United States Office of Water EPA-821-R-04-005
Environmental Protection (4303) February 2004
Agency
4*EPA Economic and Benefits
Analysis for the Final Section
316(b) Phase II Existing
Facilities Rule
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Economic and Benefits Analysis for the Final 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 2004
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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: BACKSROUN& INFORMATION
Chapter Al: Introduction and Overview
Al-l Summary of the Final Rule Al-1
Al-2 Summary of Alternative Regulatory Options Al-1
Al-3 Compliance Responses of the Final Rule Al-1
Al-4 Organization of the EBA Report Al-2
References Al-4
Chapter A2: Need for the 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 A2-7
A2-2.4 Reducing Differences Between the States A2-8
A2-2.5 Reducing Transaction Costs A2-9
References A2-10
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 A3-4
A3-2 Domestic Production A3-6
A3-2.1 Generating Capacity A3-6
A3-2.2 Electricity Generation A3-8
A3-2.3 Geographic Distribution A3-9
A3-3 Plants Subjectto Phase II Regulation A3-12
A3-3.1 Ownership Type A3-12
A3-3.2 Ownership Size A3-13
A3-3.3 Plant Size A3-15
A3-3.4 Geographic Distribution A3-16
A3-3.5 Waterbody and Cooling System Type A3-17
A3-4 Industry Outlook A3-18
A3-4.1 Current Status of Industry Deregulation A3-18
A3-4.2 Energy Market Model Forecasts A3-19
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§ 316(b) Phase II EBA Table of Contents
Glossary A3-21
References A3-23
PART B: COSTS AND ECONOMIC IMPACTS
Chapter Bl: Summary of Compliance Costs
Bl-l Unit Costs Bl-1
Bl-1.1 Technology Costs Bl-1
Bl-1.2 Energy Costs Bl-2
Bl-1.3 Administrative Costs Bl-4
Bl-2 Assigning Compliance Years to Facilities Bl-8
Bl-3 Total Private Compliance Costs Bl-9
Bl-3.1 Methodology Bl-9
Bl-3.2 Total Private Costs of the Final Rule Bl-11
Bl-4 Uncertainties and Limitations Bl-11
References Bl-13
Chapter B2: Cost Impact Analysis
B2-1 Cost-to-Revenue Measure B2-1
B2-1.1 Facility Analysis B2-1
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 forthe 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 B3-10
B3-3.1 Facility-level Impact Measures B3-11
B3-4 Analysis Results for the Final Rule B3-12
B3-4.1 Market Analysis for 2010 B3-12
B3-4.2 Analysis of Phase II Facilities for 2010 B3-18
B3-4.3 Market Analysis for 2008 B3-25
B3-5 Uncertainties and Limitations B3-30
References B3-31
Appendix A to Chapter B3 B3-32
Appendix B to Chapter B3 B3-46
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§ 316(b) Phase II EBA Table of Contents
Chapter B4: Regulatory Flexibility Analysis
B4-1 Number of In-Scope Facilities Owned by Small Entities B4-1
B4-1.1 Identification of Domestic Parent Entities B4-2
B4-1.2 Size Determination of Domestic Parent Entities B4-2
B4-2 Percent of Small Entities Regulated B4-4
B4-3 Sales Test for Small Entities B4-6
B4-4 Summary B4-7
References B4-8
Appendix to Chapter B4 B4-9
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 B5-7
B5-2 Compliance Costs for the Private Sector B5-8
B5-3 Summary of UMRA Analysis B5-8
References B5-9
Chapter B6: Other Administrative Requirements
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 B6-8
B6-9 National Technology Transfer and Advancement Act B6-8
References B6-9
PART C: NATIONAL BENEFITS
Chapter Cl: Regional Approach
Cl-l Definitions of Regions Cl-1
Cl-1.1 Coastal Regions Cl-1
Cl-1.2 Great Lakes Region Cl-2
Cl-1.3 InlandRegion Cl-2
Cl-2 Development of Regional I&E Estimates Cl-2
Cl-3 Development of Regional and National Benefits Estimates Cl-3
References Cl-4
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§ 316(b) Phase II EBA Table of Contents
Chapter C2: Summary of Current Losses Due to I&E
C2-1 Summary of I&E Losses C2-1
C2-2 Summary of Losses: Economic Value C2-2
References C2-4
Appendix to Chapter C2 C2-5
Chapter C3: Monetized Benefits
C3-1 Expected Reductions in I&E C3-1
C3-2 Regional and National Social Benefits C3-2
References C3-4
Appendix to Chapter C3 C3-5
PART &: NATIONAL BENEFIT-COST ANALYSIS
Chapter 01: Comparison of Costs and Benefits
Dl-l Social Costs Dl-1
Dl-2 Summary of National Benefits and Social Costs Dl-3
Dl-3 Regional Comparison of Benefits and Social Costs for the Final Rule Dl-4
Dl-3.1 Benefit-Cost Analysis Dl-4
Dl-3.2 Cost per Age-One Equivalent Fish Saved - Cost-Effectiveness Analysis Dl-5
Dl-3.3 Break-even Analysis Dl-6
Glossary Dl-7
References Dl-8
Appendix to Chapter Dl Dl-9
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information Al: Introduction and Overview
Chapter A1: Introduction and
Overview
INTRODUCTION CHARTER
Al-l Summary of the Final Rule Al-1
EPA is promulgating regulations implementing Section M_2 Summary of Alternative Reguiatory Options ... Al-1
Al-3 Compliance Responses of the Final Rule Al-1
A1-4 Organization of the EBA Report A1-2
References Al-4
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 Final
Section 316(b) Phase II Existing Facilities Rule establishes
national technology-based performance requirements
applicable to the location, design, construction, and capacity
of cooling water intake structures (CWIS) at existing facilities. The final national requirements 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-l SUMMARY OF THE FINAL RULE
The Final Section 316(b) Phase II Existing Facilities Rule establishes national standards applicable to the location, design,
construction, and capacity of CWIS at Phase II existing facilities to minimize AEI. The requirements of the final 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. For information on performance standards and compliance alternatives, please refer to
the preamble of today's rule.
Al-2 SUMMARY OF ALTERNATIVE REGULATORY OPTIONS
For the final rule analysis, EPA did not consider any new alternative regulatory options other than those already analyzed for
the proposed rule or the Notice of Data Availability. For a summary of previously considered alternative regulatory options,
please refer to Chapter Al-4 of the Economic and Benefits Analysis (EBA) document in support of the proposed rule (U.S.
EPA, 2002).
Al-3 COMPLIANCE RESPONSES OF THE FINAL RULE
Table Al-l shows compliance response assumptions for the final rule 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. The table shows that 149 of the 554 facilities are expected to install impingement controls; 205 are expected to install
impingement and entrainment controls; and 200 are expected to install no new technologies in response to the final Phase II
rule. Of the 200 facilities with no compliance action, 75 already meet the compliance requirements of the final rule because
they already have a recirculating system.
Al-l
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
Al: Introduction and Overview
Table Al-1: Number of Facilities by Waterbody Type and Compliance Assumption
Facility Waterbody Type
Estuaries, Tidal Rivers, and Oceans
Great Lakes
Freshwater Streams and Rivers
Freshwater Lakes and Reservoirs
Total
Impingement T „ _ ^ ,
„ *\ , _ , I&E Controls No Action
Controls Only
31 69 35
1 32 24
48 103 96
68 0 46
149 205 200
Total
136
57
247
114
554
Recirculating
System in Baseline
(no action)
3
4
42
26
75
Source: U.S. EPA analysis, 2004.
A1-4 ORGANIZATION OF THE EBA REPORT
The Econom ic and Benefits Analysis for the Final Section 316(b) Phase II Existing Facilities Rule (EBA) assesses the
economic impacts and benefits of the final 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 and key definitions of the final rule.
•• 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 SI: Summary of Compliance Costs summarizes the unit costs of compliance with the final rule and
alternative regulatory options, presents EPA's assessment of compliance years, and presents the national cost of the
final rule.
*• Chapter B'2: Cost Impact Analysis presents an assessment of the magnitude of compliance costs with the final Phase
II rule, including a cost-to-revenue analysis at the facility and firm levels, an analysis of compliance costs per
household at the North American Electric Reliability Council (NERC) level, and an analysis of compliance costs
relative to electricity price projections, also at the NERC level.
*• Chapter S3: Electricity Market Model Analysis presents an analysis of the final rule using an integrated electricity
market model. The chapter discusses potential energy effects of the final 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 final
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 final rule.
*• Chapter B'6: Other Administrative Requirements presents several other analyses in support of the final Phase II
rule. These analyses address the requirements of Executive Orders and Acts applicable to this rule.
Al-2
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information Al: Introduction and Overview
PART C: NATIONAL BENEFITS
*• Chapter Cl: Regional Approach provides an overview of the regional study approach and a map of each study
region.
*• Chapter C2: Summary of Current Losses Due to I&E summarizes, for each regional study, the estimates of
biological losses under current conditions and presents the estimated value of these losses. The chapter includes
regional results and national totals.
*• Chapter C3: Monetized Benefits presents the expected national reductions in I&E under the final rule and applies
these reductions to the national baseline losses reported in Chapter C2 to obtain an estimate of national benefits
attributable to section 3 16(b) Phase II regulation. The chapter includes regional results and national totals.
PART D: NATIONAL BENEFIT-COST ANALYSIS
•• Chapter Dl: Comparison of Costs and Benefits summarizes total private costs, develops social costs, and compares
the final rule's total social costs and total benefits at the national level. The chapter also presents comparisons of
benefits and costs at the regional level.
Al-3
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information Al: Introduction and Overview
REFERENCES
Clean Water Act (CWA). 33 U.S.C. 1251 et seq.
U.S. Environmental Protection Agency (U.S. EPA). 2002. Economic and Benefits Analysis for the Proposed Section 316(b)
Phase II Existing Facilities Rule. EPA-821-R-02-001. April 2002. DCN 4-0002. Available at
http://www.epa.gov/ost/316b/econbenefits.
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 2040-021 3). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
Al-4
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A2: Need for the Regulation
Chapter A2: Need for the Regulation
INTRODUCTION
Many CWIS have been constructed on sensitive aquatic
systems with capacities and designs that cause damage to the
waterbodies from which they withdraw water. In addition, the
absence of regulations that establish national standards for
BTA has led to an inconsistent application of section 31 6(b).
In fact, only 150 out of 554 Phase II facilities have indicated
on EPA's 2000 Section 316(b) Industry Survey that they have
ever performed an impingement and entrainment (I&E) 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.
CHAPTER CONTENTS
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 A2-7
A2-2.4 Reducing Differences Between the
States A2-8
A2-2.5 Reducing Transaction Costs A2-9
References A2-10
A2-1 OVERVIEW OF REGULATED FACILITIES
The Final 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 final Phase II rule does not cover (1) new steam electric power generating facilities, (2) new facilities in
other industry sectors, (3) existing steam electric power generating facilities with a design intake flow of less than 50 MGD,
and (4) existing facilities in other industry sectors.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
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, 543 meet the "in-scope" requirements of this final rule. These 543 facilities represent 554 facilities in
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 facilities in other industry
sectors will be addressed by a separate rule (Phase III).
A2-1
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A2: Need for the Regulation
the industry. Based on the survey, the 554 Phase II facilities account for approximately 216 BGD, or 98 percent of the
estimated average flow of all power producers. Industrial categories other than power producers are not covered by this final
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 Categories'5
Total Steam Electric and Industrial
Estimated
Number of
Facilities
708
591
117
773
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
T.-H- ^ i nr Percent of Total Steam
Billion Gal./Yr. _,, ^ . , T , A . ,
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 554 steam electric power generating facilities subject to the final Phase II rule comprise a substantial portion of the U.S.
electric power market. As shown in Table A2-2, the 554 facilities represent 14 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 438,000 megawatt (MW; 50
percent of total), generate 2.4 billion megawatt hours of electricity (MWh; 59 percent of total), and realize $80 billion in
revenues (52 percent of total).
2 EPA applied sample weights to the 543 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 referto the Information Collection Request (U.S.
EPA, 2000).
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§ 316(b) Phase II Final Rule - 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
873,000
4,060
$154
Facilities Subject to
Phase II Total
554
438,000
2,400
$80
Facilities
Phase II Rule"
% of Industry Total
14%
50%
59%
52%
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 final rule, see Chapter B3: Electricity Market Model Analysis.
b The IPM models 535 of the 543 Phase II facilities. Seven of the 535 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 528 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 (EPA electricity demand growth assumptions).
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, 302, or 54.5 percent, are coal-fired steam-electric facilities. The
other major plant types are oil- or gas-fired steam-electric facilities (168, or 30.3 percent) and nuclear facilities (59, or 10.7
percent). The remaining 4.5 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 102 (18.4 percent) and 96 (17.3 percent), respectively.
A2-3
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§ 316(b) Phase II Final Rule - 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
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
Percent of Phase II
Coal
1
92
9
7
0
17
42
34
17
56
19
7
302
54.5%
Combined
Cycle
0
1
1
5
0
2
0
0
4
1
0
3
17
3.1%
Nuclear
0
6
2
1
0
8
9
4
9
17
1
2
59
10.7%
Oil/Gas
0
3
39
17
3
15
2
6
27
22
12
21
168
30.3%
Other
Steam
0
0
0
0
0
2
0
0
5
0
0
1
8
1.4%
Total
1
102
51
30
3
45
53
44
61
96
32
35
Percent of
Phase II
0.2%
18.4%
9.2%
5.4%
0.5%
8.1%
9.6%
7.9%
11.0%
17.3%
5.8%
6.3%
554
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, 2001.
A2-2 THE NEED FOR SECTION 316(B) REGULATION
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 offish 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 offish 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
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§ 316(b) Phase II Final Rule - 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
antifouling agents such as chlorine.
Rates of 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 Saila et al., 1997). EPA estimates that CWIS used by the 554 facilities
subject to the final rule impinge and entrain millions of age 1 equivalent fish annually (see Table C2-1 in Chapter C2:
Summary of Current Losses Due to I&E 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 31 6(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 554 in-scope Phase II facilities with respect to
these technologies.
a. Cooling water system (CWS) configuration and CWIS technologies
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 554 in-scope Phase II facilities, 75 (14 percent) reported the use of
closed-cycle cooling systems.
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 554 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.
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§ 316(b) Phase II Final Rule - 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 MfiD)
CWIS Technology
Intake screening
technologies
Passive intake systems
Fish diversion or
avoidance systems
Fish handling or return
technologies
Other/no ne/unkno wn
Combination of
technologies
Total
CWS Configuration
Once Through
# | %
26
44
17
64
219
50
420
6.2%
10.5%
L
4.0%
15.2%
52.1%
L
11.9%
100.0%
Recirculating
# %
0
11
fc
2
5
50
fc
7
75
0.0%
14.7%
L
2.7%
6.7%
66.7%
L
9.3%
100.0%
Combination
h
# %
4
9
L
2
7
23
L
5
50
8.0%
18.0%
L
4.0%
14.0%
46.0%
L
10.0%
100.0%
None/unknown
h v i
# | %
0
fc
0
SJ
c
fc
9
0.0%
11.1%
L
0.0%
22.2%
55.6%
L
11.1%
100.0%
Total
h v
# | %
30
65
L
21
78
297
L
63
554
5.4%
1 1 .7%
L
3.8%
14.1%
53.6%
L
11.4%
100.0%
Source: U.S. EPA, 2000; U.S. EPA analysis, 2004.
b. 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.
Table A2-5 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 intake
flow of these facilities totaled 32 percent of the total cooling water being withdrawn by all in-scope Phase II facilities. The
remaining 419 facilities (68 percent of flow) were reported as being located on fresh waterbodies (including Great Lakes).
Table A2-5: Estimated Number of Facilities and Share of Intake Flow by Source of Water-body Type
(Design Flow >= 50 MfiD)
Waterbody Type
Estuary/Tidal River
Ocean
Great Lake
Freshwater Stream/River
Lake/Reservoir
Total"
:
:
Number of Facilities i Percent of Total
:
113 20%
22 4%
57 10%
247 45%
114 21%
554 100%
Percent of Average Annual Intake Flow
25%
6%
10%
32%
27%
100%
a Individual numbers may not add up to totals due to independent rounding.
Source: U.S. EPA, 2000.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A2: Need for the Regulation
A2-2.2 Reducing Adverse Environmental Impacts
There are multiple types of adverse environmental impacts associated with CWIS, including impingement and entrainment;
reductions of threatened, endangered, or other protected species; damage to ecologically critical aquatic organisms, including
important elements of the food chain; diminishment of a population's potential compensatory reserve; losses to populations,
including reductions of indigenous species populations, commercial fishery stocks, and recreational fisheries; and stresses to
overall communities or ecosystems as evidenced by reductions in diversity or other changes in system structure or function.
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
»• chemical toxemia induced by the addition of anti-fouling agents such as chlorine.
Impingement and entrainment losses can be substantial. For example, it is estimated that annual entrainment at three Hudson
River power plants results in year-class reductions of up to 20 percent for striped bass, 25 percent for bay anchovy, and 43
percent for Atlantic tomcod, even without assuming 100 percent mortality of entrained organisms (ConEd, 2000). At the San
Onofre Nuclear Generating Station (SONGS), it was estimated that in a normal (non-El Nino) year 57 tons of fish were killed
per year when all units were in operation (Murdoch, et al., 1989).3 This included approximately 350,000 juvenile white
croaker, a popular sport fish. This number represents 33,000 adult individuals or 3.5 tons of adult fish. It was found that
losses at SONGS resulted in a 50 to 70 percent decline in local midwater fish within three kilometers of the plant.
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 estimated reduction in impingement and entrainment as a result
of the final Phase II rule. See also the Regional Studies for the Final Section 316(b) Phase II Existing Facilities Rule (U.S.
EPA, 2004) for detailed information on baseline losses.
A2-2.3 Addressing Market Imperfections
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 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 reimbursed 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 consequence 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
Unit 1, which accounted for about 20% of total losses, was taken out of operation in November 1992.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A2: Need for the Regulation
subgroups 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.
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 A2-6 on the following page illustrates a variety of ways in which States identify the section 316(b) requirements.
Table. A2-6: 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(4556)
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 offish, 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, 1994.
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 3 1 6(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).
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A2: Need for the Regulation
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. 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 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, EPA implements section through its regional
offices.
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.
A2-9
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A2: Need for the Regulation
REFERENCES
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, and Roseton Steam Electric Generating
Stations.
Murdoch, W.W., R.C. Fay, and B.J. Mechalas. 1989. Final Report of the Marine Review Committee to the California
Coastal Commission, August 1989, MRC Document No. 89-02.
Saila, S.B., E. Lorda, J.D. Miller, R.A. Sher, and W.H. Howell. 1997. Equivalent adult estimates for losses offish eggs,
larvae, and juveniles at Seabrook Station with use of fuzzy logic to represent parametric uncertainty. North American Journal
of Fisheries Management 17:811-825.
Science Applications International Corporation (SAIC). 1994. 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
U.S. Environmental Protection Agency. April 4, 1994.
U.S. Department of Energy (U.S. DOE). 2001. Form EIA-860 (2001). Annual Electric Generator Report.
U.S. Environmental Protection Agency (U.S. EPA). 2004. Regional Studies for the Final Section 316(b) Phase II Existing
Facilities Rule. EPA-821-R-04-006. February 2004.
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.
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 2040-021 3). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
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§ 316(b) Phase II Final Rule - 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
operational 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 Final 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
final Phase II rule. For more information on general
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, capacity, and geographic distribution.
•• Section A3-3 focuses on the Phase II section 316(b) facilities. This section provides information on the physical,
geographic, and ownership characteristics of the 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 2025.
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 A3-4
A3-2 Domestic Production A3-6
A3-2.1 Generating Capacity A3-6
A3-2.2 Electricity Generation A3-8
A3-2.3 Geographic Distribution A3-9
A3-3 Plants Subject to Phase II Regulation A3-12
A3-3.1 Ownership Type A3-12
A3-3.2 Ownership Size A3-13
A3-3.3 Plant Size A3-15
A3-3.4 Geographic Distribution A3-16
A3-3.5 Waterbody and Cooling System Type A3-17
A3-4 Industry Outlook A3-18
A3-4.1 Current Status of Industry Deregulation A3-18
A3-4.2 Energy Market Model Forecasts A3-19
Glossary A3-21
References A3-23
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 Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
A 3-1.1 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; U.S. DOE, 2000a):'
*• The generation sector includes the power plants that produce, or "generate," electricity. Electric power is usually
produced by a mechanically driven rotary generator called a turbine. Generator drivers, also called prime movers,
include gas or diesel internal combustion machines, as well as streams of moving fluid such as wind, water from a
hydroelectric dam, or steam from a boiler. Most boilers are heated by direct combustion of fossil or biomass-derived
fuels or waste heat from the exhaust of a gas turbine or diesel engine, but heat from nuclear, solar, and geothermal
sources is also used. Electric power may also be produced without a generator by using electrochemical,
thermoelectric, or photovoltaic (solar) technologies.
> The transmission 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 distribution 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 of prime movers 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, oil, and natural gas) as an energy source and employ some type of turbine to produce
electricity. According to the Department of Energy, the most common prime movers are (U.S. DOE, 2000a):
»• Steam Turbine: "Most of the electricity in the United States is produced in steam turbines. In a fossil-fueled
steam turbine, the fuel is burned in a boiler to produce steam. The resulting steam then turns the turbine blades that
turn the shaft of the generator to produce electricity. In a nuclear-powered steam turbine, the boiler is replaced by a
reactor containing a core of nuclear fuel (primarily enriched uranium). Heat produced in the reactor by fission of the
uranium is used to make steam. The steam is then passed through the turbine generator to produce electricity, as in
the fossil-fueled steam turbine. Steam-turbine generating units are used primarily to serve the base load of electric
utilities. Fossil-fueled steam-turbine generating units range in size (nameplate capacity) from 1 megawatt to
more than 1,000 megawatts. The size of nuclear-powered steam-turbine generating units in operation today ranges
from 75 megawatts to more than 1,400 megawatts."
> Gas Turbine: "In a gas turbine (combustion-turbine) unit, hot gases produced from the combustion of natural gas
and distillate oil in a high-pressure combustion chamber are passed directly through the turbine, which spins the
generator to produce electricity. Gas turbines are commonly used to serve the peak loads of the electric utility.
Gas-turbine units can be installed at a variety of site locations, because their size is generally less than 100
megawatts. Gas-turbine units also have a quick startup time, compared with steam-turbine units. As a result,
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.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
gas-turbine units are suitable for peakload. emergency, and reserve-power requirements. The gas turbine, as is
typical with peaking units, has a lower efficiency than the steam turbine used for baseload power."
> Combined-Cycle Turbine: "The efficiency of the gas turbine is increased when coupled with a steam turbine in a
combined-cycle operation. In this operation, hot gases (which have already been used to spin one turbine generator)
are moved to a waste-heat recovery steam boiler where the water is heated to produce steam that, in turn, produces
electricity by running a second steam-turbine generator. In this way, two generators produce electricity from one
initial fuel input. All or part of the heat required to produce steam may come from the exhaust of the gas turbine.
Thus, the steam-turbine generator may be supplementarily fired in addition to the waste heat. Combined-cycle
generating units generally serve intermediate loads."
> Internal Combustion Engine: "These prime movers have one or more cylinders in which the combustion of fuel
takes place. The engine, which is connected to the shaft of the generator, provides the mechanical energy to drive
the generator to produce electricity. Internal-combustion (or diesel) generators can be easily transported, can be
installed upon short notice, and can begin producing electricity nearly at the moment they start. Thus, like gas
turbines, they are usually operated during periods of high demand for electricity. They are generally about 5
megawatts in size."
> Hydroelectric Generating Units: "Hydroelectric power is the result of a process in which flowing water is used
to spin a turbine connected to a generator. The two basic types of hydroelectric systems are those based on falling
water and natural river current. In the first system, water accumulates in reservoirs created by the use of dams. This
water then falls through conduits (penstocks) and applies pressure against the turbine blades to drive the generator to
produce electricity. In the second system, called a run-of-the-river system, the force of the river current (rather than
falling water) applies pressure to the turbine blades to produce electricity. Since run-of-the-river systems do not
usually have reservoirs and cannot store substantial quantities of water, power production from this type of system
depends on seasonal changes and stream flow. These conventional hydroelectric generating units range in size from
less than 1 megawatt to 700 megawatts. Because of their ability to start quickly and make rapid changes in power
output, hydroelectric generating units are suitable for serving peak loads and providing spinning reserve power, as
well as serving baseload requirements. Another kind of hydroelectric power generation is the pumped storage
hydroelectric system. Pumped storage hydroelectric plants use the same principle for generation of power as the
conventional hydroelectric operations based on falling water and river current. However, in a pumped storage
operation, low-cost off-peak energy is used to pump water to an upper reservoir where it is stored as potential
energy. The water is then released to flow back down through the turbine generator to produce electricity during
periods of high demand for electricity."
In addition, there are a number of other prime movers:
»• Other Prime Movers: "Other methods of electric power generation, which presently contribute only small
amounts to total power production, have potential for expansion. These include geothermal, solar, wind, and
biomass (wood, municipal solid waste, agricultural waste, etc.). Geothermal power comes from heat energy buried
beneath the surface of the earth. Although most of this heat is at depths beyond current drilling methods, in some
areas of the country, magma--the molten matter under the earth's crust from which igneous rock is formed by
cooling--flows close enough to the surface of the earth to produce steam. That steam can then be harnessed for use in
conventional steam-turbine plants. Solar power is derived from the energy (both light and heat) of the sun.
Photovoltaic conversion generates electric power directly from the light of the sun; whereas, solar-thermal electric
generators use the heat from the sun to produce steam to drive turbines. Wind power is derived from the conversion
of the energy contained in wind into electricity. A wind turbine is similar to a typical wind mill. However, because of
the intermittent nature of sunlight and wind, high capacity utilization factors cannot be achieved for these plants.
Several electric utilities have incorporated wood and waste (for example, municipal waste, corn cobs, and oats) as
energy sources for producing electricity at their power plants. These sources replace fossil fuels in the boiler. The
combustion of wood and waste creates steam that is typically used in conventional steam-electric plants."
The section 316(b) regulation is only relevant for electric generators that use cooling water. However, not all prime movers
require cooling water. Only prime movers with a steam electric generating cycle use large enough amounts of cooling water
to fall under the scope of the final rule. This profile will, therefore, differentiate between steam electric and other prime
A3-3
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
movers. EPA identified steam electric prime movers using data collected by the EIA (U.S. DOE, 2001a).3 For this profile,
the following prime movers, including both steam turbines and combined-cycle technologies, are classified as steam electric:
»• Steam Turbine, including nuclear, geothermal, and solar steam (not including combined cycle),
*• Combined Cycle Steam Part,
•• Combined Cycle Combustion Turbine Part,
*• Combined Cycle Single Shaft (combustion turbine and steam turbine share a single generator), and
•• Combined Cycle Total Unit (used only for plants/generators that are in the planning stage).
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 Form EIA-860 (Annual Electric Generator Report) in 2001.
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 generating capacity.
Table A3-1: Number of Existing Utility and Nonutility Plants by Prime Mover, 2001
Prime Mover
Steam Turbine
Combined-Cycle
Gas Turbine
Internal Combustion
Hydroelectric
Other
Total
Utility"
Number of Plants
636
59
308
557
900
22
2,482
Nonutility11
Number of Plants
903
239
426
346
490
134
2,538
a See definition of utility and nonutility in Section A3-1.3.
Source: U.S. DOE, 2001a.
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, 2003a):
»• Utility: A regulated entity providing electric power, traditionally vertically integrated. Utilities all have distribution
facilities for delivery of electric energy for use primarily by the public, but they 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.
> Nonutility: Entities that generate power for their own use and/or for sale to utilities and others. Nonutility power
producers include cogenerators (combined heat and 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 (adapted from U.S. DOE, 2000a).
3 U.S. DOE, 2001a (EIA Form 860, Annual Electric Generator Report) collects data used to create an annual inventory of all units,
plants, and utilities. The data collected includes: type of prime mover; nameplate rating; energy source; year of initial commercial
operation; operating status; cooling water source, andNERC region.
A3-4
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
»»» 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 to give
consumers access to services under similar conditions. Most lOUs engage in generation, transmission, and distribution. In
2001, lOUs operated 1,147 facilities, which accounted for approximately 44 percent of all U.S. electric generation capacity
(U.S. DOE, 2001a; U.S. DOE, 2001b).
»»» Publicly-owned utilities
Publicly-owned electric utilities can be State authorities, municipalities, and political subdivisions (e.g., public power
districts, irrigation projects, and other State agencies established to serve their local municipalities or nearby communities).
This profile also includes Federally-owned facilities in this category. Excess funds or "profits" from the operation of these
utilities are put toward reducing rates, increasing facility efficiency and capacity, and funding community programs and local
government budgets. 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 2001, the Federal government operated 193 facilities (accounting
for 7.6 percent of total U.S. electric generation capacity), States owned 83 facilities (2.1 percent of U.S. capacity),
municipalities owned 783 facilities (4.9 percent of U.S. capacity), and political subdivisions operated 42 facilities (1.1 percent
of U.S. capacity) (U.S. DOE, 2001a; U.S. DOE, 2001b).
»»» 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 47 States
and are incorporated under State laws. In 2001, rural electric cooperatives operated 166 generating facilities and accounted
for approximately 3 percent of all U.S. electric generation capacity (U.S. DOE, 2001a; U.S. DOE, 2001b).
A3-5
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§ 316(b) Phase II Final Rule - 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 2001, by type of ownership. 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 Form EIA-860 in 2001. The graphic shows that nonutilities account for the
largest percentage of facilities (2,538, or 52 percent), but only represent 38 percent of total U.S. generating capacity.
Investor-owned utilities operate the second largest number of facilities, 1,143, and account for 46 percent of total U.S.
capacity.
Figure A3-1: Distribution of Facilities and Capacity by Ownership Type, 2001
Inves to r- Own ed
N on utility
Federal
State
Municipality
Political Subdivision
Coop eralive
U nk now n/Othe r
I P
1.147
I *
(-I 19046
P S3
L 10.472 M
P 42
a
fl.7.666 Mf
n es
69362 h
193
i/W
fl
nr
29.010 Wl
166
w
45.120 MH
783
_ 404
i29 550 M
130MJV
t
2,538
• Cap a city
(MW)
d N urn b e r of
Plante
0.0% 10.0% 20.0% 300% 400% 50.0% 600%
Source: U.S. DOE, 2001a; U.S. DOE, 2001b.
A3-2 DOMESTIC PRODUCTION
This section presents an overview of U.S. generating capacity and electricity generation. Section A3-2.1 provides data on
capacity, and Section A3-2.2 provides data on generation. Section A3-2.3 presents an overview of the geographic distribution
of generation plants and capacity.
A3-2.1 Generating Capacity
Utilities own and operate the majority of the
generating capacity (64 percent) and capability (65
percent) in the United States. Nonutilities owned
only 35 percent of total capability in 2001.
Nonutility capacity and capability have increased
substantially in the past few years, since passage of
legislation aimed at increasing competition in the
industry. Nonutility capability has increased 637
percent between 1991 and 2001, compared with the
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
A3-6
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
decrease in utility capability of 21 percent over the same time period.4
Figure A3-2 shows the growth in utility and nonutility capability from 1991 to 2001. The growth in nonutility capability,
combined with a decrease in utility capability, has resulted in a modest growth in total generating capability. The significant
increase in nonutility capability and decrease in utility capability since 1 997 is attributable to utilities being sold to
nonutilities.
Figure A3-2: Generating Capability, 1991 to 2001
800,000 -I
700,000 •
600,000 •
900,000 •
400,000 •
300,000 •
200,000 •
100,000 •
x
t
•=
1
1
1
1
1
1
- —
\
T
l«
1991 1992 1993 1994 1995 1996 1997 1993 1999 2000
n Utility
• Nonutility
2001
Source: U.S. DOE, 2003a.
4 More accurate data were available starting in 1991, therefore, 1991 was selected as the initial year for trends analysis.
A3-7
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§ 316(b) Phase II Final Rule - 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 2001
was 3,734 billion kWh. Utility-owned plants
accounted for 70 percent of this amount. Total net
generation has increased by 22 percent over the 11
year period from 1991 to 2001. During this period,
nonutilities increased their electricity generation by
343 percent. In comparison, generation by utilities
decreased by 7 percent (U.S. DOE, 2003a; 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 2001 by energy source and
ownership type.
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 2001 (6Wh)
Energy
Source
Coal
Hydropower
Nuclear
Oil
Natural Gas
Other Gases
Renewablesa
Other"
Total
Utilities
1991
1,551
276
613
111
264
0
10
0
2,825
2001
1,560
190
534
79
264
0
2
0
2,630
% Change
0.6%
-31.0%
-12.8%
-29.2%
0.1%
n/a
-78.8%
n/a
-6.9%
Nonutilities
1991
39
9
0
8
117
11
59
5
249
2001
343
17
235
49
365
14
77
4
1,104
% Change
769.9%
95.2%
n/a
487.7%
210.8%
21.4%
30.9%
-10.3%
343.6%
Total
1991
1,591
284
613
120
382
11
69
5
3,074
2001
1,903
208
769
128
629
14
79
4
3,734
% Change
19.7%
-27.0%
25.5%
6.6%
64.9%
21.4%
14.7%
-10.2%
21.5%
a Renewables include solar, wind, wood, biomass, and geothermal energy sources.
b Other includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.
Source: U.S. DOE, 2002b; U.S. DOE, 2002c; U.S. DOE, 1995a; U.S. DOE, 1995b.
As shown in Table A3-2, natural gas generation grew the fastest among the fuel source categories, increasing by 65 percent
between 1991 and 2001. Nuclear generation increased by 26 percent, while coal generation increased by 20 percent.
Generation from renewable energy sources increased 1 5 percent. Hydropower, however, experienced a decline of 27 percent.
For utilities, generation using natural gas and coal as fuel sources was relatively constant. Generation using other sources fell,
mostly because of sales to nonutilities. Nonutility generation grew quickly between 1991 and 2001 with the passage of
legislation aimed at increasing competition in the industry. Nonutility coal generation grew the fastest among the energy
source categories, increasing 770 percent between 1991 and 2001. Generation from oil-fired facilities also increased
substantially, with a 488 percent increase in generation between 1991 and 2001.
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§ 316(b) Phase II Final Rule - 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 51 percent of total 2001 generation. Electric utilities generate 82 percent (1,560 billion
kWh) of the 1,903 billion kWh of electricity generated by coal-fired plants. This represents approximately 59 percent of total
utility generation. The remaining 1 8 percent (343 billion kWh) of coal-fired generation is provided by nonutilities,
accounting for 31 percent of total nonutility generation. The second largest source of electricity generation is nuclear power
plants, accounting for 20 percent total utility generation and 21 percent of nonutility generation. Another significant source of
electricity generation is gas-fired power plants, which account for 33 percent of nonutility generation and 17 percent of total
generation.
Figure A3-3: Percent of Electricity Generation by Primary Fuel Source, 2001
60.0<
50.0<
40.0%-
30.0%-
20.0%-
10.0%-
0.0%
y o
tt:
c/ y
Source: U.S. DOE, 2003a.
The final Phase II rule will affect facilities differently based on the fuel sources and prime movers used to generate electricity.
As described 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 with or have links to the Canadian grid system. The Western and Texas
systems have links with Mexico.
A3-9
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§ 316(b) Phase II Final Rule - 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 ten regional councils that cover the 48 contiguous States, and affiliated councils that
cover 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 above, 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 (HICC).
Figure A3-4: North American Electric Reliability Council (NERC) Regions
MAAC
FRCC
Source: U.S. DOE, 1996a; U.S. DOE, 1996b.
A3-10
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
The final Phase II rule may affect plants located in different NERC regions differently. Economic characteristics of existing
facilities affected by the final Phase II rule are likely to vary across regions by fuel mix, and the costs of fuel, transportation,
labor, and construction. Baseline differences in economic characteristics across regions may influence the impact of the final
Phase II rule on profitability, electricity prices, and other impact measures. However, as discussed in Chapter B3: Electricity
Market Model Analysis, the final Phase II rule will have little or no impact on electricity prices in each region since the final
Phase II rule is relatively inexpensive relative to the overall production costs in any region.
Table A3-3 shows the distribution of all existing plants and capacity by NERC region. The table shows that 1,306 plants,
equal to 26 percent of all facilities in the U.S., are located in the Western Systems Coordinating Council (WSCC). However,
these plants account for only 17 percent of total national capacity. Conversely, only 13 percent of generating plants are
located in the Southeastern Electric Reliability Council (SERC), yet these plants account for 22 percent of total national
capacity.
Table A3-3: Distribution of
NERC Region
ASCC
ECAR
ERCOT
FRCC
HICC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Total
Existing Plants and Capacity by NERC
Plants
Number
124
448
215
129
34
246
412
445
718
661
282
1,306
5,020
% of Total
2.5%
8.9%
4.3%
2.6%
0.7%
4.9%
8.2%
8.9%
14.3%
13.2%
5.6%
26.0%
100%
Region, 2001
Capacity
Total MW
2,261
128,301
80,523
45,736
2,452
63,676
70,568
37,410
69,861
204,538
51,743
157,287
914,356
% of Total
0.2%
14.0%
8.8%
5.0%
0.3%
7.0%
7.7%
4.1%
7.6%
22.4%
5.7%
17.2%
100%
Source: U.S. DOE, 2001a.
A3-11
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
A3-3 PLANTS SUBJECT TO PHASE II REGULATION
Section 316(b) of the Clean Water Act applies to point source facilities which use or propose to use a cooling water intake
structure that withdraws cooling water directly from a surface waterbody 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.
The following sections describe power plants that are subject to the Final Section 316(b) Phase II Existing Facilities Rule.
The final Phase II rule applies to existing steam electric power generating 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 National Pollutant Discharge Elimination System (NPDES) permit or are required to obtain one; and
»• they have a design intake flow of 50 million gallons per day (MGD) or greater.
The final 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 543
steam electric power generating facilities identified in EPA's 2000 Section 316(b) Industry Survey as being "in-scope" of this
final rule. These 543 facilities represent 554 facilities nation-wide. The remainder of this chapter will refer to these facilities
as "Phase II facilities" or "Phase II plants."
The following sections present a variety of physical,
geographic, and ownership information about the Phase II
facilities. Topics discussed include:
•• Ownership type: Section A3-3.1 discusses Phase II
facilities with respect to the entity that owns them.
•• Ownership size: Section A3-3.2 presents information
on the entity size of the owners of Phase II facilities.
»• Plant size: Section A3-3.3 discusses the size
distribution of Phase II facilities by generation
capacity.
•• Geographic distribution: Section A3-3.4 discusses
the distribution of Phase II facilities by NERC region.
•• Water body and cooling system type: Section A3-3.5
presents information on the type of waterbody from
which Phase II facilities draw their cooling water and
the type of cooling system they operate.
A3-3.1 Ownership Type
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
Utilities can be divided into seven major ownership categories:
investor-owned utilities, nonutilities, Federally-owned utilities, State-owned utilities, municipalities, political subdivisions,
and rural electric cooperatives. This classification is important because EPA has separately considered impacts on
governments in its regulatory development (see Chapter B5: UMRA Analysis for the analysis of government impacts of the
final Phase II rule).
5 EPA applied sample weights to the 543 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).
A3-12
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-4 shows the number of parent entities, plants, and capacity by ownership type. Numbers are presented for the
industry as a whole and the portion of the industry subject to section 3 16(b) Phase II regulation. Overall, four percent of all
parent entities, 11 percent of all plants, and 53 percent of all capacity is subject to Phase II regulation. The table further
shows that the majority of Phase II plants, or 274 plants, are owned by investor-owned utilities. An additional 179 Phase II
plants are owned by nonutilities. A higher percentage of the plants owned by investor-owned utilities (24 percent) and rural
electric cooperatives (15 percent) are Phase II facilities, compared to the percentage of facilities in other ownership
categories. 66.5 percent of capacity owned by investor-owned utilities is subject to the final Phase II rule.
Table A3-4: Existing Parent Entities, Plants, and Capacity by Ownership Type, 2001°
Ownership
Type
Investor-Owned
Nonutility"
Federal
State
Municipal
Political
Subdivision
Cooperative
Unknown
Total
Parent Entities Plants
Total"
359
n/a
9
27
1,868
120
889
0
3,272
With
Phase H
Plants
41
26
1
4
36
3
15
0
126
%
Phase II
Plants
11.4%
n/a
11.1%
14.8%
1.9%
2.5%
1.7%
0.0%
3.9%
Total"
1,147
2,538
193
83
783
42
166
68
5,020
Phase
IT
274
179
14
7
48
7
25
0
554
% Phase
n
23.9%
7.0%
7.3%
8.4%
6.1%
6.7%
15.1%
0.0%
11.0%
Capacity (MW)
Total"
404,130
329,550
69,362
19,046
45,120
10,472
29,010
7,666
914,356
Phase
IF
268,643
154,844
27,798
5,409
17,763
4,123
8,821
0
487,401
% Phase
n
66.5%
47.0%
40.1%
28.4%
39.4%
39.4%
30.4%
0.0%
53.3%
a Numbers may not add up to totals due to independent rounding.
b Information on the total number of parent entities is based on data from Form EIA-861 (U.S. DOE, 2001b). Information on plants
and capacity is based on data from Form EIA-860 (U.S. DOE, 2001a). These two data sources report information for non-
corresponding sets of power producers. Therefore, the total number of parent entities is not directly comparable to the information
on total plants or total capacity.
° The number of Phase II plants and capacity was sample weighted to account for survey non-respondents.
d Form EIA-861 does not provide information for nonutilities.
Source: U.S. EPA, 2000; U.S. DOE, 2001a; U.S. DOE, 2001b.
A3-3.2 Ownership Size
EPA estimates that 25 of the 126 entities owning Phase II facilities (20 percent) are small.6 The size distribution varies
considerably by ownership type: only three percent of Phase II investor-owned utilities and four percent of Phase II
nonutilities are small, compared to 44 percent of Phase II municipalities, 40 percent of Phase II cooperatives, and 33 percent
of Phase II political subdivisions. In general, entities that own Phase II plants are larger than other entities in the industry.
Out of 3,272 parent entities in the industry as a whole, 1,992 entities, or 62 percent, are small, compared to 20 percent of
Phase II facilities.
For a detailed discussion of the identification and size determination of parent entities see Chapter B4: Regulatory Flexibility
Analysis. That chapter also documents how EPA considered the economic impacts on small entities when developing this
regulation.
See Chapter B4 for information on EPA's small entity analysis.
A3-13
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-5: Existing Parent Entities by Ownership Type and Size, 2001
Ownership
Type
Investor-
Owned
Nonutility0
Federal
State
Municipal
Political
Subdivision
Cooperative
Total
Total Number of Parent Entities"
i °/
Small ; Large ; Unknown ; Total ; _ „
& | Small
35
n/a
-
983
111
862
1,992
307
n/a
9
27
884
9
25
1,260
17
n/a
-
i
-
2
20
359
n/a
9
27
1,868
120
889
3,272
9.9%
n/a
0%
0%
52.6%
92.5%
97.0%
61.5%
Total Number of Parent Entities That
Own Phase H Facilities "
I o/
Small ! Large ! Total ! 0 „
& | Small
1
1
-
-
16
1
6
25
40
25
1
4
20
2
9
101
41
26
1
4
36
3
15
126
2.4%
3.8%
0.0%
0.0%
44.4%
33.3%
40.0%
19.8%
% of Small
Entities That
Own Phase H
Facilities
2.8%
n/a
0.0%
0.0%
1.6%
0.9%
0.7%
1.3%
a The total number of parent entities that own generation utilities is based on data from Form EIA-861 (U.S. DOE, 2001b). Most of
the other industry-wide information in this profile is based on data from Form EIA-860 (U.S. DOE, 2001 a). Since these two forms
report data for differing sets of facilities, the information in this table is not directly comparable to the other information presented
in this profile.
b Numbers may not add up to totals due to independent rounding.
° Form EIA-861 does not provide data on nonutilities.
Source: U.S. EPA analysis, 2004.
Table A3-6 presents the number of Phase II facilities that are owned by small entities. The table shows that 25 of the 554
Phase II facilities are owned by small entities. Almost all of the small Phase II facilities are owned by municipalities and rural
electric cooperatives. Only a small fraction of the facilities owned by nonutilities, investor-owned utilities, and political
subdivisions have small parent entities. By definition, States and the Federal government are considered large parent entities.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-6: Phase II Facilities by Ownership Type and Size, 2001
Ownership Type
Investor-Owned
Nonutility
Federal
State
Municipal
Political Subdivision
Cooperative
Total
Number of Phase II Facilties"' b
Small
1
1
0
0
16
1
6
25
Large
273
178
14
7
32
6
19
529
Total
274
179
14
7
48
7
25
554
% Small
0.4%
0.6%
0.0%
0.0%
33.3%
14.3%
24.0%
5%
a Numbers may not add up to totals due to independent rounding.
b All numbers were sample weighted to account for survey non-respondents.
Source: U.S. EPA analysis, 2004.
A3-3.3 Plant Size
EPA also analyzed the Phase II facilities with respect to their generating capacity. The size of a plant is important because it
partly determines its need for cooling water and its importance in meeting electricity demand and reliability needs. Figure
A3-5 shows that while some Phase II plants have very large generating capacities, most have moderate capacities. Of the 554
Phase II plants, 223 plants (40 percent) have a capacity of less than 500 MW; 363 plants (65 percent) have a capacity of less
than 1,000 MW. Only seven facilities have a capacity of greater than 3,000 MW. Of the 223 plants with capacities less than
500 MW, 96 have a capacity between 250 and 500 MW, 78 have a capacity between 100 and 250 MW, and 49 have a
capacity of less than 100 MW.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Figure A3-5: Number of Phase II Facilities by Plant Size (in MW), 2001
250
200
150 -
100
" 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, 2001a.
A3-3.4 Geographic distribution
The geographic distribution of facilities is important because a high concentration of facilities with regulatory compliance
costs 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. Table A3-7
shows the distribution of Phase II plants by NERC region. The table shows that there are considerable differences between
the regions both in terms of the number of Phase II plants and the percentage of all plants that they represent. Excluding
Alaska, which has only one Phase II facility, the percentage of Phase II facilities ranges from three percent in the Western
Systems Coordinating Council (WSCC) to 24 percent in the Electric Reliability Council of Texas (ERCOT). The
Southeastern Electric Reliability Council (SERC) has the highest absolute number of Phase II facilities with 103 facilities, or
16 percent of all facilities in the region, followed by the East Central Area Reliability Coordination Agreement (ECAR) with
98 facilities, or 22 percent of all facilities in the region.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-7: Existing Plants by NERC Region, 2001
NERC Region
ASCC
ECAR
ERCOT
FRCC
HICC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
Total Number of
Facilities
124
448
215
129
34
246
412
445
718
661
282
1,306
5,020
Phase II Facilities""
Number % of Total in Region
1
98
51
27
3
46
60
37
61
103
30
36
554
1%
22%
24%
21%
9%
19%
15%
8%
9%
16%
11%
3%
11%
a Numbers may not add up to totals due to independent rounding.
b The number of facilities was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 2001a.
A3-3.5 Waterbody and Cooling System Type
Table A3-8 shows that most of the Phase II facilities draw water from a freshwater river (247 plants or 44 percent). The next
most frequent waterbody types are lakes or reservoirs (114 plants or 21 percent) and estuaries or tidal rivers (113 plants or 20
percent). The table also shows that most of the Phase II plants (420 plants or 76 percent) employ a once-through cooling
system.7 Of the 113 plants that withdraw from an estuary, the most sensitive type of waterbody, only three percent use a
recirculating system while 88 percent have a once-through system. Plants with once-through cooling water systems withdraw
between 70 and 98 percent more water than those with recirculating systems.
7 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. Recirculating systems use cooling towers or ponds to cool water
before passing it through condensers again.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information
A3: Profile of the Electric Power Industry
Table A3-8: Number of Phase II Facilities by Water Body Type and Cooling System Type"
Waterbody Type
Estuary/ Tidal River
Ocean
Lake/ Reservoir
Freshwater River
Great Lake
Total
Cooling System Type
Recirculating
No.
3
0
26
42
4
75
% of Type
3%
0%
23%
17%
7%
14%
Once-Through
No.
99
22
79
169
50
420
% of Type
88%
100%
69%
68%
88%
76%
Combination
No.
10
0
8
29
3
50
% of Type
9%
0%
7%
12%
5%
9%
Other
No.
1
0
1
6
0
8
% of Type
1%
0%
1%
2%
0%
1%
Total "
113
22
114
247
57
554
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, 2001a.
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 final section 316(b) Phase II rule. The most important change in the
electric power industry is deregulation - the transition from a highly regulated monopolistic industry to a less regulated, more
competitive industry. Section 3.4.1 discusses the current status of deregulation. Section 3.4.2 presents a summary of
forecasts from the Annual Energy Outlook 2003.
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.8 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.
8 Several key pieces of Federal legislation have made the changes in the industry's structure possible. The Public Utility
Regulatory Policies Act (PURPA) of 1978 opened up competition in the generation market by creating a class of nonutility
electricity-generating companies referred to as "qualifying facilities." The Energy Policy Act (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 Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
•• 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, hi 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 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 in 2000, has
affected restructuring in that State and several others. Since those difficulties, five States (Arkansas, Montana, Nevada, New
Mexico, and Oklahoma) have delayed the restructuring process pending further review of the issues while California has
suspended direct retail access. As of 2002, seventeen States had operating competitive retail electricity markets, two others
(Texas and Virginia) had just opened their markets to competition, and one (Oregon) had restarted its restructuring process.
(U.S. DOE, 2002a).
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).
A3-4.2 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 2003 (U.S. DOE, 2003b). The EIA models future market conditions through the
year 2025, 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 November 2002. EPA used ICF Consulting's Integrated
Planning Model (IPM®), an integrated energy market model, to conduct the economic analyses supporting the 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.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
a. Electricity demand
The AEO2003 projects electricity demand to grow by approximately 1.8 percent annually between 2000 and 2025. This
growth is driven by an estimated 2.2 percent annual increase in the demand for electricity from the commercial sector
associated with a projected annual growth in commercial floor space of 1.6 percent. EIA expects electricity demand from the
industrial sector to increase by 1.7 percent annually, largely in response to an increase in industrial output of 2.6 per year.
Residential demand is expected to increase by 1.6 percent annually over the same forecast period, due mostly to an increase in
the number of U.S. households of 1.0 percent per year between 2000 and 2025.
b. Capacity retirements
The AEO2003 projects that total fossil fuel-fired generation capacity to decline due to retirements. EIA forecasts that total
fossil-steam capacity will decrease by an estimated 12 percent (or 78 gigawatts) between 2000 and 2025, including 56
gigawatts of oil and natural gas fired steam capacity. EIA estimates total nuclear capacity to decline by an estimated 3
percent (or 3 gigawatts) between 2000 and 2025 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.
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, 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 2025, approximately 80 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 17
percent of the additional capacity forecasted to come on line between 2000 and 2025 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 AEO2003 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 2025, its share of total generation is expected to decrease from 53 percent to an estimated 50 percent. This decrease in
the share of coal generation is in favor of less capital-intensive and more efficient natural gas generation technologies. The
share of total generation associated with gas-fired technologies is projected to increase from approximately 14 percent in
2000 to an estimated 27 percent in 2025, 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.
e. Electricity prices
EIA expects the average real price of electricity, as well as the price paid by customers in each sector (residential,
commercial, and industrial), to decrease between 2000 and 2008 as a result of competition among electricity suppliers, excess
generating capacity, and a decline in coal prices. However, by 2025, EIA predicts that the average real price of electricity
will return to 2000 levels as a result of rising natural gas costs and electricity demand growth.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
GLOSSARY
Base Load: 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/electricity/page/prim2/chapter2.html)
Combined-Cycle Turbine: 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.
Distribution: The portion of an electric system that is dedicated to delivering electric energy to an end user.
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.
Energy Policy Act (EPACT): In 1992 the EPACT removed constraints on ownership of electric generation facilities and
encouraged increased competition on the wholesale electric power business.
Gas Turbine: 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.
Generation: 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).
Gross Generation: The total amount of electric energy produced by the generating units at a generating station or stations,
measured at the generator terminals.
Hydroelectric Generating Unit: A unit in which the turbine generator is driven by falling water.
Intermediate load: 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)
Internal Combustion Engine: 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.
Kilowatthours (kWh): One thousand watthours (Wh).
Megawatt (MW): Unit of power equal to one million watts.
Nameplate Capacity: The amount of electric power delivered or required for which a generator, turbine, transformer,
transmission circuit, station, or system is rated by the manufacturer.
Net Generation: Gross generation minus plant use from all plants owned by the same utility.
Nonutility: 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)
Other Prime Movers: Methods of power generation other than steam turbines, combined-cycles, gas combustion
turbines, internal combustion engines, and hydroelectric generating units. Other prime movers include:
geothermal, solar, wind, and biomass.
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§ 316(b) Phase II Final Rule - EBA, Part A: Background Information A3: Profile of the Electric Power Industry
Peakload: 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)
Power Marketers: 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)
Power Brokers: 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)
Prime Movers: 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).
Public Utility Regulatory Policies Act (PURPA): 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."
Reliability: 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)
Steam Turbine: 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.
Stranded Costs: 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)
Transmission: 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.
Utility: 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)
Watt: 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)
Watthour (Wh): 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)
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§ 316(b) Phase II Final Rule - 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.html.
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). 2003a. Energy Information Administration (EIA). Electric Power Annual 2001.
http://www.eia.doe.gov/cneaf/electricity/epa/epa.pdf.
U.S. Department of Energy (U.S. DOE). 200 3b. Energy Information Administration (EIA). Annual Energy Outlook 2003.
http://www.eia.doe.gov/oiaf/aeo/pdf/0383 (2003).pdf.
U.S. Department of Energy (U.S. DOE). 2002a. 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). 2001a. Form EIA-860 (2001). Annual Electric Generator Report.
U.S. Department of Energy (U.S. DOE). 2001b. Form EIA-861 (2001). Annual Electric Utility Data.
U.S. Department of Energy (U.S. DOE). 200Oa. 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). 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). 1995a. Energy Information Administration (EIA). Electric Power Annual 1994
Volume I. 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 2040-021 3). Industry Screener Questionnaire: Phase I
Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
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.
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Chapter Bl: Summary of Compliance
Costs
INTRODUCTION
This chapter presents the estimated costs to facilities of
complying with the Final Section 316(b) Phase II Existing
Facilities Rule. EPA developed unit costs of complying with
the various requirements of the final rule, including costs of
section 316(b) technologies, energy costs, and administrative
costs. Unit costs were then assigned to the 554 in-scope
facilities, based on the facilities' modeled compliance
responses, and aggregated to the national level.
Bl-1 UNIT COSTS
CHAPTER CONTENTS
Bl-l Unit Costs Bl-1
Bl-1.1 Technology Costs Bl-1
Bl-1.2 EnergyCosts Bl-2
Bl-1.3 Administrative Costs Bl-4
Bl-2 Assigning Compliance Years to Facilities Bl-8
Bl-3 Total Private Compliance Costs Bl-9
Bl-3.1 Methodology Bl-9
Bl-3.2 Total Private Costs of the Final Rule . Bl-11
Bl-4 Uncertainties and Limitations Bl-11
References Bl-13
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 the final rule based on a variety of technologies for impingement mortality and entrainment
reduction. 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 rule and on their projected compliance response. The unit costs
used for the final rule analysis are engineering cost estimates, expressed in July 2002 dollars. More detail on the development
of these unit costs is provided in the Technical Development Document for the Final Section 316(b) Phase II Existing
Facilities Rule, hereafter referred to as the "Phase II Technical Development Document" (U.S. EPA, 2004b).
To characterize the existing facilities' current technologies, EPA compiled facility-level, cooling system, and intake structure
data for the 227 in-scope 316(b) Detailed Questionnaire (DQ) respondents and, to the extent possible, for the 316 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. The result of the
decision process assigned an intake technology module to each facility or intake that suited the particular site characteristics
and would enable the facility to meet its compliance requirements. The Agency based its approach of assigning costing
modules to model facilities on a combination of facility and intake-specific questionnaire data in addition to satellite photos
and maps, where available. Because not all facilities received the same questionnaire, the Agency attempted to utilize data
responses to questions that were asked in both the short-technical and detailed questionnaires whenever possible. In the end,
the primary difference in data analysis between short-technical and detailed questionnaire respondents was the level at which
the Agency developed costs. The short-technical questionnaire responses did not provide significant intake-level data, outside
of intake identification information and velocity. The Agency treated short-technical questionnaire facilities as though they
were a single intake with the characteristics reported for the facility. For the detailed questionnaire facilities, the Agency
obtained sufficient intake-level information to develop individual costing decisions for each intake.
Bl-1.1 Technology Costs
Existing facilities that do not currently comply with the Section 316(b) Phase II Existing Facilities Rule will have to
implement technologies to reduce impingement mortality and/or entrainment. The specific technologies vary for the different
Bl-1
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
rule requirements and site-specific situations, but overall these technologies reduce impingement and entrainment (I&E)
through implementing design and construction technologies.
For the final rule, each model facility has three potential compliance requirements: (1) no impingement and entrainment
controls, (2) impingement controls only, or (3) impingement controls plus entrainment controls. A facility automatically
qualifies for compliance requirement (1) if it has recirculating cooling systems in place.
The Agency determined the compliance requirement for each in-scope intake (facility) and compared that requirement against
the type of technology already in-place. For the case of entrainment requirements, the intake technologies (outside of
recirculating cooling) that qualify to meet the requirements at baseline are fine mesh screen systems, and combinations of
far-offshore inlets with passive intakes or fish handling/return systems. A small subset of intakes has entrainment qualifying
technologies in-place at baseline. Therefore, in the case of entrainment requirements, most facilities with the requirement will
receive technology upgrades. For the case of impingement requirements, there are a variety of intake technologies that
qualify to meet the requirements at baseline. The intake types meeting impingement requirements at baseline include the
following: barrier net (the only fish diversion system which qualifies), passive intakes (of a variety of types), and fish handling
and return systems. A significant number of intakes (facilities) have impingement technologies in place. Therefore, some
intakes (facilities) require no technology upgrades when only impingement requirements apply.
For facilities that do not pre-qualify for impingement and/or entrainment technology in-place credits, the Agency analyzed
questionnaire data relating to the intake type to determine the particular technology module that would best meet the
requirements for the intake.
EPA developed the following costing modules for assessing model-facility compliance costs for today's final rule:
•• #1 - Fish handling and return system (impingement only)
*• #2 - Fine mesh traveling screens with fish handling and return (impingement & entrainment)
•• #3 - New larger intake structure with fine mesh, handling and return (impingement & entrainment)
*• #4 - Passive fine mesh screens with 1.75 mm mesh size at shoreline (impingement & entrainment)
*• #5 - Fish barrier net (impingement only)
•• #6 - Gunderboom (impingement & entrainment)
*• #7 - Relocate intake to submerged offshore with passive fine mesh screen with 1.75 mm mesh size (impingement &
entrainment)
*• #8 - Velocity cap at inlet of offshore submerged (impingement only)
•• #9 - Passive fine mesh screen with 1.75 mm mesh size at inlet of offshore submerged (impingement & entrainment)
*• #10 - Shoreline tech for submerged offshore (impingement only or I&E)
•• #11 - Double-entry, single-exit with fine mesh and fish handling and return (impingement & entrainment)
*• #12 - Passive fine mesh screens with 0.75 mm mesh size at shoreline (impingement & entrainment)
•• #13 - Relocate intake to submerged offshore with passive fine mesh screen with 0.75 mm mesh size (impingement &
entrainment)
*• #14 - Passive fine mesh screen at inlet of offshore submerged with 0.75 mm mesh size (impingement & entrainment)
The development and documentation accompanying these costing modules is available in the Phase II Technical
Development Document.
Bl-1.2 Energy Costs
Installation of some of the compliance technologies considered for the final rule will require a one-time, temporary downtime
of the plant.
Bl-2
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Module #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Table Bl-1: Estimated Average Downtime for Technology
Description
jFish handling and return system
jFine mesh traveling screens with fish handling and return
jNew larger intake structure with fine mesh, handling and return
! Passive fine mesh screens with 1 .75 mm mesh size at shoreline
! Fish barrier net
iGunderboom
! Relocate intake to submerged offshore with passive fine mesh screen with 1 .75
jmm mesh size
! Velocity cap at inlet of offshore submerged
! Passive fine mesh screen with 1 .75 mm mesh size at inlet of offshore submerged
! Shoreline tech for submerged offshore
! Double-entry, single-exit with fine mesh and fish handling and return
jPassive fine mesh screens with 0.75 mm mesh size at shoreline
jRelocate intake to submerged offshore with passive fine mesh screen with 0.75
jmm mesh size
Passive fine mesh screen at inlet of offshore submerged with 0.75 mm mesh size
Modules
Estimated Net Downtime
(Weeks)
0
0
2-4
9-11
0
0
9-11
0
0
0
0
9-11
0
9-11
Source: U.S. EPA analysis, 2004.
The estimated downtimes are net outages attributable to the changes made to the cooling system in response to the final Phase
II rule. EPA assumes that plants would minimize the disruption to their operations by making the required technology
upgrades 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
technology upgrades during maintenance periods, facilities could minimize the net impact of their system changes. For the
purposes of this analysis, the Agency assumed that the typical scheduled maintenance outages would be four weeks.
»»» Monetary valuation of downtime
Technology upgrade downtimes represent a cost to the facilities that incur them. This cost is a loss in revenues offset by a
simultaneous reduction in variable production costs (while the plant is out of service, it loses revenues but also does not incur
variable costs of production).
EPA estimated facility-specific baseline revenue losses using 2008 revenue projections from the Integrated Planning Model
(IPM®). IPM revenues consist of energy revenues and capacity revenues (see discussion of the IPM in Chapter B3). One-
time losses due to installation downtime were calculated by dividing each facility's annual revenue projections by 52 and
multiplying this value by the estimated average downtime (in weeks) of the facility's compliance technology. For facilities
not modeled by the IPM, EPA calculated revenues based on electricity sales for a "typical" operating year for each in-scope
facility (using public data from the Energy Information Administration) and the utility-specific wholesale price of electricity.
For more detail on this substitute methodology, please refer to Chapter B2 of the EBA as published in support of the proposed
Phase II rule.
EPA also used IPM estimates to calculate avoided variable production costs during the downtime, again using facility-specific
2008 projections from the IPM. Variable production cost include both fuel and other variable operating and maintenance
costs. Similar to revenues, each facility's annual variable production costs were divided by 52 and multiplied by the facility's
estimated average downtime (in weeks). For facilities not modeled by the IPM, EPA used average variable production cost
per megawatt hour (MWh) by North American Electric Reliability Council (NERC) region and plant type, calculated from all
For a detailed discussion of scheduled maintenance outages, see the Phase II Technical Development Document.
Bl-3
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
Phase II facilities modeled by the IPM, and multiplied the facility's generation by the average that corresponds to the
facility's NERC region and plant type.
In summary, the average cost of the technology upgrade downtime is the revenue loss during the downtime less the variable
expenses that would normally be incurred during that period. The following formulas were used to calculate the net loss due
to downtime:
Cost of Connection Outage = Revenue Loss - Variable Production Costs
where
Variable Production Cost = Fuel Cost + Variable Operating A Maintenance Cost
This approach may overstate the cost of the connection outage because it is based on average annual revenues and variable
production costs. If downtime is scheduled during off-peak times, the loss in revenues could be smaller as a result of lower
electricity sales and electricity prices.
Bl-1.3 Administrative Costs
Compliance with the final Phase II rule requires 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 National Pollution Discharge Elimination System (NPDES) permit
application
The final rule requires 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 under the current case-by-case cooling
water intake structure permitting procedures, regardless of the final Phase II rule, but are still included in EPA's compliance
cost estimate; therefore, the permitting costs of this final rule may be overestimated. 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;
»• permit application activities: developing a statement of the compliance option selected; developing drawings that
show the physical characteristics of the source water; developing a description of the cooling water intake structure
(CWIS) configuration and location; developing a facility water balance diagram; developing a narrative of CWIS
and cooling water system (CWS) operational characteristics; performing engineering calculations; submitting
materials for review by the Director; and keeping records;
In addition, the initial permit renewal application requires a comprehensive demonstration study. The comprehensive
demonstration study is a broad set of activities meant to: (1) characterize the source water baseline in the vicinity of the intake
structure(s); (2) characterize operation of the cooling water intake(s); and (3) confirm that the technology(ies), operational
measures and restoration measures proposed and/or implemented at the CWIS meet the applicable performance standards.
The following activities are associated with the comprehensive demonstration study portion of the initial permit application:
•• proposal for collection of information for comprehensive demonstration study: describing historical studies that
will be used; describing the proposed and/or implemented technologies, operational measures, and restoration
measures to be evaluated; developing a source water sampling plan; submitting data and plans for review; revising
plans based on state review; and keeping records;
2 For a detailed discussion of the NERC regions see Chapter B3, section B3-2.1.C.
Bl-4
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
•• source waterbody flow information: gathering information to characterize flow (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;
*• design and construction technology plan: delineating hydraulic zone of influence; developing narrative descriptions
of technologies; performing engineering calculations; documenting that technologies are optimal; submitting the plan
for review; and keeping records;
•• impingement mortality and entrainment characterization study: performing biological sampling; performing
impingement and entrainment monitoring; profiling source water biota; identifying critical species; developing a
description of additional stresses; developing report based on study results; revising report based on state review;
and keeping records;
*• impingement mortality and entrainment characterization study capital and O&M costs: permitting process capital
and O&M costs associated with the impingement mortality and entrainment characterization study;
•• 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; submitting data
and plan for review; revising plan based on state review; and keeping records.
Table Bl-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 and whether it exceeds capacity utilization rate and proportional flow thresholds. Certain activities are expected to
be more costly for marine and Great Lakes facilities than for freshwater facilities. Some activities apply to all facilities, while
other activities apply only if the facility exceeds the capacity utilization rate or proportional flow thresholds. Facilities that
have recirculating systems in the baseline, and facilities that already have or are required to install wedgewire screens, will
only have a few required activities. The maximum initial permitting cost for a facility that carries out all of the described
activities is estimated to be approximately $1.0 million.
Table Bl-2: Cost of Initial Post-Promulgation NPDES Permit Application Activities ($2002)
Activity
Start-up activities'5
Permit application activities"
Proposal for collection of information for
comprehensive demonstration studyb
Source waterbody flow informationa
Design and construction technology plana
Impingement mortality and entrainment
characterization study"
Impingement mortality and entrainment
characterization study capital and O&M costs"
Verification monitoring plana
Total Initial Post-Promulgation NPDES Permit
Application Cost
Estimated Maximum Cost per Permit
Freshwater
River/
Stream
$2,297
$11,105
$13,740
$3,768
$6,751
$442,474
$78,000
$6,667
$564,802
Lake
$2,297
$11,105
$13,740
$4,370
$4,875
$442,474
$78,000
$6,667
$563,528
Great Lake
$2,297
$11,105
$13,740
$0
$6,751
$811,401
$152,100
$6,667
$1,004,061
Estuary/
Tidal River
$2,297
$11,105
$13,740
$0
$6,751
$811,401
$152,100
$6,667
$1,004,061
Ocean
$2,297
$11,105
$13,740
$0
$6,751
$811,401
$152,100
$6,667
$1,004,061
a The costs for these activities are incurred during the year prior to the permit application.
b The costs for these activities are incurred during one year, three years prior to the permit application.
" The costs for these activities are incurred during the three years prior to the permit application.
Source: U.S. EPA, 2004a.
Bl-5
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
Another potential cost associated with the initial NPDES permit is pilot studies of compliance technologies. Facilities carry
out pilot studies to determine if the compliance technology will function properly when installed and operated. EPA assumes
that facilities with technology installation costs of greater than $500,000 will conduct pilot studies, and that these studies will
cost either $1 50,000 or ten percent of technology installation costs, whichever is greater. EPA estimates that approximately
15 percent of Phase II facilities will incur these costs. Activities associated with pilot studies include:
*• deploying the pilot technology: installing an intake pipe separate from the facility's actual cooling water system, but
in the vicinity of the operating CWIS; installing the proposed technology to feed into the separate intake pipe; and
pumping water through the intake pipe under various pumping scenarios and seasonal conditions;
> monitoring efforts: collecting five samples over a twenty-four hour period, every two weeks for six months;
> evaluation of data: analyzing the data; summarizing the results; and using this information to evaluate the
effectiveness of the technology.
In addition to the activities described above, some facilities are expected to conduct a site-specific determination of Best
Technology Available (BTA). Since activities associated with site-specific determinations are voluntary and would only be
conducted if the facilities expected them to be less expensive than complying with the Phase II requirements, EPA did not
include site-specific determination costs in its compliance cost estimates. The initial permitting activities associated with site-
specific determinations are:
•• information to support site-specific determination of BTA: performing a comprehensive cost evaluation study;
developing valuation of monetized benefits of reducing impingement and entrainment; evaluating detailed mortality
data; performing engineering calculations and drawings; submitting results for review; and keeping records; and
*• site-specific technology plan: describing selected technologies, operational measures, and restoration measures;
documenting that technologies, operational measures, or restoration measures are optimal; performing design
calculations and preparing drawings and estimates; performing engineering calculations, including estimates of the
efficacy of the proposed and/or implemented technologies, operational measures, or restauration measures;
submitting results for review; and keeping records.
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 required for the initial permit renewal application. EPA
expects that facilities can use some of the information from the initial permit application. 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 Bl-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 and whether it exceeds the capacity
utilization rate and proportional flow thresholds. Certain activities are expected to be more costly for facilities located on a
Great Lake, estuary, tidal river, or ocean than for freshwater facilities. The maximum repermitting cost for a facility that
carries out all of the described activities is estimated to be approximately $340,900.
Bl-6
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-3: Cost of NPDES Repermit Application Activities ($2002)a
Activity
Start-up activities
Permit application activities
Proposal for collection of information for comprehensive
demonstration study
Source waterbody flow information
Design and construction technology plan
Impingement mortality and entrainment characterization
study
Impingement mortality and entrainment characterization
study capital and O&M costs
Total NPDES Repermit Application Cost
Estimated Maximum Cost
per Permit
Freshwater
River/
Stream
$770
$6,875
$3,816
$1,170
$3,459
$143,613
$31,200
$190,904
Lake
$770
$6,875
$3,816
$1,351
$2,483
$143,613
$31,200
$190,108
Great
Lake
$770
L J
$6,875
i j
$3,816
$0
$3,459
$265,147
$60,840
$340,907
Estuary/
Tidal
River
$770
L
$6,875
L
$3,816
$0
$3,459
$265,147
$60,840
$340,907
Ocean
$770
L
$6,875
$3,816
$0
$3,459
$265,147
$60,840
$340,907
a The costs for these activities are incurred in the year prior to the application for a permit renewal.
Source: U.S. EPA, 2004a.
c. Monitoring, record keeping, and reporting
Monitoring, record keeping, and reporting activities and costs include:
•• biological monitoring for impingement: collecting monthly samples for at least two years after the initial permit
issuance; analyzing samples; performing statistical analyses; and keeping records;
*• biological monitoring for entrainment: collecting biweekly samples during the primary period of reproduction,
larval recruitment, and peak abundance for at least two years after the initial permit issuance; handling and preparing
samples; performing statistical analyses, and keeping records;
»• entrainm ent sampling capital and O&M costs: contract laboratory analysis of entrainment samples;
•• verification study: conducting technology performance monitoring; performing statistical analyses; submitting
monitoring results and study analysis; and keeping records;
*• yearly status report activities: reporting on inspection and maintenance activities; detailing biological monitoring
results; compiling and submitting the report; and keeping records.
Table Bl-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 are estimated to incur for its monitoring, record keeping, and reporting activities is approximately $99,900.
Bl-7
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
Bl: Summary of Compliance Costs
Table Bl-4: Cost of Annual Monitoring, Record Keeping, and Reporting Activities ($2002)
Activity
Biological monitoring for impingement
Biological monitoring for entrainment
Entrainment sampling capital and O&M costs
Verification study
Yearly status report activities
Total Monitoring, Record Keeping, and Reporting Cost
Estimated Cost
Freshwater
River/
Stream
$19,227
$31,724
$7,800
$7,457
$18,152
$84,361
Lake
$19,227
$31,724
$7,800
$7,457
$18,152
$84,361
Great
Lake
$24,487
$39,667
$10,140
$7,457
$18,152
$99,904
Estuary/
Tidal
River
$24,487
$39,667
$10,140
$7,457
$18,152
$99,904
Ocean
$24,487
$39,667
$10,140
$7,457
$18,152
$99,904
Source: U.S. EPA, 2004a.
Bl -2 ASSIGNING 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) a high concentration of facilities estimated to be out of service as a result of
technology upgrade downtimes in the same region and at the same time could lead to temporary energy effects in that region.
For this analysis, it was assumed that facilities have to come into compliance with the final Phase II rule during the year their
first post-promulgation NPDES permit is issued. Since NPDES permits are renewed every five years, all facilities are
estimated to come into compliance between 2005 and 2009.3 Table Bl-5 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
•• 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
Note that this assumption was made for this analysis only. EPA estimates that, in reality, compliance will begin in 2008.
B1-&
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§ 316(b) Phase II Final Rule - 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"
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
2005
1
16
11
10
0
11
15
7
15
16
10
14
126
2006
0
23
7
3
0
11
13
7
15
20
5
7
111
2007
0
29
4
1
0
11
7
11
11
25
4
4
107
2008
0
22
14
8
0
8
8
15
12
20
8
3
119
2009
0
12
15
8
3
4
10
4
8
15
5
6
91
Total
1
102
51
30
3
45
53
44
61
96
32
35
554
a Note that compliance years were estimated for this analysis. Actual compliance years might be different than stated in this
table.
Source: U.S. EPA analysis, 2004.
Bl -3 TOTAL PRIVATE COMPLIANCE COSTS
EPA estimated the total private pre-tax compliance costs for the final Phase II rule and the alternative regulatory options
based on the unit costs discussed in Section Bl-1 and the compliance years discussed in Section Bl-2. Technology
compliance costs were developed in July 2001 dollars and converted to year-2002 dollars using the construction cost index
(CCI). Administrative costs were developed in 2002 dollars.
Bl-3.1 Methodology
The private cost of the Phase II rule represents the total compliance costs of the 554 in-scope section 316(b) Phase II
facilities. For this analysis, EPA assumed that facilities will comply over a five-year period between 2005 and 2009. 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 Federal and State corporate income tax rates to privately-owned facilities (U.S. Department of
the Treasury, 2002; FTA, 2003). 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:
•• Capital Costs: This cost is incurred in the year that the facility's first post-promulgation permit is issued.
*• Cost of Connection Outage: EPA estimates that the average outage to construct and install the various compliance
technologies ranges from zero to 11 weeks. A more detailed description of this cost is presented in Section Bl-1.2
above. This cost is incurred in the year that the facility installs the technology.
Bl-9
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
•• Impingement Mortality and Entrainment Characterization Study: This is a three-year study required for all
facilities except those who already have recirculating systems in the baseline and those who already have or are
installing a wedgewire screen. The cost of this study is incurred over the three years preceding the facility's first
post-promulgation permit.
4
The following formula was used to calculate the net present value of the one-time costs as of 2004:
Cost
Present Valuex =
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 (2005 to 2009)
b. Annualization of compliance costs
Annualized compliance costs include all capital costs, O&M costs, administrative costs, and plant outage costs of compliance
with the final Phase II rule. To derive the constant annual value of the capital costs and the value of the technology
construction and/or connection plant downtime, EPA annualized them over the component's useful life, using a seven percent
discount rate. 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; the connection downtime and initial permitting costs were annualized over
30 years; the repermitting costs were annualized over 5 years. EPA calculated the annualized capital costs using the
following formula:
r x (1 + y\n
Annualized Capital Cost = Total Capital Costs x —
(1 + r)" - 1
where:
r = Discount rate (7% in this analysis)
n = Amortization period (useful life of equipment; 30 years for connection downtime and initial permitting
costs; 10 years for flow reduction and I&E technologies; 5 years for repermitting costs)
EPA then added the annualized capital, downtime, and permitting costs to annual O&M and administrative costs to derive
each facility's total annual cost of complying with the final 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 beginning of the year.
Bl-10
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§ 316(b) Phase II Final Rule - 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.5 A reduction in tax liability was only applied to privately-owned facilities (government-owned
entities and cooperatives are not subject to income taxes).
Bl-3.2 Total Private Costs of the Final Rule
EPA estimates that the 554 in-scope facilities will incur annual costs of complying with the final Phase II rule of $385 million
on a pre-tax basis and $250 million on a post-tax basis. Table Bl-6 presents annualized facility compliance costs by cost
category and steam plant type. Costs are presented on a pre-tax and post-tax basis. The annual pre-tax compliance costs
range from approximately $6.6 million for other steam facilities to $185 million for coal steam facilities. The annual post-tax
compliance costs range from approximately $4.0 million for other steam facilities to $122 million for coal steam facilities.
Table Bl-6: Private Annualized Compliance Costs by Plant Type (in millions, $2002)
Plant Type
One-Time Costs
Capital
Technology
Coal Steam
Combined Cycle
Nuclear
O/G Steam
Other Steam
Total
$87.2
$5.5
$57.1
$43.5
$3.0
$196.2
Coal Steam
Combined Cycle
Nuclear
O/G Steam
Other Steam
Total
$56.4
$3.4
$34.9
$27.9
$1.8
$124.5
Connection
Outage
$26.3
$0.3
$21.4
$3.8
$0.5
$52.3
$17.0
$0.2
$12.8
$2.3
$0.3
$32.6
Initial Permit j Pilot
Application I Study
Recurring Costs
O&M
Pre-Tax Compliance Costs
$12.7J $1.1
$0.7 1 $0.1
$2.3 1 $1.1
$9.1 1 $0.8
$0.6 1 $0.1
$25.4 1 $3.2
$24.3
$0.6
$2.9
$15.5
$1.2
$44.4
Post-Tax Compliance Costs
$8.6 1 $0.7
$0.5 1 $0.0
$1.5 1 $0.7
$6.1 1 $0.5
$0.4 1 $0.1
$17.0 1 $2.0
$16.6
$0.4
$2.1
$10.8
$0.7
$30.6
Monitoring,
Record Keeping
& Reporting
$24.2
$1.4
$4.9
$14.2
$0.7
$45.6
$16.5
$1.0
$3.1
$9.6
$0.4
$30.7
Permit
Renewal
Total
$8.9
$0.5
$1.7
$6.5
$0.4
$18.2
$184.7
$9.0
$91.4
$93.4
$6.6
$385.1
$6.1
$0.4
$1.1
$4.3
$0.3
$12.2
$122.1
$5.8
$56.2
$61.5
$4.0
$249.5
Source: U.S. EPA analysis, 2004.
Bl-4 UNCERTAINTIES AND LIMITATIONS
EPA's estimates of the compliance costs associated with the final 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 Detailed Questionnaire (DQ) and Short Technical
Questionnaire (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
5 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.
Bl-11
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
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 connection outage. EPA's analysis used projected future
information on electricity generation, electricity prices, and variable production 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 final 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-12
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
REFERENCES
Federation of Tax Administrators (FTA). 2003. Range of State Corporate Income Tax Rates (for tax year 2003).
http://www.taxadmin.org/fta/rate/corp inc.html, accessed July 17, 2003.
U.S. Department of the Treasury. 2002. Internal Revenue Service (IRS). 2002 Instructions for Forms 1120 & 1120-A,page
17 (Federal tax rates).
U.S. Environmental Protection Agency (U.S. EPA). 2004a. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Final Rule. ICR Number 2060.02. February 2004.
U.S. Environmental Protection Agency (U.S. EPA). 2004b. Technical Development Document for the Final Section 316(b)
Phase II Existing Facilities Rule. EPA-821-R-04-007. February 2004.
Bl-13
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts Bl: Summary of Compliance Costs
THIS PAGE INTENTIONALLY LEFT BLANK
Bl-14
-------
§ 316(b) Phase II Final Rule - 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 B2-1
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 implementing the Final
Section 316(b) Phase II Existing Facilities Rule, including a
cost-to-revenue analysis at the facility and firm levels, an
analysis of compliance costs per household at the North
American Electric Reliability Council (NERC) level, and an
analysis of compliance costs relative to electricity price
projections, also at the NERC level.1 Later chapters consider
the potential energy effects of the final 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 BS: UMRA Analysis).
B2-1 COST-TO-REVENUE MEASURE
The "cost-to-revenue measure" is used to assess the magnitude of compliance costs relative to revenues. 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.
Annualized compliance costs include all capital costs, operating and maintenance (O&M) costs, administrative costs, and
plant outage costs of compliance with the final Phase II rule. To derive the constant annual value of the technology capital
costs, the initial permitting cost, and the value of construction and/or connection plant outage, EPA annualized them over 10
or 30 years, using a seven percent discount rate. EPA then added the annualized capital and connection outage costs to
annual O&M costs, and administrative costs to derive each facility's total annual cost of complying with the final 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 (U.S. EPA, 2004).
EPA compared the annualized compliance costs to the estimated facility and firm revenues. This analysis uses impact
thresholds of 1.0 and 3.0 percent.
B2-1.1 Facility Analysis
EPA compared the annualized post-tax compliance costs of the final rule as a percentage of annual revenues for each of the
543 surveyed in-scope facilities. EPA used facility-specific baseline revenue projections from ICF Consulting's Integrated
Planning Model (IPM®) for 2008 for this analysis. The IPM did not provide revenues for 16 facilities. Eight of these
facilities are estimated to be baseline closures and another eight facilities are not modeled by the IPM. In addition, five
facilities are projected by IPM to have zero revenues in the baseline. 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
1 It should be noted that these 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 final 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: Summary of
Compliance Costs. 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 (for this
analysis, assumed to be 2005 to 2009).
B2-1
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
ratio for the 13 non-baseline closure facilities with missing information. EPA then applied sample weights to the 543
facilities to account for non-sampled facilities and facilities that did not respond to the survey.
Table B2-1 below presents the results of the facility-level cost-to-revenue measure conducted for the 554 electric generating
facilities subject to the final 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, greater than three percent, and the number of facilities estimated to be
baseline closures; and (3) the minimum and maximum ratio.
Table B2-1: Facility-Level Cost-to- Revenue Measure
Facility Type
Total
Number
of
Facilities
Number of Facilities with a Ratio of
<0.5%
E
Investor-Owned Utility
Nonutility
Federal Utility
State-Owned Utility
Municipality
Political Subdivision
Rural Electric Cooperative
Total"
274
179
14
7
48
7
25
554
179
94
12
3
14
4
8
314
Coal
Combined-Cycle
Nuclear
Oil and Gas Steam
Other Steam
Total"
302
17
59
168
8
554
189
10
43
72
0
314
0.5 -1%
ty Ownersh
52
36
1
1
4
0
5
99
By Fuel
67
3
1
28
0
99
1 - 3%
ip Type
27
35
1
1
20
1
9
94
Type
38
2
6
41
7
94
>3%
15
8
0
2
10
1
3
39
8
2
2
25
1
39
Baseline
Closure
Minimum
Ratio
1
6
0
0
0
1
0
8
0.01%
0.01%
0.05%
0.03%
0.03%
0.05%
0.03%
0.01%
0
0
7
1
0
8
0.01%
0.01%
0.01%
0.02%
1.20%
1.20%
Maximum
Ratio
81.7%
12.2%
1.9%
3.8%
63.3%
19.0%
8.9%
81.7%
21.1%
5.6%
4.3%
81.7%
4.0%
81.7%
a Individual numbers may not add up due to independent rounding.
Source: IPM analysis: model run for Section 316(b) base case, 2008, EPA electricity demand assumptions; U.S. EPA analysis, 2004.
Table B2-1 shows that the vast majority of facilities subject to the final Phase II rule incur low compliance costs when
compared to facility-level revenues. Out of the 554 facilities subject to the final Phase II rule, 413, or approximately 75
percent, incur annualized costs of less than 1.0 percent of revenues. Of these, 314, or approximately 57 percent, incur
annualized costs of less than 0.5 percent of revenues. Ninety-four facilities, or 17 percent are estimated to incur costs of
between 1.0 and 3.0 percent of revenues, and 39 facilities, or 7 percent, are estimated to incur costs of greater than 3.0
percent. Eight facilities are estimated to be baseline closures.
An investor-owned facility is estimated to experience the highest compliance cost compared to projected revenues, 81.7
percent. In addition, investor-owned utilities are the group with the highest number of facilities (15) with a cost-to-revenue
ratio greater than 3.0. However, State-owned utilities have the highest percentage of facilities with a cost-to-revenue ratio
greater than 3.0, two out of seven, or 29 percent. By fuel type, oil and gas steam electric generators experience the greatest
52-2
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
incidence of compliance costs to revenues: 25 of 1 68 facilities, or 14.9 percent, are estimated to have a cost-to-revenue ratio
of greater than 3.0 percent.
B2-1.2 Firm Analysis
The facility-level analysis above showed that compliance costs are generally low compared to facility-level revenues.
However, impacts experienced at the firm-level may be more significant for firms that own multiple facilities subject to the
final Phase II rule. EPA therefore also analyzed the firm-level cost-to-revenue ratios of the final Phase II rule.
EPA first identified the domestic parent entity of each in-scope Phase II facility (for a detailed description of this analysis, see
Chapter B4: Regulatory Flexibility Analysis). From this analysis, EPA determined that 126 unique domestic parent entities
own the facilities subject to the final Phase II regulation. EPA obtained the sales revenues for the 126 domestic parent entities
from publicly available data sources (the 1999, 2000, and 2001 Forms EIA-861; the Dun and Bradstreet database; company
10-K filings; and entities' websites). The firm-level analysis is based on the ratio of the aggregated post-tax compliance costs
for each facility owned by the 126 parent entities to the firm's total sales revenue. EPA identified 71 entities, out of the 126
unique domestic parent entities, that own more than one facility subject to the final Phase II rule.
Table B2-2 below summarizes the results of the cost-to-revenue measure conducted for the 126 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
Investor-Owned Utility
Nonutility
Federal Utility
State-Owned Utility
Municipality
Political Subdivision
Rural Electric
Cooperative
Total"
Total
Number of
Facilities
274
179
14
7
48
7
25
554
Total
Number
of Firms
41
26
1
4
36
3
15
126
Number of Firms with a Ratio of
<0.5% 1 0.5-1% 1 1-3% 1 >3%
39
25
1
Zj.
20
9
14
105
2
1
0
0
6
0
1
10
0
0
0
0
9
1
0
10
0
0
0
0
1
0
0
1
Minimum
Ratio
0.00%
0.01%
0.17%
0.04%
0.03%
0.09%
0.12%
0.00%
Maximum
Ratio
0.6%
0.8%
0.2%
0.3%
6.7%
1.0%
0.6%
6.7%
a Individual numbers may not add up to totals due to independent rounding.
Source: U.S. EPA analysis, 2004.
EPA estimates that the compliance costs will comprise a very low percentage of firm-level revenues. Of the 126 parent
entities with facilities subject to the final Phase II rule, 115, or approximately 91 percent, incur annualized costs of less than
1.0 percent of revenues. Of these, 105, or approximately 83 percent, incur annualized costs of less than 0.5 percent of
revenues. Ten entities incur costs of between 1.0 and 3.0 percent of revenues and only one entity incurs costs of greater than
3.0 percent. EPA estimates that one entity only owns an in-scope facility, which is projected to be a baseline closure. The
compliance cost incurred by this entity is less than 0.5 percent of revenues. Overall, the estimated annualized compliance
costs represent between less than 0.01 and 6.7 percent of the entities' annual sales revenue.
At the firm level, municipalities are estimated to experience the highest cost-to-revenue ratios. Ten out of eleven firms with
ratios of greater than 1.0 percent are municipalities. In addition, municipalities experience the highest cost-to-revenue ratio of
all parent types, 6.7 percent.
B2-3
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B2: Cost Impact Analysis
B2-2 COST PER HOUSEHOLD
EPA also conducted an analysis that evaluates the potential cost per household, if Phase II facilities were able to pass
compliance costs on to their customers.3 This analysis estimates the average compliance cost per household for each North
American Electric Reliability Council (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.4 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 2001 Form EIA-861
database. Utility-level sales were aggregated by NERC region to derive each region's total electricity sales in 2001.
In addition, EPA aggregated the national pre-tax compliance costs by the NERC region in which the 554 Phase II
facilities are located. The average compliance cost per MWh of electricity sales is calculated by dividing total pre-
tax compliance costs by total electricity sales 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 final 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. This analysis also assumes that there
will be no reduction in electricity consumption by the consumers in response to price increases.
Table B2-3 shows the results of this analysis: the estimated cost per residential consumer ranges from $0.50 per year in
Alaska (ASCC) to $8.18 per year in Hawaii (HI). The U.S. average cost per residential household is $1.21 per year.
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.
4 For a detailed discussion of NERC regions see Chapter A3, Profile of the Electric Power Industry, section A3-2.3.
B2-4
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
Table B2-3
NERC
Region "
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
U.S.
Total National
Pre-Tax
Compliance
Cost
$337,442
$76,413,402
$20,921,310
$27,281,223
$10,095,493
$39,826,208
$31,880,030
$11,833,570
$54,991,490
$63,409,419
$11,291,028
$36,821,337
$385,101,952
Annual Compliance Cost per Residential Consumer by NERC Region in 2001
Total
Electricity
Sales (MWh)
5,427,689
504,256,959
280,585,786
186,616,722
9,370,360
235,576,827
257,913,569
139,610,505
253,142,223
748,160,887
172,750,800
571,981,463
3,365,393,790
Annualized
Pre-Tax
Compliance
Cost ($ /
MWh Sales)
$0.06
$0.15
$0.07
$0.15
$1.08
$0.17
$0.12
$0.08
$0.22
$0.08
$0.07
$0.06
$0.11
Residential
Electricity
Sales (MWh)
1,891,468
161,442,646
105,198,123
94,834,627
2,665,168
82,687,782
75,925,257
49,125,931
87,587,585
278,450,252
60,173,420
200,686,234
1,200,668,493
Number of
Households
234,646
15,698,205
7,309,073
6,885,280
351,229
8,921,106
8,366,132
4,933,221
12,676,283
20,550,922
5,002,020
23,085,962
114,014,079
Annual
Residential
Sales/
Consumer
(MWh)
8.06
10.28
14.39
13.77
7.59
9.27
9.08
9.96
6.91
13.55
12.03
8.69
10.53
Annual
Compliance
Cost/
Residential
Consumer
$0.50
$1.56
$1.07
$2.01
$8.18
$1.57
$1.12
$0.84
$1.50
$1.15
$0.79
$0.56
$1.21
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, 2001; U.S. EPA analysis, 2004.
B2-5
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
B2-3 ELECTRICITY PRICE ANALYSIS
EPA also considered potential effects of the final 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 final rule; (2) total electricity sales, based on the
Annual Energy Outlook (AEO) 2003; and (3) prices by consumer type (residential, commercial, industrial, and
transportation), also from the AEO 2003. All three data elements were calculated by NERC region.5
Table B2-4 shows the annualized costs of complying with the final 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 0.007 cents per KWh sales in
SPP to 0.019 cents per KWh sales in NPCC. The U.S. average is estimated to be 0.011 cents per KWh sales.
Table E
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
U.S.
!2-4: Compliance Cos1
Annualized Pre-Tax
Compliance Costs
(National; $2002)
$337,442
$76,413,402
$20,921,310
$27,281,223
$10,095,493
$39,826,208
$31,880,030
$11,833,570
$54,991,490
$63,409,419
$11,291,028
$36,821,337
$385,101,952
t per KWh of Sales by
Total Electricity Sales
(MWh; 2001)
...
508,632,996
269,572,052
186,505,005
...
243,576,004
231,183,029
150,737,030
282,686,981
756,352,051
167,893,982
223,035,996
3,397,995,361
^JERC Region
Annualized Pre-Tax
Compliance Cost (Cents
/ KWh Sales)
...
00.015
00.008
00.015
...
00.016
00.014
00.008
00.019
00.008
00.007
00.017
00.011
Source: U.S. DOE, 2003; U.S. EPA analysis, 2004.
To determine potential effects on electricity prices as a result of the final 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 increases by consumer type that are estimated to result from the final Phase II rule. The largest potential
increase in electricity prices is 0.49 percent (00.017 / 03.39) for an industrial facility in WSCC. The average increase in
electricity prices is only estimated to be between 0.13 percent (00.Oil 708.58) for households and 0.24 percent (00.011 /
04.77) for industrial customers.
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.
5 The Annual Energy Outlook does not include two NERC regions, ASCC and HI.
B2-6
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B2: Cost Impact Analysis
Table B2-5: Estimated Price Increase as a Percent of 2001 Prices by Consumer Type and NERC Region"
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
U.S.
Annualized
Pre-Tax
Compliance
Cost (Cents /
KWh Sales)
00.015
00.008
00.015
00.016
00.014
00.008
00.019
00.008
00.007
00.017
00.011
Residential ; Commercial ; Industrial ; Transportation
i o/ i i o/ i i o/ i i o/
T, . /O T» • /O T» • /O T» • /O
"rice : : "rice : : "rice : : "rice :
; Change ; ; Change ; ; Change ; ; Change
: i : i i
07.54J 0.20% 06.54J 0.23% 04.17J 0.36%l 06.16J 0.24%
r '. r '. r '. '. r '.
08.15 1 0.10% 07.67J 0.10% 04.57J 0.17%| 07.10J 0.11%
1 i ill
08.68J 0.17% 07.14J 0.20% 05.39J 0.27%! 07.70J 0.19%
r '. r '. r '. '. r '.
09.09J 0.18% 07.75J 0.21% 06.32J 0.26%| 07.88J 0.21%
1 i ill
07.79J 0.18% 06.58J 0.21% 04.28J 0.32%l 06.45J 0.21%
r '. r '. r '. '. r '.
07.07J 0.11% 05.95J 0.13% 03.99J 0.20%| 05.93J 0.13%
1 i ill
012. 98J 0.15% 010.45J 0.19% 06.56J 0.30%| 010.48J 0.19%
07.70J 0.11% 06.67J 0.13% 04.23J 0.20%| 06.64J 0.13%
1 i ill
07.58J 0.09% 06.38J 0.11% 04.15 1 0.16%l 06.04J 0.11%
r '. r '. r '. '. r '.
06.50J 0.25% 06.15J 0.27% 03.39J 0.49%| 05.93J 0.28%
1 i ill
08.58 0.13% 07.85 1 0.14% 04.77 j 0.24% j 07.39 j 0.15%
All Sectors
Average
Price ; „,
Change
:
05.92J 0.25^
06.94J O.ll'X
I
07.80J 0.19^
07.92J 0.21%
I
06.24J 0.22^
05.60J 0.\4%
I
010. 57J O.IS'X
06.27J 0.13%
I
06.18J 0.\\°A
05.28J 03\%
I
07.21 1 0.16%
a Prices are in cents per KWh.
Source: U.S. EPA analysis, 2004.
B2-7
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B2: Cost Impact Analysis
REFERENCES
U.S. Department of Energy (U.S. DOE). 2003. Energy Information Administration (ElA). Annual Energy Outlook 2003
With Projections to 2025. DOE/EIA-0383(2003). January 2003.
U.S. Department of Energy (U.S. DOE). 2001. FormEIA-861. Annual Electric Utility Report for the Reporting Period
2001.
U.S. Environmental Protection Agency (U.S. EPA). 2004. Technical Development Document for the Final Section 3l6(b)
Phase II Existing Facilities Rule. EPA-821-R-04-007. February 2004.
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Chapter B3: Electricity Market
Model Analysis
INTRODUCTION
The Final Section 316(b) Phase II Existing Facilities Rule
applies to a subset of facilities within the electric power
generation industry. However, due to interdependencies
within the electric power market, direct 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 capacity utilization, generation,
and profitability. 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 regional and
national impacts such as changes in the price of electricity
and the construction of new generating capacity.
EPA used ICF Consulting's Integrated Planning Model
(IPM®), an integrated energy market model, to conduct the
economic analyses supporting the Final 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 final 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");1 and (2) potential
economic impacts on in-scope facilities.
The final rule was evaluated under two electricity demand growth assumptions: The first scenario uses EPA's electricity
demand assumptions. Under this scenario, demand for electricity is based on the Annual Energy Outlook (AEO) 2001
forecast adjusted to account for efficiency improvements not factored into AEO's projections of electricity sales. The second
scenario uses the unadjusted electricity demand from the AEO 2001. Section B3-4 presents the results of the IPM analysis for
the final rule under EPA's assumptions. Appendix A presents the results of the IPM analysis for the final rule under the
unadjusted AEO assumptions. The appendix also presents a comparison of the results under the two alternative scenarios.
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 B3-10
B3-3.2 Facility-level Impact Measures B3-11
B3-4 Analysis Results for the Final Rule B3-12
B3-4.1 Market Analysis for 2010 B3-12
B3-4.2 Analysis of Phase II Facilities for 2010 . . . B3-18
B3-4.3 Market Analysis for 2008 B3-25
B3-5 Uncertainties and Limitations B3-30
References B3-31
Appendix A to Chapter B3 B3-32
Appendix B to Chapter B3 B3-46
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 professionals, EPA identified three potential
models and considered each for the analyses in support of the 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 Please refer to Section B6-7 for a discussion of this analysis.
2 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
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
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
suited for the analysis of section 316(b) regulatory options. Modeling criteria refer to the models' technical capabilities that
are required to provide the outputs necessary for the analysis of the section 316(b) regulation. 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 Phase II regulation 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 section 316(b) regulation 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 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.3 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 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).
3 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 Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
B3-2 INTEGRATED PLANNING 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.
When the analyses in support of the Phase II proposal and Notice of Data Availability (NODA) were developed, the latest
EPA specification of the U.S. power market, "EPA Base Case 2000," was based on IPM Version 2.1. In July 2003 a new
version of the model, Version 2.1.6, was released. However, the tight promulgation schedule made it impossible for EPA to
switch to the newer version for the analyses in support of this final rule. The analyses presented in this chapter, and the
appendix, are therefore based on the specifications for the EPA Base Case 2000.
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.
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 orrepowering 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.
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 in impingement and entrainment 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.
B3-3
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§ 316(b) Phase II Final Rule - 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
YC
Source: U.S. EPA, 2002.
B3-4
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table 63-1: Crosswalk between NERC Regions and IPM Regions
MERC 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, and 2013.5 The model run years were selected before the analysis in support of the
proposed Phase II rule for the following reasons:
»• 2008 was selected based on the assumption that all in-scope facilities would be required to comply with the
requirements of the Phase II rule during the first five years after promulgation (at the time of proposal, promulgation
was scheduled for August 28, 2003 so that the compliance window would have been 2004 to 2008). Therefore, in
2008, all facilities would have been in compliance, and 2008 would have represented the post-compliance state of
the industry.
> 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 at proposal) would have to comply by the end of
the permit term of the first permit issued after promulgation (at the time, this was 2004 to 2012). As installation of a
cooling tower may require the temporary shut-down of the facility, 2013 would have represented the first full, post-
compliance year for options requiring cooling towers.
> 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.
With the change in promulgation date from August 28, 2003 to February, 2004, EPA revised its assumptions of when
facilities are likely to come into compliance with the Phase II rule from 2004-2008 to 2005-2009 (because start-up activities
are required for compliance with the Phase II rule, it will no longer be possible to comply in 2004).6 However, changing run
5 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 2026 was not used in this analysis.
6 Note that compliance years 2005 to 2009 are an assumption for this analysis. The "real" compliance schedule might be different.
B3-5
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
years requires significant structural changes to the IPM. EPA therefore decided not to change the model run years selected at
proposal for this analysis. EPA mainly relied on data for 2010 in the analyses of the final rule (presented in this chapter).
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 Phase II regulatory options, and the calendar years mapped to each.
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) NODA Base Case.
B3-2.2 Specifications for the Section 316(b) Analysis
The analysis of the Final Phase II Rule (and the other regulatory options analyzed at proposal and for the NODA) 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
totalnumber of model plants from 1,390 to 1,777'. For the NODA and final rule analyses, EPA also disaggregated
non-steam generators at Phase II facilities and generators at facilities subject to the upcoming Phase III regulation.
This change increased the total number of model plants from 1,777 to 2,096.
•• Use of Different Mo del Run Years: The original specification of the IPM's EPA Base Case 2000 uses five model
run years chosen based on the requirements of various air policy analyses: 2005, 2010, 2015, 2020, and 2026. As
explained above, EPA was interested in analyzing different years for the section 316(b) Phase II rule. Therefore,
EPA changed the 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.
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
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) Base Case
Run Year Run
2008
2010
2013
2020
2026
Specification
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) NODA 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:
»• Base case total production costs (capital, O&M, and fuel) using the revised section 316(b) specifications do not
change in 2010 and are lower by 0.1% in 2020.
»• Early retirements of base case oil and gas steam capacity under the section 316(b) specifications are lower by 850
megawatt (MW). Early retirements of base case nuclear capacity decreased by 480 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 use and a 1.5 percent reduction in
gas fuel use in 2010.
The IPM base case specification for the final rule is the same as the one used for the section 316(b) Phase II NODA.
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 535 facilities subject to Phase II regulation and modeled by the
IPM.7 For each facility, compliance costs consist of capital costs (including costs for new screens or fish barrier nets, intake
relocation, and intake piping modification), fixed O&M costs, variable O&M costs, permitting costs, and capacity reductions
(for information on the costing methodology, see the Section 316(b) Technical Development Document; U.S. EPA, 2004).
»• Capital cost inputs into the IPM are expressed as a fixed O&M cost, in dollars per kilowatt (KW) of capacity per
year. The capital costs of compliance reflect the up-front cost of construction, equipment, and capital associated
with the installation of required compliance technologies. The IPM uses two up-front cost values as model inputs
(one each for technologies with a useful life of 10 and 30 years, respectively) and translates these values into a series
of annual post-tax 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 for initial permitting costs and 10 years for the
various compliance technologies) or the years remaining in the modeling horizon, whichever is shorter.8
»• 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 megawatt hour (MWh) of generation.
7 Of the 543 surveyed facilities subject to the section 316(b) Phase II rule, eight are not modeled in the IPM. Three facilities are in
Hawaii and one is in Alaska. Neither state is represented in the IPM. Four facilities are on-site generators that do not provide electricity to
the grid.
8 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 Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
»• Permitting costs consist of initial permitting costs, annual monitoring costs, repermitting costs (occurring every five
years after issuance of the initial permit), and, for some facilities, pilot study costs. Permitting cost inputs are
expressed as follows: initial permitting and pilot study activities are necessary for the on-going operation of the plant
and are therefore added to the capital costs for technologies with a 30-year useful life; annual monitoring and
annualized repermitting costs are added to the fixed O&M costs.
»• Capacity reductions consist of a one-time generator downtime. Generator downtime estimates reflect the amount of
time generators are off-line while compliance technologies are constructed and/or installed and are expressed in
weeks. The generator downtime is a one-time event that affects several of the compliance technologies evaluated by
EPA. Generator downtime is estimated to occur during the year when a facility complies with the policy option.
Since the years that are mapped into a run year are assumed to have the same characteristics as the run year itself,
generator downtimes were applied as an average over the years that are mapped into each model run year.9
Estimated generator downtimes due to construction and/or installation range from two to eleven weeks (see also
Chapter Bl, Table Bl-1).
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 535 modeled section 31 6(b) facilities were identified using data
from the IPM.
> 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
design intake flow data, this distribution was based on each generator's proportion of total design intake volume; for
facilities without available design 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, 201 3, 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
9 For example, a facility with a downtime in 2008 was modeled as if l/5th of its downtime occurred in each year between 2005 and
2009. A potential drawback of this approach of averaging downtimes over the mapped years is that the snapshot of the effect of downtimes
during the model run year is the average effect; this approach does not model potential worst case effects of above-average amounts of
capacity being down in any one NERC region during any one year.
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 100 MW. Generator-level design intake flow data were not available for 57 of the 535 modeled facilities.
11 Repowering in the IPM consists of converting oil/gas or coal capacity to combined-cycle capacity. The modeling assumption is
that each one MW of existing capacity is replaced by two MW of repowered capacity.
B3-8
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
»• 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 final rule and other regulatory alternatives. 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.
»• 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
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.
»• 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 cost 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. In post-compliance scenarios, fixed O&M costs also include
annualized capital costs of compliance and permitting costs.
»• Capital Costs - The cost of construction, equipment, and capital. Capital costs are associated with investment in
new equipment, e.g., the replacement of a boiler or condenser, installation of technologies to meet the requirements
of air regulations, or the repowering of a plant.
B3-3 ECONOMIC IMPACT ANALYSIS METHODOLOGY
The outputs presented in the previous section were used to identify changes to economic and operational characteristics such
as capacity, generation, revenue, cost of generation, and electricity prices associated with Phase II regulatory options. EPA
developed impact measures at two analytic levels: (1) the market as a whole, including all facilities 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 (i.e., the model run in the absence of section
316(b) Phase II regulations) and the post-compliance scenario. The following subsections describe the impact measures used
for the two levels of analysis.
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.
B3-9
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
B3-3.1 Market-level Impact Measures
The market-level analysis evaluates regional changes as a result of Phase II 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 partial or full closures of plants subject to the rule. In the
short term, temporary plant shut-downs for the installation of Phase II compliance technologies may lead to
reductions in available capacity.13 When analyzing changes in available capacity, EPA distinguished between
existing capacity, new capacity additions, and repowering additions. Under this measure, EPA also analyzed
capacity closures. Only capacity that is projected to remain operational in the base case but is closed in the post-
compliance case is 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 unit or plant that would close in the base case but operates in the post-
compliance case.
> (2) Changes in the price of electricity: This measure considers changes in regional prices as a result of Phase II
regulation. 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 Phase II compliance technologies. This analysis considers changes in both energy prices
and capacity prices.
> (3) 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 or a change in the amount of electricity traded between
regions. In the short term, temporary plant shut-downs to install Phase II compliance technologies 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.
> (4) Changes in revenues: This measure considers the revenues realized by all facilities in the market and includes
both energy revenues and capacity revenues (see definition in section B3-2.4 above). A change in revenues could be
the result of a change in generation and/or the price of electricity.
> (5) Changes in costs: This measure considers changes in the overall cost of generating electricity, including fuel
costs, variable and fixed O&M costs, and capital costs. Fuel costs and variable O&M costs are production costs
that vary with the level of generation. Fuel costs generally account for the single largest share of production costs.
Fixed O&M costs and capital costs do not vary with generation. They are fixed in the short-term and therefore do
not affect the dispatch decision of a unit (given sufficient demand, a unit will dispatch as long as the price of
electricity is at least equal to its per MWh production costs). However, in the long-run, these costs need to be
recovered for a unit to remain economically viable.
> (6) Changes in pre-tax income: Pre-tax income is defined as total revenues minus total costs and is an indicator of
profitability. Pre-tax income may decrease as a result of reductions in revenues and/or increases in costs.
> (7) Changes in variable production costs per MWh: 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
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. This measure presents similar information to total fuel and variable O&M costs under measure
(5) above, but normalized for changes in generation.
13 Such short-term capacity reductions would not be expressed as changes in available capacity but might affect electricity generation,
production costs, and/or prices.
B3-10
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
B3-3.2 Facility-level Impact Measures (In-scope Facilities Only)
EPA used the IPM results to analyze impacts on in-scope Phase II facilities at two levels: (1) potential changes in the
economic and operational characteristics of the in-scope Phase II facilities as a group and (2) potential changes to individual
facilities within the group of in-scope Phase II facilities.
a. In-scope Phase II facilities as a group
The analysis of the in-scope Phase II facilities as a group is largely similar to the market-level analysis described in Section
B3-3.1 above, except that the base case and policy option totals only include the economic activities of the 535 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) the number of Phase II facilities that experience closure of all their steam electric capacity is
presented, and (3) repowering changes are not explicitly analyzed at the facility level. 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 535 Phase II facilities. A
long-term reduction in availability may be the result of partial or full plant closures, a change in the decision to
repower, or a change in the choice of air pollution control technologies. In the short term, temporary plant shut-
downs for the installation of Phase II compliance technologies may lead to reductions in available capacity.14 Under
this measure, EPA also analyzed closures. Only capacity that is projected to remain operational in the base case but
is closed in the post-compliance case is 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 unit or plant that would close in the base case but
operates in the post-compliance case. At the facility-level, both the number of full closure facilities and closure
capacity are analyzed.
> (2) Changes in generation: This measure considers the generation at the 535 Phase II facilities. Long-term changes
in generation may be the result of a reduction in available capacity (see discussion above) or the 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 535 Phase II facilities. For some Phase II facilities,
Phase II regulation 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 535 Phase II facilities and includes
both energy revenues and capacity revenues (see definition in section B3-2.4 above). A change in revenues could be
the result of a change in generation and/or the price of electricity. For some modeled 3 16(b) facilities, Phase II
regulation 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 costs: This measure considers changes in the overall cost of generating electricity for the 535 Phase
II facilities, including fuel costs, variable and fixed O&M costs, and capital costs. Fuel costs and variable O&M
costs are production costs that vary with the level of generation. Fuel costs generally account for the single largest
share of production costs. Fixed O&M costs and capital costs do not vary with generation. They are fixed in the
short-term and therefore do not affect the dispatch decision of a unit (given sufficient demand, a unit will dispatch as
long as the price of electricity is at least equal to its per MWh production costs). However, in the long-run, these
costs need to be recovered for a unit to remain economically viable.
> (5) Changes in pre-tax income: Pre-tax income is defined as total revenues minus total costs and is an indicator of
profitability. Pre-tax income may decrease as a result of reductions in revenues and/or increases in costs.
*• (6) Changes in variable production costs per MWh: 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.
14 Such short-term capacity reductions would not be expressed as changes in available capacity but might affect electricity generation,
production costs, and/or prices.
B3-11
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
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 three ranges: 1 percent or less, 1 to 3 percent, and more than 3 percent. 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 per MWh: See explanation in subsection a. above.
> (5) Changes in fuel costs per MWh: See explanation in subsection a. above.
*• (6) Changes in pre-tax income: See explanation in subsection a. above.
B3-4 ANALYSIS RESULTS FOR THE FINAL RULE
The remainder of this section presents the results of the economic impact analysis of the final Phase II rule for the ten NERC
regions modeled by the IPM. The analysis is based on IPM output for the base case (using EPA electricity demand
assumptions) and the final rule. Results are presented at the market level and the Phase II facility level.
The main analysis in this chapter uses output from model run year 2010. For this analysis, facilities subject to the final rule
are assumed to come into compliance during the year of their first post-promulgation national pollution discharge elimination
system (NPDES) permit (2005 to 2009). Therefore, 2010 is assumed to be the first year during which all facilities are in
compliance, but no facilities experience technology installation downtimes. 2010 thus represents the post-compliance
condition of the industry. EPA also analyzed potential market-level impacts of the final rule for a year within the compliance
period during which some Phase II facilities experience installation downtimes. This secondary analysis represents potential
short-term impacts of the final rule and uses output from model run year 2008.
B3-4.1 Market Analysis for 2010
This section presents the results of the IPM analysis for all facilities modeled by the IPM. The market-level analysis includes
results for all generators located in each NERC region including facilities that are in-scope and facilities that are out-of-scope
of Phase II regulation.
Table B3-4 presents the market-level impact measures discussed in section B3-3.1 above: (1) capacity changes, including
changes in existing capacity, new additions, repowering additions, and closures; (2) electricity price changes, including
changes in energy prices and capacity prices; (3) generation changes; (4) revenue changes; (5) cost changes, including
changes in fuel costs, variable O&M costs, fixed O&M costs, and capital costs; (6) changes in pre-tax income; and (7)
changes in variable production costs per MWh of generation. For each measure, the table presents the results for the base
case and the final rule, the absolute difference between the two cases, and the percentage difference.
B3-12
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-4: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
EPA Base Case
National Totals
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
887,915
787,280
79,683
20,951
14,122
n/a
n/a
4,113,839
$138,770
$87,486
$47,789
$7,926
$23,417
$8,354
$51,284
$13.54
East Central Area Reliability Coordinatk
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
118,529
110,066
8,394
70
0
$22.63
$56.08
649,024
$21,317
$12,492
$6,367
$1,585
$3,570
$970
$8,825
$12.25
Electric Reliability Council of Te
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
75,290
71,901
2,053
1,336
0
Final Rule
887,863
786,922
79,540
21,402
14,274
n/a
n/a
4,113,668
$138,676
$87,915
$47,782
$7,927
$23,827
$8,378
$50,761
$13.54
>n Agreement (1
118,529
110,066
8,394
70
0
$22.69
$56.15
647,671
$21,334
$12,576
$6,358
$1,583
$3,668
$968
$8,758
$12.26
xas (ERCOT)
75,290
71,721
1,871
1,697
0
Difference
(52)
(359)
(143)
451
152
n/a
n/a
(170)
($94)
$429
($7)
$1
$410
$24
($523)
$0.00
:CAR)
0
0
0
0
0
$0.06
$0.07
(1,354)
$17
$84
($9)
($2)
$98
($3)
($67)
$0.01
0
(180)
(182)
361
0
% Change
0.0%
0.0%
(0.2)%
2.2%
1.1%
n/a
n/a
0.0%
(0.1)%
0.5%
0.0%
0.0%
1.8%
0.3%
(1.0)%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.3%
0.1%
(0.2)%
0.1%
0.7%
(0.1)%
(0.1)%
2.7%
(0.3)%
(0.8)%
0.1%
0.0%
(0.2)%
(8.8)%
27.0%
0.0%
B3-13
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-4: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
EPA Base Case
$29.38
$14.09
336,956
$10,961
$8,000
$5,241
$699
$1,730
$330
$2,961
$17.63
Florida Reliability Coordinating C
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
50,324
39,262
11,062
0
812
$29.39
$37.79
189,076
$7,459
$5,406
$3,106
$364
$1,184
$753
$2,053
$18.35
Mid-Atlantic Area Council
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
63,784
56,355
5,771
1,658
2,831
$26.73
$50.61
276,051
$10,605
$6,124
$3,066
Final Rule
$31.08
$4.83
336,663
$10,826
$8,031
$5,234
$700
$1,754
$343
$2,795
$17.62
ouncil (FRCC)
50,324
39,267
11,057
0
812
$29.55
$36.82
188,844
$7,434
$5,442
$3,113
$365
$1,217
$747
$1,992
$18.42
(MAAC)
63,784
56,355
5,771
1,658
2,831
$26.76
$50.44
277,764
$10,646
$6,206
$3,101
Difference
$1.69
($9.26)
(293)
($135)
$31
($7)
$1
$24
$13
($166)
$0.00
0
5
(5)
0
0
$0.16
($0.98)
(232)
($25)
$36
$7
$2
$33
($6)
($61)
$0.07
0
0
0
0
0
$0.02
($0.17)
1,714
$41
$82
$34
% Change
5.8%
(65.7)%
(0.1)%
(1.2)%
0.4%
(0.1)%
0.2%
1.4%
4.1%
(5.6)%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.6%
(2.6)%
(0.1)%
(0.3)%
0.7%
0.2%
0.4%
2.8%
(0.8)%
(3.0)%
0.4%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
(0.3)%
0.6%
0.4%
1.3%
1.1%
B3-14
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-4: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
EPA Base Case
$557
$1,929
$571
$4,481
$13.13
Mid-America Interconnected Ne1
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
59,494
51,551
7,943
0
5,191
$22.66
$54.31
281,625
$9,607
$5,795
$2,930
$586
$1,710
$569
$3,812
$12.48
Mid-Continent Area Power Pe
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
35,835
32,672
3,163
0
476
$21.86
$54.00
181,713
$5,878
$3,430
$1,722
$381
$1,017
$311
$2,448
$11.57
Final Rule
$560
$1,969
$577
$4,440
$13.18
fwork (MAIN)
59,397
51,465
7,932
0
5,285
$22.60
$54.66
281,446
$9,602
$5,802
$2,933
$583
$1,726
$560
$3,800
$12.49
ol (MAPP)
35,835
32,676
3,159
0
476
$21.79
$54.49
181,566
$5,881
$3,431
$1,719
$379
$1,029
$304
$2,450
$11.56
Difference
$3
$39
$5
($41)
$0.05
(97)
(86)
(11)
0
94
($0.06)
$0.35
(179)
($5)
$7
$3
($3)
$15
($9)
($11)
$0.01
0
4
(4)
0
0
($0.06)
$0.49
(147)
$3
$1
($3)
($2)
$12
($7)
$2
($0.02)
% Change
0.5%
2.0%
0.9%
(0.9)%
0.4%
(0.2)%
(0.2)%
(0.1)%
0.0%
1.8%
(0.3)%
0.7%
(0.1)%
(0.1)%
0.1%
0.1%
(0.5)%
0.9%
(1.6)%
(0.3)%
0.1%
0.0%
0.0%
(0.1)%
0.0%
0.0%
(0.3)%
0.9%
(0.1)%
0.0%
0.0%
(0.2)%
(0.5)%
1.2%
(2.2)%
0.1%
(0.1)%
B3-15
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-4: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
EPA Base Case
Northeast Power Coordinating C
(I) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
72,477
59,515
2,082
10,881
4,107
$29.88
$43.23
278,649
$11,220
$7,732
$4,479
$376
$1,781
$1,096
$3,488
$17.42
Southeastern Electric Reliability
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (Gwh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
194,485
164,544
29,941
0
0
$24.64
$48.23
944,631
$32,644
$19,753
$10,314
$1,785
$5,264
$2,389
$12,891
$12.81
Southwest Power Pool (
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
49,948
48,956
992
0
Final Rule
xincil (NPCC)
72,459
59,513
2,061
10,885
4,107
$29.85
$43.22
277,433
$11,173
$7,751
$4,438
$372
$1,846
$1,095
$3,423
$17.34
Council (SERC)
194,472
164,544
29,928
0
0
$24.62
$48.40
945,913
$32,690
$19,865
$10,323
$1,790
$5,343
$2,408
$12,826
$12.81
SPP)
50,092
48,900
1,080
111
Difference
(19)
(2)
(21)
4
0
($0.02)
($0.01)
(1,216)
($46)
$18
($41)
($4)
$65
($2)
($65)
($0.08)
(13)
0
(13)
0
0
($0.02)
$0.17
1,283
$46
$112
$8
$5
$79
$20
($66)
$0.00
144
(56)
88
111
% Change
0.0%
0.0%
(1.0)%
0.0%
0.0%
(0.1)%
0.0%
(0.4)%
(0.4)%
0.2%
(0.9)%
(1.0)%
3.6%
(0.1)%
(1.9)%
(0.5)%
0.0%
0.0%
0.0%
0.0%
0.0%
(0.1)%
0.4%
0.1%
0.1%
0.6%
0.1%
0.3%
1.5%
0.8%
(0.5)%
0.0%
0.3%
(0.1)%
8.9%
100.0%
B3-16
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-4: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
EPA Base Case
0
$24.34
$40.97
221,527
$7,434
$4,254
$2,701
$422
$1,042
$88
$3,181
$14.10
Western Systems Coordinating C
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
167,748
152,459
8,283
7,006
705
$27.19
$7.56
754,587
$21,645
$14,499
$7,863
$1,171
$4,189
$1,277
$7,146
$11.97
Final Rule
0
$24.29
$41.24
221,854
$7,450
$4,282
$2,702
$422
$1,057
$101
$3,168
$14.08
ouncil (WSCC)
167,681
152,414
8,287
6,980
763
$27.18
$7.58
754,514
$21,639
$14,530
$7,862
$1,173
$4,220
$1,275
$7,110
$11.97
Difference
0
($0.05)
$0.27
327
$16
$28
$1
($1)
$14
$13
($12)
($0.02)
(67)
(45)
4
(26)
58
($0.01)
$0.03
(73)
($6)
$30
($1)
$1
$31
($2)
($36)
$0.00
% Change
0.0%
(0.2)%
0.7%
0.1%
0.2%
0.7%
0.0%
(0.1)%
1.4%
14.7%
(0.4)%
(0.1)%
0.0%
0.0%
0.0%
(0.4)%
8.2%
0.0%
0.3%
0.0%
0.0%
0.2%
0.0%
0.1%
0.7%
(0.1)%
(0.5)%
0.0%
Source: IPM analysis: Model runs for Section 316(b) NODABase Case and the final ruk (EPA electricity demand assumptions).
Summary of Market Results at the National Level The results presented in Table B 3-4 show that capacity closures are
estimated to increase by 152 MW, which represents 0.02 percent of total baseline capacity. New additions are estimated to
decrease by 143 MW. An increase in repowering additions (451 MW) is estimated to make up for this loss. Total costs of
electricity generation will increase by 0.5 percent, largely because of a 1.8 percent increase in fixed O&M costs (which
includes charges for capital costs of compliance). Revenues are estimated to decrease by 0.1 percent and pre-tax income is
estimated to decrease by 1.0 percent. The final rule will not lead to changes in total domestic capacity or total fuel costs.
Summary of Market Results at the Regional Level At the regional level, the final rule is estimated to result in the following
changes:
> MAIN and WSCC are the only regions that are estimated to experience an increase in post-compliance capacity
closures. In MAIN, the 94 MW increase in closures (0.2 percent of baseline capacity) is due to a nuclear facility that
B3-17
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
reached the end of its nuclear operating license. In the base case, this facility would have extended its license for
481 MW of capacity and continued operation until 2020. Under the final rule, however, this facility is modeled to
only extend its license for 387 MW of capacity. As a result, MAIN also experiences a decrease in capital costs. In
WSCC, oil and gas early retirements account for the 58 MW increase in closures (less than 0.1 percent of baseline
capacity). All other measures are estimated to change by less than 1.0 percent.
»• ERCOT is estimated to experience the most notable changes in electricity prices and new capacity among the ten
NERC regions. Repowering additions will increase by 361 MW (0.5 percent of baseline capacity) under the final
rule. Repowering in the IPM is modeled as a conversion of one MW of existing coal or oil and gas steam capacity
into two MW of combined-cycle capacity. As such, repowering in ERCOT under the final rule consists of the
conversion of 180 MW of existing capacity into 361 MW of new repowered capacity. Since total capacity in
ERCOT remains constant, this 181 MW net increase in capacity is offset by a 1 82 MW decrease in new capacity
additions. Repowering of oil and gas to combined cycle will cause capital costs to increase by 4.1 percent. Post-
compliance energy prices are estimated to increase by 5.8 percent. This increase is largely driven by relatively low
profit margins in the region. ERCOT also experiences the largest reduction in capacity prices with almost 66
percent. This is partially due to the increase in energy prices, which allows facilities to bid their undispatched
capacity at a lower price. Revenues and pre-tax income in ERCOT are estimated to fall by 1.2 percent and 5.6
percent, respectively, the highest in any NERC region.
»• FRCC is estimated to experience a 2.6 percent reduction in capacity prices. Revenues in FRCC are estimated to
decrease by 0.3 percent and costs will increase by 0.7 percent (largely due to an increase in fixed O&M costs of 2.8
percent), leading to a reduction in pre-tax income of 3.0 percent the second highest in any NERC region. All other
measures are estimated to change by less than 1.0 percent.
> NPCC is estimated to have the largest percentage reduction in generation of the ten NERC regions (0.4 percent). As
a result variable O&M costs decreases by 1.0 percent. Fixed O&M costs, which include the capital costs of
compliance with the final rule, increase by 3.6 percent, and pre-tax income decreases by 1.9 percent, the third highest
in any NERC region. Revenues and overall costs in NPCC are estimated to each change by less than 0.5 percent.
»• ECAR, MAPP, and SERC, are estimated to experience increases in fixed O&M costs, driven by the capital costs of
compliance with the final rule, but overall cost increases in each region will be less than 1.0 percent. Pre-tax income
in these regions is estimated to decrease by between 0.5 and 0.8 percent, with the exception of MAPP which is
estimated to experience a slight increase in pre-tax income. MAPP will also experience a decrease in capital costs
(2.2 percent) due to the avoided cost of retrofitting a scrubber. All other measures are estimated to change by less
than 1.0 percent.
> SPP is the only region estimated to experience an increase in total capacity. This increase is the result of 88 MW in
incremental new additions and 111 MW in repowering additions. However, these changes represent less than 0.5
percent of overall capacity. Similar to ECAR, MAPP, and SERC, SPP will experience increases in fixed O&M
costs. SPP is estimated to have the largest increase in capital costs of the ten NERC regions (14.7 percent). The
majority of additional capital costs comes from the repowering additions. Pretax income is estimated to decrease by
0.4 percent.
> MAAC is estimated to experience the largest increase in generation (0.6 percent) and fuel cost (1.1 percent) as a
result of the final rule. Fixed O&M costs are estimated to rise by 2.0 percent, leading to an increase in total costs of
1.3 percent. Together with FRCC, MAAC also has the largest increase in variable production cost per MWh of
generation, 0.4 percent. All other measures are estimated to change by less than 1.0 percent.
B3-4.2 Analysis of Phase II Facilities for 2010
This section presents the results of the IPM analysis for the Phase II facilities that are modeled by the IPM. Ten of the 535
Phase II facilities are closures in the base case, and 11 facilities are closures under the final rule. These facilities are not
represented in the results described in this section.
EPA used the IPM results from model run year 2010 to analyze impacts on Phase II facilities at two levels: (1) potential
changes in the economic and operational characteristics of the in-scope Phase II facilities as a group and (2) potential changes
to individual facilities within the group of in-scope Phase II facilities.
B3-18
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
a. In-scope Phase II facilities as a group
This section presents the analysis of the potential impacts of the final rule on the in-scope Phase II facilities as a group. This
analysis 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 B3-5 presents the impact measures for the group of Phase II facilities discussed in section B3-3.2
above: (1) capacity changes, including changes in the number and capacity of closure facilities; (2) generation changes; (3)
revenue changes; (4) cost changes, including changes in fuel costs, variable O&M costs, fixed O&M costs, and capital costs;
(5) changes in pre-tax income; and (6) changes in variable production costs per MWh of generation, where variable
production cost is defined as the sum of fuel cost and variable O&M cost. For each measure, the table presents the results for
the base case and the final rule, the absolute difference between the two cases, and the percentage difference.
Table B3-5: Facility -Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
EPA Base Case ! Final Rule ! Difference ! % Change
National Totals
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
433,998
10
13,644
2,323,322
$76,259
$48,264
$25,391
$5,154
$15,159
$2,561
$27,994
$13.15
East Central Area Reliability Coordinatic
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
82,313
0
1
517,126
$16,237
$9,586
$5,036
$1,248
$2,961
$342
$6,651
$12.15
Electric Reliability Council of Te
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
43,522
0
0
158,462
433,062
11
13,796
2,304,461
$75,585
$48,092
$24,990
$5,130
$15,552
$2,420
$27,494
$13.07
n Agreement (1
82,313
0
1
516,220
$16,250
$9,668
$5,022
$1,248
$3,059
$340
$6,582
$12.15
xas (ERCOT)
43,413
0
0
155,661
(936)
1
152
(18,861)
($673)
($173)
($400)
($24)
$393
($142)
($501)
($0.08)
ECAR)
0
0
0
(906)
$13
$82
($14)
$0
$98
($2)
($69)
($0.01)
(109)
0
0
(2,800)
(0.2)%
10.0%
1.1%
(0.8)%
(0.9)%
(0.4)%
(1.6)%
(0.5)%
2.6%
(5.5)%
(1.8)%
(0.6)%
0.0%
0.0%
0.0%
(0.2)%
0.1%
0.9%
(0.3)%
0.0%
3.3%
(0.7)%
(1.0)%
0.0%
(0.3)%
0.0%
0
(1.8)%
B3-19
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-5: Facility -Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
EPA Base Case Final Rule Difference % Change
$5,365
$3,910
$2,203
$426
$1,181
$99
$1,455
$16.59
Florida Reliability Coordinating C
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
27,537
0
812
82,259
$3,433
$2,021
$1,154
$188
$673
$5
$1,412
$16.31
Mid-Atlantic Area Council I
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
34,376
2
2,831
173,473
$6,339
$3,617
$1,693
$355
$1,438
$131
$2,722
$11.81
Mid -America Interconnected Ne1
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
36,498
2
5,191
226,437
$5,158
$3,855
$2,142
$422
$1,204
$86
$1,303
$16.48
ouncil (FRCC)
27,542
0
812
81,631
$3,398
$2,042
$1,148
$187
$706
$0
$1,356
$16.36
;MAAC>
34,376
2
2,831
173,782
$6,343
$3,658
$1,696
$356
$1,476
$131
$2,685
$11.81
work (MAIN)
36,412
2
5,285
225,826
($206)
($55)
($61)
($4)
$23
($13)
($152)
($0.12)
5
0
0
(628)
($35)
$21
($6)
$0
$33
($5)
($56)
$0.05
0
0
0
309
$4
$42
$3
$1
$38
$0
($37)
$0.00
(86)
0
94
(610)
(3.8)%
(1.4)%
(2.8)%
(0.9)%
1.9%
(12.9)%
(10.4)%
(0.7)%
0.0%
0.0%
0.0%
(0.8)%
(1.0)%
1.0%
(0.5)%
(0.2)%
4.9%
(100.0)%
(4.0)%
0.3%
0.0%
0.0%
0.0%
0.2%
0.1%
1.2%
0.2%
0.3%
2.6%
0.0%
(1.4)%
0.0%
(0.2)%
0.0%
1.8%
(0.3)%
B3-20
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-5: Facility -Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
EPA Base Case Final Rule Difference % Change
$7,011
$4,196
$2,109
$510
$1,472
$106
$2,815
$11.56
Mid-Continent Area Power Po
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
15,749
1
476
108,584
$3,178
$1,978
$1,044
$222
$597
$114
$1,200
$11.67
Northeast Power Coordinating Ci
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
37,651
4
4,107
165,601
$6,503
$5,114
$2,756
$276
$1,242
$840
$1,389
$18.31
Southeastern Electric Reliability <
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
107,450
0
0
639,276
$20,645
$6,993
$4,196
$2,108
$506
$1,486
$96
$2,797
$11.58
ol (MAPP)
15,753
1
476
108,533
$3,179
$1,982
$1,044
$221
$609
$107
$1,197
$11.65
Kjncil (NPCC)
37,343
4
4,107
159,701
$6,300
$4,971
$2,607
$266
$1,305
$793
$1,329
$17.99
:ouncil (SERC)
107,450
0
0
637,804
$20,617
($17)
$0
($1)
($3)
$14
($9)
($18)
$0.01
4
0
0
(52)
$1
$4
$0
($2)
$12
($6)
($3)
($0.01)
(308)
0
0
(5,900)
($203)
($143)
($149)
($9)
$62
($47)
($60)
($0.32)
0
0
0
(1,472)
($28)
(0.2)%
0.0%
(0.1)%
(0.7)%
1.0%
(8.9)%
(0.6)%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.2%
0.0%
(0.7)%
2.0%
(5.7)%
(0.3)%
(0.1)%
(0.8)%
0.0%
0.0%
(3.6)%
(3.1)%
(2.8)%
(5.4)%
(3.4)%
5.0%
(5.6)%
(4.3)%
(1.7)%
0.0%
0.0%
0.0%
(0.2)%
(0.1)%
B3-21
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-5: Facility -Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
EPA Base Case Final Rule Difference % Change
$12,038
$6,137
$1,365
$3,986
$550
$8,607
$11.73
Southwest Power Pool (I
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
20,471
0
0
109,901
$3,419
$1,962
$1,148
$248
$557
$8
$1,457
$12.71
Western Systems Coordinating C(
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
28,431
1
226
142,204
$4,131
$3,844
$2,109
$317
$1,051
$367
$287
$17.06
$12,071
$6,097
$1,366
$4,058
$549
$8,546
$11.70
5PP)
20,471
0
0
109,185
$3,401
$1,958
$1,135
$247
$569
$7
$1,443
$12.65
>uncil (WSCC)
27,989
2
284
136,117
$3,947
$3,691
$1,990
$311
$1,079
$310
$257
$16.90
$34
($39)
$2
$72
($1)
($62)
($0.03)
0
0
0
(716)
($18)
($3)
($13)
($2)
$13
($1)
($14)
($0.05)
(443)
1
58
(6,086)
($183)
($153)
($119)
($6)
$28
($56)
($30)
($0.15)
0.3%
(0.6)%
0.1%
1.8%
(0.2)%
(0.7)%
(0.3)%
0.0%
0.0%
0.0%
(0.7)%
(0.5)%
(0.2)%
(1.2)%
(0.6)%
2.3%
(13.9)%
(1.0)%
(0.4)%
-1.6%
100.0%
25.7%
-4.3%
-4.4%
-4.0%
-5.6%
-1.9%
2.6%
-15.4%
-10.4%
-0.9%
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (EPA electricity demand assumptions).
Comparison of Results for Phase II Facilities and the Market. The IPM results for the in-scope Phase II facilities as a
group (presented in Table B3-5) are similar to the results at the market level (presented in Table B3-4). On a percentage
basis, the group of Phase II facilities generally experiences higher losses in generation, revenues, and pre-tax income
compared to the overall market. This is not surprising as in-scope facilities become relatively less competitive compared to
facilities not in scope of Phase II regulation and are therefore likely to lose some market share as a result of the final rule.
B3-22
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
Total closure capacity among the Phase II facilities is the same as at the market level but represents a higher percentage of
total base case capacity. Fixed O&M costs of the group of Phase II facilities increase relatively more than at the market level
because fixed O&M costs include the capital costs of compliance with Phase II regulatory options. In many regions,
however, the other cost accounts decrease for the Phase II facilities because of the reduction in generation. On a per MWh
basis, variable production costs also decrease in many regions because the higher cost units generate less electricity under the
final rule compared to the base case, reducing the overall average cost of generation.
Summary of Phase II Facility Results at the National Level. Table B 3-5 shows that the final rule will lead to 1 52 MW in
incremental capacity closures, or less than 0.5 percent of baseline Phase II capacity. These incremental closures are estimated
to be one full facility closure of 19 MW inWSCC and partial facility closures of 39 MW inWSCCand94 MW in MAIN.
Total Phase II capacity is projected to decrease by 936 MW, due to the capacity closures and several facilities that were
projected to repower in the base case but do not under the final rule. As a result, generation, revenues, and overall costs will
decrease but by less than one percent. Fixed O&M costs, which include the capital cost of compliance, are projected to
increase by 2.6 percent. Pre-tax income for the group of Phase II facilities will decrease by 1.8 percent.
Summary of Phase II Facility Results at the Regional Level. Results for the final rule vary somewhat by region. For many
regions, impacts follow the general pattern described in the comparison to the market level above: generation, revenues, and
pre-tax income decrease. Overall costs decrease in many regions due to lower levels of generation but increase in other
regions where the additional compliance costs outweigh the reduction in generation. In addition to these general patterns,
EPA estimates that the final rule will result in the following changes:
> WSCC is estimated to experience the largest reduction in Phase II capacity, losing 443 MW, or 1.6 percent of base
case capacity under the final rule. This change is partially the result of a full facility closure of 19 MW and a partial
facility closure of 39 MW. However, the majority of the 443 MW reduction is the result of less Phase II capacity
being repowered in the post-compliance scenario. Phase II facilities in WSCC also experience the largest reductions
in generation and revenues of any NERC region (4.3 and 4.4 percent, respectively) because they bear a relatively
high compliance cost per MW of capacity under the final rule (the second highest of any of the 10 NERC regions).
In addition, only a small percentage of total capacity in WSCC (28,400 MW out of 1 67,750 MW, or 17 percent) is
subject to Phase II regulation. As a result, facilities not subject to Phase II regulation become relatively more
competitive and assume some of the generation lost by Phase II facilities. Overall, costs for the group of Phase II
facilities decrease by 4.0 percent. Fixed O&M costs, which include Phase II compliance costs, increase but fuel
costs and variable O&M costs decrease because of the reduction in generation. However, the reduction in revenues
outweighs the reduction in costs, leading to an overall reduction in pre-tax income of 10.4 percent ($30 million),
which is the highest, together with ERCOT, in any NERC region. This relatively high percentage reduction is
partially due to the low profit margins of Phase II facilities in WSCC in the base case.
> MAIN is the only other region, besides WSCC, that is projected to experience an incremental closure of Phase II
capacity under the final rule, losing 94 MW of capacity (0.3% of base case capacity). The reduction is due to a
nuclear facility that reached the end of its nuclear operating license. In the base case the facility would have
extended its license for 481 MW of capacity, and continued operating until 2020. Under the final rule the facility
only extends its license for 387 MW of capacity. The incremental capacity closure is responsible for the reduction in
Phase II capacity in the region and contributes to a decrease in Phase II post-compliance generation and revenues.
Total costs remain the same, but variable production cost per MWh increase because the projected incremental
closure affects nuclear capacity which has lower production costs than most other plant types.
»• Phase II facilities in ERCOT are estimated to experience the highest reductions pre-tax income (-10.4 percent),
together with facilities in WSCC. In addition, generation (-1.8 percent) and revenues (-3.8 percent) are predicted to
decrease. Revenues decrease by a larger percentage than generation due to the large drop in capacity prices (see
Table B3-4). Capital costs decrease by 12.9 percent (the largest reduction other than FRCC). A majority of the
reduction is the result of one less facility repowering under the final rule.
»• Phase II facilities in NPCC are estimated to experience the largest increase in fixed O&M costs of any NERC region
(5.0 percent) as a result of bearing the highest compliance cost per MW of capacity under the final rule. NPCC
facilities will also experience the second largest reduction in generation (-3.6 percent) and the third largest reduction
in pre-tax income (-4.3 percent) of any region.
> Phase II facilities in FRCC are estimated to experience an increase in total costs of 1.0 percent under the final rule,
which is driven by a 4.9 percent increase in fixed O&M costs. Combined with a reduction in revenues of 1.0
percent, this will reduce pre-tax income for Phase II facilities in FRCC by 4.0 percent.
B3-23
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
»• ECAR, MAAC, MAPP, and SERC, and SPP are estimated to experience relatively small reductions in pre-tax
income (between 0.3 and 1.4 percent) as a result of increases in fixed O&M costs (between 1.8 to 3.3 percent). The
changes in most other measures are less than 1.0 percent in these regions.
b. Individual Phase II facilities
In addition to effects of the final rule on the in-scope Phase II facilities as a group, there may be shifts in economic
performance among individual facilities subject to Phase II regulation. To assess such potential shifts, EPA analyzed facility-
specific changes in (1) capacity utilization (defined as generation divided by capacity multiplied by the number of hours per
year- 8,760); (2) generation; (3) revenues; (4) variable production costs per MWh of generation (defined as variable O&M
cost plus fuel cost divided by generation); (5) fuel cost per MWh of generation; and (6) pre-tax income. For each measure,
EPA determined the number of Phase II facilities that experience no changes, or an increase or a reduction within three
ranges: 1 percent or less, 1 to 3 percent, and more than 3 percent.
Table B 3-6 presents the total number of Phase II facilities with different estimated degrees of change due to the final rule.
This table excludes 17 in-scope facilities with estimated significant status changes in 2010: Ten facilities are baseline
closures, one facility is a full closure as a result of the final rule, and six facilities changed their repowering decision between
the base case and the post-compliance case. These facilities are either not operating at all in either the base case or the post-
compliance case, or they experience fundamental changes in the type of units they operate; therefore, the measures presented
in Table B3-6 would not be meaningful for these facilities. In addition, the change in variable production cost per MWh and
fuel cost per MWh of generation could not be developed for 57 facilities with zero generation in either the base case or post-
compliance scenario. For these facilities, the change in variable production cost per MWh is indicated as "n/a."
Table 63-6: Number of Individual Phase II Facilities with Operational Changes (2010)
Economic Measures
(1) Change in Capacity Utilization
(2) Change in Generation
(3) Change in Revenues
(4) Change in Variable Production
Costs/MWh
(5) Change in Fuel Costs/MWh
(6) Change in Pre-Tax Income
Reduction
3%
25
46
45
9
10
213
Increase
3%
11
18
16
17
13
15
No
Change
441
428
194
225
351
11
N/A
0
0
0
57
57
0
a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent.
b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post-
compliance case. For all other measures, the change is expressed as the percentage change between the base case and post-
compliance values.
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (EPA electricity demand assumptions).
Table B3-6 indicates that the majority of Phase II facilities will not experience changes in capacity utilization, generation, or
fuel costs per MWh due to compliance with the final rule. Of those facilities with changes in post-compliance capacity
utilization and generation, most will experience decreases in these measures. The majority of facilities with changes in post-
compliance variable production costs per MWh will experience increases. However, more than 80 percent of those increases
will not exceed 1.0 percent. Changes in revenues at most Phase II facilities will also not exceed 1.0 percent. The largest
effect of the final rule will be on facilities' pre-tax income: over 80 percent of facilities will experience a reduction in pre-tax
income, with about 40 percent experiencing a reduction of 3.0 percent or greater. These reductions are due to a combination
of reduced revenues and increased compliance costs.
B3-24
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
B3-4.3 Market Analysis for 2008
This section presents market-level results for the final rule for model run year 2008. Unlike the market-level analysis for
2010 described above, model run year 2008 includes facilities that experience a one-time downtime due to the installation of
Phase II compliance technologies. This analysis therefore presents potential short-term effects that may occur during the five-
year period (2005 to 2009) represented by model run year 2008. However, it should be noted that not all facilities are in
compliance by 2008. Therefore, potential effects of installation downtimes may be mitigated by the fact that some facilities
will not incur compliance costs until after 2008.
Table B3-7 presents the following market-level impacts for 2008: (1) electricity price changes, including changes in energy
prices and capacity prices; (2) generation changes; (3) revenue changes; (4) cost changes, including changes in fuel costs,
variable O&M costs, fixed O&M costs, and capital costs; (5) changes in pre-tax income; and (6) changes in variable
production costs per MWh. For each measure, the table presents the 2008 results for the base case and the final rule, the
absolute difference between the two cases, and the percentage difference. The table also repeats the percentage difference
based on the market-level analysis for 2010 presented in Table B3-4 above.
Table B3-7: Market-Level Impacts of the Final Rule (NERC 2008 and 2010)
Economic Measures
EPA Base Case
National
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
n/a
n/a
4,060,238
$154,018
$86,389
$48,097
$7,828
$23,643
$6,821
$67,629
$13.77
East Central Area Reliability C
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$22.66
$78.35
649,365
$23,972
$12,731
$6,619
$1,579
$3,569
$964
$11,241
$12.62
Final Rule
Totals
n/a
n/a
4,060,401
$153,946
$86,909
$48,182
$7,825
$24,012
$6,890
$67,037
$13.79
oordination Agr
$23.01
$78.01
646,400
$24,091
$12,771
$6,576
$1,574
$3,661
$961
$11,320
$12.61
Difference
% Change
n/a
n/a
163
($72)
$520
$85
($4)
$369
$69
($592)
$0.02
n/a
n/a
0.0%
0.0%
0.6%
0.2%
0.0%
1.6%
1.0%
(0.9)%
0.1%
zement (ECAR)
$0.35
($0.34)
(2,965)
$119
$41
($43)
($5)
$91
($3)
$78
($0.02)
1.5%
(0.4)%
(0.5)%
0.5%
0.3%
(0.6)%
(0.3)%
2.6%
(0.3)%
0.7%
(0.1)%
% Change
2010
n/a
n/a
0.0%
(0.1)%
0.5%
0.0%
0.0%
1.8%
0.3%
(1.0)%
0.0%
0.3%
0.1%
(0.2)%
0.1%
0.7%
(0.1)%
(0.1)%
2.7%
(0.3)%
(0.8)%
0.1%
B3-25
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-7: Market-Level Impacts of the Final Rule (NERC 2008 and 2010)
Economic Measures
EPA Base Case
Electric Reliability Cour
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$29.98
$0.00
325,835
$9,768
$7,728
$5,211
$673
$1,696
$148
$2,040
$18.06
Florida Reliability Coorc
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$30.18
$63.07
186,234
$8,719
$5,349
$3,129
$354
$1,172
$694
$3,370
$18.70
Mid-Atlantic Arec
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
$26.82
$73.68
274,753
$12,024
$5,985
$2,920
$553
$2,125
$386
$6,039
Final Rule
cil of Texas (E
$30.12
$0.00
325,835
$9,813
$7,766
$5,205
$672
$1,714
$175
$2,048
$18.04
mating Council
$30.38
$62.64
186,200
$8,734
$5,386
$3,150
$355
$1,193
$688
$3,348
$18.83
i Council (MAAd
$27.12
$73.85
275,349
$12,133
$6,047
$2,941
$554
$2,160
$392
$6,086
Difference
% Change
RCOT)
$0.14
$0.00
0
$45
$38
($6)
($1)
$18
$27
$7
($0.02)
0.5%
0.0%
0.0%
0.5%
0.5%
(0.1)%
(0.2)%
1.1%
18.5%
0.4%
(0.1)%
(FRCC)
$0.20
($0.43)
(34)
$15
$37
$22
$1
$20
($6)
($22)
$0.13
0.7%
(0.7)%
0.0%
0.2%
0.7%
0.7%
0.3%
1.7%
(0.8)%
(0.7)%
0.7%
')
$0.30
$0.17
596
$108
$62
$20
$1
$35
$6
$46
1.1%
0.2%
0.2%
0.9%
1.0%
0.7%
0.2%
1.6%
1.6%
0.8%
% Change
2010
5.8%
(65.7)%
(0.1)%
(1.2)%
0.4%
(0.1)%
0.2%
1.4%
4.1%
(5.6)%
0.0%
0.6%
(2.6)%
(0.1)%
(0.3)%
0.7%
0.2%
0.4%
2.8%
(0.8)%
(3.0)%
0.4%
0.1%
(0.3)%
0.6%
0.4%
1.3%
1.1%
0.5%
2.0%
0.9%
(0.9)%
B3-26
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-7: Market-Level Impacts of the Final Rule (NERC 2008 and 2010)
Economic Measures
(6) Variable Production Costs ($2002/MWh)
EPA Base Case
$12.64
Mid-America Interconne
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$22.68
$78.80
285,282
$11,208
$5,940
$2,940
$589
$1,949
$463
$5,268
$12.37
Mid-Continent Area
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$22.41
$78.32
179,067
$6,756
$3,353
$1,740
$366
$998
$249
$3,404
$11.76
Northeast Power Coorc
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
$29.48
$68.95
277,871
$12,806
$7,668
$4,459
$376
$1,779
$1,053
$5,138
Final Rule
$12.69
cted Network I
$22.96
$77.97
286,219
$11,221
$5,963
$2,960
$593
$1,972
$439
$5,258
$12.41
Power Pool (M/<
$22.72
$78.02
178,742
$6,794
$3,362
$1,737
$365
$1,012
$247
$3,432
$11.76
mating Council <
$30.35
$58.24
277,129
$12,309
$7,710
$4,447
$372
$1,837
$1,054
$4,599
Difference
$0.05
% Change
0.4%
MAIN)
$0.28
($0.82)
937
$13
$23
$20
$3
$23
($24)
($10)
$0.04
1.2%
(1.0)%
0.3%
0.1%
0.4%
0.7%
0.6%
1.2%
(5.2)%
(0.2)%
0.3%
PP)
$0.32
($0.30)
(325)
$38
$9
($2)
$0
$14
($1)
$28
$0.00
1.4%
(0.4)%
(0.2)%
0.6%
0.3%
(0.1)%
(0.1)%
1.4%
(0.5)%
0.8%
0.0%
;NPCC)
$0.87
($10.71)
(743)
($496)
$43
($13)
($3)
$58
$0
($539)
3.0%
(15.5)%
(0.3)%
(3.9)%
0.6%
(0.3)%
(0.9)%
3.3%
0.0%
(10.5)%
% Change
2010
0.4%
(0.3)%
0.7%
(0.1)%
(0.1)%
0.1%
0.1%
(0.5)%
0.9%
(1.6)%
(0.3)%
0.1%
(0.3)%
0.9%
(0.1)%
0.0%
0.0%
(0.2)%
(0.5)%
1.2%
(2.2)%
0.1%
(0.1)%
(0.1)%
0.0%
(0.4)%
(0.4)%
0.2%
(0.9)%
(1.0)%
3.6%
(0.1)%
(1.9)%
B3-27
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-7: Market-Level Impacts of the Final Rule (NERC 2008 and 2010)
Economic Measures
(6) Variable Production Costs ($2002/MWh)
EPA Base Case
$17.40
Southeastern Electric Re
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$25.48
$68.91
924,991
$36,464
$19,134
$10,337
$1,760
$5,182
$1,854
$17,330
$13.08
Southwest Row
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
$25.17
$61.73
217,634
$8,503
$4,214
$2,743
$419
$1,031
$21
$4,289
$14.53
Western Systems Coorc
(la) Energy Price ($2002/MWh)
(Ib) Capacity Price ($2002/KW)
(2) Total Generation (GWh)
(3) Total Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
$28.58
$18.17
739,205
$23,797
$14,287
$7,999
$1,160
$4,140
$989
Final Rule
$17.39
liability Council
$25.57
$68.51
927,191
$36,577
$19,316
$10,376
$1,759
$5,253
$1,928
$17,261
$13.09
er Pool (SPP)
$25.31
$61.15
217,539
$8,499
$4,224
$2,746
$419
$1,041
$18
$4,275
$14.55
mating Council
$28.71
$17.25
739,797
$23,774
$14,362
$8,044
$1,161
$4,169
$988
Difference
($0.01)
% Change
(0.1)%
(SERC)
$0.10
($0.40)
2,199
$113
$183
$39
$0
$70
$74
($69)
$0.01
0.4%
(0.6)%
0.2%
0.3%
1.0%
0.4%
0.0%
1.4%
4.0%
(0.4)%
0.1%
$0.14
($0.57)
(95)
($5)
$10
$3
$0
$10
($4)
($15)
$0.02
0.5%
(0.9)%
0.0%
(0.1)%
0.2%
0.1%
0.1%
1.0%
(17.6)%
(0.3)%
0.1%
[WSCC)
$0.13
($0.92)
592
($22)
$75
$45
$1
$29
($1)
0.5%
(5.0)%
0.1%
(0.1)%
0.5%
0.6%
0.1%
0.7%
(0.1)%
% Change
2010
(0.5)%
(0.1)%
0.4%
0.1%
0.1%
0.6%
0.1%
0.3%
1.5%
0.8%
(0.5)%
0.0%
(0.2)%
0.7%
0.1%
0.2%
0.7%
0.0%
(0.1)%
1.4%
14.7%
(0.4)%
(0.1)%
0.0%
0.3%
0.0%
0.0%
0.2%
0.0%
0.1%
0.7%
(0.1)%
B3-28
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B3: Electricity Market Model Analysis
Table B3-7: Market-Level Impacts of the Final Rule (NERC 2008 and 2010)
Economic Measures
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
EPA Base Case
$9,509
$12.39
Final Rule
$9,412
$12.44
Difference
($97)
$0.05
% Change
(1.0)%
0.4%
% Change
2010
(0.5)%
0.0%
Source: IPM analysis: Model runs for Section 316(b) NODABase Case and the final rule (EPA electricity demand assumptions).
Summary of Market Results at the National Level. The results presented in Table B 3-7 show that under the final rule
downtimes associated with the installation of compliance technologies will not lead to significant changes in economic
impacts compared to the results for 2010 (which represents the post-compliance scenario in which no facilities experience
downtimes). There will be an 0.2 percent increase in fuel costs in 2008, leading to an increase in variable production cost per
MWh of 0.1 percent. In addition, the rise in capital costs is estimated to be somewhat higher in 2008 than in 2010.
Summary of Market Results at the Regional Level. The following discussion highlights differences in the analysis results
between 2010 and 2008:
•• In FRCC and SERC, most impact results for 2008 and 2010 are either the same or slightly lower in 2008. FRCC is
estimated to experience a smaller decrease in capacity prices in 2008 which will result in higher revenues and a
smaller loss in pre-tax income compared to 2010. In SERC, energy prices and generation are estimated to increase
more in 2008 than 2010, leading to an increase in revenues and a reduction in pre-tax income loss.
*• ECAR, MACC, and MAPP are estimated to experience increases in energy prices between 1.1 and 1.5 percent in
2008. These increases will lead to higher revenues and increases in pre-tax income of between 0.7 and 0.8 percent.
> NPCC, and WSCC are both estimated to experience increases in energy prices under the final rule in 2008.
However, capacity prices are estimated to decrease, leading to a reduction in revenues and pre-tax income. In
WSCC, fuel costs will increase by 0.6 percent, resulting in an 0.4 percent increase in variable production costs per
Mwh.
> MAIN is estimated to experience increases in energy prices and a decrease in capacity prices under the final rule in
2008, similar to NPCC and WSCC. However, generation is estimated to increase rather than decrease in 2008 as
compared to 2010, resulting in higher revenues and a smaller decrease in pre-tax income.
*• ERCOT is estimated to experience substantially lower price effects in 2008 compared to 2010. The increase in
energy prices will be 0.5 percent compared to 5.8 percent in 2010. Capacity prices in 2008 are zero in both the base
case and under the final rule as a result of excess capacity in the region (note that there are no new capacity additions
in ERCOT in 2008). ERCOT is also estimated to experience an increase in revenues and an increase in pre-tax
income compared to 2010.
*• In SPP, energy prices under the final rule are estimated to increase by 0.5 percent in 2008 while capacity prices will
fall, resulting in a 0.1 percent reduction in revenues. The only other notable difference in results compared to 2010
is a relatively large percentage reduction in capital costs in 2008. This is the result of a minor delay in investment in
new capacity additions under the final rule: approximately 120 MW of capacity that is projected to be built in 2008
in the base case is postponed until 2010 under the final rule. As a result, 2008 sees a reduction in capital costs while
2010 sees an increase. Overall, the reduction in capital costs in 2008 comprises less than 0.1 percent of total base
case cost.
B3-29
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
B3-5 UNCERTAINTIES AND LIMITATIONS
There are uncertainties associated with EPA's analysis of the electric power market and the economic impacts of the final
rule:
> Demand for electricity: The IPM assumes that electricity demand at the national level 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, electricity demand 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 final rule. 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 final rule. As described in Section B3-4 above, the price increases associated with the final rule in
most NERC regions are relatively small. EPA therefore concludes that the assumption of inelastic demand-responses
to changes in prices is reasonable.
»• International imports: The IPM also assumes that imports from Canada and Mexico would not change between the
base case and the analyzed policy options. 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. On the other hand, holding imports fixed may understate effects on marginal domestic units, which may be
displaced by increased imports. However, EPA concludes that fixed imports do not materially affect the results of
the analyses. In 2010 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, 6 percent in NPCC, and 1.5 percent in WSCC).
> 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. Repowering in the IPM typically consists of
the conversion of existing oil/gas or coal capacity to new combined-cycle capacity. The modeling assumption is that
each one MW of existing capacity is replaced by two MW of repowered capacity. This change in plant type and size
might lead to a change in intake flow and potentially to different compliance requirements and costs. Since
combined-cycle facilities require substantially less cooling water than other oil/gas or coal facilities, the effect of
repowering is likely to be a reduction in cooling water requirements (even considering the doubling of the plant's
capacity). As a result, not allowing the model to adjust the compliance response or cost is likely to lead to a
conservative estimate of compliance costs and potential economic impacts from the final rule.
•• Downtime associated with installation of compliance technologies: EPA estimates that the installation of several
compliance technologies would require the steam electric generators of facilities that are projected to install such
technologies to be off-line. Downtime is estimated to range between two and eleven weeks, depending on the
technology. Generator downtime is estimated to occur during the year when a facility complies with the final rule.
Since the years that are mapped into a run year are assumed to have the same characteristics as the run year itself,
generator downtimes were applied as an average over the years that are mapped into each model run year. For
example, years 2005 to 2009 are all mapped into 2008. Therefore, a facility with a downtime in 2008 was modeled
as if l/5th of its downtime occurred in each year between 2005 and 2009. A potential drawback of this approach of
averaging downtimes over the mapped years is that the snapshot of the effect of downtimes during the model run
year is the average effect; this approach does not model potential worst case effects of above-average amounts of
capacity being down in any one NERC region during any one year.
B3-30
-------
§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B3: Electricity Market Model Analysis
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2004b. Technical Development Document for the Final Section 316(b)
Phase II Existing Facilities Rule. EPA-821-R-04-007. February 2004.
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.
B3-31
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Chapter B3 - Appendix A
CHAPTER CONTENTS
B3-A.1 Alternative Analysis Results B3-32
B3-A.1-1 Market Analysis B3-32
B3-A.1-2 Analysis of Phase II Facilities B3-39
INTRODUCTION
This appendix presents additional electricity market model
results for the final Phase II rule, using alternative
assumptions about future growth in electricity demand. In
the analyses presented in the body of this chapter,
electricity demand was based on the Annual Energy
Outlook 2001 (AEO2001) forecast adjusted to account for demand reductions resulting from implementation of the Climate
Change Action Plan (CCAP). The analyses presented in this appendix are based on the unadjusted AEO2001 forecasts.
B3-A.l ALTERNATIVE ANALYSIS RESULTS
The following subsections present results for (1) the entire market (i.e., all generators including facilities that are in-scope and
facilities that are out-of-scope of Phase II regulation); (2) the in-scope Phase II facilities as a group; and (3) individual Phase
II facilities. The tables are equivalent to the tables for the final rule presented in the section B3-4, except for the change in
electricity demand assumptions. In addition, Tables B3-A-2 and B3-A-4 present a comparison of the changes as a result of
the final rule under the two different electricity demand assumptions.
B3-A.1-1 Market Analysis for 2010 - AEO Assumptions
This section presents the results of the IPM analysis for all facilities modeled by the IPM. The market-level analysis includes
results for all generators located in each North American Electric Reliability Council (NERC) region including facilities that
are in-scope and facilities that are out-of-scope of Phase II regulation.
Table B3-A-1 below (equivalent to Table B3-4) presents seven measures of market-level impacts associated with the final
rule: (1) capacity changes, including changes in existing capacity, new additions, repowering additions, and closures; (2)
electricity price changes, including changes in energy prices and capacity prices; (3) generation changes; (4) revenue changes;
(5) cost changes, including changes in fuel costs, variable O&M costs, fixed O&M costs, and capital costs; (6) changes in
pre-tax income, defined as revenues minus total costs; and (7) changes in variable production costs perMWh. For each
measure, the Table presents the results for the base case and the final rule, the absolute difference between the two cases, and
the percentage difference by NERC region. A detailed description of each of the impact measures is presented in Section
B3-3.1 of this chapter.
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
AEO Base Case
National Totals
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
947,406
788,986
133,162
25,258
10,203
n/a
n/a
4,400,321
Final Rule
947,434
788,046
133,214
26,174
10,696
n/a
n/a
4,400,761
Difference
28
(940)
52
916
493
n/a
n/a
440
% Change
0.0%
(0.1)%
0.0%
3.6%
4.8%
n/a
n/a
0.0%
B3-32
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
AEO Base Case
$156,989
$98,824
$53,473
$8,320
$24,484
$12,547
$58,165
$14.04
East Central Area Reliability Coordinatk
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
127,332
110,034
17,228
70
0
$24.82
$54.17
680,905
$23,781
$13,854
$6,963
$1,659
$3,658
$1,573
$9,927
$12.66
Electric Reliability Council of Te
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
80,472
69,845
5,202
5,425
0
$27.20
$34.13
362,415
$12,605
$9,054
$5,760
$719
$1,783
$791
Final Rule
$156,991
$99,243
$53,471
$8,325
$24,862
$12,586
$57,748
$14.04
>n Agreement (1
127,098
110,044
16,984
70
0
$24.82
$54.18
681,417
$23,786
$13,939
$6,984
$1,658
$3,751
$1,546
$9,847
$12.68
xas (ERCOT)
80,473
69,398
4,756
6,319
0
$27.55
$32.33
362,415
$12,581
$9,089
$5,755
$718
$1,805
$811
Difference
$2
$419
($3)
$5
$377
$39
($417)
$0.00
ECAR)
(233)
10
(244)
0
0
$0.01
$0.00
511
$5
$85
$21
($1)
$93
($28)
($80)
$0.02
1
(448)
(446)
895
0
$0.35
($1.81)
0
($24)
$36
($5)
($1)
$22
$20
% Change
0.0%
0.4%
0.0%
0.1%
1.5%
0.3%
(0.7)%
0.0%
(0.2)%
0.0%
(1.4)%
0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
0.6%
0.3%
(0.1)%
2.5%
(1.8)%
(0.8)%
0.2%
0.0%
(0.6)%
(8.6)%
16.5%
0.0%
1.3%
(5.3)%
0.0%
(0.2)%
0.4%
(0.1)%
(0.2)%
1.2%
2.5%
B3-33
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
AEO Base Case | Final Rule | Difference | % Change
$3,551 $3,492 ($59) (1.7)%
$17.88 I $17.86 I ($0.02) I (0.1)%
Florida Reliability Coordinating Council (FRCC)
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
53,831 53,832 0 0.0%
39,238 39,239
14,594 14,592
0 0
812 812
$30.19 $30.34
$37.42 $36.49
204,711 204,697
$8,194 $8,175
$6,104 $6,146
$3,472 $3,477
$393 $396
$1,237 $1,272
$1,001 $1,000
$2,090 $2,030
$18.88 | $18.92
Mid-Atlantic Area Council (MAAC)
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
68,838 68,782
57,461 57,461
9,719 9,662
1,658 1,658
1,725 1,725
$27.99 $28.01
$51.00 $50.90
299,588 299,044
$11,894 $11,875
$7,085 $7,103
$3,482 $3,463
$596 $595
$2,123 $2,161
(tOO/1 (tOO/1
$004 $oo4
$4,809 $4,772
$13.61 | $13.57
Mid-America Interconnected Network (MAIN)
(1) Total Domestic Capacity (MW)
(la) Existing
63,946 63,909
53,659 53,166
2
(2)
0
0
$0.16
($0.94)
(13)
($19)
$42
$4
$3
$35
($1)
($61)
$0.04
(56)
0
(56)
0
0
$0.02
($0.10)
(543)
($19)
$18
($19)
($1)
$39
($1)
($37)
($0.04)
(38)
(493)
0.0%
0.0%
0.0%
0.0%
0.5%
(2.5)%
0.0%
(0.2)%
0.7%
0.1%
0.8%
2.8%
(0.1)%
(2.9)%
0.2%
(0.1)%
0.0%
(0.6)%
0.0%
0.0%
0.1%
(0.2)%
(0.2)%
(0.2)%
0.3%
(0.6)%
(0.1)%
1.8%
(0.1)%
(0.8)%
(0.3)%
(0.1)%
(0.9)%
B3-34
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
AEO Base Case
10,288
0
3,083
$23.96
$54.16
303,096
$10,721
$6,568
$3,196
$627
$1,994
$751
$4,153
$12.61
Mid-Continent Area Power Pe
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
38,477
32,672
5,806
0
476
$22.94
$53.64
195,033
$6,512
$3,894
$1,963
$398
$1,044
$490
$2,618
$12.10
Northeast Power Coordinating C
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
76,114
59,678
5,882
10,554
4,107
$30.65
$48.65
302,155
Final Rule
10,743
0
3,576
$23.95
$54.80
302,009
$10,729
$6,570
$3,213
$625
$1,977
$755
$4,159
$12.71
ol (MAPP)
38,477
32,672
5,806
0
476
$22.77
$54.88
195,262
$6,532
$3,915
$1,962
$398
$1,060
$494
$2,617
$12.09
xincil (NPCC)
76,154
59,691
5,935
10,528
4,107
$30.67
$48.42
302,422
Difference
455
0
493
($0.01)
$0.64
(1,087)
$8
$2
$18
($2)
($18)
$4
$6
$0.10
0
0
0
0
0
($0.17)
$1.24
229
$19
$20
($1)
$1
$16
$5
($1)
($0.01)
40
13
53
(25)
0
$0.02
($0.23)
267
% Change
4.4%
0.0%
16.0%
0.0%
1.2%
(0.4)%
0.1%
0.0%
0.6%
(0.3)%
(0.9)%
0.5%
0.1%
0.8%
0.0%
0.0%
0.0%
0.0%
0.0%
(0.7)%
2.3%
0.1%
0.3%
0.5%
0.0%
0.2%
1.5%
0.9%
0.0%
(0.1)%
0.1%
0.0%
0.9%
(0.2)%
0.0%
0.1%
(0.5)%
0.1%
B3-35
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
AEO Base Case
$12,689
$8,761
$5,116
$402
$1,831
$1,412
$3,928
$18.26
Southeastern Electric Reliability
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
207,945
164,552
43,393
0
0
$25.81
$47.48
1,012,116
$35,984
$22,345
$11,804
$1,870
$5,411
$3,260
$13,638
$13.51
Southwest Power Pool (
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(_lc) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
52,670
48,956
3,714
0
Final Rule
$12,688
$8,822
$5,110
$400
$1,895
$1,417
$3,865
$18.22
Council (SERC)
208,286
164,552
43,734
0
0
$25.81
$47.50
1,013,119
$36,031
$22,457
$11,792
$1,876
$5,492
$3,297
$13,574
$13.49
SPP)
52,644
48,956
3,688
0
Difference
($2)
$61
($6)
($2)
$64
$5
($62)
($0.04)
341
0
341
0
0
$0.00
$0.03
1,002
$48
$112
($12)
$6
$81
$37
($64)
($0.02)
(26)
0
(26)
0
% Change
0.0%
0.7%
(0.1)%
(0.6)%
3.5%
0.3%
(1.6)%
(0.2)%
0.2%
0.0%
0.8%
0.0%
0.0%
0.0%
0.1%
0.1%
0.1%
0.5%
(0.1)%
0.3%
1.5%
1.1%
(0.5)%
(0.1)%
0.0%
0.0%
(0.7)%
0.0%
0 00 0.0%
$24.92 $24.98 $0.06 0.2%
$45.59 $45.20 ($0.39) (0.8)%
233,472 233,542 70 0.0%
$8,216 $8,209 ($7) (0.1)%
$4,742 $4,751 $9 0.2%
$2,944 $2,943 ($1) 0.0%
$430 $431
$1,076 $1,088
$292 $289
$1 0.2%
$12 1.1%
($3) (1.0)%
B3-36
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-1: Market-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
AEO Base Case
$3,474
$14.45
Western Systems Coordinating C
(1) Total Domestic Capacity (MW)
(la) Existing
(Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2002/MWh)
(2b) Capacity Prices ($2002/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2002)
(5) Costs (Millions; $2002)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2002)
(7) Variable Production Costs ($/MWh)
177,780
152,891
17,337
7,552
0
$27.65
$25.05
806,830
$26,393
$16,417
$8,772
$1,226
$4,327
$2,091
$9,976
$12.39
Final Rule
$3,458
$14.45
ouncil (WSCC)
177,780
152,868
17,314
7,599
0
$27.66
$24.99
806,834
$26,384
$16,451
$8,771
$1,227
$4,360
$2,093
$9,933
$12.39
Difference
($16)
($0.01)
0
(23)
(24)
47
0
$0.01
($0.06)
4
($9)
$34
($1)
$1
$33
$1
($43)
$0.00
% Change
(0.5)%
0.0%
0.0%
0.0%
(0.1)%
0.6%
0.0%
0.0%
(0.2)%
0.0%
0.0%
0.2%
0.0%
0.1%
0.8%
0.1%
(0.4)%
0.0%
Source: IPM analysis: Model runs for Section 316(b) NODABase Case and the final rule (AEO electricity demand assumptions).
Table B2-A-2 repeats some of the information presented in Tables B3-4 and B3-A-1 to facilitate a comparison of the results
using the two different electricity demand assumptions. The columns labeled "EPA" represent the results based on EPA
electricity demand assumptions; the columns labeled"AEO" represent the results based on AEO electricity demand
assumptions. The table highlights differences between the two cases of greater than or equal to 0.5 percent with bold font and
pale blue shading. For a description of the metrics presented in this table, please refer to section B3-3.1.
B3-37
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-2: Comparison of Market-Level Impacts of the Final Rule (2010)
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
Baseline Capacity
(MW)
EPA | AEO
118,529! 127,332
75,290! 80,472
50,324! 53,831
63,784! 68,838
59,494! 63,946
35,835! 38,477
72,477! 76,114
194,485! 207,945
49,948! 52,670
167,748! 177,780
887,915 1 947,406
Incremental ; _, „, „
„ ., ; Closures as % of
Capacity ; _ ,. _
/-^i /mVnrv :- Baseline Capacity
Closures (MW) ; r J
EPA ! AEO ! EPA
oj oj 0.0%
0! 0! 0.0%
Oj Oj 0.0%
0! Oj 0.0%
94! 493! 0.2%
0! Oj 0.0%
0! Oj 0.0%
0! Oj 0.0%
Oj Oj 0.0%
58! Oj 0.0%
152 1 493 1 0.0%
AEO
0.0%
0.0%
0.0%
0.0%
0.8%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
Change in
Variable
Production Cost
per MWh
EPA
0.1%
0.0%
0.4%
0.4%
0.1%
(0.1)%
(0.5)%
0.0%
(0.1)%
0.0%
0.0%
AEO
0.2%
(0.1)%
0.2%
(0.3)%
0.8%
(0.1)%
(0.2)%
(0.1)%
0.0%
0.0%
0.0%
Change in Energy
Price per MWh
EPA
0.3%
5.8%
0.6%
0.1%
(0.3)%
(0.3)%
(0.1)%
(0.1)%
(0.2)%
0.0%
n/a
AEO
0.0%
1.3%
0.5%
0.1%
0.0%
(0.7)%
0.1%
0.0%
0.2%
0.0%
n/a
Change in Pre-
Tax Income
EPA
(0.8)%
(5.6)%
(3.0)%
(0.9)%
(0.3)%
0.1%
(1.9)%
(0.5)%
(0.4)%
(0.5)%
(1.0)%
AEO
(0.8)%
(1.7)%
(2.9)%
(0.8)%
0.1%
0.0%
(1.6)%
(0.5)%
(0.5)%
(0.4)%
(0.7)°/<
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (EPA and AEO electricity demand
assumptions).
The comparison of the two market-level analyses of the final rule, using the two different electricity demand assumptions,
shows only minor differences in the results. It should also be noted that the direction of the differences is not systematic, i.e.,
in some cases, impacts are greater under the AEO assumptions; in other cases, impacts are greater under the EPA
assumptions.
> Incremental capacity closures are 341 MW higher under the AEO assumptions than under the EPA assumptions.
This corresponds to less than 0.04 percent of total baseline capacity under either base case. MAIN is estimated to
experience 493 MW of capacity closure under the AEO assumptions, compared to 94 under the EPA assumptions.
Conversely, WSCC is estimated to experience 58 MW of capacity closure under the EPA assumptions and no
closures under the AEO assumptions.
•• MAIN is the only region with a difference in incremental closures as a percentage of baseline capacity under the
two assumptions: under the AEO assumptions closures are approximately 0.6 percent higher than under the EPA
assumptions.
> Variable production costs per MWh in MAAC increase by 0.4 percent under the EPA assumptions and fall by 0.3
percent under the AEO assumptions, a difference of 0.7 percentage points. Conversely, in MAIN, variable
production cost per MWh increase more under the AEO assumptions than under the EPA assumptions (0.8 compared
to 0.1 percent).
»• Energy price increases in ERCOT are smaller under the AEO assumptions than under the EPA assumptions (1.3
percent compared to 5.8 percent, a difference of 4.5 percentage points).
> In ERCOT, facilities experience a much larger reduction in pre-tax income under the EPA assumptions than under
the AEO assumptions (5.6 percent compared to 1.7 percent, a difference of 3.9 percentage points).
•• For all other measures and regions, the results under the two different electricity demand assumptions are
within 0.5 percent of each other.
B3-38
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
B3-A.1-2 Analysis of Phase II Facilities for 2010 - AEO Assumptions
This section presents the results of the IPM analysis for the Phase II facilities that are modeled by the IPM. Eight of the 535
Phase II facilities are closures in the base case and under the final rule. These facilities are not represented in the results
described in this section.
EPA used the IPM results from model run year 2010 to analyze impacts on Phase II facilities at two levels: (1) potential
changes in the economic and operational characteristics of the in-scope Phase II facilities as a group and (2) potential changes
to individual facilities within the group of in-scope Phase II facilities.
a. In-scope Phase II facilities as a group
The analysis of the in-scope Phase II facilities as a group is largely similar to the market-level analysis, except that the base
case and policy option totals only include the economic activities of the 535 in-scope Phase II facilities represented by the
IPM. Table B3-A-3 below (equivalent to Table B3-5) presents six impact measures for the group of Phase II facilities: (1)
capacity changes, including changes in the number and capacity of closure facilities; (2) generation changes; (3) revenue
changes; (4) cost changes, including changes in fuel costs, variable O&M costs, fixed O&M costs, and capital costs; (5)
changes in pre-tax income; and (6) changes in variable production costs per MWh of generation, where variable production
cost is defined as the sum of fuel cost and variable O&M cost. For each measure, the table presents the results for the base
case and the final rule, the absolute difference between the two cases, and the percentage difference.
Table B3-A-3: Facility-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
AEO Base Case
National Totals
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
438,510
8
10,204
2,359,403
$81,220
$49,368
$25,612
$5,250
$15,612
$2,895
$31,851
$13.08
East Central Area Reliability Coordinatic
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
82,281
0
1
532,207
$17,524
$9,924
$5,207
$1,302
$2,981
$434
$7,600
Final Rule
438,004
8
10,697
2,351,936
$80,964
$49,544
$25,465
$5,245
$15,977
$2,857
$31,420
$13.06
n Agreement (1
82,292
0
1
532,268
$17,530
$10,018
$5,221
$1,301
$3,074
$421
$7,512
Difference
(506)
0
493
(7,466)
($256)
$175
($147)
($5)
$365
($38)
($431)
($0.02)
ECAR)
10
0
0
61
$6
$94
$15
($1)
$93
($12)
($88)
% Change
(0.1)%
0.0%
4.8%
(0.3)%
(0.3)%
0.4%
(0.6)%
(0.1)%
2.3%
(1.3)%
(1.4)%
(0.2)%
0.0%
0.0%
0.0%
0.0%
0.0%
1.0%
0.3%
(0.1)%
3.1%
(2.9)%
(1.2)%
B3-39
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-3: Facility-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(6) Variable Production Costs ($2002/MWh)
AEO Base Case
$12.23
Electric Reliability Council of Te
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
44,413
0
0
160,614
$5,919
$4,026
$2,186
$421
$1,193
$227
$1,892
$16.23
Florida Reliability Coordinating C
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
27,513
0
812
80,925
$3,445
$2,002
$1,093
$197
$682
$30
$1,443
$15.94
Mid-Atlantic Area Council I
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
35,482
1
1,725
182,096
$6,846
$3,894
$1,766
$375
$1,587
$166
$2,952
Final Rule
$12.25
xas (ERCOT)
44,452
0
0
159,032
$5,842
$4,009
$2,137
$417
$1,218
$237
$1,833
$16.06
ouncil (FRCC)
27,514
0
812
80,927
$3,431
$2,045
$1,101
$200
$716
$28
$1,386
$16.07
;MAAC>
35,482
1
1,725
181,226
$6,825
$3,907
$1,741
$374
$1,626
$166
$2,918
Difference
$0.02
39
0
0
(1,582)
($76)
($17)
($49)
($3)
$25
$10
($59)
($0.17)
2
0
0
3
($14)
$43
$8
$3
$34
($2)
($57)
$0.13
0
0
0
(870)
($21)
$13
($25)
($1)
$38
$0
($34)
% Change
0.2%
0.1%
0.0%
0.0%
(1.0)%
(1.3)%
(0.4)%
(2.2)%
(0.8)%
2.1%
4.3%
(3.1)%
(1.0)%
0.0%
0.0%
0.0%
0.0%
(0.4)%
2.2%
0.7%
1.6%
5.0%
(5.6)%
(4.0)%
0.8%
0.0%
0.0%
0.0%
(0.5)%
(0.3)%
0.3%
(1.4)%
(0.3)%
2.4%
0.0%
(1.1)%
B3-40
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-3: Facility-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
(6) Variable Production Costs ($2002/MWh)
AEO Base Case
$11.76
Mid-America Interconnected Net
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
38,606
2
3,083
239,552
$7,705
$4,589
$2,185
$540
$1,732
$132
$3,116
$11.37
Mid-Continent Area Power Po
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
15,749
1
476
110,585
$3,323
$2,004
$1,067
$226
$597
$114
$1,319
$11.70
Northeast Power Coordinating C(
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
37,219
4
4,107
159,374
$6,594
$4,948
$2,667
$268
$1,238
$774
$1,646
$18.42
Final Rule
$11.67
work (MAIN)
38,113
2
3,576
236,989
$7,639
$4,529
$2,174
$537
$1,709
$109
$3,110
$11.44
ol (MAPP)
15,749
1
476
110,668
$3,327
$2,020
$1,068
$227
$612
$114
$1,307
$11.70
Hjncil (NPCC)
37,164
4
4,107
157,749
$6,532
$4,953
$2,621
$264
$1,302
$766
$1,579
$18.29
Difference
($0.09)
(493)
0
493
(2,563)
($66)
($60)
($11)
($4)
($23)
($23)
($6)
$0.06
0
0
0
83
$4
$16
$1
$0
$15
$0
($12)
$0.01
(55)
0
0
(1,626)
($63)
$5
($46)
($4)
$63
($8)
($67)
($0.13)
% Change
(0.7)%
(1.3)%
0.0%
16.0%
(1.1)%
(0.9)%
(1.3)%
(0.5)%
(0.6)%
(1.3)%
(17.4)%
(0.2)%
0.6%
0.0%
0.0%
0.0%
0.1%
0.1%
0.8%
0.1%
0.2%
2.4%
0.0%
(0.9)%
0.0%
(0.1)%
0.0%
0.0%
(1.0)%
(1.0)%
0.1%
(1.7)%
(1.6)%
5.1%
(1.1)%
(4.1)%
(0.7)%
B3-41
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-A-3: Facility-Level Impacts of the Final Rule (by NERC Region; 2010)
Economic Measures
AEO Base Case
Southeastern Electric Reliability <
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
107,458
0
0
641,200
$21,403
$12,103
$6,200
$1,370
$3,983
$549
$9,300
$11.81
Southwest Power Pool (i
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/Mwh)
20,471
0
0
109,277
$3,558
$1,941
$1,138
$241
$557
$5
$1,617
$12.63
Western Systems Coordinating C(
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2002)
(4) Costs (Millions; $2002)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2002)
(6) Variable Production Costs ($2002/MWh)
29,318
0
0
143,572
$4,902
$3,937
$2,104
$309
$1,061
$464
$964
$16.81
Final Rule
:ouncil (SERC)
107,458
0
0
641,238
$21,410
$12,168
$6,186
$1,375
$4,057
$550
$9,242
$11.79
5PP)
20,471
0
0
108,596
$3,537
$1,934
$1,120
$241
$569
$4
$1,603
$12.53
>uncil (WSCC)
29,309
0
0
143,242
$4,891
$3,961
$2,096
$310
$1,094
$463
$929
$16.79
Difference
0
0
0
39
$7
$65
($13)
$5
$73
$0
($58)
($0.01)
0
0
0
(681)
($21)
($7)
($18)
($1)
$13
($1)
($14)
($0.10)
(8)
0
0
(331)
($11)
$24
($9)
$1
$33
($1)
($35)
($0.02)
% Change
0.0%
0.0%
0.0%
0.0%
0.0%
0.5%
(0.2)%
0.4%
1.8%
0.0%
(0.6)%
(0.1)%
0.0%
0.0%
0.0%
(0.6)%
(0.6)%
(0.4)%
(1.6)%
(0.3)%
2.3%
(20.7)%
(0.9)%
(0.8)%
0.0%
0.0%
0.0%
(0.2)%
(0.2)%
0.6%
(0.4)%
0.2%
3.1%
(0.3)%
(3.6)%
(0.1)%
B3-42
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (AEO electricity demand assumptions).
Table B3-A-4 repeats some of the information presented in Tables B3-5 and B3-A-3 to facilitate a comparison of the results
using the two different electricity demand assumptions. The columns labeled "EPA" represent the results based on EPA
electricity demand assumptions; the columns labeled"AEO" represent the results based on AEO electricity demand
assumptions. The table highlights differences between the two cases of greater than or equal to 0.5 percent with bold font and
pale blue shading For a description of the metrics presented in this table, please refer to section B3-3.2.
Table B3-A-4: Comparison of Facility-Level Impacts of the Final Rule (2010)
NERC
Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
wscc
Total
Baseline Capacity
(MW)
EPA
82,313
43,522
27,537
34,376
36,498
15,749
37,651
107,450
20,471
28,431
433,998
AEO
82,281
44,413
27,513
35,482
38,606
15,749
37,219
107,458
20,471
29,318
438,510
Incremental ; „, „, „
_ ., : Closures as % of
Capacity ;„,..-, .,
/-^i /HiV.™ : Baseline Capacity
Closures (MW) ; l J
EPA 1 AEO 1 EPA
0! Oj 0.0%
0! Oj 0.0%
Oj Oj 0.0%
0! Oj 0.0%
94! 493! 0.3%
Oj Oj 0.0%
0! Oj 0.0%
0! Oj 0.0%
o! o! 0.0%
58! O! 0.2%
152 1 493 1 0.0%
AEO
0.0%
0.0%
0.0%
0.0%
1.3%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
Change in
Variable
Production Cost
per MWh
EPA
0.0%
(0.7)%
0.3%
0.0%
0.1%
(0.1)%
(1.7)%
(0.3)%
(0.4)%
(0.9)%
(0.6)%
AEO
0.2%
(1.0)%
0.8%
(0.7)%
0.6%
0.0%
(0.7)%
(0.1)%
(0.8)%
(0.1)%
(0.2)%
Change in
Generation
EPA
(0.2)%
(1.8)%
(0.8)%
0.2%
(0.3)%
0.0%
(3.6)%
(0.2)%
(0.7)%
(4.3)%
(0.8)%
AEO
0.0%
(1.0)%
0.0%
(0.5)%
(1.1)%
0.1%
(1.0)%
0.0%
(0.6)%
(0.2)%
(0.3)%
Change in Pre-
Tax Income
EPA
(1.0)%
(10.4)%
(4.0)%
(1.4)%
(0.6)%
(0.3)%
(4.3)%
(0.7)%
(1.0)%
(10.4)%
(1.8)%
AEO
(1.2)%
(3.1)%
(4.0)%
(1.1)%
(0.2)%
(0.9)%
(4.1)%
(0.6)%
(0.9)%
(3.6)%
(1.4)»/<
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (EPA and AEO electricity demand
assumptions).
The comparison of the final rule using the two different electricity demand assumptions show the differences listed below. It
should be noted that the direction of the differences is not systematic, i.e., in some cases, impacts are greater under the AEO
assumptions; in other cases, impacts are greater under the EPA assumptions.
*• Incremental capacity closures are 341 MW higher under the AEO assumptions than under the EPA assumptions.
This corresponds to less than 0.08 percent of Phase II capacity under either base case. The incremental capacity
closure results are identical to the market-level results discussed above.
*• Closures as a percentage of baseline capacity in MAIN are 1.0 percent higher under the AEO assumptions than
under the EPA assumptions.
*• The change in variable production cost per MWh differs by 0.5 percent or more in five NERC regions: in FRCC
and MAIN, it increases more under the AEO assumptions than under EPA assumptions; in MAAC, it decreases
under AEO assumptions but is unchanged under the EPA assumptions; and in NPPC and WSCC, it decreases less
under the AEO assumptions than under the EPA assumptions.
•• The change in generation differs by 0.5 percent or more in six NERC regions: in ERCOT, FRCC, NPCC, and
WSCC, Phase II facilities lose more generation under the EPA assumptions than under the AEO assumptions; in
MAIN, they lose more generation under the AEO assumptions than under the EPA assumptions; and in MAAC they
experience an increase in generation under the EPA assumptions and a decrease under the AEO assumptions.
B3-43
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
> The change in pre-tax income differs by 0.5 percent or more in three NERC regions: in MAPP, Phase II facilities
experience a slightly higher reduction in pre-tax income under the AEO assumptions than under the EPA
assumptions (0.9 percent compared to 0.3 percent). In WSCC and ERCOT, however, the reduction in pre-tax
income is substantially higher under the EPA assumptions than under the AEO assumptions (over 10 percent
compared to less than 4 percent).
•• For all other measures and regions, the results under the two different electricity demand assumptions are
within 0.5 percent of each other.
b. Individual Phase II facilities
In addition to effects of the final rule on the in-scope Phase II facilities as a group, there may be shifts in economic
performance among individual facilities subject to Phase II regulation. To assess such potential shifts, EPA analyzed
facility-specific changes in (1) capacity utilization (defined as generation divided by capacity multiplied by the number of
hours per year - 8,760); (2) generation; (3) revenues; (4) variable production costs per MWh of generation (defined as
variable O&M cost plus fuel cost divided by generation); (5) fuel cost per MWh of generation; and (6) pre-tax income. For
each measure, EPA determined the number of Phase II facilities that experience no changes, or an increase or a reduction
within three ranges: 1 percent or less, 1 to 3 percent, and more than 3 percent.
Table B3-A-5 (equivalent to Table B3-6) presents the total number of Phase II facilities with different degrees of change in
each of these measures. This table excludes 17 facilities with significant status changes including (eight facilities are baseline
closures and nine facilities changed their repowering decisions between the base case and policy case). These facilities are
either not operating at all in the base case or the post-compliance case, or they experience fundamental changes in the type of
units they operate; therefore, the measures presented below would not be meaningful for these facilities. In addition, the
changes in production cost per MWh and fuel cost per MWh could not be developed for 58 facilities with zero generation in
either the base case or post-compliance scenario. For these facilities, the change in production cost per MWh and fuel cost
per MWh is indicated as "n/a."
Table B3-A-5: Number of Individual Phase II Facilities with Operational Changes (2010)
Economic Measures
(1) Change in Capacity Utilization
(2) Change in Generation
(3) Change in Revenues
(4) Change in Variable Production
Costs/MWh
(5) Change in Fuel Costs
(6) Change in Pre-Tax Income
Reduction
3%
17
32
36
9
9
195
Increase
3%
7
15
14
13
8
9
No
Change
456
449
267
241
342
26
N/A
0
0
0
58
58
0
a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent.
b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post-
compliance case. For all other measures, the change is expressed as the percentage change between the base case and post-
compliance values.
Source: IPM analysis: Model runs for Section 316(b) NODA Base Case and the final rule (AEO electricity demand assumptions).
Table B3-A-5 indicates that the majority of Phase II facilities will not experience changes in capacity utilization, generation,
or fuel costs per MWh due to compliance with the final rule. Of those facilities with changes in post-compliance capacity
utilization and generation, most will experience decreases in these measures. The majority of facilities with changes in post-
compliance variable production costs per MWh will experience increases. However, more than 80 percent of those increases
will not exceed 1.0 percent. Changes in revenues at most Phase II facilities will also not exceed 1.0 percent. The largest
effect of the final rule will be on facilities' pre-tax income: over 85 percent of facilities will experience a reduction in pre-tax
B3-44
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3
income, with about 40 percent experiencing a reduction of 3.0 percent or greater. These reductions are due to a combination
of reduced revenues and increased compliance costs.
B3-45
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3
Chapter B3 - Appendix B
INTRODUCTION CHA(,TER CoNTENTS
B3-B.1 Summary Comparison of Energy Market Models . B3-46
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.
B3-B. l SUMMARY COMPARISON OF ENERGY MARKET MODELS
EPA performed research to identify electricity market models that could potentially be used in the analysis of impacts
associated with regulatory options considered for section 316(b) Phase II regulation. 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
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 (1PM®).
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.
B3-46
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-B-1: Comparison of Electricity Market Models
Model
DOE/EIA: MEMS
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 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 NOX emissions trading
and rate-based programs for OTAG,
CAA Title IV NOX Rule; NOX
control options; RIA for the NOX
SIP call; and GCC scenarios.
Possible to accommodate other
environmental regulations.
B3-47
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-B-1: Comparison of Electricity Market Models
Model
DOE/EIA: MEMS
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 NOX
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).
B3-48
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-B-1: Comparison of Electricity Market Models
Model
DOE/EIA: MEMS
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, hi 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 and plant 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.
B3-49
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-B-1: Comparison of Electricity Market Models
Model
DOE/EIA: MEMS
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.
B3-50
-------
§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts
Appendix to Chapter B3
Table B3-B-1: Comparison of Electricity Market Models
Model
DOE/EIA: MEMS
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.
B3-51
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§ 316(b) Phase II EBA, Part B: Costs and Economic Impacts Appendix to Chapter B3
THIS PAGE INTENTIONALLY LEFT BLANK
B3-52
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§ 316(b) Phase II Final Rule - 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 B4-1
B4-1.1 Identification of Domestic Parent
Entities B4-2
B4-1.2 Size Determination of Domestic Parent
Entities B4-2
B4-2 Percent of Small Entities Regulated B4-4
B4-3 Sales Test for Small Entities B4-6
B4-4 Summary B4-7
References B4-8
Appendix to Chapter B4 B4-9
INTRODUCTION
The Regulatory Flexibility Act (RFA) requires EPA to
consider the economic impact a new rule will 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 Final Section
316(b) Phase II Existing Facilities Rule on small entities, a
small entity is: (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
final Phase II rule.
EPA's analysis showed that the final 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.
B4-1 NUMBER OF IN-SCOPE FACILITIES OWNED BY SMALL ENTITIES
EPA's 2000 Section 316(b) Industry Survey identified 543 generating facilities expected to meet the in-scope requirements of
the Final Section 316(b) Phase II Existing Facilities Rule. As described in previous chapters of this document, these 543
facilities represent 554 facilities in the industry. It is impossible, however, to determine the parent entity of extrapolated
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.
2 EPA applied sample weights to the 543 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 referto the Information Collection Request (U.S.
EPA 1999a; U.S. EPA 2000).
B4-1
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
facilities. The remainder of this parent size analysis therefore discusses research done for the 543 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 543 in-scope facilities, and
*• determine the size of the entities owning the 543 facilities.
B4-1.1 Identification of domestic Parent Entities
Each of the 543 Phase II facilities belongs to one of the following seven types of domestic parent entities: investor-owned,
nonutility, federal, state, municipality, political subdivision, or rural electric cooperative. Investor-owned firms and
nonutilities are private entities, federal, state, municipal, and political subdivision entities are public entities, and rural electric
cooperatives are not-for-profit enterprises. EPA first identified the utility owner of each Phase II facility using the 2001 Form
EIA-860 (U.S. DOE, 2001a). In most cases, utilities that are classified as federal, state, municipal, and political subdivision
utilities are the domestic parents of the facilities that they own.
For facilities owned by a private entity, including utility (i.e., investor-owned) and nonutility plants, the immediate utility
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). To determine the domestic parent entity for all facilities owned by
a private entity, EPA used several publicly available data sources, including data from the Department of Energy's (DOE)
Energy Information Administration, 2001 Form EIA-860; 10-K filings available through the Securities and Exchange
Commission's (SEC) FreeEdgar database; corporate websites; and Dun and Bradstreet data (U.S. DOE, 2001a; Edgar Online
Inc.,2003; D&B, 2003).
EPA determined that 126 unique entities own the 543 in-scope facilities.
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 investor-owned entities 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 Dun and Bradstreet data, as well as the following publicly available data sources, to obtain the
information necessary to determine the entity size: 10-K filings available through the Security and Exchange
Commission's (SEC) FreeEdgar database, 2001 EIA Form-860, U.S. Census Data, and company websites (D&B,
2003; EDGAR Online Inc., 2003; U.S. Census Bureau, 2003; U.S. DOE, 2001a). 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 considered large for the purpose of the RFA analysis (U.S. EPA, 1999b).
> Municipalities 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 (U.S. Census Bureau, 2003).
*• 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 data from the 2001 Form EIA-861 (U.S. DOE,
2001b).
B4-2
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-1: Unique Phase II Non-Government Entity SIC Codes and SBA
SIC Code
1311
3312
4911
4924
4931
4932
4939
4953
5012
6512
8221
SIC Description
Grade 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
Automobiles and Other Motor Vehicles
Operators of Nonresidential Buildings
Colleges, Universities, and Professional Schools
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
100 Employees
$5.0 Million
$5.0 Million
Source: U.S. SBA, 2000.
Based on these size thresholds, EPA determined that 25 out of the 126 parent entities owning the 543 in-scope facilities are
small entities.3 Sixteen of the 25 small entities are municipalities, six are rural electric cooperatives, one is a nonutility, one is
an investor-owned entity, and one is a political subdivision. Table B4-2 presents the distribution of the unique entities by
entity type and size. Table B4-2 also presents the distribution of the weighted in-scope facilities by their owner's type and
size. No small entity owns more than one in-scope facility; therefore, the 25 small entities own 25 in-scope facilities.
3 EPA conducted a sensitivity analysis of domestic parent size determinations where entity size for political subdivisions and
municipalities is based on utility-level electric output rather than the population threshold of 50,000. The results of this analysis are
presented in section B4-A.1 of the appendix to this chapter.
B4-3
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-2: Phase II Unique Entities and Facilities (by Entity Type and Size)
Entity Type
Investor-Owned
Nonutility
Federal
State
Municipality
Political Subdivision
Rural Electric Cooperative
Small Entity Size
Standard
SIC Specific
SIC Specific
Large
Large
Population of 50,000
Population of 50,000
4 million MWh
Total"
Number of Entities
Large
40
25
1
4
20
2
9
101
Small
1
1
-
-
16
1
6
25
Total
41
26
1
4
36
3
15
126
Number of Facilities
Large
273
178
14
7
32
6
19
529
Small
1
1
-
-
16
1
6
25
Total
274
179
14
7
48
7
25
554
a Individual numbers may not add up to total due to independent rounding.
Source: U.S. EPA analysis, 2004.
B4-2 PERCENT OF SMALL ENTITIES REGULATED
In order to assess the small entity impact of the final Phase II rule on the electric generating industry, 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 25 small entities subject to the final Phase II rule. Since only facilities with design intake flows of 50
MGD or more are subject to the final rule, the low number of small entities owning in-scope facilities is not unexpected. EPA
identified 1,992 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 final Phase II rule.
Based on Form EIA-861, 3,272 unique utilities operated in the United States in 2001.4 It was not feasible to conduct the same
research for all 3,272 utilities that was done for the 126 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 electric output threshold of 4
million MWh, using the 2001 Form EIA-861 data. However, EPA's analysis of the 126 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, municipalities, and political subdivisions:
*• 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 only one
of these five small utilities would also be considered small at the holding company level. EPA therefore estimates
that industry-wide only 20 percent of private entities that are small at the utility level would also be small at the
holding company level. Accordingly, EPA reduced the industry-wide number of privately-owned small utilities
(based on Form EIA-861) by a factor of 80 percent.
»• Municipalities: EPA's research of municipalities owning in-scope facilities showed that 30 municipalities would be
small based on the 4 million MWh size standard. Of these 30 entities, 16, or 53 percent, would also be considered
4 It should be noted that the total number of small entities in the industry used in this analysis is based on regulated entities (utilities)
only. Information on the size of unregulated entities (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 final Phase II rule maybe overstated.
B4-4
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
small when using the population threshold. EPA therefore estimates that industry-wide only 53 percent of
municipalities that are small based on electric output would also be small based on population size. Accordingly,
EPA reduced the industry-wide number of small municipalities (based on Form EIA-861) by a factor of 47 percent.
•• Political Subdivisions: EPA's research of political subdivisions owning in-scope facilities showed that only one
political subdivision owning an in-scope utility is small based on electric output, and that this entity is also small
based on population. EPA therefore assumes that all political subdivisions within Form EIA-861 that are small
based on electric output are also small based on population. Accordingly, EPA did not make an adjustment to the
industry-wide number of small political subdivisions (based on Form EIA-861).
These adjustments are based on the assumption that Phase II utilities (i.e., utilities that own steam electric generators with
flow greater than 50 MGD) are representative of the EIA universe of electric utilities (for private entities in terms of their
respective sizes at the utility level and the holding company level; for municipalities and political subdivisions in terms of
their respective sizes based on electric output and population). If this is not the case, the industry-wide numbers of small
entities may be over- or underestimated.
B4-5
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-3 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 are subject to the final Phase II rule.
Table B4-3: Number of Small Entities (Industry Total and Entities with In-Scope Facilities)
Type of Entity
Private3' b
Municipality1'
Political Subdivision15
Rural Electric Cooperatives
All Firm Types
Total Number of
Small Entities
35
983
111
862
1,992
Number of Small
Entities with In-Scope
Facilities
2
16
1
6
25
Percent of Small Entities
Subject to the Final Phase II
Rule
5.7%
1.6%
0.9%
0.7%
1.3%
a The total number of small private entities includes only investor-owned utilities because information for determining the
total number of small nonutilities was unavailable. 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 final Phase II rule may be overstated.
b EPA estimated the total number of small entities for this entity type using the methodology described above.
Source: U.S. DOE, 2001 b; D&B, 2003.
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 final 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 final Phase II regulation.
None of the 25 facilities EPA determined to be owned by a small entity has more than one owner. Also, none of the 25 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 final rule.
The estimated annualized post-tax compliance costs include all technology costs, operation and maintenance costs, and
permitting costs associated with the final Phase II rule. A detailed summary of how these costs were developed is presented
in Chapter Bl: Summary of Compliance Costs. EPA collected revenue data for the 25 small entities from one of several
sources, depending on the availability of information. EPA used revenue data for each entity from one of the following
sources, listed in order of preference: (1) Dun and Bradstreet, (2) average utility revenue (1999-2001) from 2001 Form EIA-
861, (3) 10-K filings available through the Securities and Exchange Commission's (SEC) FreeEdgar database, or (4) other
sources such as company websites (D&B, 2003; U.S. DOE, 2001b; Edgar Online Inc., 2003).
The overall annualized compliance costs that facilities owned by small entities are estimated to incur represent between 0.005
and 6.7 percent of the entities' annual sales revenues. Table B4-4 presents the distribution of the entities' cost-to-revenue
ratios by small entity type. Of the 25 small entities, only one is estimated to incur compliance costs of greater than three
percent of revenues. Eight entities incur compliance costs of between one and three percent of revenues, while the remaining
16 entities incur compliance costs of less than one percent of revenues. Eleven small entities are estimated to incur no costs
other than permitting and monitoring costs.
B4-6
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-4: Impact Ratio Ranges by Small Entity Type
Type of Entity
Investor-Owned
Nonutility
Municipality
Political Subdivision
Rural Electric Cooperative
Total
Impact Ratio Ranges
0.005%
0.01%
0.28 to 6.72%
1.01%
0.14 to 0.40%
0.005 to 6.72%
0-1% 1-3% >3%
1 0 0
1 0 0
8 7 1
0 1 0
600
16 8 1
Total
1
1
16
1
6
25
Source: U.S. EPA analysis, 2004.
EPA has determined that, overall, the impacts faced by small entities as a result of the final Phase II rule are very low. Of the
25 entities owning in-scope facilities, only one entity is expected incur compliance costs of greater than three percent of
revenues. Moreover, this entity represents less than one percent of the 126 entities owning in-scope facilities.
B4-4 SUMMARY
EPA estimates that only 25 of 554 in-scope facilities subject to the Final Section 316(b) Phase II Existing Facilities Rule are
owned by a small entity. The absolute number of small entities potentially subject to this regulation, 25, 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 25 small entities are low, representing between 0.005 and 6.7 percent of the entities' annual sales revenue.
Only one entity is expected to incur compliance costs of greater than three percent of revenues. EPA therefore finds that this
final rule would not have a significant economic impact on a substantial number of small entities (no SISNOSE).
The RFA analysis in support of this final Phase II rule is summarized in Table B4-5.
Type of Entity
Investor-Owned"
Nonutility3
Municipality
Political Subdivision
Rural Electric Cooperative
Total
Table B4-5:
Total Number
of Small
Entities
35
983
111
862
1,992
Summary of RFA /
Number of Small
Entities with
In-scope facilities
1
L
1
fc
16
fc
1
6
25
Analysis
Percent of Small
Entities In-Scope
of Rule
5.7%
1.6%
L
0.9%
L
0.7%
1.3%
Annual Compliance
Costs/ Annual Sales
Revenue
0.005%
L
0.01%
L
0.28 to 6.72%
L
1.01%
L
0.14 to 0.40%
0.005 to 6.72%
a The total number of small private entities (i.e., investor-owned utilities and nonutilities) includes only investor-owned utilities
because information for determining the total number of small nonutilities was unavailable. 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 final Phase II rule maybe
overstated.
Source: U.S. EPA analysis, 2004.
B4-7
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B4: Regulatory Flexibility Analysis
REFERENCES
Dun and Bradstreet (D&B). 2003. Data extracted from D&B Webspectrum September 2003.
Regulatory Flexibility Act. Pub. L. 96-354, Sept. 19, 1980, 94 Stat. 1164 (Title 5, Sec. 601 et seq.).
Edgar Online Inc. 2003. Securities and Exchange Commission (SEC), FreeEdgar Database. Accessed between 1999 and
2003. www.freeedgar.com.
U.S. Department of Commerce (U.S. DOC). 2002. Bureau of the Census. 1997 NAICS Definitions: 551 Management of
Companies and Enterprises.
U.S. Census Bureau. 2003. Population Division. "National Population Datasets."
http://eire.census.gov/popest/estimates dataset.php. Accessed September 2003.
U.S. Department of Energy (U.S. DOE). 2001a. Form EIA-860 (2001). Annual Electric Generator Report.
U.S. Department of Energy (U.S. DOE). 2001b. Form EIA-861 (2001). Annual Electric Utility Report for the Reporting
Period 2001.
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.
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Appendix to Chapter B4
CHAPTER CONTENTS
B4-A.1 RFA Results Using Alternative Domestic
Parent Size Criteria B4-9
INTRODUCTION
This appendix presents a sensitivity analysis of the
domestic parent size determinations for municipalities and
political subdivisions, and of the small entity impact
assessment that is based on these size determinations. The
analysis presented in the body of this chapter used the
population-based size threshold (population of less than 50,000) for municipalities and political subdivisions; this appendix
compares those results with an analysis that uses the electric output size threshold (total electric output of less than 4 million
MWh).
B4-A. l REGULATORY FLEXIBILITY ANALYSIS (RFA) RESULTS USING ALTERNATIVE
DOMESTIC PARENT SIZE CRITERIA
Table B4-A-1 below presents the comparison of the estimated number of large and small entities and of the cost-to-revenue
ranges, by entity type, for the two methods of determining municipality and political subdivision entity size.
The top part of the table presents the results, where the small entity determinations are based on EPA guidelines (i.e.,
municipalities and political subdivisions are evaluation based on population; State and Federal entities are assumed to be
large; cooperative entities are evaluated based on electric output; and investor-owned and nonutility entities are evaluated
based on SIC-specific criteria). Based on this method, 101 of the 126 unique final parents of Phase II facilities are large and
25 are small. Sixteen of these 25 small entities are municipalities and one is a political subdivision.
The bottom part of the table presents the alternative set of results, where the size determinations for municipalities and
political subdivisions are based on electric output at the utility level, using data from 2001 Form EIA-861 (U.S. DOE, 2001).
Based on this method, 87 of the 126 unique final parents are large, and 39 are small. Compared to the first method, 14
additional municipalities would be classified as small using the electric output threshold. Ten of these 14 entities have cost-
to-revenue ratios of less than 0.5 percent, two have ratios between 0.5 and 1.0 percent, two have ratios between 1.0 and 3.0
percent, and none have ratios of 3.0 percent or greater.
Entity Type
Investor-owned
Nonutility
Federal
State
Municipality
Political Subdivision
Cooperative
Total
Table B4-A-1: Unique Entities by Type, S
Large
<0.5% 1 0.5-1% 1 1-3% 1 >=3% 1 J°tal
! ! ! ! Large
Municipality and Political Subdivision '
381 2! Oi Oi 40
$ £ j j
24 | ij OJ OJ 25
il ol ol ol i
£ £ J J,
4J OJ OJ OJ 4
16J 2J 2J OJ 20
t t f i
2| OJ OJ OJ 2
8J ll OJ Ol 9
i i i i
93 | 6\ 2\ OJ 101
ize, and Cost -Revenue Range
Small
<0.5% 1 0.5-1% 1 1-3% 1 >=3% I0tf.
i : : small
Size Based on Population
il ol ol o i
t i t
1| OJ OJ 0 1
OJ OJ OJ 0 0
OJ OJ OJ 0 0
4J 4J 7J 1 16
h t h
oj oj ij o i
el ol ol o e
i i i
12 | 4J 8J 1 25
Grand
Total
41
26
1
4
36
3
15
126
B4-9
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B4: Regulatory Flexibility Analysis
Table B4-A-1: Unique Entities by Type, Size, and Cost-Revenue Range
Entity Type
Large
<0.5%
Municif
Investor-owned
Nonutility
Federal
State
Municipality
Political Subdivision
Cooperative
Total
38
24
1
0.5-1% i 1-3%
lality and Politia
2! 0
ii o
oi o
>=3%
il Subdiv
0
0
0
Total
Large
Small
<0.5%
ision Size Based
40
25
1
4J OJ OJ OJ 4
6J OJ OJ OJ 6
?J Oj Oj OJ 2
8| l| OJ OJ 9
83 ! 4J o| o| 87
1
1
0
0.5-1%
on Electr
0
0
0
1-3% i >=3%
c Output
oi o
oi o
oi o
Total
Small
Grand
Total
1
1
0
oi oj oi oi o
14 | 6J 9J l| 30
°| °j lj °| L
6J OJ OJ OJ 6
22 | 6J 10 ! l| 39
41
26
1
4
36
3
15
126
Source: U.S. EPA analysis, 2004.
B4-A-2 below presents a comparison of the minimum and maximum cost-to-revenue ratios, by entity type and size, for the
two methods of determining municipality and political subdivision entity size. The overall minimum and maximum cost-to-
revenue ratio of unique entities does not vary across the two methods of size determination. However, there are slight
differences in both the maximum ratio for large municipalities and the minimum ratio for small municipalities.
Table B4-A-2: Minimum and Maximum
Utility Type
Cost-to-Revenue Ratios of Unique Entities by
Large
Minimum
Maximum
Type and Size
Small
Minimum
Maximum
Municipality and Political Subdivision Size Based on Population
Investor-owned
Nonutility
Municipality
Political Subdivision
Cooperative
Total
0.001%
0.006%
0.030%
0.088%
0.122%
0.001%
0.640%
0.782%
2.442%
0.096%
0.579%
2.442%
0.005%
0.007%
0.279%
1.009%
0.143%
0.005%
0.005%
0.007%
6.723%
1.009%
0.400%
6.723%
Municipality and Political Subdivision Size Based on Electric Output
Investor-owned
Nonutility
Municipality
Political Subdivision
Cooperative
Total
0.001%
0.006%
0.030%
0.088%
0.122%
0.001%
0.640%
0.782%
0.369%
0.096%
0.579%
0.782%
0.005%
0.007%
0.046%
1.009%
0.143%
0.005%
0.005%
0.007%
6.723%
1.009%
0.400%
6.723%
Source: U.S. EPA analysis, 2004.
B4-10
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§ 316(b) Phase II Final Rule - 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 the 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 by State, local, and Tribal governments, in the
aggregate, or by 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 B5-7
B5-2 Compliance Costs for the Private Sector B5-8
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 the UMRA generally requires EPA
to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective, or least
burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are
inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most
cost-effective, or least burdensome alternative if the Administrator publishes with the 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 final Phase II rule would incur annualized post-tax compliance costs of $249.5
million ($2002). Of this total, $216.3 million is incurred by private sector facilities, $23.1 million is incurred by facilities
owned by State and local governments, and $10.1 million is incurred by facilities owned by the Federal government.1 State
and Federal permitting authorities incur an additional $4.1 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 $41 9.1 million in 2009. The highest undiscounted cost
incurred by the State and local governments in any one year is approximately $43.5 million in 2008 (including facility
compliance costs and State implementation costs). 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, under §202 of the UMRA, EPA has prepared a written statement, presented in the
preamble to the final rule, that includes (1) a cost-benefit analysis; (2) an analysis of macroeconomic effects; (3) a summary of
State, local, and Tribal input; (4) a discussion related to the least burdensome option requirement; and (5) an analysis of small
government burden. This chapter contains additional information to support that statement, including information on
compliance and administrative costs, and on impacts on small governments.
B5-1 ANALYSIS OF IMPACTS ON GOVERNMENT ENTITIES
Governments may incur two types of costs as a result of this final rule:
*• direct costs to comply with the rule for facilities owned by government entities, and
»• administrative costs to implement the rule.
Both types of costs 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 14 of the 554 Phase II facilities.
B5-1
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
B5-1.1 Compliance Costs for Government-Owned Facilities
Table B5-1 presents the number of government entities that own facilities subject to the final rule and the number of in-scope
facilities owned by those governments. Of the 554 existing in-scope facilities subject to the final rule, 62 are owned by a
State or local government. Of those 62 facilities, 48 are owned by municipalities, seven are owned by State governments, and
seven are owned by political subdivisions. None of the Phase II facilities are owned by a Tribal government.
Table B5-1 also presents the total annualized compliance costs, average annualized costs, and maximum undiscounted costs
in any one year for facilities owned by different types of governments. The total annualized compliance cost incurred by the
62 government-owned Phase II facilities is $23.1 million, or approximately $372,000 per facility. The 48 facilities owned by
municipalities incur $17.6 million annually, which is the largest share of the total annualized compliance cost for government-
owned facilities. The seven State-owned facilities account for the largest average annualized compliance cost, with
approximately $602,000 per facility. The maximum undiscounted cost borne by the 62 facilities is $37.0 million, estimated to
be incurred in 2008.
Table B5-1: Compliance Costs of Government -Owned Facilities
Ownership Type
Municipality
State Government
Political Subdivision
Total
Number of
Government
Entities
36
4
3
43
Number of
Facilities
48
7
7
62
Total Annualized
Compliance Costs
(in millions, $2002)
$17.6
$4.2
$1.3
$23.1
Average Compliance
Cost
(per facility, $2002)
$366,000
$602,000
$180,000
$372,000
Maximum
One-Year Facility
Compliance Costs
(in millions, $2002)
$24.5 (2005)
$13.9 (2008)
$1.8(2006)
$37.0 (2008)
Source: U.S. EPA analysis, 2004.
B5-1.2 Administrative Costs
The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination System (NPDES)
permit program. Forty-five 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 final rule: (1) start-up activities, (2) permitting activities associated with the initial
NPDES permit containing the new section 3 16(b) requirements and subsequent permit renewals, and (3) annual activities.3
EPA estimates that the total costs for these activities will be $4.0 million, annualized over 30 years at a seven percent discount
rate. Table B5-2 below presents the estimated 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 calculate annualized costs.
3 The costs associated with implementing the requirement of the final Phase II rule are documented in EPA's Information Collection
Request (U.S. EPA, 2003).
55-2
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-2:
Activity
Start -Up Activities
Permitting Activities
Annual Activities
Total
Annualized Government Administrative Costs
(in millions, $2002)
Cost
$0.02
$2.94
$1.04
$4.00
Source: U.S. EPA analysis, 2004.
Start-up costs are incurred only once by each of the 46 permitting authorities. Permitting costs and annual activities are
incurred for every permit. Based on the specific permitting requirements of each in-scope facility, EPA calculated total
government costs of implementing the final Phase II rule by adding the cost of start-up activities to the aggregate costs for
each facility's first post-promulgation permit, repermitting activities, and annual activities. The maximum one-year
undiscounted implementation cost incurred by the government is $6.5 million, in 2008. EPA notes that the annualized cost of
administrative activities depends on when they are incurred. If facilities come into compliance later than assumed in this
analysis, permitting authorities' administrative activities will also occur in later years. As a result, the annualized costs of the
rule to permitting authorities will be lower because administrative costs incurred in later years have lower net present values.
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 final 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 final rule than are currently required.
The following subsections present more detail on the three types of implementation costs.
a. Start-up activities
Forty-five States and one Territory with NPDES permitting authority are expected to undertake start-up activities to prepare
for administering the final Phase II 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 final Phase II rule requirements for each facility's NPDES permit. In
addition, permitting authorities are expected to incur other direct costs, e.g., for purchasing supplies and copying. Table B5-3
shows the total start-up costs EPA estimated permitting authorities to incur. Each permitting authority is estimated to incur
start-up costs of $3,986 as a result of the final Phase II rule. EPA assumes that the initial start-up activities will be incurred by
all permitting authorities at the end of 2004, the year of promulgation of the final Phase II rule.
Table B5-3: government (.
(per Regulatory
Start-Up Activity
Read and Understand Rule
Mobilization/Planning
Training
Other Direct Costs
Total
'osts of Start-Up Activities
Authority; $2002)
Start-Up Costs
$994
$1,738
$1,205
$50
$3,986
Source: U.S. EPA analysis, 2004.
B5-3
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§ 316(b) Phase II Final Rule - 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 31 6(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. For this analysis, EPA assumed that
the first permit containing the new section 316(b) requirements will be issued between 2005 and 2009.4 Repermitting
activities will take place every five years after initial permitting.
The final 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 required by the initial post-promulgation
and each subsequent permit are similar. 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 (however, the costs associated with permitting facilities with (a) a recirculating system or a wedgewire screen in the
baseline or (b) a facility installing a new wedgewire screen are less). The burden of repermitting is expected to be smaller
than the burden of initial permitting 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 a site-specific determination if it
can demonstrate that the proposed technology will result in environmental performance within a watershed that is comparable
to the reductions in impingement and entrainment mortality that would otherwise be achieved under the final Phase II rule.
EPA estimates that 211 facilities will apply for a site-specific determination.5
4 For an explanation of how the compliance years were assigned to facilities subject to the final Phase II rule, see Chapter Bl:
Summary of Compliance Costs of this EBA.
5 EPA is not including this site-specific determination as a direct cost for complying facilities because this is an optional activity that
the facility will choose only in cases where the cost of the alternative technology plus the cost of the site-specific determination is less than
the cost of the technology otherwise required by the final Phase II rule. However, the site-specific determination costs for permitting
authorities are not optional, and thus are included in EPA's estimates of total cost.
B5-4
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-4: Government Permitting Costs I
Activity
Review Source Water Physical Data
Review CWIS Data
Review CWS Operation Narrative
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 Pilot Study for New Impingement & Entrainment Technology
Review Restoration Measures'1
Determine Monitoring Frequency
Determine Record Keeping and Reporting Frequency
Considering Public Comments
Issuing Permits
Permit Record Keeping
Other Direct Costs
Total (without site-specific determination of BTA)b
Review Information to Support Site-Specific Determination of BTA"
Establish Requirements for Site -Specific Technology"
Total Cost of Site-Specific Activities
Total (including a site-specific determination of BTA)b
[per Permit; $2002)
First Permit
$290
$871
$871
$1,325
$290
$1,488
$22,200
$1,325
$23,760
$290
$290
$1,325
$263
$131
$300
$33,636
$47,520
$1,162
$48,682
$82,317
Repermitting
$114
$259
$259
$414
$114
$424
$6,660
$414
$7,128
$114
$114
$414
$62
$24
$300
$10,399
$14,256
$322
$14,578
$24,977
a Assumed to apply to only 10 percent of facilities.
b Individual numbers may not add up to total due to independent rounding.
° Cost incurred only for permits of facilities conducting site-specific demonstrations.
Source: U.S. EPA analysis, 2004.
Table B5-4 shows that initial post-promulgation permits that do not require a site-specific determination of BTA are expected
to impose an average per permit cost of $33,636 on the issuing permitting authority. For initial post-promulgation permits
that include a site-specific determination, the State administrative costs associated with the site-specific determination add an
additional $48,682, resulting in total per permit costs of$82,317.
The State administrative cost for a permit renewal that does not include a site-specific determination is $10,399. For facilities
that do conduct a site-specific determination, the cost per permit imposed on the permitting authority increases by $14,578,
resulting in an average permit cost of $24,977.
Another start-up cost incurred by permitting authorities is associated with review of verification studies conducted at
facilities. In addition to reviewing the studies, permitting authorities must modify permits in case of unfavorable study results.
In total, verification study review is expected to cost permitting authorities $780 per permit. Table B5-5 lists the components
of verification study review.
55-5
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-5: Government Costs of Verification
(per Permit; $2002)
Activity
Review of Verification Studies
Permit Modification Due to Unfavorable Results
Recordkeeping
Other Direct Costs
Total
Study Review
Costs
$228
$518
$24
$10
$780
Source: U.S. EPA analysis, 2004.
A final component of start-up costs is the cost associated with alternative regulatory requirements. States can adopt
alternative regulatory requirements in their NPDES program that result in reductions of impingement mortality and
entrainment within a watershed. If these States can demonstrate to the Administrator that the reductions are comparable to
what would otherwise be achieved under rule, the Administrator will approve these alternative regulatory requirements. EPA
estimates that 10 regulatory permitting authorities will incur costs associated with alternative regulatory requirements. The
expected per permit cost to permitting authorities of establishing alternative regulatory requirements at those facilities is
$7,054. Table B5-6 shows the cost of each component of establishing alternative regulatory requirements.
Table B5-6: Government Costs of Alternative Regulatory Requirements
(per Permit; $2002)
Activity
Document Alternative Regulatory Requirements
Document Environmental Conditions within
Watershed
Include Supporting Historical Studies, Calculations,
and Analyses
Submit Documentation
Recordkeeping
Other Direct Costs
Total
Costs
$1,368
$1,824
$3,528
$96
$138
$100
$7,054
Source: U.S. EPA analysis, 2004.
c. Annual activities
In addition to the start-up and permitting activities discussed previously, permitting authorities will have to carry out certain
annual activities to ensure the continued implementation of the requirements of the final Phase II rule. These annual activities
include reviewing yearly status reports, tracking compliance, determination on monitoring frequency reduction, and record
keeping.
Table B5-7 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 $1,884 is estimated for each permit per year.
B5-6
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
Table B5-7: Government Costs for
Annual Activity
Review of Yearly Status Report
Compliance Tracking
Determination of Monitoring Frequency Reduction
Record Keeping
Other Direct Costs
Total
Annual Activities (per Permit; $2002)
Annual Costs
$684
$581
$456
$138
$25
$1,884
Source: U.S. EPA analysis, 2004.
B5-1.3 Impacts on Small Governments
EPA's analysis also considered whether the final rule may significantly or uniquely affect small governments (i.e.,
governments with a population of less than 50,000). Table B5-8 presents by ownership size: (1) the number of entities
owning facilities subject to the regulation; (2) the number of facilities; (3) the estimated annualized post-tax compliance costs;
and (4) the average annualized post-tax compliance cost per facility. EPA identified 17 facilities (of the 62 government-
owned facilities) subject to the final rule that are owned by small governments.6
Table B5-8: Number of Regulated Facilities and Post-Tax Compliance Costs by Entity Size
Ownership Size
Facilities Owned by
Small Governments
Facilities Owned by
Large Governments
Facilities Owned by
Small Non-Governments
Facilities Owned by
Large Non-Governments
All Facilities
Number
of
Entities
17
27
74
126
Number of
Phase II
Facilities
17
59
470
554
Total Annualized
Compliance Costs
(post-tax, in
millions, $2002)
$5.4
$27.8
$1.4
$214.9
$249.5
Average Annualized
Compliance Cost
per Facility
(post-tax, $2002)
$316,300
$470,200
$173,800
$457,600
$450,500
Maximum Annualized
Per Facility Compliance
Costs
(post-tax, in millions, $2002)
$1.3
$2.3
$0.3
$10.8
$10.8
Source: U.S. EPA analysis, 2004.
The total annualized compliance cost for the 17 facilities owned by small governments is $5.4 million, or approximately
$31 6,300 per facility. In comparison, the total annualized compliance cost for the 59 facilities owned by large governments is
$27.8 million, or approximately $470,200 per facility. The eight small non-government facilities incur total annualized
compliance cost of $1.4 million, or $173,800 per facility. Total annualized compliance cost for the 470 large non-
government facilities is $214.9 million, or $457,600 per facility. These numbers support EPA's evaluation that small
governments would not be significantly or uniquely affected by the final Phase II rule. The per facility average compliance
6 Chapter B4: Regulatory Flexibility Analysis of this EBA provides more information on EPA's determination of the size of entities
owning the 554 in-scope facilities.
55-7
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B5: UMRA Analysis
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 final Phase II rule.
B5-2 COMPLIANCE COSTS FOR THE PRIVATE SECTOR
The private sector only incurs compliance costs associated with facilities subject to this final rule. These direct facility costs
already include the cost to facilities of obtaining their NPDES permits. Of the 554 in-scope facilities subject to the final rule,
EPA identified 478 to be owned by a private entity.7
The methodology for determining compliance costs for the Phase II facilities is presented in Chapter Bl: Summary of
Compliance Costs of this EBA. Total annualized (post-tax) compliance costs for the 478 privately-owned facilities are
estimated to be $216 million, discounted at seven percent. The maximum aggregate post-tax cost (undiscounted) for all 478
facilities in any one year is estimated to be $419 million, which will be incurred in 2009.
B5-3 SUMMARY OF UMRA ANALYSIS
EPA estimates that the final 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 B5-9 summarizes the costs to
comply with the rule for the 540 in-scope facilities (excluding the 14 facilities owned by the Federal government) and the
costs to implement the rule for permitting authorities.
Table B5-9: Summary of UMRA Costs (in millions, $2002)
Sector
Government
Sector
Private Sector
Total Annualized Cost (Post-Tax)
Facility
Compliance Costs
$23.1
$216.3
Government
Implementation
Costs
$4.0
n/a
Total
$27.1
$216.3
Maximum One-Year Cost
Facility
Compliance
Costs
$37.0
$419.1
Government
Implementation
Costs
$6.5
n/a
Total
$43.5
$419.1
Source: U.S. EPA analysis, 2004.
The total annualized cost of the final section 3 16(b) Phase II Existing Facilities Rule to State and local governments is
approximately $27.1 million, consisting of $23.1 million in facility compliance costs and $4.0 million in government
implementation costs. The maximum one-year costs that will be incurred by government entities is expected to be $43.5
million ($37.0 million in facility compliance costs and $6.5 million in implementation costs), incurred in 2008. Total
annualized costs borne by the private sector is estimated by EPA to be $216.3 million. The maximum one-year cost to the
private sector is $419.1 million, which will be incurred in 2009.
7 For the purposes of this analysis, private entities include utilities, nonutilities, and rural electric cooperatives.
B5-8
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B5: UMRA Analysis
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2004. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Final Rule. ICR Number 2060.02. February 2004.
B5-9
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B5: UMRA Analysis
THIS PAGE INTENTIONALLY LEFT BLANK
B5-10
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§ 316(b) Phase II Final Rule - 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
Final Section 3 16(b) Phase II Existing Facilities Rule. These
analyses address the requirements of Executive Orders and
Acts applicable to this rule.
B6-1 EXECUTIVE ORDER 12866;
REGULATORY 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 B6-8
B6-9 National Technology Transfer and
Advancement Act B6-8
References B6-9
»• 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 final 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 Final Rule - EBA, Part B: Costs and Economic Impacts
B6: Other Administrative Requirements
Today's final rule requires 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 will 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 will 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, will
benefit from improved environmental conditions as a result of this rule. Under current conditions, EPA estimates that over
1.5 billion fish (expressed as age 1 equivalents) of recreational and commercial species are lost annually due to impingement
and entrainment at in-scope Phase II facilities. Under the final rule, more than 0.5 billion individuals of these commercially
and recreationally sought fish species (age 1 equivalents) are estimated to survive and join the fishery each year. These
additional 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 five percent of the total licensed population. This assumption is,
however, likely to understate the number of recreational fishers, because although fishing licenses maybe 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 five 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 14,000
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 people may engage in subsistence fishing within the vicinity of in-scope facilities. The results of this
analysis are presented in Table B6-1.
Table 66-1: Estimated Subsistence Fishing Population within 50-Mile Radius of In-Scope Facilities
Region
California
North Atlantic
Mid Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Hawaii
Interior U.S.
All In-Scope Facilities (Unweighted)
Number of In-Scope
Facilities
20
22
44
16
24
56
3
358
543
Average 2000 Population
(millions)"
6.5
5-1
10.3
1.5
1.9
2.8
1.8
1.5
2.7
Average Estimated
Subsistence Fishing
Population1"
28,000
13,000
8,000
18,000
14,000
11,000
17,000
11,000
14,000
a Total population living withing 50 miles.
b Estimated as 10% of total estimated anglers living within 50 miles of an in-scope facility. Rounded to nearest thousand.
Source: Angler estimates calculated from U.S. DOI, 1997; U.S. EPA analysis, 2004.
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts
B6: Other Administrative Requirements
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
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 543 in-scope facilities for which survey data are available.
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 tend to have significant Asian populations. As such, individuals in these areas who rely on
subsistence fishing may benefit greatly from 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 (23 of
543, or 4.2%), non-white populations (105 of 543, or 19.3%), Native American populations (33 of 543 or 6.1%), or Asian
populations (42 of 543 or 7.7%), that are significantly higher than national levels.
Based on these results, EPA does not believe that this rule will have an exclusionary effect, deny persons the benefits of the
National Pollution Discharge Elimination System (NPDES) program, or subject persons to discrimination because of their
race, color, or national origin. To the contrary, it will increase the number of fish and other aquatic organisms available for
subsistence, commercial, and recreational anglers of all races, color, and natural origin.
Table B6-2: Demographics of Populations within 50-Mile Radius of In-Scope Facilities
Waterbody Type
North Atlantic
Mid Atlantic
South Atlantic
Gulf of Mexico
California
Great Lakes
Hawaii
Interior U.S.
All In-Scope
Facilities
(Unweighted)
U.S.
Number of
In-Scope
Facilities
22
44
16
24
20
56
3
358
543
—
Average
1998
Poverty
Rate
f 9.3%
f 11.6%
13.2%
14.4%
13.4%
11.2%
9.7%
12.8%
12.5%
12.7%
Average 2000 Percent of
Population
Non-
white"
14.8%
34.1%
25.5%
24.1%
33.6%
18.7%
64.8%
17.4%
20.1%
22.9%
Native
American1"
h 0.7%
0.8%
0.7%
0.9%
1.9%
1.2%
1.8%
1.7%
1.5%
1.5%
Asian"
f 3.6%
f 6.1%
2.0%
2.5%
12.6%
2.2%
61.6%
1.7%
3.0%
4.2%
Number of Facilities with Levels >= 1.5 Times
the U.S. Level
Poverty
Rate
-
2
-
-
-
21
23
—
Non-White
Pop
1
32
3
6
12
4
3
44
105
—
Native
American
Pop
-
-
1
5
-
27
33
—
Asian
Pop
2
22
-
-
15
-
3
-
42
—
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.
° 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: Average poverty rate compiled from U.S. DOC, 1998; population estimates compiled from U.S. DOC, 2000.
B6-3 EXECUTIVE ORDER 13045: PROTECTION OF CHILDREN FROM ENVIRONMENTAL
HEALTH RISKS AND SAFETY RISKS
Executive Order 13045 (62 FR 19885, April 23, 1 997) 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
B6-3
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
final rule is an economically significant rule as defined under Executive Order 12866. However, it does not concern an
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 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 regulation.
This final 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 131 32. EPA expects an annual burden of 104,606 hours with
total average annual cost of $4.8 million for States to collectively administer this rule during the first three years after
promulgation. EPA has identified 62 Phase II existing facilities that are owned by State or local government entities. The
estimated average annual compliance cost incurred by these facilities is $372,000 per facility.
The final national cooling water intake structure requirements will 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 final Phase II regulation to have substantial direct effects on either authorized or nonauthorized
States or on local governments because it will not change how EPA and the States and local governments interact or their
respective authority or responsibilities for implementing the NPDES program. This 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 31 6(b) requirements. (See 40 CFR 123.62(e).) For purposes of this 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 rule alters 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 3 16(b) regulation and this
final 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 the Phase II rulemaking effort. 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
B6-4
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
related to the section 3 16(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
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 further
organized a meeting of technical experts (May 23, 2001) and a Symposium on Technologies for Protecting Aquatic
Organisms from Cooling Water Intake Structures (BTA symposium, May 6-7, 2003).
»• 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 130 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. In addition, EPA received more than 170 comments on the Phase II proposed rule and
NODA, including comments from State and local government representatives from Arkansas, Alabama, Indiana,
Tennessee, and Rhode Island.
> 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 the proposed Phase II 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 final Phase II Existing Facilities Rule will advance the objective of Executive Order 13158.
Marine protected areas (MPAs) 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 are developing an inventory of MPAs in the U.S. that are protected and managed under Federal, State, Territorial,
Tribal, or local laws. This list has not been completed, but it currently includes 32 Federal sites in the New England region,
31 in the Middle Atlantic region, 43 in the South Atlantic region, 45 in the Gulf of Mexico region, 12 in the Caribbean region,
15 in the Great Lakes region, and 46 in the U.S. West Coast region. Examples of marine protected areas 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.
B6-5
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
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.
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 final 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 final 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 final rule is owned
by tribal governments. This final 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, ("Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use"
(66 FR 28355, May 22, 2001)) requires EPA to prepare a Statement of Energy Effects when undertaking regulatory actions
identified as "significant energy actions." For the 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.
B6-6
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
This rule is not 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 final rule does not contain any compliance requirements that
will:
•• reduce crude oil supply in excess of 10,000 barrels per day;
*• reduce fuel production in excess of 4,000 barrels per day;
•• reduce coal production in excess of 5 million tons per day;
*• reduce electricity production in excess of 1 billion kilowatt hours per day or in excess of 500 megawatts of installed
capacity;
> increase energy prices in excess of 10 percent;
»• increase the cost of energy distribution in excess of 10 percent;
»• significantly increase dependence on foreign supplies of energy; or
> have other similar adverse outcomes, particularly unintended ones.
Of the potential significant adverse effects on the supply, distribution, or use of energy (listed above) only a few apply to the
final Phase II rule. Through increases in the cost of generating electricity and shifts in the types of generators employed, the
final Phase II rule might affect (1) the production of coal, (2) the production of electricity, (3) the amount of installed
capacity, (4) energy prices, and (5) the dependence on foreign supplies of energy. EPA used the results from its electricity
market model analysis (see Chapter B3) to analyze the final rule for each of these potential effects.
*»* Production of coal
EPA estimates that this final rule will decrease the annual use of coal for electricity generation by 82.3 trillion Btu (TBtu), or
0.4 percent. This reduction converts to 4.07 million tons of coal per year or 11,150 tons of coal per day.1 Assuming that a
reduction in the use of coal for electricity generation results in a similar reduction in coal production, EPA concludes that this
rule will not have a significant impact on the national production of coal as defined by the thresholds listed above.
*»* Production of electricity
EPA's electricity market analysis did not allow for an explicit consideration of the changes in the production of electricity.
However, based on the small effects on installed capacity and electricity prices, EPA concludes that this final rule will not
reduce electricity production in excess of 1 billion kilowatt hours per day.
*»* Installed capacity
The final rule does not contain requirements that will permanently reduce installed capacity, for example through parasitic
losses or auxiliary power requirements. However, the rule does contain requirements that may lead to one-time temporary
downtimes of steam electric generators subject to this rule, ranging from two to eleven weeks. EPA estimates that
approximately 100 facilities, accounting for 70,000 megawatts (MW) of generating capacity, will experience such downtimes.
However, EPA's analyses indicate that these downtimes will not have a significant adverse effect on the supply, distribution,
or use of energy (see Chapter B3 of the Final EBA). In addition, EPA estimates that this rule will lead to only 152 MW in
incremental permanent capacity closures, well below the 500 MW impact threshold.
»»» Energy prices
The final rule will not significantly affect energy prices in either the long run or the short run. EPA estimates that, in the long
run, energy prices will rise by less than one percent in all but two North American Electric Reliability Council (NERC)
regions. The Electric Reliability Council of Texas (ERCOT) is estimated to have the largest increase in electricity prices with
5.8 percent in 2010 and 1.3 percent in 2013. The Florida Reliability Coordinating Council (FRCC) is estimated to experience
electricity price increases of 1.3 percent in 2013 and 1.6 percent in2020. In the short run (2008), energy prices are estimated
to rise between 0.4 and 3.0 percent in all regions. EPA estimates that five regions will experience increases of less than 0.7
percent while five regions will experience increases between 1.1 and 3.0 percent. No region will experience energy price
increases of more than 10 percent as a result of the final Phase II rule.
*»* Dependence on foreign supplies of energy
EPA's electricity market analysis did not allow for an explicit consideration of the effects of this final rule on foreign imports
of energy. However, this rule only affects electricity generators, which are generally not subject to significant foreign
competition. (Only Canada and Mexico are connected to the U.S. electricity grid, and transmission losses are substantial
when electricity is transmitted over long distances.) In addition, the effects on installed capacity and electricity prices, are
This conversion assumes an average energy content of 10,115 Btu per pound of coal (U.S. DOE, 2000).
B6-7
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§ 316(b) Phase II Final Rule - EBA, Part B: Costs and Economic Impacts B6: Other Administrative Requirements
estimated to be small. EPA therefore concludes that this final rule will not significantly increase dependence on foreign
supplies of energy.
Based on these analyses, EPA concludes that this final rule will have minimal energy effects at a national and regional level.
As a result, EPA did not prepare a Statement of Energy Effects. For more detail on effects of this final rule on energy
markets, see Chapter C3: Electricity Market Model Analysis.
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 final Phase II regulation are documented in the
Information Collection Request (ICR) which accompanies this regulation (U.S. EPA, 2004).
B6-9 NATIONAL TECHNOLOGY 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 final rule does not involve such technical standards. Therefore, EPA is not considering the use of any voluntary
consensus standards.
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§ 316(b) Phase II Final Rule - 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 5 1735.
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 Energy (U.S. DOE), Energy Information Administration (EIA). 2000. Coal Industry Annual 2000 Data
Tables, Table 106 Average Quality of Coal Received at Electric Utilities by Census Division and State, 1991, 1996-2000.
Table data from Federal Energy Regulatory Commission, FERC Form 423, Monthly Report of Cost and Quality of Fuels for
Electric Plants. Accessed 11/24/03.
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). 2004. Information Collection Request for Cooling Water Intake
Structures, Phase II Existing Facility Final Rule. ICR Number 2060.02. February 2004.
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B6-10
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§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter Cl: Regional Approach
Chapter Cl: Regional Approach
INTRODUCTION
For the Section 316(b) Phase II benefits analysis EPA
examined impingement and entrainment (I&E) losses, and
the economic benefits of reducing these losses, at the
regional level. The estimated benefits were then aggregated
across all regions to yield a national benefit estimate.
The primary objective of the regional approach was to refine
the scale of resolution of the benefits case studies conducted
for proposal, so that extrapolations were within regions
rather than nation-wide. Extrapolation of I&E rates was
necessary because not all in scope facilities have I&E data. It
facilities nation-wide that have conducted I&E studies. At the
further analysis.
CHAPTER CONTENTS
Cl-l Definitions of Regions Cl-1
Cl-1.1 Coastal Regions Cl-1
Cl-1.2 Great Lakes Region Cl-2
Cl-1.3 Inland Region Cl-2
Cl-2 Development of Regional I&E Estimates Cl-2
Cl-3 Development of Regional and National Benefits
Estimates Cl-3
References Cl-4
also was not possible to evaluate all of the data from the many
same time, in many cases available data were not suitable for
While EPA believes that extrapolation within regions was reasonable for the national rulemaking, the Agency is not
advocating that this approach be followed for impact and/or benefits analyses that might be conducted for individual National
Pollution Discharge Elimination System (NPDES) permits. At the individual permit level it is possible to conduct a more
detailed, site-specific analysis on the environmental ramifications of cooling water intake structures than was necessary or
feasible for the national-level analysis.
Cl-1 DEFINITIONS OF RESIGNS
EPA defined seven regions for its analysis based on similarities in the affected aquatic species and characteristics of
commercial and recreational fishing activities in the area. These regions and the waterbody types within each region are
described below. Maps showing the facilities in each region that are in scope of the Phase II rule are provided at the end of
this chapter.
Cl-1.1 Coastal Regions
Coastal regions are fisheries regions defined by the National Atmospheric and Oceanic Administration (NOAA) National
Marine Fisheries Service (NMFS). Table Cl-1 presents these geographic areas and the number of facilities included in each
NMFS region. The California region includes all estuary/tidal river and ocean facilities in California. The North Atlantic
region includes all estuary/tidal river and ocean facilities in Maine, New Hampshire, Massachusetts, Connecticut, and Rhode
Island. The Mid Atlantic region includes all estuary/tidal river and ocean facilities in New York, New Jersey, Pennsylvania,
Maryland, the District of Columbia, Delaware, and Virginia. The South Atlantic region includes all estuary/tidal river and
ocean facilities in North Carolina, South Carolina, Georgia, and the east coast of Florida. The Gulf of Mexico region includes
all estuary/tidal river and ocean facilities in Texas, Louisiana, Mississippi, and Alabama and the west coast of Florida. There
are no facilities in scope of Phase II regulation in Oregon or Washington State.
Cl-1
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§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter Cl: Regional Approach
Table Cl-1: Definition of Costal Regions
Region Geographic Area
California I California
North Atlantic 1 Maine, New Hampshire, Massachusetts,
1 Rhode Island, Connecticut
Mid Atlantic 1 New York, New Jersey, Delaware,
1 Maryland and Virginia
South Atlantic 1 North Carolina, South Carolina, Georgia,
1 East Florida
Gulf of Mexico 1 West Florida, Alabama, Missouri,
1 Louisiana, Texas
Total Number of Estuarine and Ocean Facilities"
Number of Estuarine
Facilities
o
o
20
44
15
21
108
Number of Ocean
Facilities
12
2
0
1
3
18
Total Number of
Facilities
20
22
44
16
24
126
a hi addition, there are 3 ocean facilities in Hawaii that are not included in the NMFS-defined regions.
Source: U.S. EPA analysis, 2004.
Cl-1.2 Great Lakes Region
The Great Lakes region includes all 56 facilities located on the shoreline of a Great Lake or on a waterway with open passage
to a Great Lake and within 30 miles of a lake in Minnesota, Wisconsin, Illinois, Michigan, Indiana, Ohio, Pennsylvania, and
New York. This definition is based on EPA's estimate of the extent of the spawning habitat of Great Lakes fish species,
including spawning habitat in rivers and tributaries of the Great Lakes. The distance each species may travel upstream to
spawn varies depending on both the species and the waterway, and is influenced by obstacles such as dams. However, after
consultation with local fisheries experts, EPA determined that inclusion of waters within 30 miles of the Great Lakes is likely
to encompass spawning areas of Great Lakes fishes. EPA used geographic information systems (GIS) to determine which
facilities are on a waterbody that has unobstructed passage to the Great Lakes and is within 30 miles of a Great Lake. Data
from the Lake Huron Project were used for areas encompassed by that project. For areas not covered by the Lake Huron
Project, this was done using the Enhanced Reach File 1 (ERF1) streams coverage (Alexander et al., 1999), the national dams
coverage (U.S. Army Corps of Engineers, 1999), and a basic US states coverage. No facilities drawing from other lakes or
reservoirs were included among the Great Lake facilities unless the waterbodies were connected to the Great Lakes.
Cl-1.3 Inland Region
The Inland region includes all 358 facilities located on freshwater rivers or streams and lakes or reservoirs, in all States, with
the exception of facilities located in the Great Lakes region (defined above in Section Cl-1.2). Of the 358 inland facilities,
244 are located on freshwater rivers or streams and 114 are located on lakes or reservoirs.
Cl-2 DEVELOPMENT OF REGIONAL !<&E ESTIMATES
For the case studies presented at proposal, EPA conducted species-specific analyses of I&E on a facility-specific basis. For
the regional studies, EPA evaluated species groups comprised of species with similar life histories. Groups were based on
biological family groups or the groupings used by NMFS for landings data. For example, various anchovy species were
grouped together as "anchovies." For the regional studies, EPA evaluated I&E rates for such species groups and developed a
regional total I&E estimate by summing results for each group. An exception was made for species of exceptionally high
commercial or recreational value (e.g., striped bass). Such species were evaluated as single species.
Aggregation of species into groups of similar species facilitated parameterization of the fisheries models used by EPA to
evaluate facility I&E monitoring data. Life history data are very limited for many of the species that are impinged and
entrained. As a result, there are many data gaps for individual species. To overcome this limitation, EPA used the available
life history data for closely related species to construct a single representative life history for a given species group. For
previously completed case studies, EPA used the species-specific life history information that was previously developed and
then aggregated I&E results for the species within a given group to obtain a group estimate. Appendices to the regional
Cl-2
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter Cl: Regional Approach
studies (Parts B-H of the Regional Study Document; U.S. EPA, 2004) provide tables of all life history data and data sources
used by EPA for the regional analyses.
EPA believes that the species group approach is appropriate for the national rulemaking given the many data limitations
associated with the lack of knowledge of specific fish life histories, particularly the growth and mortality rates of early life
stages. However, EPA is not endorsing this approach for analyses to support individual permits related to specific
waterbodies and facilities. At the individual permit level, more detailed information regarding the life histories of individual
species is often available and, when available, it should be used.
EPA converted annual I&E losses for each species group into (1) age 1 equivalents, (2) fishery yield, and (3) biomass
production foregone using standard fishery modeling techniques (Ricker, 1975; Hilborn and Walters, 1992; Quinn and
Deriso, 1999). Details of these methods are provided in Chapter A5 of the Regional Study Document. Chapter A6 discusses
data uncertainties. For all analyses, EPA assumed 100 percent entrainment mortality based on the analysis of entrainment
survival studies presented in Chapter A7 of Part A of the Regional Study Document.
To obtain regional I&E estimates, EPA extrapolated losses from facilities with I&E data to facilities without data. These
results were then summed to obtain a regional total. Average annual results for facilities with I&E data were averaged and
extrapolated on the basis of operational flow, in millions of gallons per day (MGD), to facilities without data. The
extrapolation method used, by region, is:
Total losses at case study facilities * Total flow in the region /Flow at case study facilities
These regional estimates are for 540 in-scope facilities that completed the 31 6(b) facility survey (excluding the three Hawaii
facilities). To obtain complete national I&E estimates EPA performed two additional steps. First, a set of statistical survey
weights was developed to estimate losses for 11 facilities that did not provide a completed 316(b) survey. Applying these
weights provides and estimate for all 551 in-scope facilities in the continental U.S. Second, EPA estimated losses at the three
in-scope facilities in Hawaii based on losses per unit flow in the other coastal regions. The weighting and the estimates of
losses in Hawaii provide loss estimates for all 554 in-scope facilities.
The regional analyses incorporated data for many more facilities than were evaluated for proposal, and thus improved the
basis for EPA's national benefits estimates.
Cl -3 DEVELOPMENT OF REGIONAL AND NATIONAL BENEFITS ESTIMATES
EPA considered the following benefit categories in its regional and national benefits analyses: recreational fishing benefits,
commercial fishing benefits, and non-use benefits. Non-use benefits include benefits from reduced I&E of forage species,
threatened and endangered species, and the non-landed portion of commercial and recreational species. The analysis of direct
use benefits for each region includes benefits to recreational anglers from improved fishing opportunities due to reduced
impingement and entrainment based on a region-specific valuation function and benefits from improved commercial fishery
yield. Details of the methods used to estimate commercial fishery benefits and recreational fishery benefits are provided in
Chapters A10 and Al lof the section 316(b) Phase II Regional Study Document (U.S. EPA, 2004), respectively. EPA also
explored methods for evaluating non-use benefits, although the Agency was not able to monetize nonuse values (for further
detail see Chapter A12 of the Regional Study Document).
Cl-3
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter Cl: Regional Approach
REFERENCES
Alexander, Richard B., John W. Brakebill, Robert E. Brew, and Richard A. Smith. 1999. Enhanced RF1 GIS Hydrological
Coverage. Downloaded from USGS website http://water.usgs.gov/GIS/metadata/usgswrd/erfl .html. 11/4/2002.
Hilborn, R. and C.J. Walters. 1992. Quantitative Fisheries Stock Assessment, Choice, Dynamics and Uncertainty. Chapman
and Hall, London and New York.
Quinn, T.J., II. and R.B. Deriso. 1999. Quantitative Fish Dynamics. Oxford University Press, Oxford and New York.
Ricker, W.E. 1975. Computation and interpretation of biological statistics offish populations. Fisheries Research Board of
Canada, Bulletin 191.
U.S. Army Corps of Engineers. 1 999. National Inventory of Dams, Water Control Infrastructure. Downloaded from website
http://data.geocomm.com/catalog/US/group7.html. 2/6/2003.
U.S. Environmental Protection Agency (U.S. EPA). 2004. Regional Studies for the Final Section 316(b) Phase II Existing
Facilities Rule. EPA-821-R-04-006. February 2004.
Cl-4
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§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter C2: Summary of Current Losses Due to I&E
Chapter C2: Summary of Current
Losses Due to I&E
INTRODUCTION
This chapter summarizes the results of the seven
regional analyses and presents the total monetary values
to the Final Section 316(b) Phase II Existing Facilities
Rule. For a discussion of the monetary values of the
national economic benefits expected from reducing
impingement and entrainment (I&E) losses, refer to
Chapter C3 of this document.
CHAPTER CONTENTS
C2-1 Summary of I&E Losses ......................... C2-1
- .. . , .. . - .. __„ - ..... , . , C2-2 Summary of Losses: Economic Value C2-2
of national baseline losses for all 554 facilities subject „ J
References C2-4
Appendix to Chapter C2 .............................. C2-5
Greater detail on the methods and data used in the regional analyses are provided in Chapter Cl of this EBA and in the
Regional Study Document (U.S. EPA, 2004): the methods used to estimate I&E are described in Chapter A5; the methods
used to estimate the value of the benefits of prevented I&E losses are described in Chapters A9 through A15; the results of the
regional analyses are presented in Parts B through H; and a summary of national benefits is provided in Part I.
C2-1 SUMMARY OF !<&E LOSSES
Using standard fishery modeling techniques, EPA constructed models that combined facility-derived impingement and
entrainment counts with relevant life history data to derive estimates of:
(1) age 1 equivalent losses (the number of individual organisms of different ages impinged and entrained by facility
intakes, expressed as age 1 equivalents1),
(2) foregone fishery yield (pounds of commercial harvest and numbers of recreational fish and shellfish that are not
harvested due to impingement and entrainment, including indirect losses of harvested species due to losses of forage
species), and
(3) foregone biomass production (the expected total amount of future growth of impinged and entrained organisms,
expressed as pounds, had they not been impinged or entrained).
Note that estimates of foregone fishery yield include the yield of harvested species that is lost due to losses of forage species
as well as direct losses of harvested species. The conversion of forage to yield contributes only a very small fraction to the
total foregone yield. Details of the methods used for these analyses are provided in Chapter A5 of the Regional Study
Document. For all analyses, EPA assumed 100 percent entrainment mortality based on the analysis of entrainment survival
studies presented in Chapter A7 of the Regional Study Document.
Table C2-1 presents EPA's estimates of the current I&E losses in each region. The table shows that total national losses of
age 1 equivalents for all 554 facilities equals 3.4 billion fish. Nationwide, EPA estimates that 165.0 million pounds of fishery
yield is foregone under current rates of I&E, and 717.1 million pounds of potential future biomass production is lost. The
1 Age 1 equivalent losses are calculated using the the Equivalent Adult Model (EAM), a method for expressing I&E
losses as an equivalent number of individuals at some other life stage. The method provides a convenient means of
converting losses offish eggs and larvae into units of individual fish and provides a standard metric for comparing losses
among species, years, and regions. For the section 316(b) regional case studies, EPA expressed I&E losses at all life stages as
an equivalent number of age 1 individuals. For a more detailed explanation, see Chapter A5 of the Regional Studies
document.
C2-1
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C2: Summary of Current Losses Due to I&E
table shows about half of all age 1 equivalent losses, or 1.7 billion fish, occur in the Mid-Atlantic region. The Mid-Atlantic
region also has the highest foregone fishery yield, followed by the Gulf of Mexico region and the California region. The
largest amount of foregone future biomass production, 289.1 million pounds, is attributable to I&E in the North Atlantic
region. More detailed discussion of the losses in each region are provided in Sections B through H of the Regional Study
Document.
Table C2-1: Total Current Annual Impingement and Entrainment, By Region"
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic"
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Age 1 Equivalents
(millions)
312.9
65.7
1,733.1
342.5
191.2
319.1
369.0
3,449.4
Foregone Fishery Yield
(million Ibs)
28.9
1.3
67.2
18.3
35.8
3.6
3.5
165.0
Biomass Production
Foregone
(million Ibs)
43.6
289.1
110.9
28.3
48.1
19.3
122.0
717.1
a Regional results are unweighted. National totals are sample-weighted and include Hawaii.
b EPA estimated losses in the South Atlantic by extrapolating results from the Mid-Atlantic and Gulf regions.
Source: U.S. EPA analysis, 2004.
C2-2 SUMMARY OF LOSSES: ECONOMIC VALUE
In total, EPA found 554 facilities to be in scope of the final section 316(b) Phase II rule. However, the regional estimates of
baseline losses reflect only the 540 in-scope facilities that completed 316(b) questionnaires (excluding three facilities in
Hawaii). In order to calculate national losses for all 554 facilities, including the three facilities located in Hawaii and the
eleven other facilities that did not complete the questionnaire, EPA extrapolated losses from other facilities and regions, based
on intake flows and a set of statistical weights. See Chapter II of the Regional Studies document for a more detailed
discussion of the extrapolation procedure.
As mentioned in Chapter Al 2, EPA estimated non-use benefits only qualitatively. As a result, the Agency was not able to
directly monetize the value of losses for 98.2% of the age-one equivalent losses of all commercial, recreational, and forage
species for the 316(b) Phase II regulation. This means that the estimates of baseline losses presented in this section represent
the losses associated with less than 2% of the total age-one equivalents lost due to impingement and entrainment by cooling
water intake structures (CWISs) and should be interpreted with caution. See Chapter A9 of the Regional Case Study
document for a detailed description of the ecological benefits from reduced I&E.
Table C2-2 presents EPA's estimates of the value of annual baseline I&E losses at in-scope facilities. The table shows that
the total national value of fishery resources lost to I&E includes $23.2 million in commercial fishing benefits, $189.4 million
in recreational fishing benefits, and an unknown amount in non-use benefits ($2002, discounted at three percent). The total
use value of fishery resources lost is approximately $212.5 million per year. Total commercial and recreational losses are
greatest in the Mid-Atlantic region, at $8.4 million and $89.6 million, respectively, for a total use value of $97.9 million in the
Mid-Atlantic region. More detailed discussions of the value of the losses in each region are provided in Sections B through H
of the Regional Studies document. Additionally, as a sensitivity analysis, the Appendix to this chapter presents the value of
baseline losses evaluated at a seven percent discount rate.
C2-2
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C2: Summary of Current Losses Due to I&E
Table C2-2: Summary of Monetary Values of Current Impingement and Entrainment Losses
(millions; $2002; 3% discount rate)
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Use Value of I&E Losses
„ ..„.,. Recreational
Commercial Fishing Total Use Value
$6.1 $7.5 $13.6
$0.5 $4.9 $5.4
$8.4 $89.6 $97.9
$1.9 $30.0 $32.0
$4.1 $12.4 $16.5
$1.0 $29.4 $30.4
n/a $10.6 $10.6
$23.2 $189.4 $212.5
Non-Use Value of
I&E Losses"
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Total Value of
I&E Losses
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
a Regional numbers are unweighted. National totals are sample-weighted and include Hawaii.
b EPA estimated non-use values only qualitatively.
Source: U.S. EPA analysis, 2004.
C2-3
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter C2: Summary of Current Losses Due to I&E
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2004. Regional Studies for the Final Section 316(b) Phase II Existing
Facilities Rule. EPA-821-R-04-006. February 2004.
C2-4
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C2: Summary of Current Losses Due to I&E
Appendix to Chapter C2
This appendix summarizes the monetary values of current I&E losses using a 7 percent social discount rate instead of a 3
percent rate. The results of this sensitivity analysis are presented in Table C2-A-1.
Table C2-A-1: Summary of Monetary Values of Current I&E Losses
(millions; $2002; 7% discount rate)
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Use Value of I&E Losses
„ ..„.,. Recreational
Commercial Fishing „ , . Total Use Value
" Fishing
$4.4 $6.1 $10.5
$0.4 $4.3 $4.7
$7.3 $82.5 $89.9
$1.7 $28.1 $29.8
$3.4 $11.2 $14.6
$0.9 $26.7 $27.6
n/a $9.5 $9.5
$18.9 $172.9 $191.8
Non-Use Value of
I&E Losses"
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Total Value of
I&E Losses
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
a Regional numbers are unweighted. National totals are sample-weighted and include Hawaii.
b EPA estimated non-use values only qualitatively.
Source: U.S. EPA analysis, 2004.
C2-5
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter C2: Summary of Current Losses Due to I&E
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C2-6
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§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C3: Monetized Benefits
Chapter £3: Monetized Benefits
INTRODUCTION
This chapter summarizes the regional and national benefits
of the Final Section 316(b) Phase II Existing Facilities Rule.
For a discussion of regional and national baseline losses, see
Chapter C2 of this document.
Greater detail on the methods and data used in the regional
analyses are provided in Chapter Cl of this EBA and in the
Regional Study Document (U.S. EPA, 2004): the methods used to estimate impingement and entrainment (I&E) are described
in Chapter A5; the methods used to estimate the value of the benefits of prevented I&E losses are described in Chapters A9
through Al 5; the results of the regional analyses are presented in Parts B through H; and a summary of national benefits is
provided in Part I.
CHAPTER CONTENTS
C3-1 Expected Reductions in I&E C3-1
C3-2 Regional and National Social Benefits C3-2
References C3-4
Appendix to Chapter C3 C3-5
C3-1 EXPECTED REDUCTIONS IN !<&E
In order to estimate the benefits of the final Phase II rule, EPA estimated the percentage reductions in I&E that will be
achieved by implementing the final rule at each in-scope facility. These estimates reflect 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 I&E that
the Agency believes would result from technologies adopted to comply with the rule. EPA used these estimates to calculate
the average reduction in I&E expected in each region.
Table C3-1 presents average regional expected reductions in I&E. The table also presents estimates of regional and national
prevented I&E losses, expressed as (1) age-one equivalents lost, (2) fishery yield foregone, and (3) biomass production
foregone. The table shows that, at the 554 national in-scope facilities, the final rule reduces age-one equivalent losses by 1.4
billion fish, prevents 64.9 million pounds of fishery yield from being lost, and prevents 217.1 million pounds of future
biomass production from being lost. The expected reductions vary across the regions. Facilities in the Gulf of Mexico are
expected to make the largest average percentage reductions in impingement (59.0 percent), and facilities in the Mid-Atlantic
are expected to make the largest average percentage reductions in entrainment (47.9 percent). More than half of the age-one
equivalent losses prevented by the final rule, 846.4 million fish, are attributable to facilities in the Mid-Atlantic region. The
final rule prevents the mo st losses of fishery yield in the Mid-Atlantic region, and prevents the mo st losses of future biomass
production in the North Atlantic region. More detailed discussions of regional benefits are provided in Sections B through H
of the Regional Study Document.
C3-1
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C3: Monetized Benefits
Table C3-1: Expected Reduction in L&E Under the Final Rule, by Region
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Expected Reductions in I&E Under Final Rule
Impingement
30.9%
43.8%
53.5%
43.7%
59.0%
51.5%
47.2%
n/a
Entrainment
21.0%
29.1%
47.9%
17.1%
31.9%
40.1%
16.4%
n/a
Age-One Equivalents
(millions)
66.4
19.3
846.4
76.7
89.6
159.5
116.8
1,420.2
Foregone Fishery Yield
(million Ibs)
6.1
0.4
34.3
5.3
13.8
1.7
1.1
64.9
Biomass Production
Foregone
(million Ibs)
9.2
84.3
54.7
6.3
16.5
8.5
20.9
217.1
a Regional estimates are unweighted. National totals are sample-weighted and include Hawaii. Hawaii benefits are calculated based
on average expected reductions per MGD in the North Atlantic, Mid Atlantic, Gulf of Mexico, and California regions, and the total
intake flow in Hawaii.
Source: U.S. EPA analysis, 2004.
C3-2 REGIONAL AND NATIONAL SOCIAL BENEFITS
In total, EPA found 554 facilities to be in scope of the final Phase II rule. However, the regional estimates of benefits under
the final rule reflect only the 540 in-scope facilities that completed section 316(b) questionnaires (excluding three facilities in
Hawaii). In order to calculate national benefits for all 554 facilities, including the three facilities located in Hawaii and the
eleven other facilities that did not complete the questionnaire, EPA extrapolated benefits from other facilities and regions,
based on intake flows and a set of statistical weights. See Chapter II of the Regional Studies document for a more detailed
discussion of this extrapolation procedure.
As mentioned in Chapter A12, EPA estimated non-use benefits only qualitatively. As a result, the Agency was not able
monetize benefits for 98.2% of the age-one equivalent losses of all commercial, recreational, and forage species for the
section 316(b) Phase II regulation. This means that the estimates of benefits presented in this section represent the benefits
associated with less than 2% of the total age-one equivalents lost due to impingement and entrainment by cooling water intake
structures (CWISs) and should be interpreted with caution. See Chapter A9 of the Regional Case Study document for a
detailed description of the ecological benefits from reduced I&E.
Table C3-2 shows EPA's estimates of the monetary value of the I&E reductions presented in Table C3-1. The table shows
that the final rule results in national use benefits of $82.9 million per year ($2002, discounted at three percent) and an
unknown amount of non-use benefits. Recreational fishing benefits, which are $79.3 million, make up the majority of total
national use benefits. National commercial benefits are relatively small, at $3.5 million. The final rule is expected to
generate the largest commercial and recreational benefits in the Mid-Atlantic region ($1.7 million and $43.4 million,
respectively), resulting in total use benefits in the Mid-Atlantic region of $45.0 million. More detailed discussions of regional
benefits are provided in Sections B through H of the Regional Study Document. Additionally, as a sensitivity analysis, the
Appendix to this chapter presents the value of the benefits of the final rule evaluated at a seven percent discount rate.
C3-2
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C3: Monetized Benefits
Table C3-2: Summary of Social Benefits (millions; $2002; 3% discount rate)"
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Use Benefits of I&E Reductions
Commercial Recreational Total Use
Fishing Fishing Benefits
$0.5 $2.5 $3.0
$0.1 $1.4 $1.4
$1.7 $43.4 $45.0
$0.2 $6.9 $7.1
$0.7 $6.2 $6.9
$0.2 $14.0 $14.1
n/a $3.0 $3.0
$3.5 $79.3 $82.9
Non-Use Benefits of
I&E Reductions'
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Total Benefits of
I&E Reductions
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
a Discounted to account for lag in implementation and lag in time required for fish lost to I&E to reach a harvestable age.
b Regional numbers are unweighted. National totals are sample-weighted and include Hawaii.
° EPA estimated non-use values only qualitatively.
Source: U.S. EPA analysis, 2004.
C3-3
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter C3: Monetized Benefits
REFERENCES
U.S. Environmental Protection Agency (U.S. EPA). 2004. Regional Studies for the Final Section 316(b) Phase II Existing
Facilities Rule. EPA-821-R-04-006. February 2004.
C3-4
-------
§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits
Chapter C3: Monetized Benefits
Appendix to Chapter C3
This appendix summarizes the monetary benefits of the final rule using a seven percent social discount rate instead of a three
percent rate. The results of this sensitivity analysis are presented in Table C3-A-1.
Table C3-A-1: Summary of Social Benefits (millions; $2002; 7% discount rate)"
Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
Total (weighted)
Use Benefits of I&E Reductions
Commercial Recreational Total Use
Fishing Fishing Benefits
$0.4 $1.9 $2.3
$0.1 $1.2 $1.2
$1.5 $38.5 $39.9
$0.2 $6.2 $6.4
$0.6 $5.5 $6.2
$0.2 $12.2 $12.4
n/a $2.6 $2.6
$3.0 $70.0 $72.9
Non-Use Benefits of
I&E Reductions'
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Total Benefits of
I&E Reductions
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
a Discounted to account for lag in implementation and lag in time required for fish lost to I&E to reach a harvestable age.
b Regional numbers are unweighted. National totals are sample-weighted and include Hawaii.
° EPA estimated non-use values only qualitatively.
Source: U.S. EPA analysis, 2004.
C3-5
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§ 316(b) Phase II Final Rule - EBA, Part C: National Benefits Chapter C3: Monetized Benefits
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C3-6
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Chapter Dl: Comparison of Costs and
Benefits
INTRODUCTION
This chapter summarizes total private costs, develops social
costs, and compares total social costs to total monetized
benefits of the final rule at the national level. This chapter
also presents a comparison of benefits and costs at the
regional level.
Table Dl-1 shows compliance action assumptions for the
final rule based on each facility's currently installed
technologies , 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 of this EBA presents additional information on
compliance responses under the final rule.
CHAPTER CONTENTS
Dl-l Social Costs Dl-1
Dl-2 Summary of National Benefits and Social Costs Dl-3
Dl-3 Regional Comparison of Benefits and Social
Costs forthe Final Rule Dl-4
Dl-3.1 Benefit-Cost Analysis Dl-4
D1 -3.2 Cost per Age-One Equivalent Fish Saved -
Cost-Effectiveness Analysis Dl-5
Dl-3.3 Break-Even Analysis Dl-6
Glossary Dl-7
References Dl-8
Appendix to Chapter Dl Dl-9
Table Dl-1: Number of Facilities by Compliance Action"
Facility Compliance Action
No compliance action15
Impingement controls only
Impingement and entrainment controls
Flow reduction technology
Total
Final Rule
200
149
205
0
554
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.
b These facilities already meet their compliance requirements. 75 facilities have a cooling tower in the
baseline.
Source: U.S. EPA analysis, 2004.
bl-1 SOCIAL COSTS
This section develops EPA's estimates of the costs to society associated with the final 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
Dl-1
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
firms. The analyses therefore explicitly consider the tax deducibility 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 final regulation, EPA relied first on the estimated costs to facilities for the
labor, equipment, material, and other economic resources needed to comply with the final 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 construction outages
- 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 for 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 final regulation. 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 final Phase II rule are $249.5 million,
based on a seven percent discount rate (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 $385.1 million. EPA estimates that state implementation
costs for the final rule are $4.0 million annually and that federal implementation costs are approximately $64,000. The
estimated total social costs of the Final Phase II Existing Facilities Rule are therefore $389.2 million, based on a seven
percent discount rate.
Table Dl-2 summarizes the total private and social costs of the final rule, discounted at a seven percent rate. As a sensitivity
analysis, the Appendix to this chapter presents total social costs discounted at a three percent discount rate.
1 Costs incurred by government facilities and cooperatives are not adjusted for taxes, since these facilities are not subject to income
taxes.
Dl-2
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Table Dl-2: Total Private and Social Costs of Compliance by Option (millions; $2002)
Option
Final Rule
Alternative less stringent
requirements based on both
costs and benefits are allowed.
Total Private
Compliance Costs
to Facilities
(Post-tax)
$249.5
Social Costs"
Pre-Tax
Compliance Costs
to Facilities
$385.1
State
Implementation
Costs
$4.0
Federal
Implementation
Costs
$0.06
Total
Social
Costs
$389.2
a All costs were annualized and discounted using a 7 percent rate.
Source: U.S. EPA analysis, 2004.
bl -2 SUMMARY OF NATIONAL BENEFITS AND SOCIAL COSTS
The summary of national benefit estimates for the final rule is reported in Chapter C3: Monetized Benefits. Table Dl -3
presents EPA's national social cost and benefit estimates for the final Phase II rule. The benefits estimates in Table D1-3
were discounted using a 3 percent social discount rate (as a sensitivity analysis, the Appendix to this chapter presents total
social benefits discounted at a seven percent discount rate). The table shows that estimated use benefits of the final rule are
less than the social costs by $306 million. As noted in Chapter C3, the use benefits estimate includes monetized benefits to
commercial and recreational fishing; however, since non-use benefits were estimated only qualitatively, the net benefits
estimate presented here does not include non-use benefits. EPA notes that the Agency was not able to directly monetize
benefits for 98.2% of the age-one equivalent losses of all commercial, recreational, and forage species for the section 316(b)
Phase II regulation. This means that the benefits estimate used in this analysis represents the benefits associated with less than
2% of the total age-one equivalents lost due to impingement and entrainment by cooling water intake structures (CWIS) and
should be interpreted with caution.
Table Dl-3: Total National Social
Option
Final Rule
Alternative less stringent requirements based on
both costs and benefits are allowed.
Costs, Benefits, and Net Benefits b>
Total Social Benefits"
Use Non-use Total
Benefits Benefits Benefits
$82.9 n/a n/a
Option (millions
Total Social
Costs
$389.2
; $2002)"
Net Benefits
Based on Use
Benefits'
($306.3)
a Benefits were discounted using a 3 percent social discount rate; costs were annualized and discounted using a 7 percent rate.
b Use benefits presented in this table include commercial and recreational use benefits. Because EPA did not estimate non-use
benefits quantitatively, the monetary value of total benefits could not be calculated.
° The net benefits measure presented in this table is calculated by subtracting total social costs from total use benefits. This
calculation is based on a comparison of apartial measure of social benefits with a complete measure of social costs and should be
interpreted with caution.
Source: U.S. EPA analysis, 2004.
Dl-3
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
bl-3 REGIONAL COMPARISON OF BENEFITS AND SOCIAL COSTS FOR THE FINAL RULE
This section presents three measures that compare the monetized benefits and costs of the final rule at the regional level: (1) a
benefit-cost analysis, including net benefits and benefit-cost ratio; (2) an analysis of the costs per age-one equivalent fish
saved (equivalent to a cost-effectiveness analysis); and (3) a break-even analysis of the minimum non-use benefits required
for total annual benefits to equal total annualized costs, on a per household basis. For each measure, benefits were discounted
using a 3 percent social discount rate, while costs were annualized and discounted using the OMB Circular rate of 7 percent.
EPA also conducted a sensitivity analysis, using a 7 percent discount rate for benefits and a 3 percent discount rate for costs,
which is presented in the Appendix to this chapter. Each comparison measure is presented by study region.
bl-3.1 Benefit-Cost Analysis
The benefit-cost analysis compares total annualized monetized use benefits of the final rule to total social costs. The cost
estimates include costs of compliance to facilities subject to the final rule as well as administrative costs incurred by state and
local governments and by the federal government. As mentioned above, the benefits estimates include monetized benefits to
commercial and recreational fishing, but do not include non-use benefits, which may be large (see Chapter C3 of this
document for detailed benefits results). Thus, this analysis involves a comparison of a partial measure of social benefits with
a complete measure of social costs and should be interpreted with caution. Table Dl -4 below summarizes the benefits and
costs of the final rule and presents the net benefits and the benefit-cost ratios, by study region.
Table
Study Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
Dl-4: Summary of Annualized Social
Total Social Benefits'
Use Non-use Total
Benefits Benefits Benefits
$3.0 n/a n/a
$1.4 n/a n/a
$45.0 n/a n/a
$7.1 n/a n/a
$6.9 n/a n/a
$14.1 n/a n/a
$3.0 n/a n/a
$82.9 n/a n/a
Benefits and Cc
Total Social
Costs"
$31.7
$13.3
$62.6
$9.0
$22.8
$58.7
$170.1
$389.2
sts (millions; $2002)°
:
:
:
Net Benefits i Benefit-Cost Ratio
(Based on Use (Based on Use
Benefits)' Benefits)'
($28.7) 0.09
($11.9) 0.11
($17.5) 0.72
($1.9) 0.79
($15.9) 0.30
($44.6) 0.24
($167.2) 0.02
($306.3) 0.21
a Benefits were discounted using a 3 percent social discount rate; costs were annualized and discounted using a 7 percent rate.
b Regional benefit and cost estimates are unweighted; total national estimates are sample-weighted and include costs and benefits for
Hawaii.
° Use benefits presented in this table include commercial and recreational use benefits. Because EPA did not estimate non-use
benefits quantitatively, the monetary value of total benefits could not be calculated.
d U.S. total annualized costs include $4.0 million in State and local administrative costs, and $0.06 in Federal administrative costs,
that cannot be attributed to individual study regions.
° The net benefits measure presented in this table is calculated by subtracting total social costs from total use benefits. The benefit-
cost ratio is calculated by dividing total use benefits by total social costs. These calculations are based on a comparison of a partial
measure of social benefits with a complete measure of social costs and should be interpreted with caution.
Source: U.S. EPA analysis, 2004.
Dl-4
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Table Dl-4 shows that the estimated total use benefits of the final rule are not projected to exceed total social costs in any of
the regions. Without accounting for non-use values, the net social costs of the final rule are smallest in the South Atlantic
region ($1.9 million) and largest in the Inland region ($167.2 million). Benefit-cost ratios are highest in the Mid-Atlantic and
South Atlantic regions (0.7 and 0.8, respectively) and lowest in the Inland, California, and North Atlantic regions (0.02, 0.09,
and 0.11 respectively). At the national level, EPA projects total social costs to exceed total use benefits, resulting in net
benefits of-$306.3 million and a benefit-cost ratio of 0.2.
The Agency points out that EPA has produced a comparison of complete costs and incomplete benefits in the benefits cost
analysis of the final section 316(b) regulation. A comparison of complete costs and incomplete benefits does not provide an
accurate picture of net benefits to society. The regulation is expected to provide many benefits that were not accounted for in
the benefits analysis by reducing impingement and entrainment (I&E) losses offish, shellfish, and other aquatic organisms
and, as a result, increase the numbers of individuals present, increase local and regional fishery populations (a subset of which
was accounted for in the benefits analysis), and ultimately contribute to the enhanced environmental functioning of affected
waterbodies (rivers, lakes, estuaries, and oceans) and associated ecosystems (see Chapter A9 of the Regional Case Study
document for a detailed description of the ecological benefits from reduced I&E). The Agency believes that the economic
welfare of human populations is expected to increase as a consequence of the improvements in fisheries and associated
aquatic ecosystem functioning due to the final section 316(b) Phase II regulation.
bl-3.2 Cost per Age-One Equivalent Fish Saved - Cost-Effectiveness Analysis
EPA also analyzed the cost per organism saved as a result of compliance with the final rule. This analysis estimates the cost-
effectiveness of the rule, by study region. Organisms saved are measured as "age-one equivalents" (the number of individuals
of different ages impinged and entrained by facility intakes expressed as age-one). The costs used in this comparison are the
annualized social costs of the final rule.
Table D1-5 below shows that the estimated cost per age-one equivalent ranges from seven cents in the Mid Atlantic region to
$1.46 in the Inland region. At the national level, the estimated cost is 27 cents per age-one equivalent saved.
Table Dl-5: Annualized Cost per
Study Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
Total Social Costs
(millions; $2002)
$31.7
$13.3
$62.6
$9.0
$22.8
$58.7
$170.1
$389.2
Age-one Equivalent Saved
Age-One Equivalents
(millions)
66.4
19.3
846.4
76.7
89.5
159.5
116.8
1,420
Cost/ Age-One Equivalent
$0.48
$0.69
$0.07
$0.12
$0.25
$0.37
$1.46
$0.27
a Regional benefit and cost estimates are unweighted; total national estimates are sample-weighted and include Hawaii.
b U.S. total annualized costs include $4.0 million in State and local administrative costs, and $0.06 in Federal administrative costs,
that cannot be attributed to individual study regions.
Source: U.S. EPA analysis, 2004.
2 It should be noted that the national numbers include costs for the three facilities in Hawaii but do not include any benefits that may
result from their compliance with the final rule.
Dl-5
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
bl-3.3 Break-Even Analysis
Estimating non-use values is an extremely challenging and uncertain exercise, particularly when primary research using stated
preference methods is not a feasible option (as is the case for this rulemaking). In Chapter A12 of the Regional Analysis
Document for the Final Section 316(b) Existing Facilities Rule (U.S. EPA, 2004), EPA described possible alternative
approaches for developing non-use benefit estimates based on benefits transfer and associated methods. Due to the
uncertainties of providing estimates of the magnitude of non-use values associated with the final rule, this section provides an
alternative approach of evaluating the potential magnitude of non-use values. The approach used here applies a "break-even"
analysis to identify what non-use values would have to be in order for the final rule to have benefits that are equal to costs.
The break-even approach uses EPA's estimated commercial and recreational use benefits for the rule and subtracts them from
the estimated annual compliance costs incurred by facilities subject to the final rule. The resulting value enables one to work
backwards to estimate what non-use values would need to be (in terms of willingness to pay per household per year) in order
for total annual benefits to equal annualized costs. Table Dl-6 below provides this assessment for the seven study regions.
Table Dl-6: Implicit Uncaptured Benefits - Break-Even Analysis (millions; $2002)"
Study Region"
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
Use Benefits
$3.0
$1.4
$45.0
$7.1
$6.9
$14.1
$3.0
$82.9
Total Social
Costs'
$31.7
$13.3
$62.6
$9.0
$22.8
$58.7
$170.1
$389.2
Non-use Benefits
Necessary to Break
Even"
$28.7
$11.9
$17.5
$1.9
$15.9
$44.6
$167.2
$306.3
Number of
Households"
8,093,185
3,932,827
9,626,354
3,817,567
5,421,104
8,628,825
20,908,109
60,427,971
Break-Even WTP
per Household
$3.55
$3.02
$1.82
$0.50
$2.92
$5.17
$8.01
$5.07
a Benefits were discounted using a 3 percent social discount rate; costs were annualized and discounted using a 7 percent rate.
b Regional benefit and cost estimates are unweighted; total national estimates are sample-weighted.
° U.S. total annualized costs include $4.0 million in State and local administrative costs, and $0.06 in Federal administrative costs,
that cannot be attributed to individual study regions.
d The non-use benefits category in this table may include some categories of use values that were not taken into account by the
recreation and commercial fishing analyses.
° Includes anglers fishing in the region and households in abutting counties (BLS, 2000).
Source: U.S. EPA analysis, 2004.
As shown in Table Dl-6 above, for total annual benefits to equal total annualized costs, non-use values per household would
have to be between $0.50 in the Gulf of Mexico region and $8.01 in the Inland region. This estimate assumes that only
anglers fishing in the region and households in abutting counties have non-use values for the affected resources. At the
national level, the annual non-use willingness to pay per household would have to be $5.07 for total annual benefits to equal
total annualized costs.
Dl-6
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§ 316(b) Phase II Final Rule - 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 final rule. Social costs do not include costs that are
transfers among parties but that do not represent a net cost overall.
Dl-7
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
REFERENCES
U.S. Department of Commerce, Bureau of the Census, Bureau of Labor Statistics (BLS). 2000. "Summary File 1."
http://www.census.gov/Press-Release/www/2001/sumfilel .html.
U.S. Environmental Protection Agency (U.S. EPA). 2004. Regional Studies for the Final Section 316(b) Phase II Existing
Facilities Rule. EPA-821-R-04-006. February 2004.
Dl-8
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
Appendix to Chapter Dl
This appendix presents the results of the benefit-cost analysis (Section Dl-3.1 above) and the break-even analysis (Section
Dl-3.2 above) but using a seven percent discount rate for benefits, instead of a three percent rate, and using a three percent
discount rate for costs, instead of seven percent. The results of this sensitivity analysis are presented in the following tables.
In the portions of this sensitivity analysis that present a three percent rate for costs, EPA discounted the total costs of the rule
at three percent but annualized them at seven percent. The three percent rate is the social discount rate that is used to
determine the total present value to society of the regulatory costs and benefits incurred in the future. The seven percent
annualization rate reflects the real cost of capital to complying facilities.
Dl-9
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Table Dl-A-1: Summary of Annualized Social Benefits and Costs (millions; $2002)
Study Region"
Total Social Benefits"
Use
Benefits
Bene
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
$3.0
$1.4
$45.0
$7.1
$6.9
$14.1
$3.0
$82.9
Bene
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
$2.3
$1.2
$39.9
$6.4
$6.2
$12.4
$2.6
$72.9
Non-use
Benefits
fits discounter
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
fits discountet
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Total
Benefits
Total Social
Costs"
Net Benefits
(Based on Use
Benefits)"
at 3 percent; costs discounted at 3 percent.
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
$33.1
$14.9
$69.1
$10.1
$25.4
$66.1
$183.7
$426.0
($30.1)
($13.5)
($24.0)
($3.0)
($18.5)
($51.9)
($180.7)
($343.1)
at 7 percent; costs discounted at 7 percent.
F
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
$31.7
$13.3
$62.6
$9.0
$22.8
$58.7
$170.1
$389.2
($29.4)
($12.1)
($22.6)
($2.6)
($16.6)
($46.4)
($167.6)
($316.2)
Benefit-Cost Ratio
(Based on Use
Benefits)"
0.09
0.10
0.65
0.70
0.27
0.21
0.02
0.19
0.07
0.09
0.64
0.71
0.27
0.21
0.02
0.19
a Regional benefit and cost estimates are unweighted; total national estimates are sample-weighted and include costs and benefits for
Hawaii.
b Use benefits presented in this table include commercial and recreational use benefits. Because EPA did not estimate non-use
benefits quantitatively, the monetary value of total benefits could not be calculated.
° U.S. total annualized costs include $4.0 million in State and local administrative costs, and $0.06 in Federal administrative costs,
that cannot be attributed to individual study regions.
d The net benefits measure presented in this table is calculated by subtracting total social costs from total use benefits. The benefit-
cost ratio is calculated by dividing use benefits by total social costs. These calculations are based on a comparison of a partial
measure of social benefits with a complete measure of social costs and should be interpreted with caution.
Source: U.S. EPA analysis, 2004.
Dl-10
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis
Dl: Comparison of National Costs and Benefits
Table Dl-A-2: Implicit Uncaptured Benefits - Break-Even Analysis (millions; $2002)"
Study Region"
Use Benefits
Benefi
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
$3.0
$1.4
$45.0
$7.1
$6.9
$14.1
$3.0
$82.9
Benefi
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
U.S. Total
$2.3
$1.2
$39.9
$6.4
$6.2
$12.4
$2.6
$72.9
Annualized Social
Costs"
ts discounted at 3 per
$33.1
$14.9
$69.1
$10.1
$25.4
$66.1
$183.7
$426.0
ts discounted at 7 per
$31.7
$13.3
$62.6
$9.0
$22.8
$58.7
$170.1
$389.2
Uncaptured Benefits
Necessary to Break
Even
cent; costs discounted at
$30.1
$13.5
$24.0
$3.0
$18.5
$51.9
$180.7
$343.1
cent; costs discounted at
$29.4
$12.1
$22.6
$2.6
$16.6
$46.4
$167.6
$316.2
Number of
Households"
3 percent.
8,093,185
3,932,827
9,626,354
3,817,567
5,421,104
8,628,825
20,908,109
60,427,971
7 percent.
8,093,185
3,932,827
9,626,354
3,817,567
5,421,104
8,628,825
20,908,109
60,427,971
Break-Even WTP
per Household
$3.72
$3.43
$2.50
$0.80
$3.42
$6.02
$8.64
$5.68
$3.63
$3.08
$2.35
$0.68
$3.06
$5.37
$8.01
$5.23
a Regional benefit and cost estimates are unweighted; total national estimates are sample-weighted.
b U.S. total annualized costs include $4.0 million in State and local administrative costs, and $0.06 in Federal administrative costs,
that cannot be attributed to individual study regions.
° Includes anglers fishing in the region and households in abutting counties (BLS, 2000).
Source: U.S. EPA analysis, 2004.
Dl-11
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§ 316(b) Phase II Final Rule - EBA, Part D: National Benefit-Cost Analysis Dl: Comparison of National Costs and Benefits
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