement of Energy Effects if the Agency proposed this regulatory
option. The largest percentage decrease in capacity occurs in FRCC and NPCC with 0.3 percent of base case capacity. In all
other regions, the capacity reduction is less than 0.2 percent.
All cooling towers option: In aggregate, there is a reduction in total available capacity of approximately 3,380 MW, or 0.4
percent of total base case capacity. Therefore, this option would also be considered a significant energy action, and EPA
would be required to prepare a Statement of Energy Effects if the Agency proposed this regulatory option. The largest
percentage decrease in capacity occurs in MAPP with 0.7 percent of base case capacity.
8-4
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
*** Capacity additions
Table B8-4 presents the total base case capacity as well as the total cumulative capacity additions through 2013, under the
base case and both alternative options by NERC region. For each of these three scenarios, total capacity additions for each
region is expressed as a percentage of total base case capacity. Finally, the difference between capacity additions as a
percentage of total base case capacity for the two regulatory options and base case capacity additions as a percentage of total
base case capacity is calculated and presented in bold.
Table B8-4: National Domestic Capacity Additions in 2013 (MW; by NERC Region)0
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case
Total
Capacity
122,080
80,230
52,850
65,270
61,380
36,660
74,080
205,210
51,380
173,600
922,740
Base Case
Capacity
Additions
12,030
6,990
13,600
7,290
10,750
3,980
7,030
40,660
2,420
14,120
118,870
Additions
as a % of
Total Base
Case
Capacity
9.9%
8.7%
25.7%
11.2%
17.5%
10.9%
9.5%
19.8%
4.7%
8.1%
12.9%
Waterbody /Capacity -Based Option
Capacity
Additions
12,210
6,980
13,590
7,330
10,740
3,960
8,070
40,520
2,410
15,340
121,150
Additions
as a % of
Total Base
Case
Capacity
10.0%
8.7%
25.7%
11.2%
17.5%
10.8%
10.9%
19.7%
4.7%
8.8%
13.1%
Difference
0.1%
0.0%
0.0%
0.1%
0.0%
-0.1%
1.4%
-0.1%
0.0%
0.7%
0.2%
All Cooling Towers Option
Capacity
Additions
14,400
7,280
13,670
7,350
11,320
3,920
8,590
41,520
2,520
15,420
125,990
Additions
as a % of
Total Base
Case
Capacity
11.8%
9.1%
25.9%
11.3%
18.4%
10.7%
11.6%
20.2%
4.9%
8.9%
13.7%
Difference
1.9%
0.4%
0.1%
0.1%
0.9%
-0.2%
2.1%
0.4%
0.2%
0.7%
0.8%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In total, capacity additions as a percentage of base case capacity increases by 0.2
percent under this option as compared to the base case. The two largest increases in this metric occur in NPCC and WSCC,
with increases of 1.4 percent and 0.7 percent, respectively. These increases occur in part due to the closures that are
experienced under this option. MAPP and SERC experience decreases in capacity additions as a percentage of base case
capacity.
All cooling towers option: Overall, capacity additions as a percentage of base case capacity increase by 0.8 percent under the
all cooling tower option as compared to the base case. As was the case under the waterbody/capacity-based option, the
largest increase in this metric occurs in NPCC (2.1 percent). MAPP experiences a decrease in capacity additions as a
percentage of base case capacity of 0.2 percent.
8-5
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
*** Repowering capacity
Table B8-5 presents the total base case capacity as well as total repowered capacity under the base case and both alternative
options by NERC region. For each of the three scenarios total repowered capacity for each region is expressed as a
percentage of total base case capacity. Finally, the difference between repowered capacity as a percentage of total base case
capacity for the two regulatory options and the base case repowered capacity as a percentage of total base case capacity is
calculated and presented in bold.
Table B8-5
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case
Total
Capacity
122,080
80,230
52,850
65,270
61,380
36,660
74,080
205,210
51,380
173,600
922,740
Base Case
Repowered
Capacity
0
1,390
0
1,660
0
0
8,460
0
0
7,020
18,530
National Repowering Capacity in 2013 (MW; by NERC Region)0
Repowering
as a % of
Total Base
Case
Capacity
0.0%
1.7%
0.0%
2.5%
0.0%
0.0%
11.4%
0.0%
0.0%
4.0%
2.0%
Waterbody/Capacity-Based Option
Repowered
Capacity
0
1,410
0
1,640
0
0
7,900
0
0
8,960
19,910
Repowering
as a % of
Total Base
Case
Capacity
0.0%
1.8%
0.0%
2.5%
0.0%
0.0%
10.7%
0.0%
0.0%
5.2%
2.2%
Difference
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
-0.8%
0.0%
0.0%
1.1%
0.2%
All Cooling Towers Option
Repowered
Capacity
0
5,510
0
1,640
0
0
7,730
0
0
7,770
22,650
Repowering
as a % of
Total Base
Case
Capacity
0.0%
6.9%
0.0%
2.5%
0.0%
0.0%
10.4%
0.0%
0.0%
4.5%
2.5%
Difference
0.0%
5.1%
0.0%
0.0%
0.0%
0.0%
-1.0%
0.0%
0.0%
0.4%
0.4%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In aggregate, this option results in a 0.2 percent increase(450 MW) in repowered
capacity as a percentage of total base case capacity relative to the base case. Existing facilities in four NERC regions
experience repowering: WSCC, NPCC, MAAC and ERCOT. Of the 19,910 MW of repowered capacity, 8,960 MW, or 45
percent, is located in WSCC. This region also experiences the largest change in repowered capacity as a percentage of total
base case capacity, increasing by 1.1 percent. NPCC experiences the second largest absolute amount of repowered capacity
with 7,900 MW. However, this represents a 0.8 percent decrease compared to the base case.
All cooling towers option: Overall, repowered capacity as a percentage of total base case capacity increases by 0.4 percent
under this option as compared to the base case. ERCOT experiences the largest change in this metric, increasing 5.1 percent.
As was the case under the waterbody/capacity-based option, WSCC and NPCC are responsible for the majority (68 percent)
of the repowered capacity under this option.
8-6
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
c. Market generation
Table B8-6 presents total generation under the base case and the two alternative regulatory options by NERC region. Total
generation associated with each option is expressed as a percentage of total base case generation. The IPM model, as
specified for this analysis, does not capture changes in demand that may result from electricity price increases associated with
each of the regulatory options.5
Table B8-6: National Generation in 2013 (million MWh; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case
Generation
661
360
199
284
286
187
285
987
228
784
4,261
Waterbody/Capacity-Based Option
Generation % Change
661 0.0%
360 0.0%
199 0.0%
284 -0.2%
286 0.3%
187 0.0%
285 -0.1%
987 0.0%
228 0.0%
784 0.0%
4,261 0.0%
All Cooling Towers Option
Generation % Change
660 -0.2%
360 0.0%
199 0.0%
288 1.1%
285 -0.3%
186 -0.3%
284 -0.7%
988 0.0%
229 0.4%
784 0.0%
4,261 0.0%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: While there is no change in total generation under this option, there is a minor
redistribution of generation among regions. The largest increase in generation occurs in MAIN, at 0.3 percent while MAAC
experiences a decrease of 0.2 percent.
All cooling towers option: While there is no change in total generation under this option, there is a redistribution of
generation among regions. MAAC experiences a 1.1 percent increase in total generation while NPCC experiences a decrease
of 0.7 percent.
Section B3-6 of Chapter B3: Electricity Market Model Analysis presents a detailed discussion of this assumption.
8-7
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
d. Market revenues
Table B8-7 presents the base case revenues, as well as total revenues under the each of the alternative options and the percent
change in revenues between the base case and the two alternative options by NERC region.
Table B8-7: National Revenues in 2013 (in millions, $2001; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Revenues
22,180
12,060
7,840
10,960
9,960
5,960
11,020
34,360
7,750
24,840
146,930
Waterbody/Capacity-Based Option
Revenues % Change
22,190 0.0%
12,060 0.0%
7,820 -0.3%
10,940 -0.2%
9,980 0.2%
5,960 0.0%
11,280 2.4%
34,360 0.0%
7,750 0.0%
24,890 0.2%
147,230 0.2%
All Cooling Towers Option
Revenues % Change
22,440 1.2%
12,090 0.2%
7,810 -0.4%
11,070 1.0%
10,000 0.4%
5,990 0.5%
11,330 2.8%
34,450 0.3%
7,770 0.3%
24,880 0.2%
147,830 0.6%
a Revenues have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In aggregate, total revenues increase by 0.2 percent under this option. Since generation
is fixed, the overall increase in revenues is due price increases (Tables B8-10 and B8-11). Five of the ten regions experience
a change in this metric. The largest change in revenues occurs in NPCC, which experiences an increase of 2.4 percent. As
generation would remain virtually unchanged in this region, the increase in capacity prices presented in Table B8-11 is the
most likely explanation for this increase in revenues. The largest decrease in revenues, 0.3 percent, occurs in FRCC. With
stable generation and an increase in energy price in this region, this reduction is caused by the decrease in capacity prices (see
Table B8-11).
All cooling towers option: Overall, this option results in a 0.6 percent increase in total revenues. As is the case under the
waterbody/capacity-based option, the largest increase (2.8 percent) occurs in NPCC, while the only decrease (0.4 percent)
occurs in FRCC. The results presented in Table B8-11 suggest that changes in capacity prices are likely be responsible for
these changes in revenues.
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
e. Market variable production costs
Table B8-8 presents the variable production costs for the base case as well as production costs and percentage change in base
case production costs under each of the two alternative regulatory options by NERC region. Variable production costs
include fuel and other variable O&M costs and are the primary determinant of when and how often a plant's generation units
are dispatched.
Table B8-8: National Variable Production Costs/MWh Generation in 2013
(in millions, $2001; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Base Case
Production Costs
11.90
17.27
18.17
13.06
12.22
11.20
17.88
12.73
13.63
11.66
Waterbody/Capacity-Based Option
Production Costs % Change
11.90 0.0%
17.27 0.0%
18.25 0.4%
13.15 0.7%
12.25 0.2%
11.20 0.0%
17.98 0.5%
12.74 0.1%
13.63 0.0%
11.89 1.9%
All Cooling Towers Option
Production Costs % Change
12.19 2.4%
17.33 0.3%
18.31 0.7%
13.29 1.8%
12.50 2.3%
11.32 1.0%
18.07 1.0%
12.89 1.2%
13.70 0.5%
11.89 1.9%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: This option increases variable production costs in six of the ten NERC regions under
this option while remaining unchanged in the other four. The largest increase in variable production costs occurs in WSCC,
which experiences a 1.9 percent increase. The most likely cause for this increase is the economic closure of 2,170 MW of
existing capacity that occurs in this region (see Table B8-2). Of the total closures in this region, 2,150 MW comes from
nuclear capacity, a low-cost source of generation. Although new capacity comes online in the form of capacity additions and
repowerings (see Tables B8-4 and B8-5), the new capacity is in the form of combined-cycle and combustion turbine capacity,
prime movers that have higher average variable production costs than the existing nuclear capacity being replaced. As a
result, the average production cost per MWh of generation for the region increases.
Only two other NERC regions experience an increase in production costs of 0.5 percent or more, MAAC and NPCC, with
increases of 0.7 percent and 0.5 percent respectively. These increases could be associated with an increase in variable O&M
costs at facilities that are estimated to install recirculating wet cooling towers under this option. As shown in Table B8-1, a
relatively high percentage of base case capacity in these regions are required to install recirculating wet cooling towers under
this option.
All cooling towers option: This option increases variable production costs per MWh of generation in each of the ten NERC
regions with seven regions experiencing increases of 1 percent or more. The two largest impacts in this measure occur in
ECAR and MAIN, where the production costs increase by 2.4 percent and 2.3 percent, respectively. This result is not
surprising given that approximately 40 to 45 percent of base case capacity in each of these regions is estimated to install
recirculating wet cooling towers under this option (see Table B8-1).
8-9
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
f. Market fuel costs
Table B8-9 presents the base case fuel costs, as well as fuel costs under the two alternative options, and the percent change in
fuel costs between the base case and the options by NERC region.
Table B8-9: National Fuel Costs/MWh Generation in 2013
(in millions, $2001; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Base Case Fuel
Costs
9.46
15.24
16.26
11.01
10.17
9.15
16.56
10.87
11.77
10.14
Waterbody/Capacity-Based Option
Fuel Costs % Change
9.45 -0.1%
15.24 0.0%
16.35 0.6%
11.11 0.8%
10.20 0.3%
9.14 0.0%
16.67 0.6%
10.88 0.1%
11.77 0.0%
10.39 2.5%
All Cooling Towers Option
Fuel Costs % Change
9.76 3.2%
15.33 0.6%
16.42 1.0%
11.26 2.2%
10.47 2.9%
9.26 1.2%
16.76 1.2%
11.03 1.5%
11.85 0.7%
10.40 2.6%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: Seven of the ten NERC regions experience a change in fuel cost as a result of this
option. The largest increase in fuel costs per MWh of generation occurs in WSCC at 2.5 percent. This increase occurs in part
due to the nuclear facility closure. Since regional demand for generation does not change, new and repowered combined
cycle and combustion turbine capacity comes on-line. This capacity, and its subsequent generation, increases the demand on
the fuel supply, increasing the cost of fuel in the region. No other region experiences an increase in fuel costs of more than
0.8 percent. One region, ECAR, experiences a decrease of 0.1 percent.
All cooling towers option: The cost of fuel increases in each of the ten NERC regions under this option. These increases
exceed 1.0 percent in all but two regions, ERCOT and SPP. ECAR and MAIN experience the greatest impact in this measure
as fuel costs per MWh of generation increase by 3.2 percent and 2.9 percent, respectively.
B8-10
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
g. Market electricity prices
Table B8-10 presents base case energy prices as well as energy prices and the percent change under each of the two
alternative options, by NERC region. Table B8-11 presents the same information for capacity prices in each region.
Table B8-10: Energy Prices in 2013 ($2001 per KWh; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Base Case Energy
Prices
23.12
26.88
29.21
26.98
22.95
21.68
30.84
24.64
23.95
26.25
Waterbody/Capacity-Based Option
Energy Prices % Change
23.13 0.0%
26.89 0.0%
29.36 0.5%
27.15 0.6%
22.97 0.1%
21.69 0.0%
30.76 -0.3%
24.65 0.0%
23.95 0.0%
26.21 -0.1%
All Cooling Towers Option
Energy Prices % Change
23.54 1.8%
27.00 0.4%
29.52 1.1%
27.14 0.6%
23.16 0.9%
21.70 0.1%
30.87 0.1%
24.74 0.4%
24.02 0.3%
26.27 0.1%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: The average annual price received for the sale of electricity remains unchanged in five
NERC regions under this option. In three regions (FRCC, MAAC, and MAIN), it increases, and in two regions (NPCC and
WSCC), it decreases. The two largest increases in energy prices occur in MAAC (0.6 percent) and FRCC (0.5 percent). All
other things being equal, energy prices increase with an increase in the variable production costs of the last unit to be
dispatched. Table B8-8 showed that MAAC and FRCC both experience an increase in variable production costs associated
with a relatively high percentage of base case capacity that is estimated to install recirculating wet cooling towers under this
option (see Table B8-1). Energy prices decrease in NPCC and WSCC despite increases in both production and fuel costs.
This result is counter-intuitive but is due to the fact that each NERC region in the IPM consists of several subregions. For
example, NPCC consists of five sub-regions. Energy prices increase in four of the five sub-regions but decrease in the largest
sub-region. This decrease outweighs the increases in the other sub-regions while the other four sub-regions are dominant in
determining the average fuel and production costs in NPCC.
All cooling towers option: Energy prices increase in each of the ten NERC regions under this option, with the largest
increases of 1.8 percent and 1.1 percent occurring in ECAR and FRCC, respectively. As indicated above, an increase in
energy prices results from an increase in variable production costs. Table B8-8 showed that variable production costs
increase for all 10 NERC regions under this option.
8-11
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
Table B8-11: Capacity Prices in 2013 ($2001 per KW per year; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Base Case Capacity
Prices
56.62
29.93
38.52
50.40
55.63
52.64
32.57
48.98
44.83
26.81
Waterbody/Capacity-Based Option
Capacity Prices % Change
56.53 -0.2%
29.86 -0.2%
37.77 -2.0%
49.63 -1.5%
55.57 -0.1%
52.59 -0.1%
36.86 13.2%
48.96 0.0%
44.81 0.0%
27.34 2.0%
All Cooling Towers Option
Capacity Prices % Change
57.02 0.7%
29.91 -0.1%
37.06 -3.8%
50.28 -0.2%
55.80 0.3%
54.19 3.0%
37.98 16.6%
48.96 0.0%
44.52 -0.7%
27.08 1.0%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: The majority of NERC regions experience a reduction in capacity prices. Only two
regions, NPCC and WSCC, experience an increase. The largest increase in capacity price occurs in NPCC (13.2 percent).
This increase is likely the result of the decrease in total available capacity in this region, in part due to the closure of existing
capacity (see Table B8-2) while generation, or demand for electricity, remains stable. This combination of factors suggests
that a higher percentage of existing capacity is required to meet demand in this region. As such, facilities that are not
dispatched under the base case, and thus are available for reserves, are dispatched under this option. As a result, less capacity
would be available for reserves and capacity price increases.
All cooling towers option: All but one NERC region experiences a change in capacity prices under this option. As was the
case under the waterbody/capacity-based option, the largest increase in capacity prices occurs in NPCC (16.6 percent), and
the largest decrease in capacity prices occurs in FRCC (3.8 percent). No other region experiences increases or decreases of
this magnitude in capacity prices under this option.
B8-3 ANALYSIS OF PHASE II FACILITIES
This section presents the results of the IPM analysis for the Phase II facilities that are modeled by the IPM. Fifteen of the 540
Phase II facilities are identified as baseline closures, and are therefore not represented in these results. (In some cases, a
facility that is a closure in the base case is operational in the post-compliance run. Such facilities are not represented in the
base case but would be represented in the post-compliance scenario.) Except where noted, the results in this section therefore
reflect the 525 weighted, non-closure, Phase II facilities modeled by the IPM.
EPA used the IPM results to analyze impacts on Phase II facilities at two levels: (1) potential changes in the economic and
operational characteristics of the group of Phase II facilities and (2) potential changes to individual facilities within the group
of Phase II facilities. It should be noted that the results of both analyses only include the steam electric components of the
Phase II facilities and thus do not provide complete measures for in-scope facilities that also operate non-steam electric
generation, which is not subject to this rule.
B8-3.1 Group of Phase II Facilities
This section presents the analysis of the potential impacts of each of the two alternative options on the group of Phase II
facilities. Section B3-3.2 of Chapter B3: Electricity Market Model Analysis presents a detailed discussion of the seven impact
measures developed using IPM output from model run year 2013 and used to assess potential changes in the economic and
operational characteristics of this group of facilities.
8-12
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
a. Phase II plant closures
Table B8-12 presents the number of operational Phase II facilities under the base case and, for the two alternative options, the
number and percent of total Phase II facilities that would close by NERC region. Table B8-13 presents the base case capacity
of Phase II facilities and the capacity of closures under each option by NERC region. The table also presents capacity of
closures expressed as a percentage of total base case Phase II capacity.
Table B8-12: Number of Facilities with Closure Units in 2013 (by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Facilities
99
51
30
41
47
42
54
95
32
33
525
Waterbody/Capacity-Based Option
Closures % Change
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
-1 -1.9%
0 0.0%
0 0.0%
2 6.0%
1 0.2%
All Cooling Towers Option
Closures % Change
1 1.0%
1 2.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
1 3.1%
2 6.0%
5 1.0%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Table B8-13: Capacity of Closure Units by 2013 (MW; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Phase II
Capacity
78,680
42,330
24,460
30,310
33,650
14,900
36,360
100,780
19,990
30,110
411,570
Waterbody/Capacity-Based Option
Closure Capacity % of Total
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
0 0.0%
650 1.8%
0 0.0%
0 0.0%
2,170 7.2%
2,820 0.7%
All Cooling Towers Option
Closure Capacity % of Total
2,060 2.6%
420 1.0%
0 0.0%
0 0.0%
490 1.5%
0 0.0%
720 2.0%
0 0.0%
20 0.1%
2,170 7.2%
5,880 1.4%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
8-13
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options - Electricity Market Model Analysis
Waterbody/capacity-based option: Table B8-12 shows that two regions, NPCC and WSCC, experience a change in closures
of Phase II facilities as a result of this option. One fewer facility would close in NPCC in comparison to the base case: two
facilities that would have retired in the baseline remain operational under the analyzed option while another, with higher post-
compliance production costs, would close. As the total capacity of the single facility expected to close under this option
exceeds that of the two avoided closures, NPCC experiences a net reduction of 650 MW, or 1.8 percent of baseline Phase II
capacity . The largest reduction in baseline Phase II capacity occurs in WSCC where one large nuclear and one small oil/gas
facility, accounting for 7.2 percent of total base case Phase II capacity, closes under this option.
All cooling towers option: A total of five Phase II facilities from four NERC regions (ECAR, ERCOT, SPP and WSCC)
accounting for 5,880 MW, or 1.4 percent of base case Phase II capacity, closes under this option. The largest closures would
occur in WSCC and ECAR where 7.2 percent (2,170 MW) and 2.6 percent (2,060 MW) respectively of base case Phase II
capacity would close.
8-14
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
b. Phase II non-dispatch facilities
Table B8-14 presents the total base case capacity, as well as total non-dispatched capacity under the base case and both
alternative options by NERC region. For each of these three scenarios total non-dispatched capacity is expressed as a
percentage of total base case capacity in the region. The difference between total non-dispatched capacity as a percentage of
total base case capacity for each of the regulatory options and total base case non-dispatched capacity as a percentage of total
base case capacity is calculated and presented in bold.
Table B8-14: Capacity of Non-Dispatch Facilities in 2013 (MW; by NERC Region)0
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Total Base
Case
Capacity
78,680
42,330
24,460
30,310
33,650
14,900
36,360
100,780
19,990
30,110
411,570
Base Case
Capacity of
Non-
Dispatch
Facilities
190
5,830
7,800
2,070
2,760
330
7,690
5,060
2,130
4,290
38,150
Non-
Dispatch
Capacity as
a%of
Total
0.2%
13.8%
31.9%
6.8%
8.2%
2.2%
21.2%
5.0%
10.7%
14.2%
9.3%
Waterbody/Capacity-Based Option
Non-
Dispatch
Capacity
190
5,790
6,540
2,070
2,760
330
7,570
6,100
2,130
5,390
38,870
Non-
Dispatch
Capacity as
a%of
Total
0.2%
13.7%
26.7%
6.8%
8.2%
2.2%
20.8%
6.1%
10.7%
17.9%
9.4%
Difference
0.0%
-0.1%
-5.2%
0.0%
0.0%
0.0%
-0.3%
1.0%
0.0%
3.7%
0.2%
All Cooling Towers Option
Non-
Dispatch
Capacity
190
5,740
7,700
2,070
2,760
320
6,980
6,750
2,080
5,740
40,330
Non-
Dispatch
Capacity as
a%of
Total
0.2%
13.6%
31.5%
6.8%
8.2%
2.1%
19.2%
6.7%
10.4%
19.1%
9.8%
Difference
0.0%
-0.2%
-0.4%
0.0%
0.0%
-0.1%
-2.0%
1.7%
-0.3%
4.8%
0.5%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In total, non-dispatched capacity as a percentage of base case capacity increases by 0.2
percent under this option. By far the largest increase in this metric occurs in WSCC (3.7 percent). This result suggests that
Phase II facilities in this region become less competitive and are dispatched less frequently as a result of this option. The
increase in the variable production costs of Phase II facilities shown in Table B8-18 supports this finding. The largest
decrease in non-dispatched capacity as a percentage of base case capacity occurs in FRCC (5.2 percent). This reduction
implies that a higher percentage of Phase II capacity would be dispatched under this option relative to the base case, despite
the increased production cost of these facilities (see Table B8-18). This difference is due to one large oil/gas facility that is
not dispatched under the baseline, but is dispatched under the option.
All cooling towers option: Overall, non-dispatched capacity as a percentage of base case capacity increases by 0.5 percent
under this option. As was the case under the waterbody/capacity-based option, the largest increase occurs in WSCC (4.8
percent) due most likely to the increased variable production costs of Phase II facilities in this region (see Table B8-18). The
largest decrease in non-dispatched capacity as a percentage of base case capacity occurs in NPCC (2.0 percent).
8-15
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
c. Phase II capacity
Table B8-15 presents the total Phase II capacity under the base case and each of the alternative regulatory options by NERC
region. Total Phase II capacity associated with each option is expressed as a percentage of total base case Phase II capacity.
Table B8-15: Capacity in 2013 (MW; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Capacity
78,680
42,330
24,460
30,310
33,650
14,900
36,360
100,780
19,990
30,110
411,570
Waterbody/Capacity-Based Option
Capacity
78,680
42,270
24,330
30,180
33,650
14,900
35,220
100,680
19,990
27,540
407,440
% Change
0.0%
-0.1%
-0.5%
-0.4%
0.0%
0.0%
-3.1%
-0.1%
0.0%
-8.5%
-1.0%
All Cooling Towers Option
Capacity
75,690
41,400
24,200
30,030
32,790
14,700
34,500
99,540
19,840
26,280
398,970
% Change
-3.8%
-2.2%
-1.1%
-0.9%
-2.6%
-1.3%
-5.1%
-1.2%
-0.8%
-12.7%
-3.1%
a Capacities have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In aggregate, this option results in a reduction in Phase II capacity of 4,130 MW, or 1.0
percent. A majority of the decrease (2,820 MW) is due to closures. The residual 1,310 MW is due to energy penalties.
Capacity decreases in six NERC regions, while remaining unchanged the other four. The two largest reductions in this metric
occur in WSCC and NPCC, which experience reductions of 8.5 percent and 3.1 percent of base case capacity, respectively.
In both regions, the majority of this reduction in available capacity is associated with the economic closure of existing Phase
II facilities (see Table B8-13).
All cooling towers option: Overall, there is a reduction in available capacity of approximately 12,600 MW, or 3.1 percent of
total base case capacity. Of the 12,600 MW, 5,880 (47 percent) are due to closures. The residual 6,720 MW is due to energy
penalties. The three largest reductions occur in WSCC (12.7 percent), NPCC (5.1 percent), and ECAR (3.8 percent). As was
the case under the waterbody/capacity-based option, the majority of this reduction in available capacity is associated with the
economic closure of existing Phase II facilities (see Table B8-13).
8-16
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
d. Phase II generation
Table B8-16 presents the base case generation, and total generation under each of the two alternative options and the percent
change in generation between the base case and each option by NERC region.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-16:
Base Case
Generation
521
153
80
171
216
105
158
630
110
145
2,290
Generation in 2013 (Million MWh; by
Waterbody/Capacity-Based Option
Generation % Change
521 0.0%
153 0.0%
78 -3.3%
169 -1.3%
216 0.0%
105 0.0%
149 -5.5%
630 -0.1%
110 0.0%
118 -18.8%
2,249 -1.8%
NERC Region)0
All Cooling Towers Option
Generation % Change
510 -2.1%
147 -4.1%
77 -4.1%
167 -2.3%
211 -2.5%
104 -1.3%
142 -10.1%
621 -1.5%
109 -1.2%
100 -30.9%
2,188 -4.5%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In aggregate, generation decreases by 1.8 percent as a result of this option. The two
largest reductions are experienced in WSCC (18.8 percent) and NPCC (5.5 percent). These decreases in generation are most
likely attributable to the reductions in capacity resulting from closures and the energy penalty, and the increased variable
production costs of non-closure Phase II facilities that occur in these two regions under this option (see Tables B8-15 and
B8-18).
All cooling towers option: Overall, this option results in a 4.5 percent decrease in generation. While every region
experiences a reduction in this metric, the two largest reductions occur in WSCC (30.9 percent) and NPCC (10.1 percent). As
was the case under the waterbody/capacity-based option, these reductions are likely due to reductions in available capacity
and increased production costs of non-closure Phase II facilities (see Tables B8-15 and B8-18).
8-17
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
e. Phase II revenues
Table B8-17 presents total Phase II revenues under the base case and each of the two alternative regulatory options by NERC
region. Revenues associated with each option are also expressed as a percentage of total base case revenues.
Table B8-17: Revenues in 2013 (in millions, $2001; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Base Case Revenues
16,370
5,440
3,240
6,070
6,730
3,020
5,980
20,190
3,450
4,880
75,370
Waterbody/Capacity-Based Option
Revenues % Change
16,370 0.0%
5,430 -0.2%
3,170 -2.2%
6,020 -0.8%
6,730 0.0%
3,020 0.0%
5,790 -3.2%
20,180 0.0%
3,450 0.0%
4,040 -17.2%
74,200 -1.6%
All Cooling Towers Option
Revenues % Change
16,200 -1.0%
5,260 -3.3%
3,140 -3.1%
5,990 -1.3%
6,610 -1.8%
3,010 -0.3%
5,600 -6.4%
19,990 -1.0%
3,420 -0.9%
3,510 -28.1%
72,730 -3.5%
a Revenues have been rounded to the nearest 10, and percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: In total, there is a reduction in revenues of 1.6 percent associated with this option.
Revenues decrease in five NERC regions and remain unchanged in the others. The two largest reductions in revenues occur
in WSCC (17.2 percent) and NPCC (3.2 percent). The reduction in generation and price shown in Tables B8-16 and B8-10,
respectively, are likely the principal cause for the reductions in revenues in these regions.
All cooling towers option: Every NERC region experiences a reduction in revenues as a result of this option. In aggregate,
these reductions account for 3.5 percent of base case revenues. As was the case under the waterbody/capacity option, the two
largest reductions in revenues occur in WSCC (28.1 percent) and NPCC (6.4 percent), the two regions with the largest
reductions in generation under this option (see Table B8-16). The reductions in generation and price shown in Tables B8-16
and B8-10, respectively, are the likely cause for the reductions in revenues in these regions.
B8-18
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
f. Phase II variable production costs
Table B8-18 presents the base case variable production costs per MWh of generation, as well as variable production costs
under the each of the two alternative options and the percent change in variable production costs between the base case and
each of the two alternative options by NERC region.
Table B8-18: Variable Production Costs/MWh Generation in 2013
(in millions, $2001; by NERC Region)0
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Base Case
Production Costs
11.59
15.67
15.21
11.43
11.30
11.04
18.43
11.16
12.13
16.83
Waterbody/Capacity-Based Option
Production Costs % Change
11.58 -0.1%
15.68 0.0%
15.32 0.7%
11.43 0.0%
11.30 0.0%
11.04 0.0%
18.39 -0.2%
11.16 0.0%
12.13 0.0%
17.48 3.9%
All Cooling Towers Option
Production Costs % Change
11.75 1.4%
15.60 -0.5%
15.32 0.8%
11.32 -1.0%
11.46 1.4%
11.19 1.3%
18.38 -0.3%
11.27 1.0%
12.15 0.1%
17.26 2.6%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: Four NERC regions experience a change in variable production costs per MWh of
generation under this option. The largest increase occurs in WSCC (3.9 percent). This increase is most likely attributable to
the increase in production costs of non-closure Phase II facilities, and the economic closure of Phase II capacity. The
majority of the 2,170 MW of closed capacity in the WSCC region listed in Table B8-13, is relatively low cost nuclear
capacity. The elimination of low cost nuclear capacity from the group of Phase II facilities in this region increases the
average variable production cost for the group in this region. In NPCC, the economic closure of relatively high cost oil and
gas fired capacity is most likely responsible for the 0.2 percent reduction invariable production costs of Phase II facilities.
All cooling towers option: Seven NERC regions experience an increase in variable production costs under this option while
the remaining three see a decrease in this metric. As was the case under the waterbody/capacity-based option, data presented
in Table B8-13 suggest the economic closure of low cost nuclear capacity in WSCC is most likely responsible for the largest
increase in variable production costs per MWh (2.6 percent). The largest decrease in variable production costs would occur
in ERCOT, at 0.5 percent.
8-19
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
g. Phase II fuel costs
Table B8-19 presents the base case fuel costs as well as fuel costs under the two alternative options and the percent change in
fuel costs between the base case and the two options by NERC region.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Table
Base Case Fuel
Costs
9.13
12.89
12.80
9.28
9.06
8.99
16.73
9.01
9.90
14.72
B8-19: Fuel Costs/MWh Generation in
(in millions, $2001; by NERC Region)0
Waterbody/Capacity-Based Option
Fuel Costs % Change
9.13 -0.1%
12.89 0.1%
12.92 0.9%
9.27 -0.1%
9.06 0.0%
8.99 0.0%
16.67 -0.3%
9.01 0.0%
9.90 0.0%
15.35 4.3%
2013
All Cooling Towers Option
Fuel Costs % Change
9.29 1.7%
12.82 -0.5%
12.96 1.2%
9.18 -1.1%
9.22 1.8%
9.13 1.5%
16.64 -0.6%
9.12 1.3%
9.91 0.1%
14.97 1.7%
a Percent changes have been rounded to the nearest 10th.
Source: IPM analysis: model runs for Section 316(b) Base Case, Waterbody/Capacity-Based Option, and All Cooling Towers Option.
Waterbody/capacity-based option: Six of the ten NERC regions experience a change in fuel cost per MWh of generation as
a result of this option. This increase occurs in part due to the nuclear facility closure. Since total regional demand for
generation does not change (Table B8-6), new and repowered combined cycle and combustion turbine capacity comes on-line
(Tables B8-4 and B8-5). This capacity, and its subsequent generation, increases the demand on the fuel supply, increasing
the cost of fuel in the region. The largest increase in fuel costs occurs in WSCC (4.3 percent) while the largest decrease
occurs in NPCC (0.3 percent).
All cooling towers option: Fuel cost per MWh of generation changes in each of the ten NERC regions under this option.
The largest increases in fuel cost per MWh of generation occur in MAIN (1.8 percent), ECAR (1.7 percent), and WSCC (1.7
percent). The largest decrease in fuel costs occurs in MAAC, (at 1.1 percent).
B8-3.2 Individual Phase II Facilities
In addition to effects of the two alternative options in the group of Phase II facilities, there may be shifts in economic
performance among individual facilities subject to section 316(b) regulation. To assess potential distributional effects, EPA
analyzed facility-specific changes in net generation, production costs, capacity utilization, revenue, and operating income.
For each measure, EPA determined the number of Phase II facilities that experience an increase or a reduction within three
ranges: 0 to 1 percent, 1 to 3 percent, and 3 percent or more. Excluded from this analysis were facilities experiencing
significant structural changes as a result of a policy option, including partial or full closures, avoided closures, or repowering.
Tables B8-20 and B8-21 present the total number of Phase II facilities with different degrees of change in each of these
measures under the waterbody/capacity-based and all cooling towers options.
B8-20
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
Table B8-20: Operational Changes at Phase II Facilities from
the Waterbody/Capacity- Based Option (2013)° b
Economic Measures
Change in Net Generation
Change in Variable Production Costs
Change in Capacity Utilization
Change in Total Revenue
Change in Operating Income
Reduction
0-1%
7
6
10
57
75
1-3%
17
5
7
43
42
>3%
21
1
12
17
10
Increase
0-1%
4
13
7
48
46
1-3%
4
16
3
15
15
>3%
9
3
5
20
22
No Change
444
380
462
306
296
a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a
percent.
b Of the 540 Phase II facilities, 34 would experience a significant structural change as a result of the rule, and are therefore excluded
from this analysis. Of the remaining 506 facilities, 82 facilities had zero generation in either the base case or post compliance
scenario. It was therefore not possible to calculate the change in variable production costs for these facilities. As a result, the
number of facilities adds up to 424 instead of 506 for this measure.
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-20 indicates that the majority of Phase II facilities do not experience changes in generation, production costs, or
capacity utilization due to compliance with the waterbody/capacity-based option. Of those facilities with changes in post-
compliance generation and capacity utilization, most experience decreases in these measures. In addition, while
approximately 40 percent of Phase II facilities experience an increase or decrease in revenues and/or operating income, the
magnitude of such changes are small.
Table B8-21: Operational Changes at Phase II Facilities from
the All Cooling Towers Option (2013)° b
Economic Measures
Change in Net Generation
Change in Variable Production Costs
Change in Capacity Utilization
Change in Total Revenue
Change in Operating Income
Reduction
0-1%
18
16
15
154
118
1-3%
251
12
25
121
160
>3%
53
4
25
55
50
Increase
0-1%
^
64
8
88
83
1-3%
4
257
12
39
47
>3%
22
17
15
35
29
No Change
151
51
402
10
15
a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a
percent.
B Of the 540 Phase II facilities, 38 would experience a significant structural change as a result of the rule, and are therefore excluded
from this analysis. Of the remaining 502 facilities, 81 facilities had zero generation in either the base case or post-compliance
scenario. It was therefore not possible to calculate the change in variable production costs for these facilities. As a result, the
number of facilities adds up to 421 instead of 502 for this measure.
Source: IPM analysis: model runs for Section 316(b) base case and all cooling towers option.
Table B8-21 indicates that under the all cooling towers option, more facilities would experience changes in their operations
and economic performance than under the waterbody/capacity-based option. For example, 322 out of 502 facilities, or 64
8-21
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
B8: Alternative Options - Electricity Market Model Analysis
percent, experience a reduction in generation.6 In addition, 328 facilities experience a reduction in operating income while
338 facilities see their production cost per MWh increase. However, some facilities benefit from regulation under this option:
162 facilities experience an increase in revenues and 159 experience an increase in operating income.
B8-4 UNCERTAINTIES AND LIMITATIONS
EPA has identified uncertainties and limitations associated with the electricity market model analysis of the
waterbody/capacity-based option and the all cooling towers option. These uncertainties and limitations are discussed below.
Capacity Utilization Assumption Used in IPM Analysis: EPA estimated compliance responses for in-scope facilities and
developed compliance costs using capacity utilization rates from EIA data sources (average 1995-1999 generation from Form
EIA-906; average 1995-1999 capacity from Forms EIA-860A and 860B). However, this capacity utilization rate does not
always match the rate projected by the IPM for run year 2008. A discrepancy between the rates from the two data sources
may lead to an overestimation or underestimation of economic impacts and/or energy effects in the market model analysis
using the IPM.
Facilities with a capacity utilization rate of less than 15 percent would be subject to less stringent compliance requirements
under the proposed rule and the two analyzed alternative regulatory options, partially because stringent compliance
requirements, and high compliance costs, are not required if the facility is used on an intermittent basis only. Economically, a
low utilization rate means lower revenues as the facility generates and sells less electricity (this fact is somewhat mitigated by
the presence of capacity revenues in the IPM). Using a capacity utilization rate from EIA sources could introduce two types
of errors in the economic impact analysis based on the IPM. These errors arise from the following two scenarios: (1) A
facility was costed with less stringent compliance requirements because its EIA capacity utilization rate is less than 15
percent. However, its IPM rate is greater than 15 percent. Such a facility is undercosted relative to its economic condition
modeled by the IPM. (2) A facility was costed with the full compliance requirements because its EIA capacity utilization rate
is greater than 15 percent. However, its IPM rate is less than 15 percent. Such a facility is overcosted relative to its economic
condition modeled by the IPM.
To assess the potential uncertainty associated with using a capacity utilization rate that does not always match the assumption
of the IPM, EPA compared the rates between the EIA data sources and the IPM. This comparison showed that 56 out of the
540 in-scope facilities modeled by the IPM would fall under the 15 percent capacity utilization threshold based on the EIA
data. Of these 56 facilities, 21 exceed the 15 percent threshold based on IPM data. These 21 facilities, or 3.9 percent of all
facilities, have potentially been undercosted. Conversely, 112 facilities would fall under the 15 percent capacity utilization
threshold based on the IPM data. Of these 112 facilities, 77 exceed the 15 percent threshold based on EIA data. These 77
facilities, or 14.3 percent of all facilities, have potentially been overcosted. Table B8-22 summarizes the differences between
the EIA and IPM capacity utilization rates.
Table B8-22: Comparison
Capacity
Capacity
Capacity
Capacity
Total
Utilization <
Utilization <
Utilization <
Utilization >
15%
15%
15%
15%
of EIA and IPM Capacity Utilization Rates
in both EIA
in IPM, but
in EIA, but
in both EIA
and IPM
> 15% in El A
> 15 % in IPM
and IPM
407
77
21
35
540
Source: IPM analysis: model run for Section 316(b) Base Case; U.S. DOE, 1999a;
U.S. DOE, 1999b.
The largest cost differential is associated with facilities that would or would not be costed with a recirculating cooling tower
based on their capacity utilization. EPA therefore compared the number of facilities that would be costed with a cooling
6 As explained earlier, facilities with significant status changes (including baseline closures, avoided closures, and facilities that
repower) are excluded from this comparison.
8-22
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options - Electricity Market Model Analysis
tower under the waterbody/capacity-based option, using the two respective capacity utilization rates. With the EIA rate, EPA
determined that of 60 facilities meeting the criteria that would require a cooling tower, 52 have a capacity utilization rate of
greater than 15 percent. For the analysis presented in this chapter, these 52 facilities were costed with a cooling tower.
However, with the IPM capacity utilization rate, 16 of these 52 facilities would not have been costed with a cooling tower.
Conversely, of the eight facilities that were not costed with a cooling tower based on the 15 percent threshold using the EIA
rate, two facilities would have been costed with a cooling tower, had the IPM rate been used. The differential between the
two utilization rates is therefore 14 cooling towers (16 minus 2).
Based on these analyses, EPA concludes that a capacity utilization rate using EIA data would likely overstate the total cost of
the proposed rule and the alternative regulatory options, and therefore lead to a conservative estimate of economic impacts.
Data Input Errors: Due to a costing error, the compliance costs of one facility located in MAAC were understated in the IPM
analysis of the waterbody/capacity-based option. The facility should have been costed with a fish handling and return system
and annualized compliance cost of approximately $1.2 million. The IPM input represented no compliance technology and
annualized compliance costs of less than $100,000. As a result of the understatement of compliance costs for this facility, the
IPM analysis may have underestimated production costs in this region, thereby potentially increasing the dispatch of this
facility.
Modeling Issues: EPA identified three modeling issues that could potentially impact the magnitude of the results of the IPM
analysis. These issues are associated with: (1) repowering, (2) downtime associated with cooling tower connection, and (3)
application of the energy penalty. Repowering: For the section 316(b) analysis, EPA is not using the IPM function that
allows the model to pick among a set of compliance responses. As a result, there is no iterative process that would adjust the
compliance response, and as a result the cost of compliance, if a facility chooses to repower. In the IPM, some oil/gas
facilities repower to combined-cycle prime movers. This would often lead to a reduction in intake flow and potentially to less
stringent compliance requirements or to lower costs (for costs that are a function of intake flow). Not allowing the model to
adjust the compliance response or cost would lead to a conservative estimate of compliance costs and potential economic
impacts from the proposed rule and the alternative regulatory options analyzed with the IPM. Downtime associated with
cooling tower connection: EPA assumes that it would take one month of generator down-time to install and connect a
recirculating cooling tower. As a result of the current specification of seasons in the IPM, it is not possible to model the
downtime as a 100 percent outage during one month. Instead, the downtime is spread over the entire winter season of seven
months and is represented as if a l/7th of the facility were down for a period of seven months. It is unclear how this current
modeling constraint would impact the results of the model. It is possible that short term impacts that would lead to temporary
price increases would be understated, leading to an overall lower average price over the model run year. Application of the
energy penalty: Due to a programming error in the model, which could not be resolved in time for the proposed rule, the
energy penalty for some facilities was incorrectly applied. This problem affected one out of 52 facilities for the
waterbody/capacity-based option and nine out of 416 facilities for the all cooling towers option. As a result of this omission,
regional energy effects and impacts on the facilities in question may have been understated.
8-23
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options - Electricity Market Model Analysis
REFERENCES
U.S. Department of Energy (U.S. DOE). 1999a. FormEIA-860A (1999). Annual Electric Generator Report - Utility.
U.S. Department of Energy (U.S. DOE). 1999b. Form EIA-860B (1999). Annual Electric Generator Report-Nonutility.
U.S. Environmental Protection Agency (U.S. EPA). 2002. Documentation of EPA Modeling Applications (V.2.1) Using the
Integrated Planning Model. EPA 430/R-02-004. March 2002.
8-24
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options - Electricity Market Model Analysis
THIS PAGE INTENTIONALLY LEFT BLANK
8-25
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B8
Appendix to Chapter B8
APPENDIX CONTENTS
B8-A.1 Market Analysis B8-26
B8-A.2 Phase II Facility Analysis B8-31
B8-A.2.1 Group of Phase II Facilities B8-31
B8-A.2.2 Individual Phase II Facilities B8-35
EPA conducted model runs based on two different
electricity demand assumptions: (1) a case using EPA's
electricity demand assumptions and (2) a case using
Annual Energy Outlook (AEO) electricity demand
assumptions.7 The analyses presented in this appendix are
based on using Annual Energy Outlook (AEO) electricity
demand assumptions; the main body of Chapter B8
presented the results using EPA's assumptions. Under the
EPA assumption, the demand for electricity is based on the
AEO 2001 forecast adjusted to account for demand reductions resulting from implementation of the Climate Change Action
Plan (CCAP). The AEO electricity demand assumption, on the other hand, utilizes the AEO 2001 without adjustment. The
remainder of this appendix presents the results of the waterbody/capacity-based option under the AEO electricity demand
assumptions, and a comparison of the differences in results between the AEO based assumptions and the EPA based
assumptions.
B8-A1 MARKET ANALYSIS
This section presents the results of the IPM analysis for all facilities modeled by the IPM. The results in this section include
facilities that are in-scope and facilities that are out-of-scope of section 316(b) regulation under the two demand assumptions
presented above. Market level impacts associated with each of the alternative assumptions are assessed using seven impact
measures developed from IPM output for model run year 2013.8 A detailed description of each of the impact measures
presented below can be found in Section B3-3.1 of Chapter B3: Electricity Market Model Analysis.
7 The Annual Energy Outlook reflects all current legislation and environmental regulations, such as the Clean Air Act Amendments
of 1990.
8 The IPM model simulates electricity market function for a period of 25 years. Model output is provided for five user-specified
model run years. EPA selected three run years to provide output across the ten year compliance period for the rule. Analyses of regulatory
options are based on output for model run years that reflect a scenario in which all facilities are operating in their post-compliance
condition. Options requiring the installation of cooling towers are analyzed using output from model run year 2013.
B8-26
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-1: National Capacity of Closure Units in 2013 (MW; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
133,020 0 0.0%
86,610 0 0.0%
57,080 0 0.0%
70,530 1,110 1.6%
66,420 0 0.0%
39,700 0 0.0%
79,360 460 0.6%
220,570 0 0.0%
55,710 0 0.0%
186,000 0 0.0%
995,000 1,570 0.2%
% Change with
EPA Assumptions
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
1.1%
0.0%
0.0%
1.3%
0.3%
Difference between
AEO and EPA
Assumptions
0.0%
0.0%
0.0%
1.6%
0.0%
0.0%
-0.5%
0.0%
0.0%
-1.3%
-0.1%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-A-2: National Domestic Capacity in 2013 (MW
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
133,020 133,020 0.0%
86,610 86,550 -0.1%
57,080 56,960 -0.2%
70,530 70,420 -0.2%
66,420 66,240 -0.3%
39,700 39,700 0.0%
79,360 79,070 -0.4%
220,570 220,710 0.1%
55,710 55,710 0.0%
186,000 185,860 -0.1%
995,000 994,240 -0.1%
; by NERC Region)
% Change with
EPA Assumptions
0.1%
-0.1%
-0.3%
-0.2%
0.0%
-0.1%
-0.3%
-0.1%
0.0%
-0.1%
-0.1%
Difference between
AEO and EPA
Assumptions
-0.1%
0.0%
0.1%
0.0%
-0.3%
0.1%
-0.1%
0.2%
0.0%
0.0%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
8-27
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-3: National Domestic Capacity Additions in 2013 (MW; by NERC Region)
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case „ „
„ . , Base Case _ . _,
Total . ,,... % Change
„ .. Additions &
Capacity
133,020 22,990 17.3%
86,610 11,320 13.1%
57,080 17,840 31.3%
70,530 11,450 16.2%
66,420 15,300 23.0%
39,700 7,020 17.7%
79,360 11,490 14.5%
220,570 56,020 25.4%
55,710 6,750 12.1%
186,000 25,560 13.7%
995,000 185,740 18.7%
Post-
Compliance % Change
Additions
22,990 17.3%
11,310 13.1%
17,860 31.3%
12,580 17.8%
15,120 22.8%
7,020 17.7%
11,930 15.0%
56,260 25.5%
6,750 12.1%
25,460 13.7%
187,280 18.8%
Difference
0.0%
0.0%
0.0%
1.6%
-0.3%
0.0%
0.6%
0.1%
0.0%
-0.1%
0.2%
% Change
from EPA
Assumptions
0.1%
0.0%
0.0%
0.1%
0.0%
-0.1%
1.4%
-0.1%
0.0%
0.7%
0.2%
Difference
between
AEO and
EPA
Assumptions
-0.1%
0.0%
0.0%
1.5%
-0.3%
0.1%
-0.8%
0.2%
0.0%
-0.8%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-A-4: National Repowering Capacity in 2013 (MW; by NERC Region)
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Repowering
Base Case Base Case as a % of
Total Repowered Total Base
Capacity Capacity Case
Capacity
133,020 0 0.0%
86,610 5,490 6.3%
57,080 0 0.0%
70,530 1,660 2.4%
66,420 0 0.0%
39,700 0 0.0%
79,360 7,960 10.0%
220,570 0 0.0%
55,710 0 0.0%
186,000 7,550 4.1%
995,000 22,660 2.3%
Repowering
Post- as a % of
Compliance Total Base
Repowering Case
Capacity
0 0.0%
5,510 0.4%
0 0.0%
1,640 -1.2%
0 0.0%
0 0.0%
7,730 -2.9%
0 0.0%
0 0.0%
7,770 2.9%
22,650 0.0%
Difference
0.0%
-5.9%
0.0%
-3.6%
0.0%
0.0%
-12.9%
0.0%
0.0%
-1.2%
-2.3%
% Change
with EPA
Assumptions
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
-0.8%
0.0%
0.0%
1.1%
0.2%
Difference
between
AEO and
EPA
Assumptions
0.0%
-5.9%
0.0%
-3.6%
0.0%
0.0%
-12.1%
0.0%
0.0%
-2.3%
-2.5%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
B8-28
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-A-5: National Generation in 2013 (million MWt
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
703 704 0.2%
389 389 0.0%
218 218 0.0%
311 310 -0.3%
306 306 -0.1%
201 201 0.0%
312 312 0.2%
1,072 1,071 -0.1%
244 244 0.0%
849 849 0.0%
4,604 4,604 0.0%
i; by NERC Region)
% Change with
EPA Assumptions
0.0%
0.0%
0.0%
-0.2%
0.3%
0.0%
-0.1%
0.0%
0.0%
0.0%
0.0%
Difference between
AEO and EPA
Assumptions
0.2%
0.0%
0.0%
-0.1%
-0.4%
0.0%
0.3%
-0.1%
0.0%
0.0%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-A-6: National Revenues in 20]
(in millions, $2001; by NERC Region)
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
24,750 24,790 0.2%
13,480 13,470 -0.1%
8,890 8,910 0.2%
12,280 12,270 -0.1%
11,020 11,010 -0.1%
6,680 6,680 0.0%
12,330 13,070 6.0%
38,060 38,050 0.0%
8,660 8,660 0.0%
28,490 28,490 0.0%
164,640 165,400 0.5%
3
% Change with
EPA Assumptions
0.0%
0.0%
-0.3%
-0.2%
0.2%
0.0%
2.4%
0.0%
0.0%
0.2%
0.2%
Difference between
AEO and EPA
Assumptions
0.2%
-0.1%
0.5%
0.1%
-0.3%
0.0%
3.6%
0.0%
0.0%
-0.2%
0.3%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
8-29
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-7: National Variable Production Costs/MWh Generation in 2013 ($2001; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
12.51 12.53 0.1%
17.52 17.52 0.0%
18.93 19.00 0.4%
13.70 14.08 2.8%
12.81 12.79 -0.1%
11.79 11.79 -0.1%
18.25 18.33 0.4%
13.49 13.50 0.1%
14.19 14.19 0.0%
12.19 12.20 0.1%
13.85 13.89 0.3%
% Change with
EPA Assumptions
0.0%
0.0%
0.4%
0.7%
0.2%
0.0%
0.5%
0.1%
0.0%
1.9%
0.5%
Difference between
AEO and EPA
Assumptions
0.1%
0.0%
0.0%
2.1%
-0.3%
-0.1%
-0.1%
0.0%
0.0%
-1.8%
-0.2%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-A-8: National Fuel Costs/MWh of Generation in 2013
(in millions, $2001; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
10.11 10.13 0.2%
15.59 15.59 0.0%
17.04 17.12 0.4%
11.68 12.08 3.4%
10.80 10.78 -0.2%
9.79 9.78 -0.1%
16.93 17.01 0.4%
11.68 11.68 0.1%
12.40 12.40 0.0%
10.72 10.72 0.1%
12.01 12.05 0.3%
% Change with
EPA Assumptions
-0.1%
0.0%
0.6%
0.8%
0.3%
0.0%
0.6%
0.1%
0.0%
2.5%
0.6%
Difference between
AEO and EPA
Assumptions
0.3%
0.0%
-0.2%
2.6%
-0.5%
-0.1%
-0.2%
0.0%
0.0%
-2.4%
-0.3%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
B8-30
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Table B8-A-9: Energy Prices in 2013 ($2001 per KWh,
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
24.53 24.52 0.0%
26.77 26.81 0.1%
29.66 29.58 -0.3%
27.94 27.98 0.1%
23.83 23.82 0.0%
22.37 22.37 0.0%
30.68 30.67 0.0%
25.46 25.46 0.0%
24.33 24.34 0.0%
26.09 26.10 0.0%
by NERC Region)
% Change with
EPA Assumptions
0.0%
0.0%
0.5%
0.6%
0.1%
0.0%
-0.3%
0.0%
0.0%
-0.1%
Difference between
AEO and EPA
Assumptions
0.0%
0.1%
-0.8%
-0.5%
-0.1%
0.0%
0.3%
0.0%
0.0%
0.1%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-A-10: Capacity Prices in 2013 ($2001 per KW per year; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
56.54 56.63 0.2%
35.56 35.35 -0.6%
42.33 43.13 1.9%
51.11 51.30 0.4%
56.15 56.16 0.0%
55.58 55.58 0.0%
37.80 47.65 26.0%
48.92 48.90 0.0%
48.94 48.94 0.0%
37.04 37.06 0.1%
% Change with
EPA Assumptions
-0.2%
-0.2%
-2.0%
-1.5%
-0.1%
-0.1%
13.2%
0.0%
0.0%
2.0%
Difference between
AEO and EPA
Assumptions
0.4%
-0.4%
3.9%
1.9%
0.1%
0.1%
12.8%
0.0%
0.0%
-1.9%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
B8-A2 PHASE II FACILITY ANALYSIS
EPA used the IPM results to analyze two potential facility-level impacts of the waterbody/capacity-based option: (1) potential
changes in the economic and operational characteristics of the group of Phase II facilities and (2) potential changes to
individual facilities within the group of Phase II facilities. It should be noted that the results of both analyses only include the
steam electric components of the Phase II facilities and thus do not provide complete measures for in-scope facilities that also
operate non-steam electric generation, which is not subject to this rule.
B8-A2.1 Group of Phase II Facilities
This section presents the analysis of the potential impacts of the waterbody/capacity-based option on the group of Phase II
facilities. Section B3-3.2 of Chapter B3: Electricity Market Model Analysis presents a detailed discussion of the seven impact
S-31
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
measures developed using IPM output from model run year 2013 and used to assess potential changes in the economic and
operational characteristics of this group of facilities.
Table B8-A-11: Number of Facilities with Closure Units in 2013 (by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
99 0 0.0%
51 0 0.0%
30 0 0.0%
41 1 2.4%
47 0 0.0%
42 0 0.0%
57 (1) -1.8%
95 0 0.0%
32 0 0.0%
34 0 0.0%
528 0 0.0%
% Change with
EPA Assumptions
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
-1.9%
0.0%
0.0%
6.0%
0.2%
Difference between
AEO and EPA
Assumptions
0.0%
0.0%
0.0%
2.4%
0.0%
0.0%
0.1%
0.0%
0.0%
-6.0%
-0.2%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody'/Capacity-Based Option.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-A-12: Capacity of Closure Units in 2013 (MW
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
78,660 0 0.0%
43,460 0 0.0%
24,440 0 0.0%
31,410 1,110 3.5%
34,140 0 0.0%
14,890 0 0.0%
37,290 930 2.5%
100,780 0 0.0%
19,990 0 0.0%
30,950 0 0.0%
416,010 2,040 0.5%
; by NERC Region)
% Change with
EPA Assumptions
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
1.8%
0.0%
0.0%
7.2%
0.7%
Difference between
AEO and EPA
Assumptions
0.0%
0.0%
0.0%
3.5%
0.0%
0.0%
0.7%
0.0%
0.0%
-7.2%
-0.2%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody'/Capacity-Based Option.
8-32
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-13: Capacity of Non- Dispatched Facilities in 2013 (MW; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
190 190 0.0%
6,330 5,790 -8.5%
7,800 7,760 -0.5%
2,070 2,070 0.0%
2,760 2,760 0.0%
330 330 0.0%
5,820 7,980 37.1%
6,960 6,930 -0.4%
2,130 2,130 0.0%
5,860 7,280 24.2%
40,250 43,220 7.4%
% Change with
EPA Assumptions
0.0%
-0.7%
-16.2%
0.0%
0.0%
0.0%
-1.6%
20.6%
0.0%
25.6%
1.9%
Difference between
AEO and EPA
Assumptions
0.0%
-7.8%
15.7%
0.0%
0.0%
0.0%
38.7%
-21.0%
0.0%
-1.4%
5.5%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-A-14: Capacity in 2013 (MW; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
78,660 78,660 0.0%
43,460 43,420 -0.1%
24,440 24,300 -0.6%
31,410 30,180 -3.9%
34,140 34,140 0.0%
14,890 14,890 0.0%
37,290 36,040 -3.4%
100,780 99,050 -1.7%
19,990 19,990 0.0%
30,950 29,790 -3.7%
416,010 410,460 -1.3%
% Change with
EPA Assumptions
0.0%
-0.1%
-0.5%
-0.4%
0.0%
0.0%
-3.1%
-0.1%
0.0%
-8.5%
-1.0%
Difference between
AEO and EPA
Assumptions
0.0%
0.0%
-0.1%
-3.5%
0.0%
0.0%
-0.3%
-1.6%
0.0%
4.8%
-0.3%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
8-33
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-15: Generation in 2013 (MWh; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance ! % Change
533 536! 0.6%
162 171 ! 5.8%
80 106! 32.8%
179 155! -13.3%
221 243! 10.2%
107 129! 21.1%
161 174! 8.1%
630 545! -13.4%
109 117! 7.6%
140 114 ! -18.6%
2,321 2,291! -1.3%
% Change with
EPA Assumptions
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
-6.3%
0.0%
0.0%
-14.3%
-1.3%
Difference between
AEO and EPA
Assumptions
0.6%
5.8%
32.8%
-13.3%
10.2%
21.1%
14.4%
-13.4%
7.6%
-4.3%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
Table B8-A-16: Revenues in 2013 ($2001 Million; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
17,320 17,600 1.6%
5,850 6,250 6.8%
3,360 4,180 24.4%
6,520 5,740 -12.0%
7,060 7,680 8.8%
3,160 3,910 23.7%
6,220 6,710 7.9%
20,690 17,950 -13.2%
3,550 3,980 12.1%
5,000 4,130 -17.4%
78,730 78,130 -0.8%
% Change with
EPA Assumptions
0.0%
-0.2%
-2.2%
-0.8%
0.0%
0.0%
-3.2%
0.0%
0.0%
-17.2%
-1.6%
Difference between
AEO and EPA
Assumptions
1.6%
7.0%
26.6%
-11.2%
8.8%
23.7%
11.1%
-13.2%
12.1%
-0.2%
0.8%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
8-34
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
Table B8-A-17: Variable Production Costs/MWh of Generation in 2013
(in millions, $2001; by NERC Region)
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
11.68 11.68 0.0%
15.39 15.39 0.1%
15.11 15.05 -0.4%
11.41 11.62 1.9%
11.29 11.29 0.0%
11.08 11.08 0.0%
17.99 18.01 0.2%
11.18 11.14 -0.3%
11.99 11.99 0.0%
16.16 15.58 -3.6%
12.56 12.51 -0.3%
% Change with
EPA Assumptions
-0.1%
0.0%
0.7%
0.0%
0.0%
0.0%
-0.2%
0.0%
0.0%
3.9%
-0.3%
Difference between
AEO and EPA
Assumptions
0.1%
0.1%
-1.1%
1.9%
0.0%
0.0%
0.4%
-0.3%
0.0%
-7.5%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody'/Capacity-Based Option.
NERC Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Table B8-A-18: Fuel Costs/MWh of Generation
(in millions, $2001; by NERC Region)
AEO Electricity Demand Assumptions
Base Case Post-Compliance % Change
9.22 9.22 -0.1%
12.76 12.77 0.1%
12.60 12.50 -0.8%
9.24 9.45 2.3%
9.04 9.04 0.0%
9.02 9.02 0.0%
16.28 16.29 0.1%
9.02 8.98 -0.5%
9.80 9.80 0.0%
14.13 13.43 -4.9%
10.32 10.26 -0.5%
in 2013
% Change with
EPA Assumptions
-0.1%
0.1%
0.9%
-0.1%
0.0%
0.0%
-0.3%
0.0%
0.0%
4.3%
-0.5%
Difference between
AEO and EPA
Assumptions
0.0%
0.0%
-1.7%
2.4%
0.0%
0.0%
0.4%
-0.5%
0.0%
-9.2%
0.0%
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody'/Capacity-Based Option.
B8-A.2.2 Individual Phase II Facilities
In addition to effects of the two alternative options in the group of Phase II facilities, there may be shifts in economic
performance among individual facilities subject to section 316(b) regulation. To assess potential distributional effects, EPA
analyzed facility-specific changes in generation, production costs, capacity utilization, revenue, and operating income. For
each measure, EPA determined the number of Phase II facilities that would experience an increase or a reduction within three
ranges: 0 to 1 percent, 1 to 3 percent, and 3 percent or more. Excluded from this analysis were facilities that would
experience significant structural changes as a result of a policy option, including partial or full closures, avoided closures, or
8-35
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B8
repowering. Table B8-A. 19 presents the total number of Phase II facilities with different degrees of change in each of these
measures under the waterbody/capacity-based option.
Table B8-A-19.— Operational Changes at Phase II Facilities from
the Waterbody/Capacity- Based Option (2013)° b
Economic Measures
Change in Net Generation
Change in Variable Production Costs
Change in Capacity Utilization
Change in Total Revenue
Change in Operating Income
Reduction
0-1%
9
7
5
62
107
1-3%
20
3
4
21
16
>3%
11
2
6
8
7
Increase
0-1%
3
17
10
64
74
1-3%
4
22
4
16
28
>3%
14
2
8
22
12
No Change
451
373
475
318
267
a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent.
b Of the 512 Phase II facilities, 86 facilities had zero generation in either the base case or post-compliance scenario. It was therefore
not possible to calculate the change in variable production costs for these facilities. As a result, the number of facilities adds up to
426 instead of 512 for this measure. One facility had zero revenues and operating income in the base case. As such, it was not
possible to calculate its change in revenue or operating income. As a result, the number of facilities adds up to 511 instead of 512
for these measures.
Source: IPM analysis: model runs for Section 316(b) Base Case and Waterbody/Capacity-Based Option.
8-36
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter Cl: Case Study Introduction
Chapter Cl: Case Study Introduction
INTRODUCTION
Part C of this Economic and Benefits Analysis (EBA)
presents a summary of the results of the § 316(b) benefits
case studies and the extrapolation of these results to other
facilities nationwide. This chapter provides an overview
of the case study objectives, selection, and design.
Chapter C2: Summary of Case Study Results summarizes
case study results, Chapter C3: National Extrapolation of
Baseline Economic Losses presents the results of the
national extrapolation of baseline losses, and Chapter C4:
Benefits discusses potential economic benefits of the
proposed rule based on case study results. Case study
methods and results are presented in detail in the Case
Study Document.
Cl-1 WHY CASE STUDIES WERE
UNDERTAKEN
CHAPTER CONTENTS
Cl-l Why Case Studies were Undertaken Cl-1
Cl-2 What Sites were Chosen and Why Cl-1
Cl-3 Steps Taken in the Case Studies Cl-3
Cl-4 Summary of Case Study Analyses Cl-3
Cl-5 Data Uncertainties Leading to Underestimates of
Case Study Impacts and Benefits Cl-6
Cl-5.1 Data Limitations Cl-6
Cl-5.2 Estimated Technology Effectiveness Cl-6
Cl-5.3 Potential Cumulative Impacts Cl-6
Cl-5.4 Recreational Benefits Cl-7
Cl-5.5 Secondary (indirect) Economic Impacts Cl-7
Cl-5.6 Commercial Benefits Cl-7
Cl-5.7 Forage Species Cl-7
Cl-5.8 Nonuse Benefits Cl-8
Cl-5.9 Incidental Benefits Cl-8
Appendix to Chapter Cl Cl-10
It is difficult to develop a national aggregate estimate of potential economic benefits of the proposed rule, particularly since
many impacts and benefits are site-specific, and there are more than 500 facilities that are in the scope of the proposed rule.
However, to the extent that the impacts and benefits associated with a specific case study facility are similar to other facilities
in similar environments, results can be extrapolated to other, similar sites. EPA used this approach to estimate the potential
national benefits of the proposed rule.
Cl-2 WHAT SITES WERE CHOSEN AND WHY
The case studies were designed to capture some of the site-specific aspects of ecological and economic impacts as well as to
develop information that could be extrapolated to other, similar sites to estimate national benefits. Site-specific information is
critical in predicting impacts and potential benefits of the proposed rule, since existing studies demonstrate that impacts and
benefits are highly variable across facilities and environmental settings. Even similar facilities on the same waterbody can
have very different impacts depending on the aquatic ecosystem in the vicinity of the facility.
EPA selected case studies to represent a range of intake characteristics and environmental conditions throughout the United
States. Important intake-specific characteristics relating to location, design, construction, and capacity include:
*• Cooling water intake structure (CWIS) size and scale of operation (e.g., flow volume and velocity);
*• CWIS and/or operational practices in place (if any) for impingement and entrainment(I&E) reduction at baseline
(i.e., absent any new regulations);
>• CWIS intake location in relation to local zones of ecological activity and significance (e.g., depth and orientation of
the intake point, and its distance from shore); and
*• CWIS flow volumes in relation to the size of the impacted waterbody.
Cl-1
-------
§ 316(b) Phase II EBA, Part C: National Benefits
Chapter Cl: Case Study Introduction
Environmental factors that influence the magnitude of impacts and the potential benefits of reducing impacts include the types
of waterbodies impacted, the aquatic species that are affected in those waterbodies, and the people who use and/or value the
status of the water resources and aquatic ecosystems affected. The most important site-specific environmental factors are:
>• The aquatic species present near a facility;
*• The ages and life stages of the aquatic species present near the intakes;
*• The timing and duration of species' exposure to the intakes;
>• The ecological value of the impacted species in the context of the aquatic ecosystem;
>• Whether any of the impacted species are threatened, endangered, or otherwise of special concern and status (e.g.,
depleted commercial stocks); and
*• Local ambient water quality issues that may also affect the fisheries and their uses.
Figure Cl-1: Location of Case Study Facilities
Pacific
Ocean
Source: U.S. EPA analysis, 2002.
The case study sites used for extrapolation are considered representative of the majority of steam electric generators in the
United States. The map in Figure Cl-1 indicates the locations of the case study facilities in relation to other facilities
nationwide.
Cl-2
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter Cl: Case Study Introduction
Cl -3 STEPS TAKEN IN THE CASE STUDIES
Each case study was a comprehensive analysis of historical ecological impacts, potential reductions in these impacts resulting
from the proposed rule, and the anticipated economic benefits of reducing impacts. Data gathering and analytical steps are
described in detail in Chapter A5 of Part A of the Case Study Document and summarized below in Figure Cl-2. The major
steps were as follows.
>• EPA compiled any economic, technical, and biological data available from previous § 316(b) studies and from
results of EPA's survey of the industry for the § 316(b) rulemaking.
*• This information was supplemented as needed by data in the scientific literature and government reports on the
environmental settings and socioeconomic characteristics of the case study sites.
*• EPA compiled life history data from local fishery surveys, facility monitoring, and the scientific literature for all
species identified as vulnerable to I&E based on previous intake or waterbody monitoring. This information was
used to implement biological models to express annual counts of impinged and entrained organisms as numbers of
age 1 equivalents, pounds of fishery yield, and production foregone, as described in Chapter A5 of Part A of the
Case Study Document.
*• Once historical I&E losses were quantified, EPA estimated potential reductions in I&E with the proposed rule, and
estimated human use and nonuse benefits expected to result from the predicted reductions in I&E.
Cl -4 SUMMARY OF CASE STUDY ANALYSES
Table Cl-1 summarizes the analyses conducted in the different case studies. Three studies (Delaware Estuary, Tampa Bay,
and Ohio River) evaluated multiple CWIS within a single waterbody to develop an indication of potential cumulative impacts
at the watershed scale. One study (San Francisco Estuary) examined impacts to threatened and endangered species and the
potential economic benefits associated with protecting rare species. Several studies focused on discrete technology or
operational alternatives such as once-through versus closed-cycle cooling (Brayton Point), offshore versus shoreline intake
locations (Pilgrim and Seabrook), and use of a barrier net to reduce impingement (J.R. Whiting).
All studies applied benefits transfer techniques to estimate the economic value of losses to commercial and recreational
fisheries, but several studies also applied other standard, well-accepted economic techniques that are new to the analysis of
§ 316(b) I&E losses to capture other economic values, including societal revealed preference techniques (San Francisco
Bay/Delta), a random utility model (RUM) of recreational behavior (Delaware Estuary, Ohio River, and Tampa Bay) and
habitat-based replacement cost (HRC) analysis (J.R. Whiting, Monroe, Brayton Point, and Pilgrim). The RUM approach
evaluates changes in consumer valuation of water resources expected to result from reductions in I&E-related fish losses.
The HRC technique assigns economic value to I&E losses based on the combined costs of implementing restoration actions to
produce the organisms that were lost, administering the programs, and monitoring the production resulting from restoration
actions.
Cl-3
-------
§ 316(b) Phase II EBA, Part C: National Benefits
Chapter Cl: Case Study Introduction
Figure Cl-2: Steps in § 316(b) Case Study Data Gathering and Analysis
Compilation and Analysis of
I&E Data,
Species Life History Data,
and Fisheries Data
Calculation of
Age 1 Equivalents
Calculation of
Foregone Fisheries Yield
Baseline I&E
Differences
in losses
Benefits
Valuation
1
Calculation of
Production
Foregone
1
I&E
With Regulation
Source: U.S. EPA analysis, 2002.
Cl-4
-------
§ 316(b) Phase II EBA, Part C: National Benefits
Chapter Cl: Case Study Introduction
Facilities Evaluated
CS
Salem
Hope Creek
Deepwater
Edgemoor
PL Barlow
FJ Gannon
Hookers Point
Manatee
Big Bend
W.H. Sammis, OH
Cardinal, OH
Kyger Creek, OH
Tanners Creek, IN
Clifty Creek, IN
P. Sporn, WV
Kammer, WV
Pittsburg
Contra Costa
CS-E
Brayton Point
Seabrook
Pilgrim
JR Whiting
CS-
Monroe
Table Cl-1: Case Study Sites
Type of Study
-1: Delaware Estuary Watershed Study
Mid-Atlantic Estuary
Watershed-Scale Study
>• Cumulative Impacts
RUM Analysis
Electricity Region: MACC, Mid-Atlantic Area Council
CS-2: Tampa Bay Watershed Study
Southern Gulf Coast Estuary
Watershed-Scale Study
>• Cumulative Impacts
RUM Analysis
Electricity Region: FRCC, Florida Reliability Coordinating Council
CS.-3: Ohio River Watershed Study
Large River
Watershed-Scale Study
>• Cumulative Impacts
RUM Analysis
Electricity Region: ECAR, East Central Area Reliability Coordination Agreement
CS-4: San Francisco Bay / Delta
Threatened and Endangered Species
Western Estuary
Societal Revealed Preference Analysis
Electricity Region: WSCC, Western Systems Coordinating Council
>: New England Estuary (Mount Hope Bay)
New England Estuary
Fish Population Decline
>• Once Through v. Wet Cooling
Habitat-based Replacement Cost Analysis
Electricity Region: NPCC, Northeast Power Coordinating Council
CS-6: New England Coast
Intake Location Study
- Off-Shore v. Shoreline
Habitat-based Replacement Cost Analysis of Pilgrim
Electricity Region: NPCC, Northeast Power Coordinating Council
CS-7: Great Lakes
Technology Study
>• Impingement Deterrent Net
Habitat-based Replacement Cost Analysis
Electricity Region: ECAR, East Central Area Reliability Coordination Agreement
8: Large River Tributary to Great Lakes
Intake Flow Study
>• Intake Flow exceeds the waterbody flow most of year
Habitat-based Replacement Cost Analysis
Electricity Region: ECAR, East Central Area Reliability Coordination Agreement
Source: U.S. EPA analysis, 2002.
Cl-5
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter Cl: Case Study Introduction
Cl-5 DATA UNCERTAINTIES LEADINS TO UNDERESTIMATES OF CASE STUDY IMPACTS
AND BENEFITS
EPA's estimates of case study impacts and the potential economic benefits of the proposed rule are subject to considerable
uncertainties. As a result, the Agency's estimated benefits could be either over- or underestimated. However, because of the
many factors omitted from the analysis (typically because of data limitations), and the manner in which several key
uncertainties were addressed, EPA believes that its analysis is likely to lead to potentially significant underestimates of
baseline losses in most cases, and therefore underestimates of regulatory benefits. These factors are discussed in the Case
Study Document and summarized below.
Cl-5.1 Data Limitations
EPA's analysis is based on facility-provided biological monitoring data. These facility-furnished data typically focus on a
subset of the fish species impacted by I&E, resulting in an underestimate of the total magnitude of losses.
Industry biological studies often lack a consistent method for monitoring I&E. Thus, there are often substantial uncertainties
and potential biases in the I&E estimates. Comparison of results between studies is therefore very difficult and sometimes
impossible, even among facilities that impinge and entrain the same species.
The facility-derived biological monitoring data often pertain to conditions existing many years ago (e.g., the available
biological monitoring often was conducted by the facilities 20 or more years ago, before activities under the Clean Water Act
had improved aquatic conditions). In those locations where water quality was relatively degraded at the time of monitoring
relative to current conditions, the numbers and diversity offish are likely to have been depressed during the monitoring
period, resulting in low I&E. In most of the nation's waters, current water quality and fishery levels have improved, so that
current I&E losses are likely to be greater than available estimates for depressed populations.
Cl-5.2 Estimated Technology Effectiveness
I&E benefits are dependent in the technologies that are installed, the proper use of those technologies, the degree to which the
technologies are maintained and repaired, and the commitment of the facility to optimizing the technologies for their given
location. Potential latent mortality rates are unknown for most technologies. The only technology effectiveness that is certain
is reductions in I&E with cooling towers. If the towers are running, I&E reductions can be estimated with some certainty.
EPA's analyses assumes that installed technologies will be operate at the maximum efficiency assumed by EPA in its
estimates of technology effectiveness. To the degree that this is not the case, benefits could be lower.
Cl-5.3 Potential Cumulative Impacts
I&E impacts often have cumulative impacts that are usually not considered. Cumulative impacts refer to the temporal and
spatial accumulation of changes in ecosystems that can be additive or interactive. Cumulative impacts can result from the
effects of multiple facilities located within the same waterbody and from individually minor but collectively significant I&E
impacts taking place over a period or time. Because of time and funding constraints, EPA was able to estimate potential
cumulative impacts for only three of its case studies (Delaware Estuary, Ohio River, Tampa Bay).
Relatively low estimates of I&E impacts may reflect a situation where cumulative I&E impacts (and other stresses) have
appreciably reduced fishery populations so that there are fewer organisms present in intake flows.
In many locations (especially estuary and coastal waters), many fish species migrate long distances. As such, these species
are often subject to I&E risks from a large number cooling water intake structures. EPA's analyses reflect the impacts of a
limited set of facilities on any given fishery, whereas many of these fish are subjected to I&E at a greater number of cooling
water intake structures than are included in the boundaries of the Agency's case studies.
Cl-6
-------
§ 316(b) Phase II EBA, Part C: National Benefits Chapter Cl: Case Study Introduction
Cl-5.4 Recreational Benefits
Recreational values were underestimated for a number of reasons. These include:
*• The proportion of I&E losses of fishery species that were valued as lost recreational catch was determined from
stock-specific fishing mortality rates, which indicate the fraction of a stock that is harvested. Because fishing
mortality rates are typically less than 20 percent, a large proportion of the losses of fishery species was not valued in
the benefits transfer and RUM analyses.
*• Only selected species were evaluated because I&E or valuation data were limited.
*• In applying benefits transfer to value the benefits of improved recreational angling, the Agency assigned a monetary
benefit to only the increases in consumer surplus for the baseline number of fishing days. Changes in participation
(except where the RUM is estimated) are not considered. Thus, benefits will be understated if participation increases
in response to increased availability of fishery species as a result of reduced I&E. This approach omits the portion of
recreational fishing benefits that arise when improved conditions lead to higher levels of participation. Empirical
evidence suggests that the omission of increased angling days can lead to an underestimate of total recreational
fishing benefits. Where EPA has been able to apply its RUM analyses, the recreational angling benefits are more
indicative of the full range of beneficial angling outcomes.
Cl-5.5 Secondary (indirect) Economic Impacts
Secondary impacts are not calculated (effects on marinas, bait sales, property values, and so forth are not included, even
though they may be significant and applicable on a regional scale).
Cl-5.6 Commercial Benefits
Commercial benefits were underestimated for the following reasons:
*• The proportion of I&E losses of fishery species that were valued as lost commercial catch was determined from
stock-specific fishing mortality rates, which indicate the fraction of a stock that is harvested. Because fishing
mortality rates are typically less than 20 percent, a large proportion of the losses of fishery species was not valued in
the benefits transfer analyses.
>• In most cases, invertebrate species (e.g, lobsters, mussels, crabs, shrimp) were not included because of a lack of I&E
data and/or life history information.
*• I&E impacts and associated reductions in fishery yields are probably understated even for those species EPA could
evaluate because of a lack of monitoring data to capture population variability and cumulative I&E impacts over
time.
>• Current fishing mortality rates (and resulting estimates of yield) often reflect depleted fisheries, not what the
fisheries should or could be if not adversely impacted by I&E and other stressors. As such, yield estimates may be
artificially low because of significantly curtailed recreational and/or commercial catch of key species impinged and
entrained (e.g., winter flounder in Mount Hope Bay).
Cl-5.7 Forage Species
Benefits for forage species are underestimated for many reasons. These reasons include:
*• Forage species often make up the predominant share of losses due to I&E. However, I&E losses of forage species
are usually not known because many facility studies focus only on commercial and recreational fishery species.
>• Even when forage species are included in loss estimates, the monetary value assigned to forage species is likely to be
understated because the full ecological value of the species as part of the food web is not considered.
Cl-7
-------
§ 316(b) Phase II EBA, Part C: National Benefits Chapter Cl: Case Study Introduction
> Forage losses are often valued at only a fraction of their potential full value because of partial "replacement" cost
(even if feasible to replace).
>• The value of production foregone includes only the value of added biomass to landed recreational and commercial
species is considered. The inherent value of forage species is not included in the benefits estimates.
*• In one valuation approach EPA applied to forage species, only a small share of these losses is valued — namely, the
contribution of the forage species to the increased biomass of landed recreational and commercial species.
>• This does not apply to benefits derived by the habitat-based replacement cost approach, which provides a more
comprehensive indication of the benefits of reducing I&E on all species, including forage fish. EPA has applied this
approach to a limited number of settings, and in those settings the findings suggest benefits appreciably greater than
derived from the more conventional, partial benefits approaches applied by the Agency.
Cl-5.8 Nonuse Benefits
EPA's benefit estimate of nonuse benefits is understated using the 50 percent rule because the recreational values used are
likely to be understated. The 50 percent rule itself is conservative (e.g., it only reflects nonuse component of total value to
recreational users; it does not reflect any nonuse benefits to recreational nonusers). In addition, the rule does not capture
impacts on threatened and endangered species.
Cl-5.9 Incidental Benefits
EPA's estimates of benefits are underestimates for some options because EPA has not accounted for thermal impact
reductions, which will occur in all options where once-through facilities are replaced with recirculating water regimes (e.g.,
sites going to cooling towers).
-------
§ 316(b) Phase II EBA, Part C: National Benefits Appendix to Chapter Cl
THIS PAGE INTENTIONALLY LEFT BLANK
Cl-9
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§ 316(b) Phase II EBA, Part C: National Benefits
Appendix to Chapter Cl
Appendix to Chapter Cl
INTRODUCTION
In developing the national benefits estimates for
Chapter C4: Benefits, EPA used the sample weights
estimated during the sampling design for the 316(b)
questionnaires. These weights were used to generate
benefits estimates for all 550 in-scope facilities based on
the baseline losses for 539 in-scope facilities for which
questionnaire data was available. This appendix presents
the unweighted benefits estimates in the tables below.
APPENDIX CONTENTS
Cl-A.l Options with Benefit Estimates Cl-10
C1-A.2 Impingement Reductions and Benefits Cl-11
C1-A.3 Entrainment Reductions and Benefits Cl-12
C1-A.4 Benefits Associated with Various Impingement and
Entrainment Percentage Reductions Cl-13
C1-A.5 Impingement and Entrainment Benefits Associated with
The Proposed Option Cl-13
The reported percent reduction in baseline losses for each facility reflects EPA's assessment of (1) regulatory baseline
conditions at the facility (i.e., current practices and technologies in place), and (2) the percent reductions in impingement and
entrainment that EPA estimated would be achieved at each facility that the Agency believes would be adopted under each
regulatory option.
Cl-A.l OPTIONS WITH BENEFIT ESTIMATES
EPA estimated benefits for the following six options. These options include:
>• Option 1: Track I of the waterbody /capacity-based option;
*• Option 2: Track I and II of the waterbody /capacity-based option;
>• Option 3: (the Agency's proposed rule), impingement and entrainment controls everywhere with exceptions for low-
flow facilities on lakes and rivers;
> Option 3a: impingement and entrainment controls everywhere with no exceptions;
*• Option 4: requires all Phase II existing facilities to reduce intake capacity commensurate with the use of closed-
cycle, recirculating cooling systems; and
>• Option 5: requires that all Phase II existing facilities reduce intake capacity commensurate with the use of dry
cooling systems.
>• Option 6: similar to Optionl, but requires reduction commensurate with the use of closed-cycle, recirculating
systems for all facilities on estuaries, tidal rivers, and oceans
National estimates including weights can be found in Chapter C4: Benefits, and a complete description of the options detailed
in the following tables can be found in Part A, Chapter Al of this document.
Cl-10
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§ 316(b) Phase II EBA, Part C: National Benefits
Appendix to Chapter Cl
C1-A.2 IMPINSEMENT REDUCTIONS AND BENEFITS
Table Cl-A-1 presents the percentage reductions in impingement that are expected to occur under the six options listed above
and Table Cl-A-2 presents the benefit value associated with those reductions.
Table Cl-A-1: Unweighted Impingement Reductions for Various Options - By Reduction Level
Waterbody
Type
Estuary - Non-
Gulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Number of
In-Scope
Facilities
78
30
393
16
22
539
Baseline
Impingement
Loss
$52,463
$4,097
$40,417
$31,506
$14,174
$142,656
Percentage Reductions
Option
64.5%
63.2%
47.3%
80.0%
73.2%
Option
2
47.5%
45.9%
47.3%
80.0%
59.0%
Option
3
33.2%
26.5%
47.3%
80.0%
50.6%
Option
3a
25.0%
30.0%
46.7%
77.0%
47.2%
Option
4
40.9%
45.3%
59.0%
88.6%
59.7%
Option
5
97.5%
96.7%
98.0%
96.3%
88.8%
Option
6
84.2%
79.4%
47.8%
79.4%
78.9%
Source: U.S. EPA analysis, 2002.
Table Cl-A-2: Unweighted Impingement Benefits for Various Options - By Benefit Level
(in thousands, $2001)
Waterbody
Type
Estuary -
Non-Gulf
Estuary -
Gulf
Freshwater
Great Lake
Ocean
Total
Number of
In-Scope
Facilities
78
30
393
16
22
539
Baseline
Impingement
Loss
$52,463
$4,097
$40,417
$31,506
$14,174
$142,656
Benefits
Option 1
$33,834
$2,588
$19,117
$25,205
$10,369
$91,113
Option 2
$24,909
$1,882
$19,117
$25,205
$8,359
$79,472
Option 3
$17,418
$1,087
$19,117
$25,205
$7,171
$69,998
Option
3a
$13,125
$1,230
$18,855
$24,260
$6,686
$64,156
Option 4
$21,470
$1,856
$23,828
$27,900
$8,467
$83,520
Option 5
$51,141
$3,961
$39,605
$30,326
$12,585
$137,619
Option 6
$44,148
$3,253
$19,304
$25,018
$11,182
$102,905
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part C: National Benefits
Appendix to Chapter Cl
C1-A.3 ENTRAINMENT REDUCTIONS AND BENEFITS
Table Cl-A-3 presents the percentage reductions in impingement that are expected to occur under the six options listed above
and Table Cl-A-4 presents the benefit value associated with those reductions.
Table Cl-A-3: Unweighted Entrainment Benefits for Various Options - By Reduction Level
Waterbody
Type
Estuary -
Non-Gulf
Estuary -
Gulf
Freshwater
Great Lake
Ocean
Total
Number of
In-Scope
Facilities
78
30
393
16
22
539
Baseline
Entrainment
Loss
$876,002
$103,593
$95,660
$43,448
$259,656
$1,378,359
Entrainment Percentage Reductions
Option 1
67.2%
66.9%
12.4%
57.8%
74.2%
Option 2
59.1%
52.3%
12.4%
57.8%
58.9%
Option 3
48.5%
47.0%
12.4%
57.8%
45.0%
Option
3a
47.1%
47.8%
44.2%
57.8%
45.0%
Option 4
79.2%
79.3%
72.7%
88.6%
74.1%
Option 5
97.5%
96.7%
98.0%
96.3%
88.8%
Option 6
78.0%
78.3%
9.8%
57.3%
74.1%
Source: U.S. EPA analysis, 2002.
Table Cl-A-4: Unweighted Entrainment Benefits for Various Options -
By Benefit Level (in thousands, $2001)
Waterbody
Type
Estuary -
NonGulf
Estuary -
Gulf
Freshwater
Great Lake
Ocean
Total
Number of
In-Scope
Facilities
78
30
393
16
22
539
Baseline
Entrainment
Loss
$876,002
$103,593
$95,660
$43,448
$259,656
$1,378,359
Entrainment Benefit
Option 1
$588,552
$69,324
$11,883
$25,092
$192,560
$887,410
Option 2
$517,960
$54,206
$11,883
$25,092
$152,869
$762,010
Option 3
$424,708
$48,645
$11,883
$25,092
$116,796
$627,123
Option
3a
$412,696
$49,508
$42,277
$25,092
$116,796
$646,368
Option 4
$693,420
$82,186
$69,575
$38,474
$192,296
$1,075,951
Option 5
$853,940
$100,175
$93,738
$41,820
$230,553
$1,320,227
Option 6
$683,494
$81,160
$9,410
$24,899
$192,296
$991,259 |
Source: U.S. EPA analysis, 2002.
Cl-12
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§ 316(b) Phase II EBA, Part C: National Benefits
Appendix to Chapter Cl
C1-A.4 BENEFITS ASSOCIATED WITH VARIOUS PERCENTAGE REDUCTIONS
Table Cl-A-5 presents the national benefits that would occur with various percentage reductions.
Table Cl-A-5: Summary of Unweighted Potential Benefits Associated with Various
Impingement and Entrapment Reduction Levels
(All 539 In-Scope Facilities)
Reduction Level
10%
20%
30%
40%
50%
60%
70%
80%
90%
Benefits
Impingement
$14,266
$28,531
$42,797
$57,063
$71,328
$85,594
$99,859
$114,125
$128,391
(in thousands, $2001)
Entrainment
$137,836
$275,672
$413,508
$551,344
$689,180
$827,016
$964,851
$1,102,687
$1,240,523
Source: U.S. EPA analysis, 2002.
C1-A.5 BENEFITS ASSOCIATED WITH THE PROPOSED OPTION
Table Cl-A-6 presents the benefits that would occur with various percentage reductions
Table Cl-A-6: Summary of Unweighted Potential Benefits from Impingement and Entrainment
Controls Associated with the Proposed Rule (Option 3)
Waterbody Type
Estuary - NonGulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Number of In-
Scope Facilities
78
30
393
16
22
539
Benefits
Impingement
$17,418
$1,087
$19,117
$25,205
$7,171
$69,998
(in thousands, $2001)
Entrainment
$424,708
$48,645
$11,883
$25,092
$116,796
$627,123
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part C: National Benefits Appendix to Chapter Cl
Under today's proposal, facilities can choose the Site-Specific Determination of Best Technology Available in § 125.94(a) in
which a facility can demonstrate to the Director that the cost of compliance with the applicable performance standards in §
125.94(b) would be significantly greater than the costs considered by EPA when establishing these performance standards, or
the costs would be significantly greater than the benefits of complying with these performance standards. EPA expects that if
facilities were to choose this approach, then the overall national benefits of this rule will decrease markedly. This is because
under this approach facilities would choose the lowest cost technologies possible and not necessarily the most effective
technologies to reduce impingement and entrainment at the facility. See Chapter C4: Benefits for additional information on
the certainty of each of the other options.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
Chapter C2: Summary of Case Study
Results
INTRODUCTION
This chapter summarizes the results of the eight case study
analyses. Each case study section reports EPA's estimate
of the number of age 1 equivalent fish that are lost to I&E
at the case study facilities and the economic value of these
losses. The final section presents EPA's extrapolation of
the losses from five case studies to estimates of national
I&E losses.
C2-1 THE DELAWARE ESTUARY
WATERSHED STUDY (MiD-ATLANTIC
ESTUARIES)
CHAPTER CONTENTS
C2-1 The Delaware Estuary Watershed (Mid-Atlantic
Estuaries) C2-1
C2-2 Tampa Bay Watershed Study (Gulf Estuaries) C2-3
C2-3 The Ohio River Watershed Study (Large Rivers). . . C2-4
C2-4 San Francisco Bay/Delta (Western Estuaries) C2-6
C2-5 Mount Hope Bay (New England Estuaries) C2-7
C2-6 Oceans (New England Coast) C2-8
C2-7 The GreatLakes C2-9
C2-8 Large River Tributary to the Great Lakes C2-10
C2-9 National Baseline Losses Due to
I&E at In-Scope Facilities C2-11
To evaluate potential I&E impacts of cooling water intake structures in the Delaware Estuary transition zone, EPA evaluated
I&E rates at Salem Nuclear Generating Station located in the transition zone of the Delaware Estuary. EPA estimated that the
impingement impact of Salem Nuclear Generating Station is over 3.1 million age 1 equivalent fish and over 135,900 pounds
of lost fishery yield per year. The entrainment impact is over 356.3 million age 1 equivalent fish and 9.9 million pounds of
lost fishery yield. Extrapolation of these losses to four other facilities indicated a cumulative impingement impact of over
12.2 million age 1 fish and a cumulative entrainment impact of over 526 million age 1 equivalent fish each year (Table C2-1).
These results indicate that the cumulative impacts of multiple cooling water intake structures (CWIS) in a single area can be
substantial.1
Table C2-1: Baseline Impacts (annual average) for the Delaware Estuary Transition Zone
(Four In-Scope Facilities)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
>12.2million/yr
> 374,000 Ib/yr
$0.50 million - $0.8 million/yr
Entrainment
> 526.3 million/yr
> 13. 8 million Ib/yr
$16.8 million - $30.5 million/yr
Source: U.S. EPA analysis, 2002.
Average losses at the four in-scope facilities are valued (using benefits transfer combined with RUM recreation estimates) to
range from $0.5 million to $0.8 million per year for impingement and from $16.8 to $30.5 million per year for entrainment
(all in $2001).
1 For an estimation of lost fishery yield per year and age 1 equivalent fish each year, see Chapter B3: Ecological Risk
Assessment in PartB:The Delaware Estuary of the Watershed Case Study Analysis for the Proposed Section 316(b) Phase II Existing
Facilities Rule.
C2-1
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C2: Summary of Case Study Results
In this estuarine setting, benefits attributed to reducing losses due to both impingement and entrainment may be quite large in
terms of numbers offish and in terms of the portion of benefits that could be monetized. This reflects the typical richness of
estuary waters as important nursery locations for many important aquatic species. In addition, the higher benefit associated
with entrainment reflects the high vulnerability of abundant early life stages of estuarine species, and indicates the relative
importance of entrainment controls in estuary areas.
In part, EPA's recreational benefits estimates for the Delaware Estuary are based on a random utility model (RUM) analysis
of recreational fishing benefits from reduced I&E. The RUM application in the Delaware Estuary focuses on weakfish and
striped bass fishing valuation. Several recreational fishing studies have valued weakfish and striped bass, but values specific
to these studies are not available. The study area includes recreational fishing sites at the Delaware River Estuary and the
Atlantic coasts of Delaware and New Jersey.
EPA used data for this case study from the Marine Recreational Fishery Statistics Survey (MRFSS), combined with the 1994
Add-on MRFSS Economic Survey (AMES). The study used MRFSS information on angler characteristics and angler
preferences, such as where they go fishing and what species they catch, to infer their values for changes in recreational
fishing quality. EPA estimated angler behavior using a RUM for single-day trips. The study used standard assumptions and
specifications of the RUM model that are readily available from the recreation demand literature. Among these assumptions
are that anglers choose fishing mode and then the site in which to fish; and that anglers' choice of target species is exogenous
to the model. EPA modeled an angler's decision to visit a site as a function of site-specific cost, fishing trip quality, presence
of boat launching facilities, and water quality.
The quality of a recreational fishing trip is expressed in terms of the number of fish caught per hour of fishing. Catch rate is
the most important attribute of a fishing site from the angler's perspective. This attribute is also a policy variable of concern
because catch rate is a function of fish abundance, which may be affected by fish mortality caused by I&E.
The Agency combined the estimated model coefficients with the estimated changes in I&E associated with various cooling
water intake structure technologies to estimate per trip welfare losses from I&E at the cooling water intake structures located
in the Delaware Estuary transition zone. The estimated economic values of recreational losses from I&E at the 12 cooling
water intake structures located in the case study area are $0.75, $2.04, and $9.97 per trip for anglers not targeting any
particular species and anglers targeting weakfish and striped bass, respectively (all in $2001). EPA then estimated benefits of
reducing I&E of two species — weakfish and striped bass — at the four in-scope cooling water intake structures in the case
study area. The estimated values of an increase in the quality of fishing sites from reducing I&E at the in-scope cooling water
intake structures are $0.52, $1.40 and $6.90 per trip for no target anglers and anglers targeting weakfish and striped bass,
respectively (all in $2001).
EPA also examined the effects of changes in fishing circumstances on fishing participation during the recreational season.
First, the Agency used the negative binomial form of the Poisson model to model an angler's decision concerning the number
of fishing trips per recreation season. The number of fishing trips is modeled as function of the individual's socioeconomic
characteristics and estimates of individual utility derived from the site choice model. The Agency then used the estimated
model coefficients to estimate percentage changes in the total number of recreational fishing trips due to improvements in
recreational site quality. EPA combined fishing participation data for Delaware and New Jersey obtained from MFRSS with
the estimated percentage change in the number of trips under various policy scenarios to estimate changes in total
participation stemming from changes in the fishing site quality in the study area. The MRFSS fishing participation data
include information on both single-day and multiple-day trips. The Agency assumed that per day welfare gain from improved
fishing site quality is independent of trip length. EPA therefore calculated total fishing participation for this analysis as the
sum of the number of single-day trips and the number of fishing days corresponding to multiple-day trips. Analysis results
indicate that improvements in fishing site quality from reducing I&E at all in-scope facilities will increase the total number of
fishing days in Delaware and New Jersey by 9,464.
EPA combined fishing participation estimates with the estimated per trip welfare gain under various policy scenarios to
estimate the value to recreational anglers of changes in catch rates resulting from changes in I&E in the Delaware Estuary
transition zone. EPA calculated low and high estimates of economic values of recreational losses from I&E by multiplying
the estimated per trip welfare gain by the baseline and policy scenario number of trips, respectively. The estimated
recreational losses ($2001) to Delaware and New Jersey anglers from I&E of two species at all Phase 2 facilities in the
transitional estuary and at all facilities in the transitional estuary range from $0.2 to $0.3 and from $7.2 to $13.2 million,
respectively. Using similar calculations, the Agency estimated that reducing I&E of weakfish and striped bass at the four in-
scope cooling water intake structures in the transition zone will generate $5.2 to $9.3 million ($2001) annually in recreational
fishing benefits alone to Delaware and New Jersey anglers.
C2-2
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C2: Summary of Case Study Results
In interpreting the results of the Delaware case study, it is important to consider several critical caveats and limitations of the
analysis. First, EPA believes that it has conservatively estimated cumulative impacts on Delaware Estuary species by
considering only the I&E impacts of transition zone cooling water intake structures. In fact, many of the species affected by
cooling water intake structures within the transition zone move in and out of this area, and therefore may be exposed to many
more cooling water intake structures than considered here.
Second, the economic valuation of I&E losses is often complicated by the lack of market value for forage species, which may
comprise a large proportion of total losses. EPA estimates that more than 450 million age 1 equivalents of bay anchovy may
be lost to entrainment at transition zone cooling water intake structure each year (over 85 percent of the total of over 526
million estimated lost age 1 individuals for all species combined). Bay anchovy has no direct market value, but it is
nonetheless a critical component of estuarine food webs. EPA included forage species impacts in the economic benefits
calculations, but the final estimates may well underestimate the full value of the losses imposed by I&E. Thus, on the whole,
EPA believes the estimates developed here probably understate the economic benefits of reducing I&E in the Delaware
Estuary transition zone.
C2-2 TAMPA BAY WATERSHED STUDY (6ui_F COAST ESTUARY)
To evaluate potential I&E impacts of cooling water intake structures in estuaries of the Gulf Coast and Southeast Atlantic,
EPA evaluated I&E rates at the Big Bend facility in Tampa Bay. EPA estimated that the impingement impact of Big Bend is
420,000 age 1 equivalent fish and over 11,000 pounds of lost fishery yield per year. The entrainment impact is 7.71 billion
age 1 equivalent fish and nearly 23 million pounds of lost fishery yield per year. Extrapolation of these losses to other Tampa
Bay facilities indicated a cumulative impingement impact of 1 million age 1 fish (27,000 pounds of lost fishery yield) and a
cumulative entrainment impact of 19 billion age 1 equivalent fish (56 million pounds of lost fishery yield) each year.
The results of EPA's evaluation of the dollar value of I&E losses at Big Bend, as calculated using benefits transfer, indicate
that baseline economic losses range from $60,000 to $66,000 per year for impingement and from $7.1 million to $7.3 million
per year for entrainment (all in $2001). Baseline economic losses using benefits transfer for all in-scope facilities in Tampa
Bay (Big Bend, PL Bartow, FJ Gannon, and Hookers Point) range from $150,000 to $163,000 per year for impingement and
from $17.0 million to $18.0 million per year for entrainment (all in $2001).
EPA also developed a RUM approach to estimate the effects of improved fishing opportunities due to reduced I&E in the
Tampa Bay Region. Cooling water intake structures withdrawing water from Tampa Bay impinge and entrain many of the
species sought by recreational anglers. These species include spotted seatrout, black drum, sheepshead, pinfish, and silver
perch. The study area includes Tampa Bay itself and coastal sites to the north and south of Tampa Bay.
The study's main assumption is that anglers will get greater satisfaction, and thus greater economic value, from sites where
the catch rate is higher, all else being equal. This benefit may occur in two ways: first, an angler may get greater enjoyment
from a given fishing trip when catch rates are higher, and thus get a greater value per trip; second, anglers may take more
fishing trips when catch rates are higher, resulting in greater overall value for fishing in the region.
EPA's analysis of improvements in recreational fishing opportunities in the Tampa Bay Region relied on a subset of the 1997
MRFSS combined with the 1997 AMES and the follow-up telephone survey for the southeastern United States. The Agency
evaluated five species and species groups in the model: drums (including red and black drum), spotted seatrout, gamefish,
snapper-grouper, and all other species. I&E was found to affect black drum, spotted seatrout, and sheepshead, which is
included in the snapper-grouper species category.
EPA estimated both a random utility site choice model and a negative binomial trip participation model. The random utility
model assumes that anglers choose the site that provides them with the greatest satisfaction, based on the characteristics of
different sites and the travel costs associated with visiting different sites. The trip participation model assumes that the total
number of trips taken in a year are a function of the value of each site to the angler and characteristics of the angler.
To estimate changes in the quality of fishing sites under different policy scenarios, EPA relied on the recreational fishery
landings data by state and the estimates of recreational losses from I&E on the relevant species at the Tampa Bay CWISs.
The Agency estimated changes in the quality of recreational fishing sites under different policy scenarios in terms of the
percentage change in the historical catch rate. EPA divided losses to the recreational fishery from I&E by the total
recreational landings for the Tampa Bay area to calculate the percentage change in historical catch rate from baseline losses
(i.e., eliminating I&E completely).
C2-3
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C2: Summary of Case Study Results
The results show that anglers targeting black drum have the largest per-trip welfare gain ($7.18 in $2001) from eliminating
I&E in the Tampa region. Anglers targeting spotted seatrout and sheepshead have smaller per-trip gains ($1.80 and $1.77
respectively, in $2001). The large gains for black drum are due to the large predicted increase in catch rates. In general,
based on a hypothetical one fish per trip increase in catch rate, gamefish and snapper-grouper are the most highly valued fish
in the study area, followed by drums and spotted seatrout.
EPA calculated total economic values by combining the estimated per trip welfare gain with the total number of trips to sites
in the Tampa Bay region. EPA used the estimated trip participation model to estimate the percentage change in the number of
fishing trips with the elimination of I&E. These estimated percentage increases are 0.93 percent for anglers who target
sheepshead,0 .94 percent for anglers who target spotted seatrout, and 3.82 percent for anglers who target black drum.
If I&E were eliminated in the Tampa region, EPA estimated total benefits to be $2,428,000 per year at the baseline number of
trips, and $2,458,000 per year at the predicted increased number of trips (all in $2001). At the baseline number of trips, the
I&E benefits to black drum anglers are $270,000 per year; benefits to spotted seatrout anglers are $2,016,000 per year; and
benefits to sheepshead anglers are $143,000 peryear (all in $2001).
EPA merged the results for the RUM analysis with the benefits transfer-based estimates to create an estimate of recreational
fishery losses from I&E in a manner that avoids double counting of the recreation impacts. Baseline economic losses
combining both approaches for all in-scope facilities in Tampa Bay (Big Bend, PL Bartow, FJ Gannon, and Hookers Point)
range from $0.80 million to $0.82 million per year for impingement and from $20.0 million to $20.9 million per year for
entrainment (all in $2001) (see Table C2-2).
For a variety of reasons, EPA believes that the estimates developed here underestimate the value of I&E losses at Tampa Bay
facilities. EPA assumed that the effects of I&E on fish populations are constant over time (i.e., that fish kills do not have
cumulatively greater impacts on diminished fish populations). EPA also did not analyze whether the number offish affected
by I&E would increase as populations increase in response to improved water quality or other improvements in environmental
conditions. In the economic analyses, EPA also assumed that fishing is the only recreational activity affected.
Table C2-2:
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Baseline Impacts (annual average) for Tampa Bay
(Four In -Scope Facilities)
Impingement
> 1 million/yr
> 27,000 Ib/yr
$0.80 million - $0.82 million/yr
Entrainment
> 19 billion/yr
> 56 million Ib/yr
$20.0 million - $20.9 million/yr
Source: U.S. EPA analysis, 2002.
C2-3 OHIO RIVER WATERSHED STUDY (LARGE RIVERS)
Using facility-generated data, EPA evaluated the impacts of I&E along a 500-mile stretch of the Ohio River, from the western
portion of Pennsylvania, along the southern border of Ohio, and into eastern Indiana. EPA evaluated the available I&E
monitoring data at nine case study facilities (W.C. Beckjord, Cardinal, Clifty Creek, Kammer, Kyger Creek, Miami Fort,
Philip Sporn, Tanners Creek, and WH Sammis) and extrapolated the results to the 20 remaining in-scope facilities in the case
study area to derive a cumulative impact estimate for all facilities subject to the proposed rule. The extrapolations were made
on the basis of relative operating size (operating MOD) and by river pool (Hannibal, Markland, McAlpine, New Cumberland,
Pike Island, and Robert C. Byrd pools).
The results indicate that impingement at the nine case study facilities causes the mortality of approximately 188,000 age 1
equivalents of fishery species per year. This translates into over 9,000 pounds of lost fishery yield annually. In addition, over
6.1 million age 1 equivalents of forage species are impinged each year at the nine case study facilities. For entrainment, the
results indicate that about 2.2 million age 1 equivalents of fishery species are lost each year, amounting to some 47,000
pounds of lost fishery yield annually. Entrainment of forage species results in losses of an additional 14.7 million age 1
equivalents each year.
C2-4
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
EPA extrapolated loss rates per MOD of intake flow for the nine case study facilities to all other in-scope cooling water
intake structures in the Ohio River case study area on the basis of intake flow to estimate the total baseline economic value of
I&E at Ohio River facilities. The economic value of these losses is based on benefits transfer-based values applied to losses
to the recreational fishery, nonuse values, and the partial value of forage species impacts (measured as replacement costs or
production foregone). Average historical losses from all in-scope facilities in the case study area for impingement are valued
using benefits transfer at between roughly $0.1 million and $1.4 million per year (in $2001). Average historical losses from
entrainment are valued using benefits transfer at between approximately $0.8 million and $2.4 million per year (all in $2001)
for in-scope facilities.
EPA also estimated a random utility model to provide primary estimates of the recreational fishery losses associated with I&E
in the Ohio River case study area. This primary research results supplement the benefits transfer estimates derived by EPA.
The average annual recreation-related fishery losses at all facilities in the case study amount to approximately $8.4 million (in
$2001) per year (I&E impacts combined). For the in-scope facilities covered by the proposed Phase 2 rule, the losses due to
I&E were estimated via the RUM to amount to approximately $8.3 million per year (in $2001). Results for the RUM analysis
were merged with the benefits transfer-based estimates in a manner that avoids double counting, and indicate that baseline
losses at in-scope facilities amount to between $3.5 million and $4.7 million per year for impingement and between $9.3 and
$9.9 million per year for entrainment (in $2001) (see Table C2-3).
Table C2-3: Baseline Impacts (annual average) in the Ohio River
(29 In -Scope Facilities)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
> 11.3 million/yr
> 14,9001b/yr
$3.5 million - $4.7 million/yr
Entrainment
> 23.0 million/yr
> 39,0001b/yr
$9.3 million - $9.9 million/yr
Source: U.S. EPA analysis, 2002.
In interpreting the results of the case study analysis, it is important to consider several critical caveats and limitations of the
analysis. In the economic valuation component of the analysis, valuation of I&E losses is often complicated by the lack of
market value for forage species, which may comprise a large proportion of total losses. Forage species have no direct market
value, but are nonetheless a critical component of aquatic food webs. EPA included forage species impacts in the economic
benefits calculations, but because techniques for valuing such losses are limited, the final estimates may well underestimate
the full ecological and economic value of these losses.
In addition, the Ohio River case study is intended to reflect the level of I&E, and hence the benefits associated with reducing
I&E impacts, for cooling water impact structures along major rivers of the United States. However, there are several factors
that suggest that the Ohio River case study findings may be a low-end scenario in terms of estimating the benefits of the
proposed regulation at facilities along major inland rivers of the United States. These factors include the following:
C2-5
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C2: Summary of Case Study Results
>• The I&E data developed by the facilities were limited to one year only, are from 1977 (nearly 25 years ago), and
pertain to a period of time when water quality in the case study area was worse than it is currently. This suggests
that the numbers of impinged and entrained fish today (the regulatory baseline) would be appreciably higher than
observed in the data collection period. In addition, the reliance on a monitoring period of one year or less implies
that the naturally high variability in fishery populations is not captured in the analysis, and the results may reflect a
year of below average I&E.
*• The Ohio River is heavily impacted by numerous significant anthropocentric stressors in addition to I&E. The
river's hydrology has been extensively modified by a series of 20 dams and pools, and the river also has been
extensively impacted by municipal and industrial wastewater discharges along this heavily populated and
industrialized corridor. To the degree to which these multiple stressors were atypically extensive along the Ohio
River (in 1977) relative to those along other cooling water intake structure-impacted rivers in the United States (in
2002), the case study will yield smaller than typical I&E impact estimates.
*• The Ohio River is very heavily impacted by cumulative effects of I&E over time and across a large number of
cooling water intake structures. The case study segment of the river has 29 facilities that are in-scope for the Phase 2
rulemaking, plus an additional 19 facilities that are out of scope. Steam electric power generation accounted for
5,873 MOD of water withdrawal from the river basin, more than 90 percent of the total surface water withdrawals,
according to 1995 data from USGS.
Because of these circumstances on the Ohio River, the results EPA obtained for this case study may not underestimate I&E
and regulatory benefits on other inland rivers.
In conclusion, several issues and limitations in the I&E data for the Ohio case study (e.g., the reliance on data for one year,
nearly 25 years ago), and the many stressors that affect the river (especially in the 1977 time frame), suggest that the results
obtained by EPA underestimate the benefits of the rule relative to current Ohio River conditions. The results are also likely to
underestimate the benefits value of I&E reductions at other inland river facilities.
C2-4 SAN FRANCISCO BAY/DELTA (PACIFIC COAST ESTUARIES)
The results of EPA's evaluation of I&E of striped bass and threatened and endangered and other special status fish species at
the Pittsburg and Contra Costa facilities in the San Francisco Bay/Delta demonstrate the significant economic benefits that
can be achieved if losses of highly valued species are reduced by the proposed section 316(b) rule. The benefits were
estimated by reference to other programs already in place to protect and restore the declining striped bass population and
threatened and endangered fish species of the San Francisco Bay/Delta region. The special status species that were evaluated
included delta smelt, threatened and endangered runs of chinook salmon and steelhead, sacramento splittail, and longfin
smelt.
Based on limited facility data, EPA estimated that the striped bass recreational catch is reduced by about 27,203 fish per year
because of impingement at the two facilities and 185,073 fish per year because of entrainment. Estimated impingement losses
of striped bass are valued at between $379,000 and $589,000 per year, and estimated entrainment losses are valued at
between $2.58 million to $4.01 million per year (all in $2001).
EPA estimated that the total loss of special status fish species at the two facilities is over 431,700 age 1 equivalents per year
resulting from impingement and 2.2 million age 1 equivalents per year because of entrainment. Estimated impingement
losses of these species are valued at between $12.38 million and $42.65 million per year, and estimated entrainment losses are
valued at between $23.1 million and $79.2 million per year (all in $2001).
The estimated value of the recreational losses and the special status species losses combined ranges from $12.8 million to
$43.2 million per year for impingement and from $25.6 million to $83.2 million per year for entrainment (all in $2001) (see
Table C2-4).
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C2: Summary of Case Study Results
Table C2-4: Baseline Impacts (annual
average) for Special Status Fish Species in the San Francisco Bay/Delta
(Two In -Scope Facilities)
Baseline Impacts
Age 1 equivalent fish lost
Number of striped bass lost to recreational catch
$ value of combined loss ($2001)
Impingement
>431,700/yr
27,203
$12.8 million - $43.2 million/yr
Entrainment
> 2.. 2 million/yr
185,073
$25.6 million - $83.2 million/yr
Source: U.S. EPA analysis, 2002.
In interpreting these results, it is important to consider several critical caveats and limitations of the analysis. No commercial
fisheries losses or non-special status forage species losses are included in the analysis. Recreational losses are analyzed only
for striped bass. There are also uncertainties about the effectiveness of restoration programs in terms of meeting special status
fishery outcome targets.
It is also important to note that under the Endangered Species Act, losses of all life stages of endangered fish are of concern,
not simply losses of adults. However, because methods are unavailable for valuing losses offish eggs and larvae, EPA
valued the losses of threatened and endangered species based on the estimated number of age 1 equivalents that are lost.
Because the number of age 1 equivalents can be substantially less than the original number of eggs and larvae lost to I&E,
and because the life history data required to calculate age 1 equivalent are uncertain for these rare species, this method of
quantifying I&E losses may result in an underestimate of the true benefits to society of section 316(b) regulation.
C2-5 MT HOPE BAY POINT (NEW ENSLAND ESTUARY)
EPA evaluated cumulative I&E impacts at the Brayton Point Station facility in Mount Hope Bay in Somerset, Massachusetts.
EPA estimates that the cumulative impingement impact is 69,300 age 1 equivalents and 5,100 pounds of lost fishery yield per
year. The cumulative entrainment impact amounts to 3.8 million age 1 equivalents and 70,400 pounds of lost fishery yield
each year.
The results of EP A's evaluation of the dollar value of I&E losses at Brayton Point (as calculated using benefits transfer)
indicate that baseline economic losses range from $7,000 to $12,000 per year for impingement and from $166,000 to
$303,000 per year for entrainment (all in $2001).
EPA also developed an HRC analysis to examine the costs of restoring I&E losses at Brayton Point. These HRC estimates
were merged with the benefits transfer results to develop a more comprehensive range of loss estimates. The HRC results
were used as an upper bound and the midpoint of the benefits transfer method was used as a lower bound (HRC annualized at
7 percent over 20 years). Combining both approaches, the value of I&E losses at Brayton Point ranges from approximately
$9,000 to $890,00 per year for impingement, and from $0.2 million to $28.3 million per year for entrainment (all in $2001)
(see Table C2-5).
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
Table C2-5: Baseline Impacts (annual average) in Mount Hope Bay
(One In -Scope Facility: Brayton Point)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
> 69,300/yr
> 5,100 Ib/yr
$9,000 - $890,000/yr
Entrainment
> 3.8million/yr
> 70,400 Ib/yr
$0.2 mil - $28.3 million/yr
Source: U.S. EPA analysis, 2002.
For a variety of reasons, EPA believes that the estimates developed here underestimate the total economic benefits of
reducing I&E at Brayton Point. EPA assumed that the effects of I&E on fish populations are constant over time (i.e., that fish
kills do not have cumulatively greater impacts on diminished fish populations). EPA also did not analyze whether the number
offish affected by I&E would increase as populations increase in response to improved water quality or other improvements
in environmental conditions. In the economic analyses, EPA also assumed that fishing is the only recreational activity
affected.
C2-6 OCEANS (NEW ENSLAND COAST)
To evaluate potential I&E impacts of cooling water intake structures in oceans of the New England Coast, EPA evaluated
I&E rates at the Pilgrim and Seabrook Nuclear Power Plants. EPA estimated that the impingement impact of Seabrook is
over 13,000 age 1 equivalent fish and over 1,800 pounds of lost fishery yield per year. The entrainment impact is over 4.5
million age 1 equivalent fish and over 29,300 pounds of lost fishery yield per year. The impingement impact of Pilgrim is
over 52,700 age 1 equivalent fish and over 4,200 pounds of lost fishery yield per year. The entrainment impact is over 14.3
million age 1 equivalent fish and over 91,000 pounds of lost fishery yield per year.
EPA's evaluation of I&E rates at Seabrook and Pilgrim indicates that I&E at Seabrook's offshore intake is substantially less
than I&E at Pilgrim's nearshore intake. Impingement per MOD averages 68 percent less at Seabrook and entrainment
averages 58 percent less. The species most commonly impinged at both facilities are primarily winter flounder, Atlantic
herring, Atlantic menhaden, and red hake. These are species of commercial and recreational interest. However, the species
most commonly entrained at the facilities are predominately forage species. Because it is difficult to assign an economic
value to such losses, and because entrainment losses are much greater than impingement losses, the benefits of an offshore
intake or other technologies that may reduce I&E at these facilities are likely to be underestimated. Several important factors
in addition to the intake location (nearshore versus offshore) complicate the comparison of I&E at the Seabrook facility to
I&E at Pilgrim (e.g., entrainment data are based on different flow regimes, different years of data collection, and protocols for
reporting monitoring results).
Average impingement losses at Seabrook are valued at between $3,500 and $5,200 per year, and average entrainment losses
are valued at between $ 142,000 and $315,000 per year (all in $2001) (see Table C2-6). Average impingement losses at
Pilgrim are valued at between $3,300 and $5,000 per year, and average entrainment losses are valued at between $523,500
and $759,300 per year (all in $2001). These values reflect estimates derived using benefits transfer.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
Table C2-6: Baseline Impacts (annual average) in Oceans of the New England Coast
(One In -Scope Facility: Seabrook)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
> 13,000
>l,8001b/yr
$3,000 - $5,000
Entrainment
> 4.5 million/yr
> 29,300 Ib/yr
$142,000 -$315,000
Source: U.S. EPA analysis, 2002.
EPA also developed an HRC analysis to examine the costs of restoring I&E losses at Pilgrim. Using the HRC approach, the
value of I&E losses at Pilgrim is approximately $507,000 for impingement, and over $9.3 million per year for entrainment
(HRC annualized at 7 percent over 20 years) (all in $2001). These HRC estimates were merged with the benefits transfer
results to develop a more comprehensive range of loss estimates.
These HRC estimates were merged with the benefits transfer results to develop a more comprehensive range of loss estimates.
The HRC results were used as an upper bound and the midpoint of the benefits transfer method was used as a lower bound
(HRC annualized at 7 percent over 20 years). Combining both approaches, the value of I&E losses at Pilgrim ranges from
approximately $4,000 to $507,00 per year for impingement, and from $0.6 million to $9.3 million per year for entrainment
(all in $2001) (see Table C2-7).
Table C2-7: Baseline Impacts (annual average) in Oceans of the New England Coast
(One In-Scope Facility: Pilgrim)
Baseline Impacts
Losses
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Losses Using HRC as Upper Bo
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
Using Benefits Transfer
> 52,700 million/yr
> 4,200 Ib/yr
$3,000 - $5,000/yr
unds and Benefits Transfer
> 52,700/yr
> 4,2001b/yr
$4,000 - $507,000/yr
Entrainment
> 214.3 million/yr
>91,0001b/yr
$0.5 million - $0.7 million/yr
Midpoints as Lower
> 14.3 million/yr
> 91,000 Ib/yr
$0.6 million - $9.3 million/yr
Source: U.S. EPA analysis, 2002.
C2-7 THE 6REAT LAKES
To evaluate potential I&E impacts of cooling water intake structures in the Great Lakes, EPA evaluated I&E rates at
J.R. Whiting. EPA estimated that the impingement impact of J.R. Whiting before installation of a deterrent net to reduce
impingement is 21.4 million age 1 equivalent fish and over 844,000 pounds of lost fishery yield per year. The entrainment
impact is 1.8 million age 1 equivalent fish and 70,000 pounds of lost fishery yield per year. After installation of the deterrent
net in 1981, average annual impingement loss at J.R. Whiting was 1.6 million age 1 equivalent fish per year. No entrainment
data was available for this time period.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
EPA examined the estimated economic value of I&E at J.R. Whiting before installation of the deterrent net to estimate the
historical losses of the plant and potential I&E damages at other Great Lakes facilities that do not employ technologies to
reduce impingement or entrainment. Average impingement without the net is valued at between $0.4 million and $1.2 million
peryear, and average entrainment is valued at between $42,000 and $1.7 million per year (all in $2001) (see Table: C2-8).
The midpoints of the pre-net results from the benefits transfer approach were used as the lower ends of the valuations losses.
The upper ends of the valuation of losses reflect results of the HRC method for valuing I&E losses. EPA included the HRC-
based estimates of the economic value of I&E losses at J.R. Whiting with the transfer-based estimates to provide a better
estimate of loss values, particularly for forage species for which valuation techniques are limited.
Table C2-B: Baseline Impacts (annual average) in the Great Lakes
(One In-Scope Facility: J.R. Whiting Without Net)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
>21.4million/yr
> 844,300 Ib/yr
$0.4 million - $1 .2 million/yr
Entrainment
> 1.8 million/yr
> 70,0001b/yr
$42,000 - $1.7 million/yr
Source: U.S. EPA analysis, 2002.
Impingement losses at J.R. Whiting with an aquatic barrier net are estimated to be reduced by 92 percent, while entrainment
losses are not significantly affected. Thus, losses with a net are valued at between $29,000 and $99,000 for impingement and
between $42,000 and $1.7 million per year for entrainment (all in $2001) (see Table C2-9).
Table C2-9: Baseline Impacts (annual average) in the Great Lakes
(One In-Scope Facility: J.R. Whiting With Net)
Baseline Impacts
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
> 1 .6million/yr
> 62,700 Ib/yr
$29,000 - $99,000/yr
Entrainment
n/a
n/a
n/a
Source: U.S. EPA analysis, 2002.
C2-8 LARGE RIVER TRIBUTARY TO THE GREAT LAKES
EPA estimates that the baseline impingement losses at the Monroe facility are 35.8 million age 1 equivalents and 1.4 million
pounds of lost fishery yield per year. Baseline entrainment impacts amount to 11.6 million age 1 equivalents and 608,300
pounds of lost fishery yield each year.
The results of EPA's evaluation of the dollar value of baseline I&E losses at Monroe (as calculated using benefits transfer)
indicate that baseline economic losses range from $502,200 to $981,750 per year for impingement and from $314,600 to
$2,298,500 per year for entrainment (all in $2001).
EPA also developed an HRC analysis to examine the costs of restoring I&E losses at Monroe. These HRC estimates were
merged with the benefits transfer results to develop a more comprehensive range of loss estimates. The HRC results were
used as an upper bound and the midpoint of the benefits transfer method was used as a lower bound (HRC annualized at 7
percent over 20 years). Combining both approaches, the value of I&E losses at Monroe range from approximately $0.7
million to $5.6 million per year for impingement, and from $ 1.3 million to $ 13.9 million per year for entrainment (all in
$2001) (see Table C2-10).
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
For a variety of reasons, EPA believes that the estimates developed here underestimate the total economic benefits of
reducing I&E at the Monroe facility. EPA assumed that the effects of I&E on fish populations are constant over time (i.e.,
that fish kills do not have cumulatively greater impacts on diminished fish populations). EPA also did not analyze whether
the number offish affected by I&E would increase as populations increase in response to improved water quality or other
improvements in environmental conditions. In the economic analyses, EPA also assumed that fishing is the only recreational
activity affected.
Table C2-10: Baseline
Losses at (annual average) in a Large River Tributary to the Great Lakes
(One In -Scope Facility: Monroe using HRC)
Baseline Losses
Age 1 equivalent fish lost
# Ibs lost to landed fishery
$ value of loss ($2001)
Impingement
> 35.8million/yr
> 1 .4 million Ib/yr
$0.7 million -$5.6 million
Entrainment
> 1 1 .6 million/yr
> 608,3001b/yr
$1.3 million -$13.9 million
Source: U.S. EPA analysis, 2002.
C2-9 NATIONAL BASELINE LOSSES DUE TO IMPINSEMENT AND ENTRAINMENT AT
IN-SCOPE FACILITIES
Using the case study results reported above, EPA calculated the average number of age 1 equivalent fish lost per million
gallons of daily average flow at several representative case study sites (one for each waterbody type). EPA then multiplied
these average loss values by the estimated total average daily flow at all in-scope facilities in each waterbody category2. The
result is an estimate of the total number of baseline losses offish impinged and entrained in cooling water intake structures at
in-scope facilities.
2 To estimate the total average daily flow by waterbody type, EPA applied sample weights based on the sampling design for the
316(b) questionnaires to the reported average daily flows and summed the weighted flows by category to obtain an estimated of total
average daily flow at all 550 in-scope facilities, by waterbody type.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C2: Summary of Case Study Results
The results of this analysis indicate that over 1.1 billion age 1 equivalent fish are lost annually as a results of I&Eatthe 550
in-scope facilities. Results by waterbody type are presented in Table C2-11. The national economic value of these losses is
discussed in Chapter C3: National Extrapolation of Baseline Losses of this EBA.
Table C2-11: Estimated Impingement and Entrapment Losses at In-Scope Facilities
(values in millions of age 1 equivalents)
Waterbody Type
Estuary /Tidal River-
North Atlantic3
Estuary /Tidal River-
South Atlantic/Gulf
Freshwater Systems
Great Lake
Ocean
Total
Facility Used to
Extrapolate
Salem
(Delaware)
Big Bend
(Tampa Bay)
9 Ohio Facilities
(Ohio)
JR Whiting
(Great Lakes)
Pilgrim
(Seabrook and Pilgrim)
Impingement
Fishery
Species
84.69
4.57
3.53
528.64
1.55
622.98
Forage
Species
137.49
0.80
114.93
19.58
0.05
272.85
Total
222.18
5.37
118.46
548.22
1.60
895.83
Entrainment
Fishery
Species
1,418.81
134.41
40.85
43.06
78.56
1,715.68
Forage
Species
7,080.16
98,593.63
277.73
3.67
356.66
106,311.85
Total
8,498.97
98,728.04
318.58
46.72
435.22
108,027.53
a Based on I&E losses at Salem assuming 100% through-plant mortality. See Chapter B3: Ecological Risk Assessment mPart
B:The Delaware Estuary of the Watershed Case Study Analysis for the Proposed Section 316(b) Phase II Existing Facilities Rule
for a detailed analysis of I&E losses.
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
Chapter C3: National Extrapolation
of Baseline Losses
INTRODUCTION
In this chapter the case study results detailed in
Chapter C2: Summary of Case Study Results are used to
develop EPA's estimates of baseline losses from
impingement and entrainment (I&E) at in-scope facilities
nationwide. The case study losses are extrapolated to
national losses, by waterbody type, using two methods.
The first method uses data on average daily flow to
capture the stress level the facility places on the
environment. The second method uses data on angling
activity near the facility to capture the level of demand for
the fishery. A combination of these national loss estimates
is then used to develop EPA's best estimates of baseline
losses by waterbody type.
C3 -1 EXTRAPOLATION
CHAPTER CONTENTS
C3-1 Extrapolation Methodology C3-1
C3-1.1 Consideration of Volume of Water (Flow) C3-2
C3-1.2 Consideration of Level of Recreational
Angling C3-2
C3-1.3 Consideration of Waterbody Type C3-3
C3-1.4 Angling and Flow Indices C3-4
C3-1.5 Waterbody Considerations C3-4
C3-1.6 Advantages and Disadvantages of EPA's
Extrapolation Approach C3-5
C3-2 Results of National Benefits Extrapolation C3-5
C3-2.1 Case Study Baseline Losses C3-6
C3-2.2 Extrapolation of Baseline Losses to All Facilities
Using Flow Index C3-7
C3-2.3 Extrapolation of Baseline Losses to All Facilities
Using Angling Index C3-8
C3-2.4 Average of Flow-Based and Angling-Based
Losses C3-9
C3-2.5 Best Estimates C3-10
References C3-12
To compare benefits to costs for a national rulemaking
such as the 316b Phase II existing facility rule, national
estimates of both costs and benefits must be determined. This chapter describes the methods EPA used to estimate national
baseline losses due to I&E. These baseline losses are then used to estimate national benefits in Chapter C4: Benefits.
Baseline losses are very site-specific. This limited EPA's options for developing national-level baseline loss estimates from a
diverse set of 550 in-scope entities. Time, resources, and data limited the number of case studies that could be performed for
proposal, so to interpret these cases in a national context, the Agency identified a range of settings that reflect the likely losses
at a given type of facility (and its key stressor-related attributes) in combination with the characteristics of the waterbody
(receptor attributes) in which it is located. Losses can thus be defined by the various possible combinations of stressor
(facility) and receptor (waterbody, etc.) combinations.
Ideally, case studies would be selected to represent each of these "loss potential" settings and then could be used to
extrapolate to facilities with similar cooling water intake structures. However, data limitations and other considerations
precluded EPA from developing enough case studies to reflect all loss potential settings. Data limitations also made it
difficult to assign facilities to the various loss potential categories.
Based on the difficulties noted above, EPA adopted a more practical, streamlined extrapolation version of its preferred
approach, since this is the only feasible approach available to the Agency. To develop a feasible, tractable manner for
developing national baseline loss estimates from a small number of case study investigations, EPA made its national
extrapolations on the basis of a combination of three relevant variables:
*• the volume of water (operational flow) drawn by a facility;
*• the level of recreational angling activity within the vicinity of the facility; and
>• the type of waterbody on which the facility is located. Extrapolations were then made across facilities according to
their respective waterbody type.
The first of these variables - operational flow (measured as millions of gallons per day, or MOD) - reflects the degree of
stress caused by a facility. The second variable - the number of angler days in the area (measured as the number of
C3-1
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C3: National Extrapolation of Baseline Losses
recreational angling days within a 120 mile radius) - reflects the degree to which there is a demand (value) by local residents
to use the fishery that is impacted. The third variable - waterbody type (e.g., estuary, ocean, freshwater river or lake, or Great
Lakes) - reflects the types, numbers, and lifestages of fish and other biological receptors that are impacted by the facilities.
Accordingly, the extrapolations based on these three variables reflect the key factors that affect losses: the relevant stressor,
the biological receptors, and the human demands for the natural resources and services impacted.
C3-1.1 Consideration of Volume of Water (Flow)
The flow variable the Agency developed for each facility is the flow at the facility (in MOD) divided by the total flow for all
facilities located on the same type of waterbody. Thus, this flow index is the facility's percentage share of the total flow at all
facilities in its waterbody type. Since this flow index has a value between 0 and 1, dividing the baseline loss at a case study
site by the flow index yields an estimate of the total baseline loss at all facilities drawing cooling from the same type of
waterbody.
The MOD levels used to calculate the flow index are based on average operational flows as reported by the facilities in the
EPA 316(b) Detailed Questionnaire and Short Technical Questionnaire responses, or through publically available data.
C3-1.2 Consideration of Level of Recreational Angling
The angler day variable the Agency used is an index based on results from the U.S. Fish and Wildlife Survey as part of its
1996 National Survey of Fishing, Hunting, and Wildlife-Associated Recreation (U.S. DOI, 1997). These data were
interpreted within a GIS-based approach to estimate the level of recreational angling pursued by populations living within 120
miles of each facility.
In developing the index, EPA used a GIS analysis to identify counties where any portion of the county is within a 120-mile
radius of each facility. EPA then defined the area for each facility to include the county the facility is located in and any
other county with at least 50 percent of its population residing within 120 miles of the facility. In total, EPA identified 2,757
counties that were within the 120-mile radius of at least one in-scope facility.
Using estimates of angling activity by state, EPA then estimated angling activity levels for each county within the 120-mile
area. The type of angling days estimated for each county are based on the angling categories defined in the 1996 survey and
the type of waterbody where the facility's cooling water intake structures are located. For facilities located on freshwater
streams, rivers, and lakes (not including the Great Lakes), EPA estimated the total number of freshwater angling days. For
facilities located on an ocean, estuary, or tidal river EPA estimated the total number of saltwater angling days. For facilities
located on one of the Great Lakes, EPA estimated the total number of Great Lakes angling days.
EPA then summed angling days across all counties in a facility's area to yield estimated angling days in the area near the
facility. For each type of angling, EPA estimated angling days by county residents as a percentage of the state angling days
by residents 16 years and older reported in the 1996 survey. Angling days in each state were partitioned into days by urban
anglers and days by rural anglers based on the national percentages reported in the 1996 survey.1 EPA then used these state
urban and rural angling days to estimate the number of angling days in each county within the 120-mile radius of an in-scope
facility.
EPA used the following formula to calculate angling days for urban counties within a 120-mile radius of each in-scope
facility:
TJ , „ , . ,. ~ „„ . TT , . ,. ~ w Urban County Population Within 120 Mile Radius
Urban County Angling Days = State Urban Angling Days x —
State Urban Population
EPA used a similar formula to the one above for calculating rural county angling days within a 120-mile radius of each in-
scope facility.
1 For example, the 1996 national survey found that 58.8% of anglers in the U.S. came from urban areas. So for each state, EPA
assigned 58.8% of the total freshwater angling days reported in the survey to the state's urban angling days and 41.2% to the state's rural
angling days. Similar calculations were performed for saltwater angling and Great Lakes angling.
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C3: National Extrapolation of Baseline Losses
EPA determined urban and rural population by state by summing the 1999 county populations for the state's urban and rural
counties respectively. EPA determined each county's urban/rural status using definitions developed by the U.S. Department
of Agriculture (U.S. DOI, 1997).
Once total angling days were estimated, EPA calculated an angling index value for each facility. Like the flow index, the
angling index is a measure of the facility's percentage share of the total angling days estimated at all in-scope facilities
located on a similar waterbody. This index value provides an indication of the relative level of angling activity at each
facility compared to other in-scope facilities on the same type of waterbody. Since angling index also has a value between 0
and 1, dividing the baseline loss at a case study site by the angling index yields a second estimate of the total baseline loss at
all facilities drawing cooling from the same type of waterbody.
C3-1.3 Consideration of Waterbody Type
a. Estuaries
National baseline losses for estuaries are based on the Salem and Tampa Bay case studies. The case study results are
extrapolated to other facilities on the basis of regional fishery types, to reflect the different types of fisheries that are impacted
in various regions of the country's coastal waters. EPA used the estimated baseline losses from the four Tampa Bay facilities
to extrapolate losses to all in-scope estuarine facilities in Gulf Coast states that were not included in the Tampa Bay case
study. Likewise, the estimated baseline losses at the Salem facility were used to extrapolate to all in-scope estuarine facilities
in states that are not on the Gulf Coast and that were not included in the Salem, Brayton Point, Contra Costa, or Pitsburgh
case studies (note that the Salem results used for the extrapolation differ from the case study results presented above in order
to reflect losses without a screen currently in place at the facility). Ideally, a West Coast facility would have served as the
basis of extrapolation to estuarine facilities along the Pacific Coast, but EPA could not develop a suitable case study for that
purpose in time for this proposal. EPA intends to develop such a western estuary case study and report its findings in an
anticipated forthcoming Notice of Data Availability.
b. Rivers and Lakes
EPA combined rivers, lakes, and reservoirs into one class of freshwater-based facilities (the Great Lakes were considered
separately and are not included in this group). The waterbody classifications for freshwater streams/rivers and
lakes/reservoirs were grouped together for the extrapolation because of the similar ecological and hydrological characteristics
of freshwater systems used as cooling water. The majority of these hydrologic systems have undergone some degree of
modification for purposes such as water storage, flood control, and navigation. The degree of modification can range from
very minor to quite dramatic. A facility in the lake/reservoir category may withdraw cooling water from a lake that has been
reclassified as a reservoir due to the addition of an earthen dam, or from a reservoir created by the diversion of a river through
a diversion canal for use as a cooling lake. The species composition and ecology of these two waterbodies may vary greatly.
While the ecology of river systems and lakes or reservoirs is considerably different, structural modifications can make these
two classifications may be quite similar ecologically, depending on the waterbody in question. For example, many river
systems, including the Ohio River, are now broken up into a series of navigational pools controlled by dams that may function
more like a reservoir than a naturally flowing river.
Baseline I&E losses in the Ohio case study were based on 29 in-scope facilities in the Ohio River case study area. In the
results presented below, EPA used the estimated losses at these 29 facilities to extrapolate to an estimate of national losses at
all in-scope facilities on other freshwater rivers, lakes, and reservoirs that were not included in the Ohio or Monroe case
studies. The extrapolations were performed using both the flow and angling indices.
Because of the large number of facilities in the Ohio study and their proximity to each other, EPA used a slightly different
method to estimate angling activity at these facilities. Rather than calculating the angling days within the 120-mile radius of
each individual facility, EPA instead summed the angling days in all counties within 120 miles of any of the 29 Ohio facilities
and divided this by the number of angling near any freshwater facility nationwide. Essentially, this method treats the 29 Ohio
facilities as one large facility for the purposes of calculating an angling index. This eliminates the problem of multiple-
counting of angling days in counties that occurs because the Ohio facilities are so close to each other.
c. Oceans and Great Lakes
Oceans and Great Lakes estimates were based on extrapolations from the Pilgrim and J.R. Whiting facility case studies,
respectively. For these two facilities (and their associated waterbody types), the valuation method applied by EPA in the
national extrapolations was based on the Habitat-based Replacement Cost (HRC) approach, which reflects values for
addressing a much greater number of impacted species (not just the small share that are recreational or commercial species
that are landed by anglers). For example, at JR Whiting, the benefits transfer approach developed values for recreational
C3-3
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
angling amounted to only 4% of the estimated total impingement losses, and reflected only 0.02 % of the age 1 fish lost due
to impingement. At Pilgrim, the benefits transfer approach reflected recreational losses for only 0.5 % of the entrained age 1
equivalent fish at that site. Because the Agency was able to develop HRC values for these sites and recreational fishery
impacts were such a small part of the impacts, EPA extrapolated only based on HRC estimates and used only the flow-based
(MOD) index for oceans and the Great Lakes.
In the results presented below, EPA used the estimated baseline losses from the Pilgrim facility to extrapolate losses to all in-
scope ocean facilities with the exception of Seabrook, which has an off-shore intake and represents itself. Likewise, the
estimated baseline losses at the J.R. Whiting facility were used to extrapolate to all in-scope Great Lakes facilities that were
not included in the J.R. Whiting case study with the exception of the Monroe facility, which represents itself. The
extrapolations were performed using both the flow and angling indices.
C3-1.4 Flow and Angling Indices
The results of the index calculations for operational flow and angling effort used for extrapolating case study baseline losses
to national baseline losses for all in-scope facilities are reported in Table C3-1.
Waterbody Type
Estuary -N. Atlantic
Estuary-S. Atlantic
Freshwater systems
Great Lake
Ocean
Table C3-1: Flo
Based on
Salem (without screens)
4 Tampa Bay facilities
29 Ohio River facilities
JR Whiting
Pilgrim
w and Angling Indices
Normalized MGD
4.39%
19.24%
9.30%
3.92%
3.42%
Percentage of In-Scope Angling
Base
2.10%
20.28%
12.34%
13.89%
6.54%
Source: U.S. EPA analysis, 2002.
C3-1.5 Waterbody Considerations
EPA further tailored its extrapolation approach to base monetized baseline loss (and benefits) estimates on available data for
similar types of waterbody settings. Thus, for example, the case study results for the Salem facility (located in the Delaware
Estuary) and the Tampa facilities are applied (on a per MGD and angling day index basis) only to other facilities located in
estuary waters. Likewise, results from Ohio River facilities are applied to inland freshwater water cooling water intake
structures (excluding facilities on the Great Lakes), and losses estimated for the Pilgrim plant are applied to facilities using
ocean waters at their intakes, and results for J.R. Whiting are used for the Great Lakes facilities.
As noted above, EPA grouped the waterbody classifications for freshwater rivers and lakes/reservoirs for the extrapolation
based on similar ecological and hydrological characteristics of freshwater systems used as cooling water. The majority of
these hydrologic systems have undergone some degree of modification for purposes such as water storage, flood control, and
navigation. Structural modifications can make these freshwater waterbody types quite similar ecologically. For example,
many river systems, including the Ohio River, are now broken up into a series of navigational pools controlled by dams that
may function more similarly to a reservoir than a naturally flowing river.
The natural species distribution, genetic movement, and seasonal migration of aquatic organisms that may be expected in a
natural system is affected by factors such as dams, stocking of fish, and water diversions. Since the degree of modification of
inland waterbodies and the occurrence offish stocking could not be determined for every cooling water source, EPA grouped
the waterbody categories "freshwater rivers" and "lakes/reservoirs" were grouped together.
The facilities chosen for extrapolation are expected to have relatively average losses per MGD and angling day index, for
their respective waterbody types. Losses per MGD and angling day index are not expected to be extremely high or low
C3-4
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C3: National Extrapolation of Baseline Losses
relative to other facilities. EPA was careful not use facilities that were unusual in this regard. Salem is located in the
transitional zone of the estuary, a lesser productive part of the estuary.
C3-1.6 Advantages and Disadvantages of EPA's Extrapolation Approach
The use of flow and angler day basis for extrapolation has some practical advantages and basis in logic; however, it also has
some less than fully satisfactory implications. The advantages of using this extrapolation approach include:
>• The methods are easily implemented because the extrapolation relies on waterbody type, angler demand, and MOD
data that are available or easily estimated for all in-scope facilities.
*• Selectively extrapolating case study results to facilities on like types of waterbodies reflects the type of aquatic
setting impacted, which is intended to capture the number and types of species impacted by I&E at such facilities
(i.e., impacts at facilities on estuaries are more similar to impacts at other estuary-based cooling water intake
structures than they are to facilities on inland waters).
>• Flow in MOD is a useful proxy for the scale of operation at cooling water intake structures, a variable that typically
will have a large impact on baseline losses and potential regulatory benefits.
>• While there may be a high degree of variability in the actual losses (and benefits) per MOD across facilities that
impact similar water bodies, the extrapolations are expected to be reasonably accurate on average for developing an
order-of-magnitude national-level estimate of benefits. There is no systematic upward or downward bias to these
estimates.
*• The recreational participation level (angler days) variable provides a logical basis to reflect the extent of human user
demands for the fishery and other resources affected by I&E.
>• The national benefit estimates are not biased in either direction.
Some of the disadvantages of the use of extrapolating results on the basis of waterbody type, recreational angling day data,
and operational flows (MOD) include:
*• The approach may not reflect all of the variability that exists in I&E impacts (and monetized losses or benefits)
within waterbody classifications. For example, within and across U.S. estuaries, there may be different species,
numbers of individuals, and life stages present at different cooling water intake structures.
>• The approach may not reflect all of the variability that exists in I&E impacts (and monetized losses or benefits)
across operational flow levels (MOD) at different facilities within a given waterbody type.
Extrapolating to national baseline losses according to flow (MOD), angling levels, and waterbody type, as derived from
estimates for a small number of case studies, may introduce inaccuracies into national estimates. This is because the three
variables used as the basis for the extrapolation (MOD, recreational angling days, and waterbody type) may not account for
all of the variability expected in site-specific benefits levels. The case studies may not reflect the average or "typical" cooling
water intake structures impacts on a specific waterbody (i.e., the extrapolated results might under- or overstate the physical
and dollar value of impacts per MOD and fishing day index, by waterbody type for a specific facility). The inaccuracies
introduced to the national-level estimates by this extrapolation approach are of unknown magnitude or direction (i.e., the
estimates may over- or understate the anticipated national-level benefits); however, EPA has no data to indicate that the case
study results are atypical for any of the waterbody types analyzed or that they are in any way biased.
C3-2 RESULTS OF NATIONAL BENEFITS EXTRAPOLATION
EPA developed estimates of national benefits attributable to the proposed rule in two main stages. In the first stage, national
baseline losses were estimated. The methods used for this analysis are detailed above and the results are presented below. In
the second, EPA applied the expected reductions under several regulatory options to the national baseline loss estimates to
calculated expected benefits of the rule. EPA's benefits estimates are presented in Chapter C4: Benefits.
C3-2.1 Case Study Baseline Losses
In the first step of the baseline loss extrapolation, EPA used the baseline losses (dollars per year) derived from the analysis of
facilities examined in the case studies. In some instances, the case study facilities had already implemented some measures to
reduce impingement and/or entrainment. In such cases, baseline losses as appropriate to the national extrapolation were
estimated using data for years prior to the facilities' actions (e.g., based on I&E before the impingement deterrent net was
installed at J.R. Whiting). These pre-action baselines provide a basis for examining other facilities that have not yet taken
-------
§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
actions to reduce impingement and/or entrainment. Baseline losses at the selected case study facilities are summarized in
Table C3-2.
Table C3-2: Baseline Losses from Selected Case Studies (in thousands, $2001)
Case Study
Salem
Brayton Point
Contra Costa
Pittsburgh
4 Tampa Bay
Facilities
29 Ohio Facilities
Monroe
JR Whiting
Pilgrim Nuclear
Seabrook Nuclear
Impingement
Low
$528
$9
$2,666
$10,096
$801
$3,452
$742
$358
$4
$3
Mid
$704
$450
$5,726
$22,268
$809
$4,052
$3,190
$797
$256
$4
High
$879
$890
$8,785
$34,440
$817
$4,652
$5,639
$1,235
$507
$5
Entrainment
Low
$16,766
$235
$6,413
$19,166
$20,007
$9,257
$1,307
$42
$642
$142
Mid
$23,657
$14,261
$13,630
$40,760
$20,454
$9,584
$7,604
$873
$4,960
$229
High
$30,548
$28,288
$20,847
$62,354
$20,901
$9,912
$13,902
$1,703
$9,279
$315
Source: U.S. EPA analysis, 2002.
C3-6
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
C3-2.2 Extrapolation of Baseline Losses to All Facilities Using Flow Index
In the second step, EPA extrapolated the baseline dollar loss estimates from the case study models to all 539 facilities that
responded to the Agency's facility survey by dividing the estimated dollar losses at baseline per unit flow by the sum of the
index of operational flow for each non-case study facility. This extrapolation was done by source waterbody type. This
resulted in a national estimate of baseline monetizable losses for all 539 responding facilities as summarized in Table C3-3.2
Table C3-3: Baseline Losses Extrapolated to All In-Scope Facilities Using M6D Only0 (in thousands, $2001)
Facility
Case Study
Impingement
Low
Estuary
Salem
Brayton Point
Contra Costa
Pittsburgh
All Other In-Scope
Total (78 In-Scope Facilities)
Delaware
Brayton
California
California
...
—
$528
$9
$2,666
$10,096
$11,167
$24,467
Estuary -
4 Tampa Facilities
All Other In-Scope
Total (30 In-Scope Facilities)
Tampa Bay
...
—
$801
$3,361
$4,162
Fres
29 Ohio Facilities
Monroe
All Other In-Scope
Total (393 In-Scope Facilities)
Ohio
Monroe
...
—
$3,452
$742
$33,317
$37,511
Grec
JR Whiting
All Other In-Scope
Total (16 In-Scope Facilities)
JR Whiting
...
—
$358
$8,774
$9,132
0
Pilgrim Nuclear
Seabrook Nuclear
All Other In-Scope
Total (22 In-Scope Facilities)
Pilgrim
Seabrook
...
—
$4
$3
$110
$118
All In-Sec
Total (539 In-Scope Facilities)
—
$75,388
Mid
- Non 6ulf
$704
$450
$5,726
$22,268
$14,875
$44,022
Gulf Coasl
$809
$3,395
$4,204
fiwater
$4,052
$3,190
$39,111
$46,353
t Lake
$797
$19,523
$20,319
cean
$256
$4
$6,886
$7,146
>pe Facilitie
$122,045
High
Entrainment
Low
$879
$890
$8,785
$34,440
$18,583
$63,578
$16,766
$235
$6,413
$19,166
$354,346
$396,925
1-
$817
$3,429
$4,247
$20,007
$83,982
$103,989
$4,652
$5,639
$44,906
$55,196
$9,257
$1,307
$89,348
$99,911
$1,235
$30,271
$31,506
$42
$1,025
$1,067
$507
$5
$13,662
$14,174
$642
$142
$17,290
$18,074
s
$168,701
$619,966
Mid
$23,657
$14,261
$13,630
$40,760
$499,991
$592,298
$20,454
$85,857
$106,311
$9,584
$7,604
$92,514
$109,702
$873
$21,385
$22,257
$4,960
$229
$133,676
$138,865
$969,434
High
$30,548
$28,288
$20,847
$62,354
$645,636
$787,672
$20,901
$87,732
$108,633
$9,912
$13,902
$95,679
$119,493
$1,703
$41,745
$43,448
$9,279
$315
$250,062
$259, 656
$1,318,902
a Baseline losses are estimated based on survey data from 539 in-scope facilities and include baseline closures.
Source: U.S. EPA analysis, 2002.
2 Data from the 316(b) questionnaire were available for 539 of the estimated 550 in-scope facilities. EPA presents sample-weighted
benefits estimates in Chapter C4 that reflect baseline losses and benefits at all 550 in-scope facilities. Un-weighted benefits estimates are
presented in Appendix C1.
C3-7
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
C3-2.3 Extrapolation of Baseline Losses to All Facilities Using Angling Index
In the third step, the Agency extrapolated the baseline dollar loss estimates from the case studies to all in-scope facilities in
the database by dividing baseline losses from the case study models by the sum of the angling index values for all non-case
study facilities. This was done by source waterbody type. The calculation of the index is described above. The results are
summarized in Table C3-4.
Table C3-4: Baseline Losses Extrapolated - Angling Days Only0
(in thousands, $2001)
Facility
Case
Study
Impingement
Low
Estuary
Salem
Brayton Point
Contra Costa
Pittsburgh
All Other In-Scope
Total (78 In-Scope Facilities)
Delaware
Brayton
California
California
...
—
$528
$9
$2,666
$10,096
$23,840
$37,139
Estuary
4 Tampa Facilities
All Other In-Scope
Total (30 In-Scope Facilities)
Tampa Bay
—
—
$801
$3,148
$3,949
Fre
29 Ohio Facilities
Monroe
All Other In-Scope
Total (393 In-Scope Facilities)
Ohio
Monroe
—
—
$3,452
$742
$23,203
$27,396
Gre
JR Whiting
All Other In-Scope
Total (16 In-Scope Facilities)
JR Whiting
—
—
$358
$2,220
$2,578
c
Pilgrim Nuclear
Seabrook Nuclear
All Other In-Scope
Total (22 In-Scope Facilities)
Pilgrim
Seabrook
...
—
$4
$3
$54
$62
All In-S<
Total (539 In-Scope Facilities)
—
$71,125
Mid
- Non Gull
$704
$450
$5,726
$22,268
$31,755
$60,903
- Sulf Coa:
$809
$3,180
$3,989
shwater
$4,052
$3,190
$27,238
$34,480
at Lake
$797
$4,940
$5,737
)cean
$256
$4
$3,402
$3,662
ope Faciliti
$108,771
High
Entrainment
Low
f
$879
$890
$8,785
$34,440
$39,671
$84,667
$16,766
$235
$6,413
$19,166
$756,471
$799,050
t
$817
$3,212
$4,029
$20,007
$78,664
$98,672
$4,652
$5,639
$31,273
$41,564
$9,257
$1,307
$62,224
$72,787
$1,235
$7,660
$8,895
$42
$259
$301
$507
$5
$6,750
$7,262
$642
$142
$8,543
$9,326
es
$146,418
$980,137
Mid
$23,657
$14,261
$13,630
$40,760
$1,067,399
$1,159,706
$20,454
$80,421
$100,875
$9,584
$7,604
$64,429
$81,617
$873
$5,411
$6,284
$4,960
$229
$66,047
$71,236
$1,419,718
High
$30,548
$28,288
$20,847
$62,354
$1,378,327
$1,520,363
$20,901
$82,177
$103,078
$9,912
$13,902
$66,633
$90,447
$1,703
$10,564
$12,267
$9,279
$315
$123,551
$133,145
$1,859,300
a Baseline losses are estimated based on survey data from 539 in-scope facilities and include baseline closures.
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
C3-2.4 Average of Flow-Based and Angling-Based Losses
As a fourth step, EPA calculated the average baseline losses of the flow-based results and the angling-based results. This
develops results that reflect an equally-weighted extrapolation measure of each case study facility's baseline loss, based on
it's percent share of flow and recreational fishing relative to all in-scope facilities in each waterbody type. The results of this
average are reported in Table C3-5.
Table C3-5: Baseline Losses Extrapolated to All In-Scope Facilities - Means of MGD and Angling0
(in thousands, $2001)
Facility
Case
Study
Impingement
Low
Estuary
Salem
Brayton Point
Contra Costa
Pittsburgh
All Other In-Scope
Total (78 In-Scope Facilities)
Delaware
Brayton
California
California
—
—
$528
$9
$2,666
$10,096
$17,503
$30,803
Estuary
4 Tampa Facilities
All Other In-Scope
Total (30 In-Scope Facilities)
Tampa Bay
—
—
$801
$3,255
$4,055
Fre
29 Ohio Facilities
Monroe
All Other In-Scope
Total (393 In-Scope Facilities)
Ohio
Monroe
—
—
$3,452
$742
$28,260
$32,453
Gre
JR Whiting
All Other In-Scope
Total (16 In-Scope Facilities)
JR Whiting
—
—
$358
$5,497
$5,855
c
Pilgrim Nuclear
Seabrook Nuclear
All Other In-Scope
Total (22 In-Scope Facilities)
Pilgrim
Seabrook
—
—
$4
$3
$82
$90
All In-S<
Total (539 In-Scope Facilities)
—
$73,257
Mid
- Non Gull
$704
$450
$5,726
$22,268
$23,315
$52,463
- Sulf Coa<
$809
$3,288
$4,097
shwater
$4,052
$3,190
$33,175
$40,417
at Lake
$797
$12,231
$13,028
)cean
$256
$4
$5,144
$5,404
ope Faciliti
$115,408
High
Entrainment
Low
f
$879
$890
$8,785
$34,440
$29,127
$74,122
$16,766
$235
$6,413
$19,166
$555,409
$597,988
t
$817
$3,321
$4,138
$20,007
$81,323
$101,330
$4,652
$5,639
$38,089
$48,380
$9,257
$1,307
$75,786
$86,349
$1,235
$18,966
$20,201
$42
$642
$684
$507
$5
$10,206
$10,718
$642
$142
$12,916
$13,700
es
$157,559
$800,051
Mid
$23,657
$14,261
$13,630
$40,760
$783,695
$876,002
$20,454
$83,139
$103,593
$9,584
$7,604
$78,471
$95,660
$873
$13,398
$14,271
$4,960
$229
$99,861
$105,050
$1,194,576
High
$30,548
$28,288
$20,847
$62,354
$1,011,981
$1,154,017
$20,901
$84,955
$105,856
$9,912
$13,902
$81,156
$104,970
$1,703
$26,154
$27,858
$9,279
$315
$186,806
$196,401
$1,589,101
3 Baseline losses are estimated based on survey data from 539 in-scope facilities and include baseline closures.
Source: U.S. EPA analysis, 2002.
C3-9
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C3: National Extrapolation of Baseline Losses
C3-2.5 Best Estimates
In the fifth step, EPA selected the set of extrapolation values the Agency believes are the most reflective of the baseline loss
scenarios for each waterbody type. For estuaries and freshwater facilities, EPA used the midpoint of its loss estimates of I&E
at the case study facilities, and then applied the average of the MOD- and angler-based extrapolation results. This provides
estimates of national baseline losses that reflect the broadest set of values and parameters (i.e., the full range of loss estimates,
plus the application of all three extrapolation variables).
For oceans and the Great Lakes, EPA developed national-scale estimates using its HRC-based loss estimates. These HRC
estimates are most appropriate because these HRC values are more comprehensive than the values derived using the more
traditional benefits transfer approach. The HRC estimates cover losses for a much larger percentage offish lost due to I&E,
whereas the benefits transfer approach addressed losses only for a small share of the impacted fish. Since recreational fish
impacts were an extremely small share of the total fish impacts at these sites, EPA extrapolated the HRC findings using only
the MGD-based index (i.e., the angler-based index was not relevant).
The results of EPA's assessment of its best estimates for baseline losses due to I&E are shown in Table C3-6.
C3-10
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C3: National Extrapolation of Baseline Losses
Table C3-6: Best Estimate Baseline Losses" b
(in thousands, $2001)
Facility Case Study
Impingement
Entrainment
Estuary - Non Gulf
Salem Delaware
Brayton Point Brayton
Contra Costa California
Pittsburgh California
All Other In-Scope
Total (78 In-Scope Facilities)
$704
$450
$5,726
$22,268
$23,315
$52,463
$23,657
$14,261
$13,630
$40,760
$783,695
$876,002
Estuary - Gulf Coast
4 Tampa Facilities Tampa Bay
All Other In-Scope
Total (30 In-Scope Facilities)
$809
$3,288
$4,097
$20,454
$83,139
$103,593
Freshwater
29 Ohio Facilities Ohio
Monroe Monroe
All Other In-Scope
Total (393 In-Scope Facilities)
$4,052
$3,190
$30,891
$38,133
$9,584
$7,604
$73,069
$90,258
Great Lake
JR Whiting JR Whiting
All Other In-Scope
Total (1 6 In-Scope Facilities)
$1,235
$30,271
$31,506
$1,703
$41,745
$43,448
Ocean
Pilgrim Nuclear Pilgrim
Seabrook Nuclear Seabrook
All Other In-Scope
Total (22 In-Scope Facilities)
$507
$5
$13,662
$14,174
$9,279
$315
$250,062
$259,656
All In-Scope Facilities
Total (539 In-Scope Facilities)
$142,656
$1,378,359
a Baseline losses are estimated based on survey data from 539 in-scope facilities and include baseline closures.
b Facilities in bold, were used for extrapolation.
Source: U.S. EPA analysis, 2002.
C3-11
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C3: National Extrapolation of Baseline Losses
REFERENCES
U.S. Department of the Interior (U.S. DOI), Fish and Wildlife Service, and U.S. Department of Commerce (U.S. DOC),
Bureau of the Census. 1997. 1996 National Survey of Fishing, Hunting, and Wildlife-Associated Recreation.
C3-12
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C4: Benefits
Chapter C4: Benefits
INTRODUCTION
Using the national baseline loss estimates reported in
Chapter C3: National Extrapolation of Baseline Losses,
EPA estimated the potential national benefits of each
regulatory option by applying a set of estimated percent
reductions to baseline losses. The estimates were
developed using sample weights based on the sampling
design for the 316(b) questionnaires. These weights were
used to generate benefits estimates for all 550 in-scope
facilities based on the baseline losses for 539 in-scope
facilities for which questionnaire data was available.
Estimates of benefits for only the 539 in-scope facilities can
be found in the Appendix to Chapter Cl.
CHAPTER CONTENTS
C4-1 Options with Benefit Estimates C4-1
C4-2 Impingement Reductions and Benefits C4-2
C4-3 Entrainment Reductions and Benefits C4-3
C4-4 Certainty Levels Associated with the Benefits
Estimates of Various Options C4-4
C4-5 Benefits Associated with Various Impingement and
Entrainment Percentage Reductions C4-5
C4-6 Impingement and Entrainment Benefits Associated with
The Proposed Option C4-5
The percent reduction in baseline losses for each facility reflects EPA's assessment of (1) regulatory baseline conditions at
the facility (i.e., current practices and technologies in place), and (2) the percent reductions in impingement and entrainment
that EPA estimated would be achieved at each facility that the Agency believes would be adopted under each regulatory
option.
C4-1 OPTIONS WITH BENEFIT ESTIMATES
EPA estimated benefits for the following six options. These options include:
*• Option 1: Track I of the waterbody /capacity-based option;
>• Option 2: Track I and II of the waterbody /capacity-based option;
*• Option 3: (the Agency's proposed rule), impingement and entrainment controls everywhere with exceptions for low-
flow facilities on lakes and rivers;
*• Option 3a: impingement and entrainment controls everywhere with no exceptions;
>• Option 4: requires all Phase II existing facilities to reduce intake capacity commensurate with the use of closed-
cycle, recirculating cooling systems; and
*• Option 5: requires that all Phase II existing facilities reduce intake capacity commensurate with the use of dry
cooling systems.
*• Option 6: similar to Optionl, but requires reduction commensurate with the use of closed-cycle, recirculating
systems for all facilities on estuaries, tidal rivers, and oceans
A complete description of the options detailed in the following tables can be found in Chapter A1: Introduction and Overview
of this Economic and Benefits Analysis (EBA). Benefits detailed in this chapter are the flow-weighted average reductions
across all facilities in each water body category for each regulatory option.. See Chapter C3: National Extrapolation of
Baseline Losses for a discussion on the methodology used to extrapolate benefits.
C4-1
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C4: Benefits
C4-2 IMPINSEMENT REDUCTIONS AND BENEFITS
Table C4-1 presents the percentage reductions in impingement that are expected to occur under the six options listed above
and Table C4-2 presents the benefit value associated with those reductions.
Table C4-1: National Impingement Benefits for Various Options - By reduction Level
Waterbody Type
Estuary - Non-Gulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Baseline
Impingement
Loss
$57,802
$4,098
$40,813
$31,506
$15,136
$149,356
Percentage Reductions
Option 1
64.4%
63.2%
47.2%
80.0%
72.8%
_
Option 2
47.5%
45.9%
47.2%
80.0%
59.0%
Option 3
33.2%
27.1%
47.2%
80.0%
50.1%
Option
3a
25.5%
30.0%
46.6%
77.0%
46.5%
Option 4
41.4%
45.3%
58.9%
88.6%
58.9%
Option 5
97.5%
96.7%
98.0%
96.3%
87.6%
Option 6
84.4%
79.4%
47.7%
80.0%
77.7%
Source: U.S. EPA analysis, 2002.
Table C4-2: National Impingement Benefits for Various Options - By Benefit Level (in thousands, $2001)
Waterbody Type
Estuary - Non-Gulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Baseline
Impingement
Loss
$57,802
$4,098
$40,813
$31,506
$15,136
$149,356
Benefits
Option 1
$37,233
$2,590
$19,282
$25,205
$11,020
$95,330
Option 2
$27,452
$1,883
$19,282
$25,205
$8,923
$82,744
Option 3
$19,193
$1,109
$19,282
$25,205
$7,587
$72,375
Option
3a
$14,754
$1,230
$19,015
$24,260
$7,034
$66,294
Option 4
$23,924
$1,857
$24,041
$27,900
$8,912
$86,633
Option 5
$56,338
$3,963
$39,991
$30,326
$13,265
$143,883
Option 6
$48,777
$3,254
$19,471
$25,205
$11,763
$108,470 |
Source: U.S. EPA analysis, 2002.
C4-2
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C4: Benefits
C4-3 ENTRAINMENT REDUCTIONS AND BENEFITS
Table C4-3 presents the percentage reductions in impingement that are expected to occur under the six options listed above
and Table C4-4 presents the benefit value associated with those reductions.
Table C4-3: National Entrainment Benefits for Various Options - By Reduction Level
Waterbody Type
Estuary - Non-Gulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Baseline
Loss
$936,275
$103,635
$96,597
$43,448
$277,269
$1,457,225
Entrainment Percentage Reductions
Option 1
67.3%
66.9%
12.4%
57.8%
72.9%
Option 2
59.3%
52.3%
12.4%
57.8%
57.8%
Option 3
48.5%
47.2%
12.4%
57.8%
44.1%
Option
3a
47.3%
47.8%
44.2%
57.8%
44.1%
Option 4
79.4%
79.3%
72.8%
88.6%
72.8%
Option 5
97.5%
96.7%
98.0%
96.3%
87.6%
Option 6
$48,777
$3,254
$19,471
$25,205
$11,763
$108,470 |
Source: U.S. EPA analysis, 2002.
Table C4-4: National Entrainment Benefits for Various Options By Benefit Level (in thousands, $2001)
Waterbody Type
Estuary - NonGulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Baseline
Loss
$936,275
$103,635
$96,597
$43,448
$277,269
$1,457,225
Entrainment Benefit
Option 1
$630,568
$69,352
$11,957
$25,092
$202,116
$939,085
Option 2
$555,238
$54,229
$11,957
$25,092
$160,288
$806,803
Option 3
$453,938
$48,910
$11,957
$25,092
$122,351
$662,248
Option
3a
$443,239
$49,529
$42,737
$25,092
$122,351
$682,949
Option 4
$743,085
$82,220
$70,310
$38,474
$201,983
$1,136,073
Option 5
$912,568
$100,216
$94,652
$41,820
$242,989
$1,392,246
Option 6
$732,964
$81,194
$9,472
$25,092
$201,983
$1,050,705 |
Source: U.S. EPA analysis, 2002.
C4-3
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C4: Benefits
C4-4 CERTAINTY LEVELS ASSOCIATED WITH BENEFIT ESTIMATES OF VARIOUS
OPTIONS
Table C4-5 presents information detailing differences in levels of uncertainty associated with the different options.
Table C4-5: Certainty of Benefits Estimates
Option
Option 1
Waterbody/
Capacity-Based
Option
(Allows two tracks)
Option 2
Proposed Rule
(Option 3)
Impingement Mortality and
Entrainment Controls
Everywhere
(Option 3a)
All Cooling Towers
(Option 4)
Dry Cooling
(Option 5)
Waterbody-Based
(Option 6)
Characteristics / Assumptions
assumes everyone will use Track 1
assumes that 20 sample facilities
will use Track 2
impingement and entrainment
controls everywhere with
exceptions for low-flow facilities on
lakes and rivers
impingement and entrainment
controls everywhere with no
exceptions
requires reduction commensurate
with the use of closed-cycle,
recirculating systems
requires reduction commensurate
with the use of dry cooling systems
Similar to Optionl , but requires
reduction commensurate with the
use of closed-cycle, recirculating
systems for all facilities on
estuaries, tidal rivers, and oceans
Associated with the Various Options
Certainty of Achieving Predicted Reductions and
Benefits
Very certain for the 5 1 facilities assumed to install cooling
towers. Expected percentage reductions are within a
limited range
Less certain for other facilities as technology is unknown
Expected percentage reductions are within a limited range
Less certain for other facilities as technology that would
be chosen is unknown.
Uncertainty due to assumptions about the number of
facilities that may choose Track 2 instead of Track 1
Very certain for the 33 facilities assumed to install cooling
towers.
Uncertain because the technologies chosen by facilities is
unknown
Number of facilities that would request alternative less
stringent requirements based on costs is unknown.
Number of facilities that would request alternative less
stringent requirements based on benefits is unknown.
Fairly certain, but the technologies chosen by facilities is
unknown
Very certain for the 470 facilities installing wet cooling
towers. Expected percentage reductions are within a
limited range
Extremely certain for the 539 facilities installing dry
cooling
Very certain for the 109 facilities assumed to install
cooling towers. Expected percentage reductions are
within a limited range
Less certain for other facilities as technology is unknown
Source: U.S. EPA analysis, 2002.
C4-4
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§ 316(b) Phase II EBA, Part C: National Benefits
Chapter C4: Benefits
C4-5 BENEFITS ASSOCIATED WITH VARIOUS PERCENTAGE REDUCTIONS
In addition to percentage reductions by option, EPA developed a more generic illustration of potential benefits, based on a
broad range (from 10 percent to 90 percent) of potential reductions in impingement and entrainment. These results are
shown in Table C4-6.
Table C4-6: Summary of Potential Benefits Associated with Various
Impingement and Entrainment Reduction Levels
Reduction Level
10%
20%
30%
40%
50%
60%
70%
80%
90%
Benefits
Impingement
$14,936
$29,871
$44,807
$59,742
$74,678
$89,613
$104,549
$119,484
$134,420
(in thousands, $2001)
Entrainment
$145,722
$291,445
$437,167
$582,890
$728,612
$874,335
$1,020,057
$1,165,780
$1,311,502
Source: U.S. EPA analysis, 2002.
C4-6 BENEFITS ASSOCIATED WITH THE PROPOSED OPTION
Table C4-7 presents the benefits that would occur with various percentage reductions
Table C4-7: Summary of Benefits from Impingement Controls Associated
with the Proposed Rule (Option 3)
Waterbody Type
Estuary - NonGulf
Estuary - Gulf
Freshwater
Great Lake
Ocean
Total
Benefits (in
Impingement
$19,193
$1,109
$19,282
$25,205
$7,587
$72,375
thousands, $2001)
Entrainment
$453,938
$48,910
$11,957
$25,092
$122,351
$662,248
Source: U.S. EPA analysis, 2002.
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§ 316(b) Phase II EBA, Part C: National Benefits Chapter C4: Benefits
Under today's proposal, facilities can choose the Site-Specific Determination of Best Technology Available in § 125.94(a) in
which a facility can demonstrate to the Director that the cost of compliance with the applicable performance standards in §
125.94(b) would be significantly greater than the costs considered by EPA when establishing these performance standards, or
the costs would be significantly greater than the benefits of complying with these performance standards. EPA expects that if
facilities were to choose this approach, then the overall national benefits of this rule will decrease markedly. This is because
under this approach facilities would choose the lowest cost technologies possible and not necessarily the most effective
technologies to reduce impingement and entrainment at the facility.
The estimates that appear in this chapter are weighted estimates of benefits at all 550 in-scope facilities. The weights use are
based on the sampling design for the 316(b) questionnaires. See the Appendix to Chapter Cl for the benefit estimates on an
unweighted basis.
C4-6
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Chapter Dl: Comparison of National
Costs and Benefits
INTRODUCTION
This chapter summarizes total private costs, develops social
costs, and compares total social costs to total benefits at the
national level for the proposed rule and five alternative
regulatory options.
CHAPTER CONTENTS
Dl-l Social Costs Dl-2
Dl-2 Summary of National Benefits and Social Costs Dl-4
Glossary Dl-5
Table Dl-l shows compliance response assumptions for the proposed rule and five alternative regulatory options based on
each facility's current technologies installed, capacity utilization, waterbody type, annual intake flow, and design intake flow
as a percent of source waterbody mean annual flow. Chapter Al: Introduction and Overview includes a more detailed
discussion of compliance responses under the proposed rule and alternative regulatory options.
Table Dl-l: Number of Facilities by Compliance Assumption and Regulatory Option
(based on 539 sample facilities)
Facility Compliance
Assumption
Cooling tower in
baseline (no action)
Impingement
Controls Only
Impingement and
Entrainment Controls
Flow Reduction
Technology
Waterbody/Capacity-
Based Option
(Allows two tracks)
Option 1 Option 2
69 69
241 241
178 198
51 31
Proposed
Rule"
(Option 3)
69
241
229
0
Impingement
Mortality and
Entrainment Controls
Everywhere Option
(Option 3a)
69
53
417
0
All
Cooling
Towers
Option
(Option 4)
69
53
0
417
Dry
Cooling
Option
(Option
5)
69
241
178
51
Waterbody-
Based
Option
(Option 6)
69
241
120
a Alternative less stringent requirements based on both costs and benefits are allowed. There is some uncertainty in predicting
compliance responses because the number of facilities requesting alternative less stringent requirements based on costs and
benefits is unknown.
Source: U.S. EPA analysis, 2002.
Dl-l
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
Dl-1 SOCIAL COSTS
This section develops EPA's estimates of the costs to society associated with the proposed rule. The social costs of
regulatory actions are the opportunity costs to society of employing scarce resources in pollution prevention and pollution
control activities. The compliance costs used to estimate total social costs differ in their consideration of taxes from those in
Part B: Costs and Economic Impacts, which were calculated for the purpose of estimating the private costs and impacts of the
rule. For the impact analyses, compliance costs are measured as they affect the financial performance of the regulated
facilities and firms. The analyses therefore explicitly consider the tax deductibility of compliance expenditures.1 In the
analysis of costs to society, however, these compliance costs are considered on a pre-tax basis. The costs to society are the
full value of the resources used, whether they are paid for by the regulated facilities or by all taxpayers in the form of lost tax
revenues.
To assess the economic costs to society of the proposed regulation, EPA relied first on the estimated costs to facilities for the
labor, equipment, material, and other economic resources needed to comply with the proposed rule. In this analysis, EPA
assumes that the market prices for labor, equipment, material, and other compliance resources represent the opportunity costs
to society for use of those resources in regulatory compliance. EPA also assumes that the lost revenue from energy penalties
and construction outage - which is recognized as a compliance cost - approximates the cost of the replacement energy that
would be provided by other generating units. Implicit in this assumption is that the variable production cost of the
replacement energy sources is essentially the same as the energy price received, on the margin, for production of the
replacement energy. This assumption is consistent with the market equilibrium concept that the variable production cost of
the last generating unit to be dispatched will be approximately the same as the price received for the last unit of production.
Finally, EPA assumes in its social cost analysis that the regulation does not affect the aggregate quantity of electricity that
would be sold to consumers and, thus, that the regulation's social cost will include no loss in consumer and producer surplus
from lost electricity sales by the electricity industry in aggregate. Given the very small impact of the regulation on electricity
production cost for the total industry, EPA believes this assumption is reasonable the social cost analysis.
Other components of social costs include costs to federal and state governments of administering the permitting and
compliance monitoring activities under the proposed regulation.2 Chapter B5: UMRA Analysis presents more information on
state and federal implementation costs.
EPA's estimate of social costs includes three components:
*• (1) direct costs of compliance incurred by in-scope facilities,
*• (2) administrative costs incurred by state governments, and
>• (3) administrative costs incurred by the federal government.
The estimated after-tax annualized compliance costs incurred by facilities under the proposed Phase II rule are $182 million
(see Chapter Bl: Summary of Compliance Costs, Table Bl-6). The estimated social value of these compliance costs,
calculated on a pre-tax basis is $279 million. EPA estimates that state implementation costs for the proposed rule are $3.6
million annually and that federal implementation costs are approximately $62,000. The estimated total social costs of the
Proposed Phase II Existing Facilities Rule are therefore $283 million.
Total social costs for the four alternative regulatory options range from $300 million for the impingement mortality and
entrainment controls everywhere option (Option 3a) to $3,507 million for the all cooling towers option (Option 4).3
1 Costs incurred by government facilities and cooperatives are not adjusted for taxes, since these facilities are not subject to income
taxes.
2 State and federal implementation costs were developed for the proposed rule and Options 1 and 2 only. EPA assumed that the costs
for Option 3a would be similar to the proposed rule and that the costs for Options 4 and 5 would be similar to Option 1.
3 Note that EPA did not develop costs for Option 6.
Dl-2
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Table Dl-2 summarizes the total private and social costs of the proposed rule and five alternative regulatory options.
Table Dl-2: Total Private and Social Costs of Compliance by Option ($2001; million)
Option
Waterbody/ All Track I
Capacity-Based ..^™..}).
^n^ t t ^ Track I and II
(Allows two tracks) (Option2)
Proposed Rule
(Option 3)
Alternative less stringent
requirements based on both costs
and benefits are allowed.
Impingement Mortality and
Entrainment Controls Everywhere
Option
(Option 3 a)
All Cooling Towers Option
(Option 4)
Dry Cooling Option
(Option 5)
Waterbody-Based Option
(Option 6)
Total Private
Compliance
Costs to
Facilities
(Post-tax)
$595
$379
$182
$195
$2,316
$1,252
Social Costs
Pre-Tax State Federal
Compliance Implementation Implementation
Costs to Facilities Costs Costs
$968 $1.4 $0.04
$609 $1.4 $0.04
$279 $3.6 $0.1
$296 $3.6 $0.1
$3,506 $1.4 $0.04
$2,052 $1.4 $0.04
Total
Social
Costs
$969
$610
$283
$300
$3,507
$2,054
Not costed.
Costs expected to be
greater than Option 1 (5 1 have flow reduction), but
significantly less than Option 5 (417 have flow reduction).
Source: U.S. EPA analysis, 2002.
Dl-3
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Dl-2 SUMMARY OF NATIONAL BENEFITS AND SOCIAL COSTS
The summary of national benefit estimates for the proposed option and five regulatory options is reported in Chapter C4:
Benefits. Table Dl-3 presents EPA's national social cost and benefit estimates for the proposed Phase II rule and five
alternative regulatory options. The table shows that the proposed rule, the impingement mortality and entrainment controls
everywhere option, and the waterbody/capacity-based option all have estimated benefits that exceed social costs. The all
cooling towers option and dry cooling option have negative net benefits (i.e., social costs exceed benefits). The Agency's
proposed rule has the largest estimated net benefits, $452 million, of the five regulatory options analyzed.
Table Dl-3: Total National Social C
Option
All Track I
Waterbody/ Capacity- (Option 1 )
Based Option
(Allows two tracks) Track I and II
(Option 2)
Proposed Rule
(Option 3)
Alternative less stringent requirements based on
both costs and benefits are allowed.
Impingement Mortality and Entrainment Controls
Everywhere Option
(Option 3 a)
All Cooling Towers Option
(Option 4)
Dry Cooling Option
(Option 5)
Waterbody -Based Option
(Option 6)
osts. Benefits, and Net Benefits by Optior
Total Benefits Total Social Costs
$1,034 $969
$890 $610
$735 $283
$749 $300
$1,223 $3,507
$1,536 $2,054
Not costed:
ni i J.Q greater than Option 1,
4)i, ijy ..- .11
sigmiicantly less
than Option 5.
i ($2001; million)
Net Benefits
(Benefits minus Costs)
$65
$280
$452
$449
($2,284)
($518)
N/A
Source: U.S. EPA analysis, 2002.
Dl-4
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
GLOSSARY
opportunity cost: The lost value of alternative uses of resources (capital, labor, and raw materials) used in pollution
control activities.
social costs: The costs incurred by society as a whole as a result of the proposed rule. Social costs do not include costs that
are transfers among parties but that do not represent a net cost overall.
Dl-5
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§ 316(b) Phase II EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
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