United States Off ice of December 1982
rnviron-nental Protection Policy Analysis
Agency Washington DC 20460
SEPA Environmental Regulations
and the
Electric Utility Industry
An Integrated Overview
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\ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
* WASHINGTON, D.C. 20460
pro^°
APR 2 5 1983
OFFICE OF
POLICY AND RESOURCE MANAGEMENT
Alexandra B. Smith, Director
Air & Waste Management Division
Region X
1200 6th Avenue
Seattle, WA 98101
Dear Mr. Smith:
We are pleased to send you a copy of Environmental Regulations
and the Electric Utility Industry—An Integrated Overview. This
study, prepared by Temple, Barker, and Sloane, Inc. for EPA, assesses
the cumulative economic and financial impacts of EPA's regulations
on the electric utility industry.
Electric utilities and their customers have borne a major
burden for protecting and improving the quality of our national
environment. In 1980 utilities spent over $8.4 billion to comply
with EPA's air regulations as well as those governing water and
solid waste. This translated into a charge of $2.36 for pollution
control on the average residential customer's $35.94 monthly bill.
These costs were incurred during a period when rapidly escalating
fuel and construction expenses led to major increases in the price
of electricity and, indirectly, to a marked decline in electric
utilities' financial condition, as evidenced by wholesale declines
in bond ratings and by stock prices well below their book values.
This study has four major components:
o A "national" analysis of total utility industry
expenditures for pollution control.
o A unit-by-unit examination, drawing on an extensive
data base, of environmental compliance strategies,
costs, and plans as reported by utilities for over
1,600 generating units. The findings are presented
in "unit-category" and regional analyses.
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APR 2 8 1983
Ai m C» inh i a.riLS 01V
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ENVIRONMENTAL REGULATIONS AND
THE ELECTRIC UTILITY INDUSTRY
AN INTEGRATED OVERVIEW
i
FINAL REPORT PREPARED FOR
U. S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF POLICY ANALYSIS
ENERGY POLICY DIVISION
PREPARED BY
TEMPLE, BARKER & SLOANE, INC.
-------
- 2 -
o A set of case studies intended to address the issue
of indirect costs and uncover some of the subtle
influences of environmental requirements on utility
decisionmaking.
o A description of the environmental regulations which
affect electric utilities.
Sincerely
J
Associate Administrator
for Policy and Resource Management
-------
PREFACE
The information in this document has been funded wholly
or in part by the United States Environmental Protection
Agency (EPA) under assistance agreements 68-01-5845 and 68-01-
5771 to Temple, Barker & Sloane, Inc. (TBS), 33 Hayden Avenue,
Lexington, Massachusetts 02173. It has been subject to the
Agency's peer and administrative review, and it has been
approved for publication as an EPA document. Mention of trade
names or commercial products does not constitute endorsement
or recommendation for use.
The report incorporates modifications—reflecting the
reviews and comments of EPA and others—to the draft report
issued by EPA under the same title in July 1981. The basic
findings presented in the draft report have not changed.
TBS wishes to express its gratitude to the many
organizations and individuals who contributed to this study*
If you have any questions regarding this study, please
contact the EPA project officer, Rob Brenner, at (202) 382-
2772.
-------
CONTENTS
TOPICAL GUIDE
I. INTRODUCTION AND KEY FINDTncs
INTRODUCTION ~
KEY FINDINGS
II. AN OVERVIEW OF ENVIRONMENTAT. PttnrTT.&TT^NR
AFFECTING ELECTRIC UTILITIES—
INTRODUCTION
THE CLEAN AIR ACT AND REGULATIONS
IMPLEMENTING THE ACT
THE CLEAN WATER ACT AND REGULATIONS
IMPLEMENTING THE ACT
REGULATIONS CONTROLLING THE DISPOSAL OF
SOLID WASTES
INTERACTIONS AMONG ENVIRONMENTAL
REGULATIONS
III. THE EFFECTS OF ENVIRONMENTAL REGULATIONS
ON THE OPERATIONS AND PLANS OF ELECTRIC
UTILITIES-"
INTRODUCTION AND MAJOR FINDINGS
RESEARCH METHODOLOGY
THE BUSINESS ENVIRONMENT OF ELECTRIC
UTILITIES
EFFECTS OF ENVIRONMENTAL REGULATIONS
ON EXISTING POWERPLANTS
ELECTRIC UTILITY CAPACITY PLANNING AND
ENVIRONMENTAL REGULATIONS
UTILITY RECOMMENDATIONS FOR IMPROVING
ENVIRONMENTAL REGULATIONS
IMPLICATIONS FOR THE QUANTITATIVE ANALYSIS
1
1-1
1-1
1-5
II-l
II-l
II-2
11-13
11-20
11-24
III-l
III-l
III-5
III-6
111-13
111-22
111-40
111-46
-------
CONTENTS
(continued)
17' EFFECTS OF ENVIRONMENTAL REGULATIONS ON
ELECTRIC UTILITY UNITS IV-1
INTRODUCTION AND MAJOR FINDINGS IV-1
RESEARCH METHODOLOGY AND DATA SOURCES IV-12
UNIT COMPLIANCE STRATEGIES IV-15
1979 UNIT-LEVEL COSTS IV-26
FUTURE UNIT-LEVEL COMPLIANCE STRATEGIES
AND" COSTS IV-47
COST-EFFECTIVENESS ANALYSIS IV-52
V. REGIONAL EFFECTS OF ENVIRONMENTAL
REGULATIONS ON THE ELECTRIC
UTILITY INDUSTRY V-l
INTRODUCTION AND MAJOR FINDINGS v-l
RESEARCH METHODOLOGY V-5
REGIONAL DISTRIBUTION OF CURRENT
CAPACITY AND COSTS V-7
REGIONAL DISTRIBUTION OF FUTURE CAPACITY
AND COMPLIANCE COSTS: 1980-1990 v-16
OTHER REGIONAL ISSUES V-29
VI. NATIONAL EFFECTS OF ENVIRONMENTAL
REGULATIONS ON THE ELECTRIC
UTILITY INDUSTRY VI-1
INTRODUCTION AND MAJOR FINDINGS VI-1
RESEARCH METHODOLOGY VI-11
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CONTENTS
(continued)
HISTORICAL PERSPECTIVE AND BASELINE
INPUT ASSUMPTIONS VI-12
BASELINE FINANCIAL PROFILE VI-35
UNIT POLLUTION CONTROL COSTS VI-42
RESULTS OF THE NATIONAL ANALYSIS VI-55
APPENDIX A THE ENERGY DATABASE A_1
APPENDIX B PTm(ELECTRIC UTILITIES) RESEARCH
METHODOLOGY B-l
EXTERNAL MODULE B-2
PHYSICAL PLANT AND EQUIPMENT MODULE B-2
FINANCIAL MODULE B-3
A CONCLUDING COMMENT B-6
APPENDIX C CAPITAL EXPENDITURES AND ELECTRIC
UTILITY ACCOUNTING PROCEDURES C-l
DEFINITIONS OF PLANT IN-SERVICE AND
CAPITALIZED EXPENDITURES C-l
TREATMENT OF FINANCING COSTS C-2
APPENDIX D COAL PRICES D-l
UTILITY OPERATING AND CONSTRUCTION
DECISIONS D-l
COAL PRICES IN THE ABSENCE OF
ENVIRONMENTAL REGULATIONS D-5
THE EFFECTS OF ENVIRONMENTAL REGULA-
TIONS ON COAL PRICES AND AMOUNTS D-12
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CONTENTS
(continued)
APPENDIX E TERMS, ACRONYMS, AND
CONVERSION FACTORS E-l
DEFINITIONS E-l
ACRONYMS E-23
CONVERSION FACTORS E-24
-------
list of tables
1-1 Distribution of Possil-Puel Units by
Fuel Type 1-14
1-2 Distribution of Fossil-Fuel Units by
In-Service Year X-14
1-3 Distribution of Coal Capacity by Reported
SO2 Compliance Strategy 1-15
1-4 Distribution of Coal Capacity by Reported
TSP Compliance Strategy 1-16
1-5 Distribution of Oil Capacity by Reported
SO2 Control Strategy
1-6 Distribution of Fossil-Fuel Capacity by
Thermal Control Strategy 1-17
1-7 Total National Potential Air Pollutant
Emissions and Removals by Fuel Type 1-22
1-8 Average Cost per Ton of S02 and TSP
Removal
1-9 Determinants in Regional Pollution Control
Costs
1-10 Summary of Industry Cumulative Expenditures
with and without Pollution Controls
I-11 Changes in Plant In-Service Attributable
to Pollution Control Regulations
1-12 External Financing Effects of Pollution
Control Regulations
1-13 operating Revenue Effects of Pollution
Control Regulations
1-14 operation and Maintenance Expense Effects
of Pollution Control Regulations
1-15 Consumer Charge Effects of Pollution
Control Regulations
1-16
1-23
1-26
1-30
1-31
1-32
1-33
1-34
1-35
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LIST OF TABLES
(continued)
II-l Evolution of Water Quality Regulations
Since 1974 11-17
II-2 Powerplant Pollution Sources as a
Function of Plant Fuel Type 11-25
IV-1 Distribution of Fossil-Fuel Units by
Fuel Type IV-2
IV-2 Distribution of Fossil-Fuel Units by
In-Service Year IV-2
IV-3 Distribution of Coal Capacity by
Reported SO2 Compliance Strategy IV-3
IV-4 Distribution of Oil Capacity by Reported
SO2 and TSP Control Strategy IV-4
IV-5 Distribution of Fossil-Fuel Capacity
by Thermal Control Strategy IV-5
IV-6 Total National Potential Air Pollutant
Emissions and Removals by Fuel Type
in 1979 and for Future NSPS II Units IV-10
IV-7 Average Cost per Ton of SO2 and TSP
Removal in 1979 and for Future NSPS II
Units IV-11
IV-8 Distribution of Units by Unit Categories IV-13
IV-9 Reported SO2 Compliance Strategies:
Pre-1977 Coal Units IV-18
IV-10 Reported SO2 Compliance Strategies:
1977-1979 Coal Units IV-19
IV-11 Reported SO2 Compliance Strategies:
1980-1984 Coal Units IV-19
IV-12 Reported Coal Unit TSP Compliance
StstategiSs IV-21
IV-13 Future SO2 and TSP Compliance Strategies
by Existing Coal Units IV-22
-------
LIST OF TABLES
(continued)
IV-35
IV-3 7
IV-14 Reported SO2 Compliance Strategies:
Oil Units IV-22
IV-15 Reported TSP Compliance Strategies:
Existing Oil Units IV-23
IV-16 Trends in Cooling Tower Use IV-25
IV-17 Sensitivity of Capital Cost and
Investment Life Assumptions Used
in the Unit-Category Analysis IV-27
IV-18 Plant Construction Costs Used in
the Unit-Category Analysis IV-31
IV-19 Unit Characteristics Used in Developing
Baseline Costs of Generating Electricity
IV-20 Baseline Costs of Generating Electricity
at Model Units Selected for Analysis
IV-21 Average Annualized Costs of Compliance
by Pollutant IV-40
IV-22 Average Annualized Costs of Compliance
by Cost Component—Total Air, Water,
and Solid Waste IV-41
IV-23 Future Costs of Compliance with Alternative
Regulations for a 500-MW Coal Plant IV-49
IV-24 Total Unit-Level Costs per kWh under
Alternative Future Regulations IV-51
IV-25 Total 1979 National Potential Air Pollutant
Emissions and Removals by Unit Category IV-54
IV-26 Average Unit-Category Potential Air
Pollutant Emissions and Removals IV-55
IV-27 Average Cost per Ton of SO2 and TSP
Removal IV-58
-------
LIST OP TABLES
(continued)
IV-28 Average Unit-Category Potential Air
Pollutant Emissions and Removals IV-59
IV-29 Average Cost Per Ton of SO2 and TSP Removal IV-61
V-l Determinants in Regional Pollution
Control Costs v"2
V-2 1979 Regional Capacity by Fuel Type V-8
V-3 Fossil Steam Units: Type of Capacity
by In-Service Year V-10
V-4 Baseline Costs of Generating Electricity
in 1979 at Unit Categories Selected
for Analysis V-ll
V-5 Determinants in 1979 Regional Pollution
Control Costs V-12
V-6 Regional Average Annualized Costs of
Complying with Air, Water, and Solid
Waste Regulations in 1979 V-l3
V-7 Average Annualized Costs of Compliance
by Pollutant for Typically Affected
Fossil Steam Units in 1979 V-14
V-8 1979 Unit-Category Costs of Compliance by
Cost Component: Total Air, Water,
and Solid Waste V-16
V-9 Projected Growth of Regional Demand for
Electricity: 1979 to 1990 V-18
V-10 1985 Regional Capacity by Fuel Type V-19
V-ll 1990 Regional Capacity by Fuel Type V-19
V-12 Estimated 1980-1990 Reconversions to Coal V-21
V-13 1980-1990 Reconversions: Average
Annualized Unit-Category Costs of
Compliance and Regional Effects V-22
-------
list of tables
(continued)
T7 Til pestimated 1980-1985 NSPS I Coal-Fired
Capacity Additions and Average Unit-
Category Costs of Compliance V-24
v-15 Estimated 1985:1?90 USPS II Coal-Fired
r__aeitv Additions and Average Unit-
Category Costs of Compliance v-27
ut i Summary of Industry Cumulative Expend-
n l ^tureswith and without Pollution
Controls
Plant In-Service Attributable
v!-2 to pollution Control Regulations W-3
vi-3 External Financing Effects of Pollution
Control Regulations
VI-4 operating Revenue Effects of Pollution
Control Regulations VI 7
VI-5 Operation and Maintenance Expense Effects
of pollution Control Regulations VI-8
VI-6 Consumer Charge Effects of Pollution
Control Regulations
V!-7 HistoricaJ.anandJorecastyAnnual Growth in ^
-8 NUHour ^e1ereCuSt^errage KilOWatt"
VI-9 Comparison of Forecast Annual Growth
in Electricity Demand VI ib
vi-in u S Electric Utility Capacity, Addi-
* tions, Reconversions, and Retirements by
Fuel Type: 1980-2010
VI-11 Selected Demand, Energy, and Capacity
Statistics
VI-12 Projected Capacity "tilUation Factors
by Fuel Type: 1979-2005
VI-9
VI-15
VI-19
VI-20
-------
LIST OF TABLES
(continued)
VI-13 New Plant Construction Costs by Fuel Type VI-23
VI-14 Average Heat Rates VI-2 7
VI-15 1979 Operation and Maintenance Expenses
by Fuel Type: Nonfuel and Fuel Expenses Vl-28
VI-16 U.S. Privately Owned Electric Utilities:
Electric Plant Long-Term Assets and
Liabilities with and without Pollution
Control Equipment as of December 31/ 1979 VI-30
VI-17 Projected Inflation Rates: 1979-2007 VI-31
VI-18 . Financial Assumptions VI-33
VI-19 Pattern of Cash Flows for Capital Projects:
Annual Expenditures of Funds (excluding
AFDC) for Years Prior to and Including
the In-Service Year VI-35
VI-20 Summary of Baseline Financial Projections:
Base Case Scenario VI-37
VI-21 Summary of Baseline Financial Projections:
2 Percent Growth Rate Scenario VI-40
VI-22 Summary of Baseline Financial Projections:
No Post-1989 Nuclear Scenario VI-41
VI-23 Incremental Pollution Control Costs for
Units Existing in 1979 and 1980-1990
Reconversions VI-44
VI-24 Weighted Average Pollution Control Costs
for Units Coming into Service during
1980-1984 VI-51
VI-25 Weighted Average Pollution Control Costs
for Units Coming into Service after
1984: Base Case Scenario VI-53
-------
LIST OF TABLES
(continued)
VI-26 Financial Effects of All Pollution Control
Expenditures: Base Case Scenario VI-56
C-l Estimates of Various Treatments of Capital
Expenditures C-8
D-l 1981 Coal Uses D-l
D-2 Selected Rail Rates d-6
D-3 Mid-1982 Spot Coal Prices D-13
-------
LIST OF FIGURES
1-1 Components of 1979 Average Cost of
Pollution Control for Fossil Fuel Units 1-18
1-2 Components of 1979 National Average Cost
of Pollution Control for Fossil Fuel
Units by Fuel Type 1-20
1-3 Components of 1979 National Average Cost
of Pollution for Coal Units by Age
Category 1-21
1-4 EPA Regions 1-24
1-5 Comparison of Cumulative Plant Additions
and Operating Revenues Under Alternative
Scenarios 1-37
XX—1 Overview of Federal Air Quality
Regulations II-4
II-2 Applicability of Environmental Regulations
to Existing and New Electric Utility
Plants 11-27
IV-1 Components of 1979 Average Cost of
Pollution Control for Fossil Fuel Units IV-6
IV-2 Components of 1979 National Average Cost
of Pollution control for Fossil Fuel
Units by Fuel Type IV-7
IV-3 Components of 19 79 National Average Cost
of Pollution for Coal Units by Age
Category IV-9
IV-4 Low-Sulfur Fuel Premiums IV-29
IV-5 Distribution of Fossil-Fired Steam-
Electric Generation as a Function of
Pollution Control Costs and Fuel Type IV-38
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LIST OP FIGURES
(continued)
V-l EPA Regions V-6
VI-1 Pollution Control Cost Categories and Unit
In-Service Dates Vl-2
VI-2 Comparison of Cumulative Plant Additions
and Operating Revenues Under Alternative
Scenarios VI-10
VI-3 Distribution of Generating Capacity by
Fuel Type: 1980-2010 VI-14
VI-4 1979 Generating Capacity by Fuel Type
and Ownership Category VI-22
VI-5 Average Industry Fuel Cost per Net
Kilowatt-Hour, Total Electric Utility
Industry: 1960-1980 VI-25
VI-6 Projected Fuel Prices: 1979-2005 VI-26
VI-7 Attribution of the Costs of Increased Oil
Consumption, Conversion to Oil, and
Reconversion to Coal Since 1965 to
Economic or Environmental Decision VI-48
VI-8 Cumulative Changes to Plant In-Service
and Operating Revenues: Base Case
Scenario VI-57
VI-9 Cumulative Pollution Control Additions
by Unit In-Service Year: Base Case
Scenario VI-60
VI-10 Annual Pollution Control Operating
Revenues by In-Service Year: Base
Case Scenario VI-62
VI-11 Base Pollution Control Consumer Charges
by Unit In-Service Year: Base Case
Scenario VI-63
VI-12 Cumfclativ-e Pollution Control Additions
ijy Pollutant: Base Case Scenario VI-64
-------
LIST OF FIGURES
(continued)
VI-13 Annual Pollution Control Revenues by
Pollutant: BaSe Case Scenario Vl-66
VI-14 Annual Pollution Control Consumer Charges
by Pollutant: Base Case Scenario Vl-67
VI-15 Comparison of Cumulative Pollution Control
Plant Additions under Alternative
Scenarios VI-68
VI-16 Comparison of Cumulative Pollution Control
Operating Revenues under Alternative
Scenarios Vl-69
C-l Accounting Treatment of Cash Outlays for
New Equipment C-4
C-2 Determination of Annual Changes to Plant
In-Service and CWIP Accounts: Industry
versus PTm Treatments C-5
D-l Mine-Mouth Costs and Prices D-8
D-2 Coal Reserves by Sulfur Content D-9
D-3 Mine-Mouth Costs: Appalachian High-
Sulfur Coal D-10
D-4 Mine-Mouth Costs: Midwest High-Sulfur Coal D-ll
D-5 Mine-Mouth Costs: Western Northern Great
Plains Subbituminous Low-Sulfur Coal D-ll
D-6 Mine-Mouth Costs: Appalachian Low-
Sulfur Coal D~14
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LIST OF EXHIBITS
VI-1 PTm(Electric Utilities) Model: Balance Sheet for
Investor-Owned Electric Utilities
VI-2 PTm(Electric Utilities) Model: Income Statement for
Investor-Owned Electric Utilities
VI-3 PTm(Electric Utilities) Model: Applications and
Sources of Funds for Investor-Owned Electric
Utilities
VI-4 PTm(Electric Utilities) Model: Fuels Consumed for
Generation of Electricity
VI-5 PTm(Electric Utilities) Model: Total Generation by
Driver
VI-6 PTm(Electric Utilities) Model: Gross Additions to
Generating Plant Including Conversions to Coal from
Oil
VI-7 PTm(Electric Utilities) Model: Sales and Capacity
Assumptions, U.S. Electric Utility Industry
VI-8 Unit Pollution Control Costs Used to Develop Post-
1984 Cost Assumptions
VI-9 Financial Effects of Pollution Control Expenditures
by Units in Existence as of 1979, plus Coal
Conversions and Retrofits: Base Case Scenario
VI-10 Financial Effects of Pollution Control Expenditures
for Units Coming into Service During 1980-19 84:
Base Case Scenario
VI-11 Financial Effects of Pollution Control Expenditures
by Units Coming into Service after 1984: Base Case
Scenario
VI-12 Financial-Effects of Fuel Premiums for Units in
Existence as of 1979: Base Case Scenario
VI-13 Financial Effects of all Pollution Control Expendi-
tures, Excluding Fuel Premiums, for Units in
Existence as of 1979: Base Case Scenario
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list op exhibits
(continued)
VI-14 Financial Effects of Fuel Premiums for Units Coming
into Service after 1979, plus Coal Conversions:
Base Case Scenario
VI-15 Financial Effects of S02 Controls Installed after
1979 (excluding solid waste disposal costs and fuel
premiums): Base Case Scenario
VI-16 Financial Effects of TSP Controls Installed after
1979 (excluding solid waste disposal costs): Base
Case Scenario
VI-17 Financial Effects of Solid Waste Disposal Costs
Incurred after 1979: Base Case Scenario
VI-18 Financial Effects of Water Pollution Controls
Installed after 1979: Base Case Scenario
VI-19 Financial Effects of Pollution Control Expenditures:
2 Percent Growth Rate Scenario
VI-20 Financial Effects of all Pollution Control Expendi-
tures: No Nuclear Additions after 1989 Scenario
A-l
Data
File
Name:
PLANT.FILE
A-2
Data
File
Name:
BOILER.FILE
A-3
Data
File
Name:
STACK.FILE
A-4
Data
File
Name:
FUTURE.PLANT.FILE
A-5
Data
File
Name:
FUTURE.BOILER.FILE
A-6
Data
File
Name:
EMISSIONS.DATA.FILE
B-l Interactions between the Environment and the Physical
and Financial Characteristics of the Electric Utility
Industry
B-2 Determinants bf Plant and Equipment in Service and
in Construction for the Electric Utility Industry
B-3 Determinants of Uses of Funds for the Electric
Utility Industry
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LIST OF EXHIBITS
(continued)
B-4 Determinants and Composition of Total Sources of
Funds for the Electric Utility Industry
B-5 Determinants of Revenues, Expenses, and Profits for
the Electric Utility Industry
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TOPICAL GUIDE TO THE REPORT
This topical guide, a cross-referencing aid to the large
amount of data in the report, is organized by major topics.
Those topics are:
• Acts and Regulations
• Capacity Planning
• Cost-Effectiveness Analysis
• Effects of Pollution Control Strategies on Financial
Profile
• Electric Utility Baseline Operations
• Fuel Choices
• Pollutants and Discharges
• Pollution Control Strategies
• Research Methodology Used
ACTS AND REGULATIONS
Clean Air Act, and regulations and standards implementing the
Act
• Overview: 1-8, II-2-12, Figure II-l, V-30
• Attainment policies
--General: II—5, Figure II-2, V-30
—Prevention of significant deterioration (PSD)
regulations: 1—11, Figure II-l, II-6-7, 11-10,
Figure II-2, III-3, 111-32-33, 111-37-38, 111-44,
V-28-30
—Visibility standards: Figure II-l, II-7
• Nonattainment policies
—General: II-8, Figure 11-2,111-36-37, V-30
—Offsets: Figure II-l* H-8, 11-10, Figure II-2,
111-36-37, 111-42-43
—Bubbles: 111-42-43
• Best available control technology (BACT): II-9,
111-32-35, IH-45, IV-17, VI-54
• Lowest achievable emission rate (LAER): II-8-9,
111-33-35, 111-45, IV-17
• Reasonably available control technology (RACT):
Figure II-l, II-9, Figure II-2-, IV-16
• National Ambient Air Quality Standards (NAAQS):
1-8, II-3, Figure II-l, Figure II-2
-------
Topical Guide-2
• New source performance standards .(NSPS)
—General: II-3, Figure II-l
—NSPS I: II-5, Figure II-2, VI-50-52
—NSPS II: II-5, Figure II-2, IV-17, VI-53
• State implementation plans (SIPs): Figure II-l,
II-5 , II-9-10 , 111-18111-33
• Other provisions
—General: 11-10
—Stack heights: 11-10-11
— Section 125: 11-11-12
Clean Water Act, and regulations implementing the Act
• Overview: 1-8, 11-12-20, Table II-l
• National pollution discharge elimination system
(NPDES) and effluent limitation guidelines
—General: 1-9, 11-14-19, IV-24
—Best practicable control technology (BPT): 11-14,
11-15, Table II-l, Figure II-2, IV-24, VI-52
—Best available technology economically achievable
(BAT): 11-14, Table II-l, 11-17, Figure II-2
—Best conventional technology (BCT): 11-15
—New source performance standards (NSPS): 11-15,
Table II-l, 11-17
—Pretreatment standards for existing sources
(PSES): 11-15
—Pretreatment standards for new sources (PSNS):
11-15
• Cooling water intake standards: 11-19
• Water quality effluent limitations: 11-19-20,
III-18-19
Regulations regarding solid and hazardous waste disposal
• Overview: 1-9, 11-20-23
• Resource Conservation and Recovery Act (RCRA)
—Overview: 1-9, 11-20-23, Figure II-2
—RCRA Section 3004—hazardous waste disposal
regulations: 11-21
—RCRA Section 4004—nonhazardous waste disposal
guidelines: 11-21-23, VI-53, VI-54
• Polychlorinated biphenals (PCB) interim control
measures: 11-23
Other Acts
• Powerplant and Industrial Fuel Use Act (FUA):
111-10
• Public Utility Regulatory Policies Act (PURPA):
-------
Topical Guide-3
Interactions among environmental regulations; 11-23-28
Interactions between environmental and other regulatory
bodies: III-7. III-8
CAPACITY PLANNING
Planning process within utility companies
• Understanding the business environment of electric
utilities
—General: III-6-11
—Objectives, rate regulatory environment, and
financial condition of utilities: III-6-10
—Federal and state energy regulation: III-10-ll
—Market uncertainties: 111-11-12
• Environmental planning: 111-24-26
National capacity planning
• Additions: 1-6, Table-VI-10, Exhibit VI-6, VI-17,
VI-37, VI-58
• Reconversions: Table VI-10, VI-17, Figure VI-7
• Retirements: Table VI-10, VI-17
• Extending useful life: 111-19-20
• 1979 capacity: IV-1-3, Table IV-1, Table IV-2,
Figure VI-3, Tables VI-10-12, Exhibit VI-7, VI-17,
VI-21
• 1985 capacity: Table V-13, V-22, Tables VI-9-12,
Table VI-24, Figure VI-3, VI-17, Exhibit VI-7
• 1990 capacity: Table V-13, V-22, Table V-15, Tables
VI-9-12, Table VI-25, Figure VI-3, Exhibit VI-7,
VI-17
• Post-1990 capacity: VI-36, Table VI-10
• Alternative scenarios
—Overview: VI-39-42, VI-67
—Lower-growth: 111-11-12, Figure VI-2, VI-39,
VI-67
—No-nuclear: III-ll, Figure VI-2, VI-39, VI-41-42,
VI-67
Regional capacity planning
• Additions: Table V-14, V-25-27
• Reconversions: V-17-22, Table"~V-l2. Table V-13
• Retirements: V-17
• 1979 capacity: V-7-15
• 1985 capacity: Table V-9, Table V-10, V-23-25
-------
Topical Guide-4
• 1990 capacity: Table V-9, Table V-ll, V-25-27,
VI-2, VI-4
• Siting difficulties
—Overview: 1-11, 1-27, III-2, 111-19, 111-36-40,
V-4, V-30
—Regional growth patterns: 1-28, 111-36, V-4,
V-28
—Air-quality-related values: 1-28, V-4, V-28
—Prevention of significant deterioration (PSD):
1-11, 1-28, V-36-37, V-4, V-28-29
—Acid precipitation: V-29
COST-EFFECTIVENESS ANALYSIS
Overview: 111-40-41, IV-51-61
Quantities of pollutants removed
• Sulfur dioxide (SO2): 1-22, IV-10, Table IV-6,
IV-17, Tables IV-9-11, IV-60
• Total suspended particulates (TSP): 1-22,
IV-10, Table IV-6, Table IV-12, IV-60
Costs of pollutants removed
• S02: 1-22, Table 1-8, II-2, Figure IV-2, IV-10,
Table IjV-7, IV-12, Table IV-21, Table IV-23, Tables
IV-25-27, IV-56, IV-58, Table IV-28, lv-60, Table
IV-29, Exhibit VI-15, VI-2, VI-49
• NOx: U-2» VI-49
• TSP: 1-22, Table 1-8, II-2, Figure IV-2, IV-10,
Table IV-10, IV-12, Table IV-21, Table IV-23, Table
IV-27, IV-56, IV-58, Table IV-28, IV-60, Table IV-
29, Exhibit VI-16, VI-3, VI-49
Existing units: 111-13-22, IV-52-58, Table V-l, VI-36-37
NSPS I units: 1-6, Table IV-23, IV-58, Table IV-28,
Table IV-29, V-19
NSPS II units: IT6, 1-20, IV-8, Table IV-7, Table IV-23,
IV-59 # Table IV-28, Table IV-29, V-19, V-23-24, v-27
BACT units: III-4, IV-8, Table IV-23, IV-59, Table IV-28,
Table IV-29
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Topical Guide-5
Uncontrolled emissions: Table IV-20, VI-35-42, Tables
VI-20-22
EFFECTS OF POLLUTION CONTROL STRATEGIES ON FINANCIAL PROFILE
Unit category
• Overview: Table IV-23, VI-42-55
• Capital costs: Table IV-23, VI-16
• Operation and maintenance expenses: Table IV-23
Baseline projection
• Overview: VI-36-39
• Changes in plant in-service: VI-36, Table VI-20
• External financing: VI-37-38, Table VI-20
• Operating revenues: VI-38, Table VI-20
• Operation and maintenance expenses: VI-38,
Table VI-20
• Consumer charges: VI-39, Table VI-20
• Alternative scenarios: VI-39-42, Table VI-20,
Table VI-22
Base case scenario
• Overview: VI-56-59, Table VI-26
• Changes in plant in-service: Table 1-10, Table
1-11, VI-2, Table VI-1, Table VI-2, Table VI-20,
Table VI*>21, Table VI-22, VI-58, VI-59, VI-64, Table
VI-26, Figure VI-9, Figure VI-12, Exhibits VI-9-20
• External financing: Table 1-10, Table 1-12, Table
VI-1, Table VI-3, Tables VI-20-22, Table VI-26,
Exhibits VI-9-20, VI-3, VI-58
• Operating revenues: Table 1-10, 1-30, 1-32, Table
1-13, Table VI-1, Table VI-4, Tables VI-20-22, Table
VI-26, Figure VI-10, Figure VT-13, Exhibits VI-9-20,
VI-2, VI-48
• Operation and maintenance expenses: Table I-iO,
Table 1-14, 1-33, Figure IV-1, Figure IV-2, Table
VI-1, Table VI-5, Table VI-15, Tables VI-20-22,
Table VI-26, Exhibits VI-9-20, VI-2, VI-4, Vl-36,
VI-59
• Consumer charges: 1-5, Table 1-10, 1-30, Table
1-15, 11-12, Table VI-1, Table Vl-6, Table VI-8,
Tables VI-20-22, Table VI-26, Figure VI-11, Figure
VI-14, Exhibits VT-9-20, VI-2, VI-5, VI-49, VI-61,
VI-65
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Topical Guide-6
Low-growth scenario: pollution controls
• General: Table VI-21, Figure VI-2, Figure VI-15,
Figure VI-16, VI-6, VI-67-70, Exhibit VI-19
—Changes in plant in-service: Figure VI-15, VI-70,
Exhibit VI-19
—External financing: Exhibit VI-J.9
—Operating revenues: Table VI-21,Figure VI-2,
Figure VI-16, IV-70, Exhibit VI-19
—Operation and maintenance expenses: Exhibit VI-19
—Consumer charges: Exhibit VI-19
No-nuclear scenario: pollution controls
• General: Figure VI-2, Figure VI-15, Figure VI-16,
VI-6, VI-67-70, Exhibit VI-20
• Changes in plant in-service: Figure VI-15, VI-70,
Exhibit VI-20
• External financing: Exhibit VI-20
• Operating revenues: Figure VI-2, Figure VI-16, VI-
20, Exhibit VI-20
• Operation and maintenance expenses: Exhibit VI-20
• Consumer charges: Exhibit VI-20
ELECTRIC UTILITY BASEL INF. OPERATIONS
Baseline input assumptions: III-6, IV-34-36, Table IV-19,
Table IV-20, Table IV-24, Table V-4, V-5-6, V-17, VI-12-42,
Tables VI-7-20, Figures VI-5-6
Existing capacity
• Unit categories: Table VI-1, Table IV-8
• Regional categories: V-7-15
• National categories: VI-16-22, Tables VI-10-JL2,
Figure VI-3, Figure VI-4
• Fuel type
—Coal: IV-1, Table IV-1, Table IV-8, IV-14, Table
IV-19, Table IV-20, Table IV-22, Table IV-25,
Table IV-27, Tables V-l-6, V-12, V-13, Table VI-
10, Figure VI-4, VI-16-22
Oil: IV-1, Table IV-1, Table IV-8, IV-14, Table
IV-19, Table IV-20, Table IV-22, Table IV-25,
Table IV-27, Tables V-l-6, V-12, V-13, Table VI-
10, Figure VI-4, VI-16-22
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Topical Guide-7
—Gas: IV-1, Table 17-1, Table IV-8, IV-14, Table
IV-19, Table IV-20, Table IV-22, Table IV-25,
Table IV-27, Tables V-l-6, V-7, V-12, Table VI-10,
Figure VI-4, VI-16-20
• Year in-service
—Pre-1972: 1-13-14, IV-2, Figure IV-3, Table IV-8,
IV-15, Table IV-19, Table IV-20, Table IV-22,
Table IV-25, Table IV-27, Table V-l, Table V-3,
Table V-5
—1972-1976: 1-14, IV-2, Figure IV-3, Table IV-8,
IV-15, Table IV-19, Table IV-20, Table IV-22,
Table IV-25, Table IV-27, Table V-l, Table V-3,
Table V-5
—Post-1976: 1-14, Figure IV-3, Table IV-8, IV-15,
Table IV-19, Table IV-20, Table IV-22, IV-44, IV-
45, Table IV-25, Table IV-27, Table V-3, Table
VI-5, Table VI-10, Figure VI-3
Future capacity
• Overview: V-15-27, VI-16-22, Tables VI-10-12,
Figures VI-3-4
• Fuel choices
—Coal: 1-27, Table IV-24, V-17-27, Table V-10,
Table V-ll, V-23-27, Table V-14, VI-19, Tables
VI-10-12, Figures VI-3-4, Exhibits VI-4-6
—Oil: VI-20, Tables VI-10-12, Figures VI-3-4,
Exhibits VI-4-6
—Gas: VI-20, Tables VI-10-12, Figures VI-3-4,
Exhibits VI-4-6
—Gas/Oil: Table VI-10
—Nuclear: 1-27, V-17, Table V-10. Table V-ll,
Table VI-10, Exhibit VI-5, Exhibit VI-6, VI-28
—Hydro: Table V-10. Table V-ll, Table VI-10,
Exhibit VI-5, Exhibit VI-6
—Pumped storage: Table VI-10. Exhibit VI-5,
Exhibit VI-6
• Cost of technology
—General: 111-46
—Unit: IV-37-51, V-24, VI-34-44
—National: 111-36, VI-44-53
—Capital: 111-46, Figure IV-2, Table VI-10, VI-22-
24
—Nonfuel operating: 111-46, Table VI-15, VI-27-28
—Fuel: 111-46, Figure IV-2, Table V-l, Figure
VI-6, VI-24-27
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Topical Guide-8
m Financial and accounting assumptions
—General: 1-4-5, Table VI-18, VI-28-29
—Inflation rates: IV-12, Table VI-17, Vl-30-32
—Construction schedules: VI-16, VI-34, Table VI-
10, Table VI-19
—Capital costs: III-8, Table VI-13, VI-22-24
—Capital mix: Table VI-18
—Cost rates: VI-28-34, Table VI-18
—Long-term assets and liabilities: Table VI-16,
Exhibit VI-1
—Growth (decline) in peak demand: 111-11-12, VI-
12-»16, Tables VI-7-9
—Capacity utilization: Table VI-12
—Cash flow for capital projects: III-7, Table
VI-19, VI-27
—Tax rates: Table VI-18, VI-27-28
Baseline financial profile
• Overview: VI-35-39, Table VI-20
• Current financial status: III-7, VI-29-32, Table
VI-16
• Baseline projections
—General: Table VI-1, Table VI-20, VI-2
—Base case scenario: Tables VI-1-6, Table VI-20,
Table VI-26, Figure VI-1, Figures VI-8-14,
Exhibits VI-9-18, VI-1, VI-56-67
—Low-growth scenario: 1-35, Figure 1-5, VI-67-70,
Table VI-21, Figures VI-15-16, Exhibit VI-19
—No-nuclear scenario: 1-35, Figure 1-5, 111-25-26,
VI^67-70, Table VI-22, Figure VI-2, Figures VI-15-
16, Exhibit VI-20, VI-33-34
FUEL CHOICES
Coal
• Overview: 1-11, 111-31-40, IV-23, V-13, V-19-27,
Table VI-14, Figure VI-3, Figure VI-5, VI-16-22,
Figure VI-6, D-l-12
m Reconversions: V-17-22, Table V-12, Table V-13,
VI-17, VI-43-50, Table VI-10, Figure VI-7
• High-sulfur content: IV-20, VI-42, C-l-12
• Low-sulfur content: 11-11, IV-18, IV-28, Figure IV-
4, VI-38, VI-42, VI-43, C-l-12
• Improved quality: 1-5, 1-10, 1-17, C-l-12
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Topical Guide-9
Noncoal alternatives
• Overview: 111-26-31
• Oils 111-26, Table VI-10, Figure VI-3, Figure VI-4,
Figure VI-7
• Gas: 111-26, Table VI-10, Table VI-15, Figure VI-3r
Figure VI-4
• Gas/oil: Table VI-10
• Nuclear: III-ll, 111-26, Table VI-10, Figure VI-3,
Figure VI-4, VI-8-11, VI-39-42
• Hydro: Table VI-10, Figure VI-3, Figure VI-4,
VI-8-12
• Geothermal: 111-27
• Internal combustion/gas turbine (IC/GT): Table
VI-10, Figure VI-3, Figure VI-4
• Pumped storage: Table VI-10, Figure VI-3, Figure
VI-4, VI-8-12
• Unconventional: 1-11, III-ll, 111-21-22, 111-27-28
• Purchased power: 1-11, 111-28-29
• Synfuel: 1-11, 111-22, 111-29
POLLUTANTS AND DISCHARGES
Air pollutants
• S02: 1-5, 1-7, II-2, II-7, Table II-2, 111-14-16,
VI-2, VI-63-67
• NQ„: 1-7, II-2, II-7, Table II-2, 111-16-17, VI-63-
67
• TSP: II-7, Table II-2, 111-17-18, VI-3, VI-63-67
Water pollutants
• General: 111-18-19
• Chemical: 11-13, Table II-l, Table II-2
• Thermal: 11-13, Table II-l, 11-17, Table II-2
• Other: Table II-l, Table II-2
Solid and hazardous wastes
• General: 11-20, IV-25-26, VI-63-67
• PCBs: 1-9, 11-15, 11-20, 11-23, Table II-2
• Ash
—General: Table II-2
—Fly ash: 1-7, II-2, 11-13, 11-21. VI-63-67
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Topical Guide-10
—Bottom ash: 11-21, VI-63-67
• Sludge: 11-20, 11-21, Table II-2, 11-27, IV-26
POLLUTION CONTROL STRATEGIES
Pollution control equipment
• Technology
—Study methodology
• Unit technology
• National coverage
—Air pollution control equipment
• Flue gas desulfurization (PGD—scrubbers):
1-14, 11-11, 11-27, 111-14-15, III-17, IV-3,
Table IV-3, IV-8, Table IV-9, Table IV-23, V-4,
V-24, V-25, VI-42
—Electrostatic precipitators (ESP): 1-15,
111-17, IV-20, Table IV-20, V-2, V-26, VI-42-55
—Baghouses: 111-17, IV-20, V-26, VI-42-55
—Catalytic reduction systems: 111-16
• Water pollution control equipment
—Thermal: Table 1-6, 1-16, 11-13, 11-17, 11-25,
III-18, IV-4, Table IV-5, IV-24, Table IV-16. IV-
24, VI-41
—Chemical additives: 11-15
• Solid and hazardous waste control
—Overview: 11-27-28, IV-25-26
—Ash handling: 11-22-23, 11-25, 111-18, IV-25-2 6
—Sludge handling: 11-27, IV-25-26
—Sanitary landfills: 11-23, VI-25-26
Cost of technology
• General: 111-36, IV-5
• Study methodology
—Unit costs: Table 1-9, IV-37-51, IV-52, Tables
VI-23-25, Exhibit VI-8
—National costs: Table 1-10, V-14, Table V-8,
Tables VI-1-6, Table VI-26, Figures VI-8-16,
Exhibits VI-9-20
—Capital costs: 1-20, Figure 1-1, 111-31, Figure
IV-1, Figure IV-2, IV-8, Figure IV-3, IV-40, V-14,
Table V-8, V-27, Tables VI-23-25
—Nonfuel operating costs: Figure 1-1, V-14,
Table V-8, Tables VI-23-25
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Topical Guide-11
—Fuel premiums: Figure 1-1, Figure IV-2, Figure
IV-3, V-14, Table V-8, Table V-5, Tables VI-23-25
• Air pollution control equipment
—General: Table V-8, Tables VI-2-6, Tables VI-23-
25, Figures VI-8-14
—FGD (scrubbers): 1-20, 1-26, 1-34, Figure IV-2,
IV-8, Figure IV-3, IV-10, Figures IV-9-11, Table
IV-21, IV-50, IV-60, Table IV-28, V-3, Table V-7,
V-14, Table V-13, Tables VI-23-25, Exhibits VI-8-
14
—TSP control: Figures VI-8-14, Exhibit VI-8,
Exhibit VI-16, VI-3, VI-5, VI-56-67
—ESP: 111-18 , IV-21, IV-49 , VI-44
—Baghouses: IV-20, V-26, VI-42-55
—Catalytic reduction systems: 111-16
• Water pollution control equipment
—General: IV-43, Table V-8, Table VI-3, Figures
VI-8-14, Figure VI-13, Exhibit VI-lS, VI-5,
VI-56-67
—Thermal: Figure 1-1, 1-26, 11-19, 111-19-20,
Table IV-5, Table IV-16, Figures IV-1-3, V-3,
Table V-7, V-14, Tables VI-23-25, VI-50-55
—Chemical additives: Figure 1-1, 11-15, 111-19,
Figure IV-1-3, rv-32, Table IV-21, V-3, Table V-l,
V-14, Tables VI-23-25
• Solid and hazardous waste control equipment
—General: IV-25-26, Table V-8, Tables VI-2-6,
Figures VI-8-14, Exhibit VI-8, Exhibit VI-17, VI-
4, VI-5, VI-42-67
—Ash handling: IV-43, VI-42-55
—Sludge handling: IV-43, VI-42-55
RESEARCH METHODOLOGY USED
Selection of case-studv companies: 1-2, III-5, III—40—46
Quantitative analysis
• Energy Database: I~2, 1-4, 1-13, IV-1, IV-12-15, A-^
1-3, Exhibits A-l-6
• PTm(Electric Utilities): 1-4, Exhibits VI-1-8, VI-
1, VI-8, B-l-7, Exhibits B-l-5
• Accounting methodology: VI-28-35, C-l-4
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Topical Guide-12
Unit category analysis
Development of Energy Database: 1-3, IV-12, IV-
A-l-3
Definition of unit categories: IV-12
Identification of strategies and costs: IV-12
Regional analysis
• Selection of regions: V-5, Figure V-l
• Development of baseline costs: V-5
• Development of pollution control costs: V-7
National analysis
• Overview: VI-11-12, Appendix B
• Determination of applicable regulations: VI-42-
• Development of financial assumptions: VI-28-34,
Appendices B and C
• Coverage of strategies and costs: VI-42-55
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89 SB
2 H
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i§
O H
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CHAPTER I
INTRODUCTION AND KEY FINDINGS
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CONTENTS
INTRODUCTION 1-1
Guide to the Study 1-1
Research Methodology and Assumptions 1-4
KEY FINDINGS 1-5
An Overview of Environmental Regulations
Affecting Electric Utilities 1-7
The Effects of Environmental Regulations
on Utility Operations and Plans 1-10
The Effects of Environmental Regulations
on Electric Utility Units 1-13
Distribution of Units by Fuel Type
and Age 1-13
Environmental Compliance Strategies 1-15
Pollution Control Costs 1-17
Pollutant Removal and Cost Effectiveness 1-22
The Regional Effects of Environmental
Regulations on the Electric Utility
Industry 1-23
Existing Capacity: Costs of Compliance 1-25
New Coal-Fired Capacity: Costs of
Compliance 1-27
National Issues That Affect Compliance 1-28
The National Effects of Environmental
Regulations on the Electric Utility
Industry 1-29
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I. INTRODUCTION AND KEY FINDINGS
INTRODUCTION
This study by Temple, Barker & Sloane, Inc. (TBS), for
the Energy Policy Division of the U.S. Environmental Protec-
tion Agency (EPA), updates and, perhaps more important,
broadens and deepens the scope of a 1976 analysis of the cumu-
lative financial and economic effects of environmental regula-
tions on the U.S. electric utility industry.1
The 1976 report, also prepared by TBS for EPA, antici-
pated in part the fundamental shifts in the industry's fuel
sources, the changing patterns of demand, and the strained
financial conditions currently affecting the industry. None-
theless, a plethora of changes—in environmental and energy
regulations; in technology; in construction and fuel costs;
and in demand growth—led EPA to ask TBS to update that
report.
Guide to the Study
The current report is organized in six chapters. Follow-
ing Chapter I, and to provide a context for the analysis in
later chapters, Chapter II presents an overview of the envi-
ronmental regulations affecting electric utilities. This
overview is intended as a summary synthesis of regulations.
Its need stems from the complexity of the regulations, which
in turn stems from legislative and administrative attempts to
meet multiple environmental objectives in a manner that is
flexible and applicable to a host of specific situations. A
consequence of the complexity is that few people have an over-
view of the scope and impact of the regulations. This report
is intended to provide that perspective.
Chapter III explores the influences of environmental
regulations on management decision making within utilities by
^-Temple, Barker & Sloane, Inc., Economic and Financial Impacts
of Federal Air and Water Pollution Controls on the Electric
Utility Industry, May 1976.
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1-2
reporting the findings of six case studies conducted by TBS
for this study. This exploration adds a first new dimension
to the scope of the 1976 analysis. As is highlighted in the
following paragraphs, two key issues are addressed in this
chapter. The first is why companies have selected particular
compliance strategies in the past and whether their actions in
the future are likely to conform to the prospective engineer-
ing assumptions used in this study's analysis. Actions by
regulatory commissions that lead to inadequate rates of return
and to financing constraints, for example/ can influence
choices of compliance strategies in ways not captured in engi-
neering economic studies.
A second issue concerns costs that may not be reflected
adequately either in utilities' reports of historic and antic-
ipated costs or in engineering analyses. There is the ques-
tion, for example, whether environmental regulations cause
uncertainties and delays in planning, permitting, construct-
ion, and operating activities that have costs that are real
and significant, but that are often unrecognized and rarely
quantified. As another example, there is the question whether
environmental regulations will lead not only to the easily
identifiable use of expensive fuels and pollution control
equipment, but also to the less easily observed costs associ-
ated with the construction of smaller and less efficient
units, the location of units at sites remote from customers,
or the inability to expand capacity in parallel with demand at
any reasonable cost.
In an attempt to explore the issue of real but indirect
costs and to illuminate some of the subtle influences on util-
ity decision making, TBS conducted a series of interviews with
company executives and technical staff. These were supple-
mented by interviews with a variety of environmental and other
regulatory officials in various states and regions and by
discussions with other knowledgeable individuals in other
organizations. This research identified the qualitative con-
sequences of environmental regulations that are not easily
captured in quantitative terms.
Another new dimension in the current study is a detailed
quantitative investigation into what actions the industry
actually has taken and is currently planning tg take to meet
environmental requirements. This analysis draws on an exten-
sive database, developed by TBS for EPA, of compliance strat-
egies, costs, and plans as reported by utilities for 2,277
generating units, representing 96 percent of the industry's
total fossil-fuel generating capacity. • This database provides
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1-3
a solid empirical foundation for many of the assumptions con-
cerning the average costs and prevalence of alternative strat-
egies for complying with, environmental regulations.
Perhaps even more important, the database supports a new
Jcind of analysis appearing in Chapters IV and V—namely an
investigation into the differences in total pollution control
costs among units. This analysis of the industry's unit-by-
unit pollution control actions and plans has two major parts.
The first, called the "unit-category" analysis, focuses on the
differences in costs across units coming into service at dif-
ferent times—and therefore subject to different environmental
regulations—and burning different types of fuels—i.e., coal,
oil, gas, or nuclear. This discussion appears in Chapter IV.
The second analysis of the industry's reported actions
and plans, called the "regional" analysis, appears in Chap-
ter V and focuses on the differences in costs across geograph-
ic regions. This analysis illuminates the differences in
pollution control costs per kilowatt-hour (kWh) that arise
from regional variations in existing air and water quality
pollution control requirements, mix of generating capacity,
availability and cost of low-sulfur fuels, and other factors.
To the extent that utilities in a region are all affected by
and respond to environmental requirements similarly, this
analysis also indicates the differences among regions in the
increases in consumer bills associated with pollution control
strategies.
The earlier study focused essentially on the financial
and economic implications of engineering analyses concerning
the average construction and operating costs of various meth-
ods for controlling specific pollutants and concerning the
extent to which each method would be used to comply with regu-
latory requirements. The sixth and last chapter of the cur-
rent study, called the "national" analysis, again uses this
methodology. The analysis reflects new environmental require-
ments, updated engineering estimates, and the latest available
information concerning the industry's present condition and
future trends. A 25-year time span is evaluated using TBS's
computerized financial model of the industry.
Each chapter in this report is preceded by a table of
contents to aid the reader in sorting through the vast amount
of information covered in the study. In addition, Chap-
ters III through VI contain introductory sections summarizing
the key findings that are explored more fully in subsequent
sections.
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1-4
Four appendices follow the chapters. Appendix A briefly
describes the Energy Database? Appendix B presents an overview
of PTm(Electric Utilities); Appendix C discusses financial
procedures used by the electric utility industry to account
for capital expenditures. Appendix D discusses determinants
of coal prices in the absence of environmental regulations and
within the context of environmental regulations.
Research Methodology
and Assumptions
The research methodology employed in this study is based
on two quantitative tools and one qualitative tool.
The Policy Testing model of the electric utility indus-
try, PTm(Electric Utilities), is one of a series of computer
models developed by TBS to project the economic and financial
implications of alternative policy options in the form of
growth rates, mix of generating capacity additions, financial
strategies, regulatory actions, taxation policies, economic
conditions, and other influences.
The second quantitative tool, the Energy Database, is a
computerized information system developed by TBS for EPA. The
information was obtained from 1979 Federal Energy Regulatory
Commission's Form 67s submitted by utilities to the Energy
Information Administration of the Department of Energy. In-
cluded in the database are all fossil-fueled steam-electric
units with a capacity of 25 megawatts (MW) or greater for
which Form 67 data were available. The database provides a
comprehensive foundation for the analysis of utility plant
operations.
Finally, qualitative case studies of utilities explore
the influences of environmental regulations on management
decision making within utilities.
Although this study focuses on federal environmental
regulations, the only actual cost data available reflect total
pollution control costs. To the extent, therefore, that state
or local requirements for air, water, or solid waste pollution
control exist in the absence of federal regulations or exceed
the minimum standards necessary for compliance with federal
regulations, the costs identified in this analysis are not
entirely attributable to federal requirements. To the extent
that utilities undertake certain expenditures for reasons
other than environmental- Compliance—for example, installing
cooling towers for economic reasons—the costs identified in
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1-5
this analysis may have joint attributes. Where possible the
discussion identifies contributing components of costs, par-
ticularly at the unit-category level in Chapter iv.
KEY FINDINGS
During the 1970s, environmental regulations covering air,
water, and solid wastes were strengthened substantially.
During the same period, rapidly escalating fuel arid construc-
tion costs have led to major increases in the price of elec-
tricity and, indirectly, to a marked decline in electric util-
ities' financial condition, as evidenced by wholesale declines
in bond ratings and by stock prices well below their book
values. In these circumstances, the uncertainties and costs
associated with environmental regulations have come to be
increasingly important to utility plans and operations.
Electric utilities are major contributors to total pollu-
tant loadings in the environment. In 1979 pollution controls
at electric utility powerplants were responsible for removing
42 percent of total potential SO2 emissions, or 12.2 million
tons, and 98 percent of total potential particulate emissions,
or 45 million tons. Environmental controls on coal units
contributed the dominant share of pollutants removed. Refer
to page 1-22 for a more detailed discussion of pollutant re-
movals by unit type.
Nationwide in 1980, consumer charges—the average cost of
electrical energy per kilowatt-hour—attributable to compli-
ance with pollution control requirements averaged 4.0 mills
per kWh (expressed in 1982 dollar^)-. This represents an in-
crease of 9.3 percent over base consumer charges of 42.7 mills
per kWh that would be incurred in the absence of compliance
costs. In 1999, consumer charges for pollution control strat-
egies that respond to regulations in place during the period
1971-1999 are expected to average 5.0 mills per kWh, or
9.8 percent over base costs of 51.2 mills per kWh (expressed
in 1982 dollars).
The expense and difficulty of achieving compliance with
environmental regulations vary greatly across regions of the
country, electric utility companies, and individual generating
units. Some utilities have stated that environmental regula-
tions constitute a major obstacle, especially to meeting fu-
ture demand for electricity. Others have expressed no great
concern. The primary influencing factors appear to be ambient
air quality near powerplants, the types of fuels consumed, the
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1-6
local availability of low-sulfur coal, and the stringency of
state implementation plans (SIPs).
To date, utilities have complied with the ro°st costly
regulations—those related^tojsulfur^dioxide^S
ing^equipment. In W79, the fuel premiumaccountedfor nearly
65 percent of the national average annualizeed cost
3.88 mills per kWh for pollution con"° ™ firioi^ul fur
units (expressed in 1979 dollars). nollution Pnnt-mi
oil accounted for nearly 90 percent of total pollution control
costs at oil-fired units.
Past and future strategies for compliance with SO2 and
total suspended particulate (TSP) regulations have reflected
and will reflect increasingly stringent standards and result
in rising capital costs-for pollution control equipment For
example, for coal-fired units in®efv^®ts f° q 76 n^r
capital portion of pollution control costs xs 0.76 nulls per
kWh; for units coming into service/n^® 2nSlep?!i°5 r)
that are subject to new source performance standards (NSPS I)
for air, the capital costs contribute an average of 5.12 mills
per kWh (expressed in 1979 dollars).
During the period 1980-1999, pollution control equipment
will add $87.3 billion, or 8.4 Pf^cent, to the industry's
plant in-service base of $1,041.5
$68.2 billion, or 7.9 percent, to the xndiistry 8 baseline
external financing requirements of $857.6 billion (expressed
in 1982 dollars). The magnitude of this financing need, com-
bined with the financial difficulties already confronting the
industry, could create significant problems for individual
utilities.
In 1979, the average cost of reducing SO2 emissions was
$461 per ton. Among coal units, reducing SO2 emissions was on
average nearly twice as expensive using scrubbers as it was
using low—sulfur coal. The national average cost of reducing
TSP emissions was $22 per ton. This average cost is dominated
by ths low average cost of rsmoving v©ry laxg© quantities of
TSP at coal-fired units. Removal costs for future, NSPS II,
units are dominated by scrubbers and are projected to be
significantly greater than costs at existing units. Refer to
page 1-22 for more detailed information on removal costs by
unit type.
When future growth in demand requires new capacity to be
added, coal-fired powerplants will be the most likely choice.
However, the large capital requirements associated with build-
ing plants that meet the revised new source performance stand-
ards (NSPS II) and the possible siting constraints imposed by
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1-1
a lack of_increments in attainment areas and the cost or un-
availability of offsets in nonattainment areas will hamper
some utilities in their attempts to meet growth in the demand
for electricity.
The following sections present a summary of key findings
in each area of analysis. They conform to the organization of
the full report, beginning with an overview of environmental
regulations affecting the electric utility industry and ending
with a discussion of national effects of those regulations.
The reader is cautioned that, as this is a summary, there is
no discussion of the methodological approach, assumptions, and
uncertainties that are contained in each full chapter.
An Overview of Environmental Regulations
Affecting Electric Utilities
Environmental regulations applicable to electric utili-
ties are extensive, complex, and evolving over time. The
regulations are extensive because the electric utility indus-
try is an important source of air and water pollution and a
major generator of solid wastes. They are complex and evolv-
ing because a multiplicity of interests, objectives, and tech-
nical and scientific developments have influenced and are
influencing their development.
Although the industry traditionally has had its own pro-
grams for controlling air, water, and solid waste pollution,
further requirements pertaining to each type of pollutant have
evolved separately through legislative, regulatory, and legal
processes at the local, state, and federal levels. The speci-
fic requirements often vary from plant to plant, sometimes,
even from unit to unit in a plant, depending on a variety of
considerations, including a generating unit's age, location,
fuel type, and technical configuration. In addition to the
air, water, and solid waste regulations that are assessed in
this report, the industry has to comply with other environ-
mentally related regulations, such as noise control and the
protection of endangered species and coastal zones.
In some geographic areas, it is arguable that regulations
affecting local utilities would be just as strict as they are
now even in the total absence of federal regulations. In some
other geographic areas, it is arguable that federal require-
ments are the sole driving force behind some existing regula-
tions. However, because of the complexity of the interactions
among regulations, the appropriateness of these arguments can-
not be determined readily. Further, responsibility for the
detailed specification and enforcement of particular
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1-8
regulations is often delegated from one level jLit^on env;_
another. Thus, this study does not attempt P f , al
ronmental requirements into those attribu a >
state, and local initiatives.
Electric utility air pollution has been a
regulation because of the large total qu ^ _ , larae
emitted by the industry as a whole ^ egome piants. The
amounts of c^t;inPollut!^Se®®bustion by-products. The corn-
regulated pollutants are all forms nitrogen oxides
bustion of natural gas, coal, ana oix imnuriti
™HTn\°nl operation "ready
try in that year still emitted abou^ ^ i mlll?^n
&£ of TSP In the cLe of S02, ^ average electric utility
plant has uncontrolled emissions substantially larger than
other industrial sources.
During the late 1960s, Congress concluded that previous
state and federal initiatives to address the problems of air
^XtlSn, Infludiig thl clean Air Act of 1964wereinade-
quate and, in the 1970s, passed two major pieces of legisla-
tion. Thi Clean Air Act Amendments of 1970 (generally known
as the Clean Air Act or the Act) established a new legal
framework to protect and enhance air quality and to provide
oversight in the implementation of air quality control pro-
grams. The Act stated that EPA should establish nationwide
national ambient air quality standards tNAAQS) and industry-
specific new source performance standards. Individual states
were given responsibility for the actual implementation of the
Clean Air Act's provisions.
In 1977, further amendments extended the deadline for
the attainment of all primary (health-related) standards.
States were to prepare and submit to EPA, by January 1979,
revised implementation plans for all nonattainment areas. The
plans were to provide for the implementation of all reasona-
bly available control measures as expeditiously as practi-
cable" for existing sources and for "reasonable further pro-
gress," demonstrated on an annual basis, toward meeting stand-
ards. Currently, the Clean Air Act is again under review by
Congress.
Water regulations have affected electric utilities less
than air regulations. The industry uses water primarily for
cooling and, therefore, pollutants in most electric powerplant
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1-9
waste streams tend to be similar and not highly concentrated.
However, the volumes of these streams can be great. The in-
dustry is the nation's largest industrial user of water, de-
spite the fact that water use by steam electric utilities has
decreased dramatically over the past decade. According to the
Bureau of the Census, in 1975 steam electric plants used
89 billion gallons of water per day; by the year 2000 it is
expected to decrease to 80 billion gallons. Even with contin-
uing declines in usage per plant, electric utilities will
account for more than one-third of the nation's total water
use over the next two decades and for more than twice as much
water use as all other industrial plants combined.
Current regulations to control water pollution were man-
dated by Congress in the Federal Water Pollution Control Act
of 1972 (the Clean Water Act) as amended in 1977. The ap-
proach taken by regulations implementing the Clean Water Act
differs in important respects from the approach taken by air
regulations. Whereas ambient air quality standards drive
regulations controlling air pollution, technology standards
dominate water pollution control. Consequently, while air
regulations have imposed different standards for attainment
and nonattainment areas, federal regulations to control water
pollution generally have not differentiated among regions of
the country. States, of course, can and do impose additional
water-quality-related requirements.
The basic mechanism for enforcing the requirements of the
Clean Water Act is the national pollution discharge elimina-
tion system (NPDES) permit required for all point source dis-
charges into the navigable waters of the United States. NPDES
permits incorporate specific pollution control requirements
based on effluent limitations guidelines that have been issued
periodically by EPA. In practice, the major standards apply-
ing to electric utilities have been best practicable control
technology (BPT), specifying standards to be met by July 1,
1977; best available technology economically achievable (BAT),
specifying standards for toxic pollutants to be met by July 1,
1984; and NSPS, setting requirements for plants commencing
construction after a given date (usually the date of proposal
of the regulations containing the NSPS).
Until recently, electric utility solid waste disposal
practices have received little attention relative to utility
air and water pollution practices. Electric utility solid
wastes include: by-products of coal combustion and flue gas
cleaning such as ash and scrubber sludges; chemical wastes
from metal cleaning, from degreasing, and from wastewater and
makeup water cleaning; and hazardous substances (notably
polychlorinated biphenyls—PCBs) contained in electrical
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1-10
c. .... r, 0 Thrpe f3.Ct03TSf tlOWSVSJT, tlSV©
equipment such as transforme . .soiid wastes: (1) the
focused increasing attention o Qr poiiution regulations
increasing stringency of air themselves generate
that have led to control f"^^me or all of these
solid waste; (2) the possibill y dous„ under the Resource
wastes may be designated as RA) and therefore will re-
Conservation and Recovery Act and (3) an increasing
quire expensive d^®PosJ1 waSte'disposal in the wake of
awareness nationwide of solid was
events at Love Canal and elsewhere.
The major federal ^®gu^gQ®rce9Conservation and Recovery
posal were mandated by t^ie required to develop an inte-
Act of 1976. Under RCRA' f ^a^dou2 and solid wastes. As
grated program for ®anJ9^;Lous waste management aspect of the
provided by RCRA, the haza;r . . lly by EPA, but authority for
program would be de^®.1J£e| lec.ated subsequently to states with
implementing it would be de g^^ programs. Programs for
programs equivalent to the wastes were to be developed by
managing nonhazardous soil aeneral minimum guidelines
individual states, provided that gener^
promulgated by EPA are me
i-.T nrnorains for air, water, and solid
Though environment/^JL-^tory context, they come together
waste are distinct in a . 9 llutants removed by wet systems
at individual plants, a v eate waste streams controlled
to comply with air regu3;a . turn generate sludges that must
by water regulations, which in ^idywaste regulations. The
bi disposed in compliance witheSol^.^ £or 9.^ ^
overlapping c°Yefa?®s ?;t electric utilities consider cross-
solid wastes dictate ^ha „H+-hin the context of unit and
media compliance stEa*e9 antitative assessment presented in
plant operations. The sRantitativ aDoroach.
this study is consistent with that approac
Tha BffAPts of Environmental Regulations
on Utility operations and Plans
,-1-4-^nc affect both the operation of
Environmental reg . the pianning for future ca-
existing utility po e p wg wifch the case study companies
pacity additions. In regarding their compliance
uncovered £wr ^^^"iSrSowatJlants. First, the
activities associa achieving compliance at existing
ooSerSlantt tlrils grJatly among utilities and appears to be a
powerplants varies g ambient air quality near power-
olants°nthe*types of fuel consumed, and the stringency of
SHs Seclndf as is corroborated by the quantitative umt-
Xevei analysis discussed in Chapter IV, utilities have
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1-11
complied with the most costly regulations—those related to
SO2 primarily by increasing the quality of their fuels rather
than by installing equipment. Third, utilities fully accept
their responsibility to monitor pollutant emissions and report
violations accurately to BPA or state environmental agencies.
Finally, to reduce capital and operating costs, utilities have
usually sought to reduce the stringency of regulations they
have to meet through negotiation or litigation.
The TBS interviews also revealed a pervasive concern that
financial considerations will become more influential in util-
ity decision making and will hamper the ability and willing-
ness of utilities to meet the capital requirements associated
with capacity expansion and pollution control. The full im-
pact of the industry's current weak financial condition has
not yet been felt, in part because load growth since 1974 has
fallen dramatically. Many utilities have continued the con-
struction of powerplants already under way before the falloff
in growth became apparent, but they have been able to pare
back other construction programs and lower their long-run
financing requirements. However, when future growth in demand
requires new capacity to be added, the large capital require-
ments associated with building new coal-fired powerplants may
be an obstacle for financially weak utilities. Perhaps as
important, even utilities that have relatively high bond rat-
ings—-e.g., those with A bond ratings—will be reluctant to
make investments that require the issuance of additional com-
mon stock if they expect future earnings to be inadequate. To
the extent that environmental regulations contribute to the
capital and operating costs of new capacity, both utilities
and consumers may attempt to modify environmental requirements
in an attempt to lower electricity costs and to avoid reduc-
tions in service reliability.
While some case study companies, principally those oper-
ating in areas with relatively good ambient air quality, are
not greatly concerned with prevention of significant deterior-
ation (PSD) regulations, other companies stated that, even in
the absence of financial constraints, existing air environmen-
tal regulations will all but eliminate their ability to site
coal-fired powerplants in the future. These companies are
convinced that existing PSD regulations are unworkable and are
actively working to secure passage of legislation to revise
them. These utilities believe that PSD increments will be
exhausted over time and that utilities will be required to
obtain offsets—which may be costly or unavailable at any
price. These beliefs are a point of contention with various
environmental officials.
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1-12
To avoid or to mitigate the _ financial and
difficulties associated with siting, case studv
new coal-fired powerplants, the majority o alternatives
utilities are actively pursuing othe- ffcxty^lternatxves.^
For example, some companies are expior ^ - ntili-
* i PP nrtn?id©rino his
torical standards of reliabil-
ties also are reconsidering historic*ai , * d there»bv
ity with an eye toward lowering such standar
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1-13
concern that, as new technologies are introduced, environment-
al standards will change, thereby creating additional uncer-
tainty and higher costs.
Utilities have responded to the challenges presented by
environmental regulations in several ways. First, they have
made their environmental affairs departments an important
element in the utility planning process. These departments
are typically responsible for gathering and assessing informa-
tion on regulatory requirements, costs, and risks and for
trying to anticipate changes in environmental regulations.
The departments attempt to reduce the potential adverse conse-
quences of uncertainty about regulations by identifying key
environmental issues, preparing contingency plans, and at-
tempting to maintain as much flexibility as possible in the
utilities' supply plans. Utilities also have supported lobby-
ing efforts to change requirements from a technology-forcing
orientation to an approach that focuses on meeting pollutant
loading goals. Finally, utilities have initiated research and
development activities that have contributed to their ability
to meet existing requirements in a cost-effective manner and
that develop technical expertise which can be used to support
negotiations and, when necessary, litigation.
The Effects of Environmental
Regulations on Electric Utility Units
The analysis of the effects of environmental regulations
on steam-electric generating units is based on data compiled
in the Energy Database from 1979 Form 67 submittals by util-
ities. The 2,277 units represent approximately 96 percent of
the total capacity of fossil-fired steam-electric units re-
ported in DOE's 1979 Inventory of Powerplants.
Distribution of Units by
Fuel Type and Age
Coal-fired units account for nearly 60 percent of the
capacity of units in the Energy Database (Table 1-1). The
remaining 40 percent of capacity is relatively evenly distrib-
uted among units that burn oil, gas, and oil and gas com-
bined.
Electric utility units are subject to different regula-
tory requirements depending on their in-service dates.
Eighty-six percent of the units in the Energy Database were in
service by 1972 (Table 1-2). Environmental compliance for
these units has consisted of retrofitting pollution control
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1-14
Table 1-1
DISTRIBUTION OF FOSSIL-
FUEL
UNITS BY FUEL TYPE
Percent of
Percent of
Fuel Type
Units
Capacity
Coal
47
59
Oil
17
15
Gas
17
13
Gas/Oil
19
13
Total
100
100
Source:
Energy Database.
equipment to comply with regulations for existing sources
promulgated under the Clean Air and Clean Water Acts. Units
that came into service in the 1972-1976 period, representsng
9 percent of the units, have also been subject toexisting
source air and water regulations, but in most cases compliance
for these units has consisted of installing original pollution
control equipment. Finally, units
since 1976, representing 5 percent of the units, ha e a
rule been subject to new source standards under the Clean Air
and Clean Water Acts.
Table 1-2
DISTRIBUTION OF FOSSIL-FUEL
UNITS
BY IN-SERVICE
YEAR
In-Service
Percent of
Percent of
Y£gr
Units
Capacity
Pre-1972
86
64
1972-1976
9
25
• 1976-1979
5
11
__
—
Total
100
100
Source: Energy Database.
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1-15
Environmental Compliance Strategies
Strategies for compliance with SO2 and TSP requirements
among coal units reflect increasingly stringent standards.
Twenty-three percent of coal capacity that came into service
before 1977 either burns coal with less than 0.8 percent sul-
fur or has flue gas desulfurization (FGD) systems (Table 1-3).
The proportion of capacity in this category rises dramatically
to 73 percent of 1977-1979 capacity and to 98 percent of capa-
city that is projected to come into service in 1980-1984.
This increase reflects primarily the increasing use of scrub-
bers (FGD systems) from 5 percent of pre-1977 capacity, to
35 percent of 1977-1979 capacity, and to 52 percent of 1980-
1984 capacity.
Table 1-3
DISTRIBUTION OF COAL
CAPACITY
BY REPORTED S02 COMPLIANCE STRATEGY
(percent of age-category capacity)
SO-j Compliance Strateay
In-Service Year
C0.8S Sulfur Coal Pre-1977
1977-1979
1980-1984
With FGD 2
22
14
Without FGD 18
38
46
_>0.8S Sulfur
With FGD 3
13
38
Without FGD 77
27
2
Total 100
100
100
Source: Energy Database.
Over 96 percent of the capacity in coal-fired units has
TSP collection systems whose removal efficiencies are above
98 percent (Table 1-4). Although all coal units attain high
levels of TSP removal, the types of equipment in place reflect
evolving regulatory requirements. Units that came into serv-
ice before 1972, for example, often have retrofitted electro-
static precipitators alongside older, less efficient mechan-
ical collectors.
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1-16
Table 1-4
DISTRIBUTION OF COAL CAPACITY BY
REPORTED TSP COMPLIANCE STRATEGY
(percent of age-category capacity)
TSP Collection
Efficiency
>98
96-98
90-95
<90
Total
Pre-1977 1977-1979
96
2
1
1
100
97
2
0
1_
100
Source: Energy Database.
Air pollution control strategies at oil and gas/oil units
consist primarily of the use of low-sulfur oil to control SO2
emissions. Over 60 percent of the capacity in oil-fired units
burns oil with less than 1 percent s£lfur i n
further 30 percent of this capacity burns oil with 1 to 2 per-
cent sulfur, and less than 10 percent uses oil with more than
2 percent sulfur (Table 1-5). Only 40 percent of oil and
oil/gas capacity has particulate control systems and less than
a fourth of these systems have removal efficiencies greater
than 98 percent.
Table 1-5
DISTRIBUTION OF OIL CAPACITY BY
REPORTED S02 CONTROL STRATEGY1
Fuel Percent
Sulfur
<0.9
1-1.9
>2.0 .
percent of
Capacity
63
29
8
11ncludes gas/oil units.
Source: Energy Database.
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1-17
Water pollution controls at steam-electric units are much
less elaborate and costly than air pollution controls. None-
theless, virtually all plants have central treatment facili-
ties to treat a number of relatively low-volume waste streams
simultaneously. In addition, some plants have installed ash
transport water recirculation systems which are no longer
required by federal regulations. Moreover, the use of cooling
towers or ponds to control thermal discharges is becoming
increasingly prevalent. The share of capacity with cooling
systems increases from less than one-third of pre-1972 capac-
ity to two-thirds of 1977-1979 capacity (Table 1-6). This
shift reflects both environmental requirements and an increas-
ing proportion of units sited in water-constrained areas where
recirculating cooling systems are used primarily for economic
rather than environmental reasons.
Table 1-6
DISTRIBUTION OF FOSSIL-FUEL CAPACITY
BY THERMAL CONTROL STRATEGY1
(percent of age-category capacity)
Pre-1972 1972-1976 1977-1979
With cooling tower
or pond 26 63 66
Without cooling
tower or pond 74 37 33
1Totals may not add to 100% due to rounding.
Source: Energy Oatabaae.'
Pollution Control Costs
The average annualized cost of pollution control at fos-
sil-fuel plants in 1979 was 3.88 mills per kWh of generation
(Figure 1-1). The dominant contributor to this cost was con-
trol of SC>2 emissions, which accounted for 2.72 mills per kWh
or 70 percent of total pollution control expenditures. The
remaining pollution control expenditures were relatively even-
ly divided among controls for TSP emissions and chemical and
thermal discharges. By cost component, the largest single
component of pollution control cost was a premium paid by
utilities for low-sulfur fuels. This premium accounted for
nearly 65 percent of the average cost of pollution control,
and contributed more than three times as much as did capital
expenditures to pollution control costs.
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1-18
Figure 1—1
COMPONENTS OF 1979 AVERAGE COST OF POLLUTION CONTROL
FOR FOSSIL FUEL UNITS
1979 DOLLARS
National Average Cost: 3.88 mills per kWh 3.88 mills per kWh
Source: Energy Database.
Energy Penalty
Operations and Maintenance
Capital
Fuel Premium
Thermal Control
Chemical Control
TSP Control
SO2 Control
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1-19
Consumption c5f oil for steam generation resulted in
greater pollution control expenditures in 1979 than did con-
sumption of coal or gas because of the premium paid by
Snii iS? lovf-sulfur oil (Figure 1-2). The average 6.86
lls P®:r kWh paid by utilities for low-sulfur oil was more
as 9reat as the low-sulfur coal premium and it
exceeded total pollution control expenditures by coal units.
Aside from the low-sulfur fuel premium, in 1979 coal
units incurred greater pollution control expenditures than did
units burning oil or gas. Coal units incurred average expen-
ditures of 1.85 mills per kWh for pollution control in addi-
tion to the fuel premium; oil, gas, and gas/oil units spent
0.5 to 1.0 mills per kWh for capital and nonfuel operating
costs. The major reasons for these greater costs incurred by
coal units were their expenditures for scrubbers and TSP con-
trol systems.
The major trend in pollution control costs is a continu-
ing rise, in capital expenditures. Coal plants, which will
increasingly dominate fossil-steam capacity, exhibit dramatic
increases in pollution control capital costs over time (Fig-
ure 1-3). Among pre-1972 coal units, capital costs accounted
for 1979 pollution control costs of 0.76 mills per kWh. This
cost increased by 270 percent to 2.81 miils per kWh for units
that were subject to NSPS I regulations. In the future, with
higher costs for scrubbers required for all new coal units
under NSPS II regulations, capital costs will continue to
increase. If eastern utilities choose to burn high-sulfur
coal with high-efficiency scrubbers, a decrease in the low-
sulfur coal premium may partially offset higher capital costs.
In the future, scrubber costs will increasingly dominate
pollution control costs. Approximately one-half the capacity
that will come into service in the United States from 1980
through 1984 will meet NSPS II requirements. In the West,
80 percent of the NSPS II capacity will install scrubbers with
70 percent removal efficiencies. The remaining 20 percent of
western capacity will be located at sites where more stringent
emission limits will require scrubbers with 90 percent removal
efficiencies as well as low-sulfur coal. In the East, about
90 percent of the NSPS II capacity will install scrubbers with
greater than 90 percent removal efficiencies and burn high-
sulfur coal. Thus only the 10 percent of the eastern NSPS II
units that burn low-sulfur coal will incur a fuel premium.
Costs for future units meeting NSPS II requirements were
calculated using engineering cost assumptions supplied by EPA.
These costs will range from 9.4 mills per kWh for western low-
sulfur coal units to 13.4 mills per kWh for eastern low-sulfur
-------
1-20
Figure 1—2
COMPONENTS OF 1979 NATIONAL AVERAGE COST OF POLLUTION CONTROL
FOR FOSSIL FUEL UNITS BY FUEL TYPE
1979 DOLLARS
28%
.•.v.v.v.v.-.v.v.v.v.v.-.v
COAL
3.68 mills per kWh
J2%
OIL
7.89 mills per kWh
GAS
0.55 mills per kWh
Energy Penalty
Operations & Maintenance
J Capital Cost
Fuel Premium
yTotal (Gas Units Only)
I 7%
1%
. 3%
89%
GAS/OIL
4.72 mills per kWh
9%
13%
60%
COAL
3.68 mills per kWh
2%
OIL
7.89 mills per kWh
GAS
0.55 mills per kWh
r I Thermal Control
I Chemical Control
TSP Control
3 SOj Control
V // J Total (Gas Units Only)
9%
89%
^2%
—<1%
GAS/OIL
4.72 mills per kWh
Source: Energy Database; TBS calculations.
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1-21
Figure 1—3
COMPONENTS OF 1979 NATIONAL AVERAGE COST OF POLLUTION
FOR COAL UNITS BY AGE CATEGORY
1979 DOLLARS
Energy Penalty
Operations & Maintenance
Capital Cost
Fuel Premium
JSBSWfR
mm*®.
-1%
13%
15%
'
28° o
44%
Pre—1972 Units
3.42 millt per kWh
1972-1975 Units
3.47 mills per kWh
10%
12%
iSASSiKKfiS:
49% ^
'¦*' V'v.vXv
lilililiil
: 29%
Post—1976 Units
5.81 mills per kWh
t- .] Thermal Control
I I Chemical Control
PSM TSP Control
SOj Control
¦... ~
f< 1%
25%
10%
54%
j|i|v-ri'ni
17%
63%
Pre—1972 Units 1972-1976 Units
3.42 mills per kWh " 3.47 mills per kWh
Post-1976 Units
5.81 mills per kWh
Source: Energy Database.
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1-22
coal units. Given existing wet scrubbing technologies for
eastern units, 90 percent removal scrubbing on eastern high-
sulfur coal is slightly less costly than 70 percent removal
scrubbing on more expensive low-sulfur coal. If less costly
dry scrubbing technologies become generally available for
eastern low-sulfur coal, 70 percent removal dry scrubbing will
become economically more attractive.
Pollutant Removal and Cost Effectiveness
Nationally, in 1979, electric utility air pollution con-
trol measures resulted in the removal from the atmosphere of
approximately 42 percent.of potential SO2 emissions of 29 mil-
lion tons and 98 percent of potential TSP emissions of 46 mil-
lion tons (Table 1-7). Coal units contributed the dominant
share of both potential emissions and pollutant removals,
reducing emissions of TSP by 98 percent from over 45 million
tons to less than 1 million tons and SO? by 37 percent from
24 million tons to 15 million tons. Oil units and gas/oil
units reduced potential emissions of SO2 by 70 percent from
5 million tons. Oil and gas/oil units had only minor TSP
emissions, and units that only burn gas do not emit SO2 or
TSP.
Table 1-7
TOTAL NATIONAL POTENTIAL AIR POLLUTANT
EMISSIONS AND REMOVALS
BY FUEL TYPE
(thousands of tons)
1
i
! IS
j N>
TSP
Potential
Total
Percent
Potential
Total
Percent
Fuel Tvd(
) Emissions
Removed
Removed
Emissions
Removed
Removed
Coal
24,398
9,015
37
45,651
44,775
98
Oil
2,695
1,783
68
170
143
84
Gas/Oil
1,954
1,418
73
127
1Q0
79
Total
29,047
12,216
42
45,948
45,018
98
5ource:
Energy Database and TBS calculations.
As shown in Table 1-8, the average cost of removing pol-
lutants varies significantly among unit categories and pollu-
tants. In 1979, the average cost of reducing SO2 emissions
was $461 per ton. The cost of reducing these emissions was
nearly three times as great at oil-fired units as it was at
coal-fired units. Among coal units, reducing SO2 emissions
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1-23
was on average nearly twice as expensive using scrubbers as it
was using low-sulfur coal. The national average cost of re-
ducing TSP emissions was $22 per ton. This average cost is
dominated by the low average cost of removing very large quan-
tities of TSP at coal-fired units. Removal costs for future,
NSPS II, units are dominated by scrubbers and are projected to
be significantly greater than costs at existing units. On a
weighted average basis, SO2 and TSP removal costs will at
least double or triple compared to 1979 removal costs.
Table 1-8
AVERAGE COST PER TON OF S02 AND TSP REMOVAL
(1979 dollars per ton)
so2
Removal Strategy
Fuel Type
1979 Generation
Low-
Sulfur
Coal
Low-
Sulfur
Oil
Scrubbers
Total
TSP
Equipment
Coal
229
412a
418
263
20
Oil
N/A
737
N/A
737
534
Gas/Oil
N/A
742
N/A
741
b
National Total
229
721
418
461
22
NSPS II Units
Eastern Low-
219
1,145
385
80
Sulfur Coal
Eastern High-
Sulfur Coal
0
417
417
47
Western Low-
Sulfur Coal
0
1,347
1,347
67
N/A a Not applicable.
aSome coal units burn both coal and oil; these units attain reductions
in SO2 from both fuels,
b = Insufficient observations.
Source: EPA; Energy Database; and TBS calculations.
The Regional Effects of
Environmental Regulations on
the Electric Utility Industry
Each of the ten EPA regions (Figure 1-4) has a unique
profile of existing capacity by age of unit and fuel type and,
-------
Figure 1—4
EPA REGIONS
-------
1-25
therefore, is affected differently by environmental regula-
tions. Generally, units in the eastern regions are older than
in the western regions. More than 30 percent of eastern ca-
pacity was installed before 1960; only 6 percent of western
capacity is of that vintage. Seventy-five percent of coal-
fired capacity and 45 percent of oil- and gas-fired capacity
is in the East.
Each region's profile influences the most likely range of
pollution control strategies for the region. The strategies,
whether they involve equipment or fuels upgrading, are trans-
lated into costs that the average regional customer pays for
service.
Regional variations in the average costs of compliance
for unit categories capture the effects of differing fuel
mixes, fuel quality, and preferred compliance strategies.
These are summarized in Table 1-9. Although the national
average cost of pollution control across all units in 19 79 was
3.88 mills per kWh, regional costs range from a high of
8.35 mills per kWh in Region I to a low of 1.07 mills per kWh
in Region VI. In every region except Regions VI and VIII
(which have relatively low average costs), low-sulfur fuel
premiums dominate the costs.
Existing Capacity:
Costs or Compliance
Oil-fired units relied exclusively on low-sulfur fuel to
achieve compliance with SO2 standards in 19 79. This is re-
flected in the national average fuel oil premium of 6.86 mills
per kWh, and substantially affects the eastern regional costs.
Region I, with 99 percent of its fossil-fuel capacity in oil
units, faced a low-sulfur oil premium of 7.56 mills per kWh,
more than 90 percent of Region I's average pollution control
costs. Without a change in capacity mix in the future, Region
I's utility customers will face an even greater differential
in costs if, as projected, the fuel oil premium escalates at a
more rapid rate than the cost of alternative compliance
methods.
The relatively high costs in Region II are driven by SO2
control strategies at both oil-fired and coal-fired units.
More than half of Region II's 1979 generation was provided by
oil-fired units; one-quarter of its 1979 capacity was in
-------
1-26
Table 1-9
DETERMINANTS IN REGIONAL POLLUTION CONTROL COSTS
EPA
Region Dominant Capacity Type
I Pre-77 oil units
II Pre-77 coal and oil units
III
VI
Pre-77 coal and oil units
IV Coal units and pre-72 oil units
Coal units especially pre-72
Post-72 coal units, pre-72 gas units
VII Coal units; pre-72 gas units
VIII Coal units, especially post-76
IX Pre-72 oil and gas units; pre-77
coal units
X 72-76 coal units; pre-77 oil units
Reasons for Costs
(in order of relative magnitude)
Fuel (oil) premium
Fuel (coal and oil) premiumi FGD capital
and operating costs
Fuel (coal and oil) premium? pre-72 coal
FGD, TSP, and chemical control
Fuel (coal and oil) premium; coal pre-72
TSP and chemical control
Fuel (coal) premium; TSP control;
chemical control
Thermal and chemical control
Fuel (oil) premiu# for coal units that
also burn oil; TSP control
TSP control? FGD for post-76 units;
thermal and chemical control
Fuel (oil) premium; thermal and chemical
control for coal and oil units
Fuel (oil) premium; TSP control; thermal
and chemical control For coal units
Weighted Average
Unit-Category
Costs of Compliance
(tnills/WWh)
8.35
6.18
4.36
4.41
3.73
1.07
4.53
2.94
4.53
2.35
Source: Energy Database and TBS calculations.
service before 1972. The costs of SO2 control at coal units
in Region II demonstrate the evolution of compliance strat-
egies over time. In 1979, units installed before 1972 de-
pended exclusively on improved fuel quality, while units
installed after 1972 reflect the influence of NSPS I require-
ments in environmental standards. These units combined lower
sulfur (but not compliance) coal with FGD equipment. Costs
for the 1972-1976 units were no greater than for the pre-1972
units, but units installed after 1976, in meeting the nSPS I
emissions limit of 1.2 pounds of SO2 per million Btu, faced a
tripling of costs for SO2 control.
-------
1-27
As of 1979, coal-fired capacity in Region VIII accounted
for three-fourths of its total fossil-fuel capacity, with
nearly one-third of the coal capacity in NSPS I units. Con-
trol costs for units with in-service dates after 1976 were
150 percent greater than the average costs for units of all
vintages. The components of the high pollution control costs
include TSP control systems, FGD equipment, thermal control
equipment, and energy penalties and operating costs associated
with the capital strategies. These costs reflect, at a mini-
mum, the compliance requirements of the next two decades, as
new coal units are subject to NSPS I, NSPS II, and at times
even stricter best available control technology (BACT)
requirements.
Expansion plans for utilities during the 1980s are pro-
jected to favor nuclear and coal capacity. All regions will
participate in the growth of nuclear capacity, which will
nearly double by 1990 if units currently under construction
are completed as planned. Pollution control requirements for
nuclear units resemble gas units in their emphasis on thermal
and chemical control and in their low costs of compliance.
Oil and gas conversions to coal will contribute to a substan-
tial increase in coal capacity in Regions I, II, Illf and IV,
and new coal capacity will dominate total additions in all
regions except IX and X.
New Coal-Fired Capacity:
Costs of Compliance
The emphasis on new coal-fired capacity will present
significant environmental concerns during the 1980s. Although
NSPS I standards can be met without installing scrubbers, it
is expected that eastern units generally will install FGD
equipment with removal efficiencies of 85 to 90 percent and
will burn high-sulfur coal. In the West, approximately one-
third of all new capacity in Regions VI and VII will be
scrubbed, and nearly all new capacity in Region VIII will be
scrubbed.
The projected average cost of compliance for SO2, TSP,
thermal and chemical control for new 1980-1984 coal-fired
capacity is 7.4 mills per kWh (in 1979 mills). The range is
broad, from a low of 5.3 mills per kWh in Regions IX and X
where the use of low-sulfur coal is the preferred strategy and
scrubbers are rare, to a high of 8.6 mills per kWh in Re-
gion VIII where scrubbers with removal efficiency of 90 per-
cent are combined with fuel that has less than 0.8 percent
sulfur content.
-------
1-28
Specific compliance strategies for NSPS II additions in
the latter half of 1980 and beyond are difficult to predict,
although scrubbers will be required on all coal-fired units.
Individual units may choose a strategy of higher quality coal
and 70 percent removal efficiency in the scrubber design or
lower quality coal and 90 percent design removal efficiency.
On the basis of the assumptions described in Chapter IV,
eastern NSPS II compliance strategies are projected to cost
12.4 mills per JcWh, while western compliance strategies will
cost 9.4 mills per kWh.
National Issues That
Affect Compliance
Several issues that are national in scope may have a
bearing on future regional compliance requirements and costs.
These include: regional growth patterns and their effects on
emissions; PSD and regional air-quality-related values; and
regional siting in attainment and nonattainment areas.
Changes in growth patterns can have a noticeable effect
on air quality and on the level of control necessary to
achieve and maintain the NAAQS. The Clean Air Act requires
that states incorporate in their SIPs the application of ap-
propriate controls based on growing or diminishing emissions.
If industrial growth occurs at a higher than predicted rate in
the Southeast or Southwest, or if conversions to coal increase
SO2 emissions in the East, powerplants may be required to meet
more stringent emission limitations by installing complex and
costly equipment.
Visibility impairment, particularly in the West, and acid
precipitation, particularly in the Bast, are two air-quality-
related values that may be the focus of much attention over
the next few years. An important element of the PSD program
is the consideration of these values during review of a permit
application. To the extent that objectives in these areas
change, and lead to changes in PSD requirements, compliance
strategies and costs will change over time.
The technology requirement for major sources in attain-
ment areas is less stringent than the requirement in nonat-
tainment areas. Further, the offset requirement exists only
in nonattainment areas. In the future, growth may be limited
in nonattainment areas if_ offsets are unavailable or extremely
costly, although interregional effects are difficult to quan-
tify at this time.
-------
1-29
The National Effects nf Environment*n
Regulations on the Electric utility Industry
effects of environmental regulations na-
ne*t two ^eca<^es * TBS examined five key
ii-if ?«.I«5
-------
1-30
Table
M
1
t—
o
SUMMARY OF INDUSTRY CUMULATIVE EXPENDITURES
WITH AND WITHOUT POLLUTION CONTROLS
(billions of 1982 dollars)
Chanaes in Plant In-Service
1980-1985
1980-1999
Baseline
Pre-1980 Pollution Control
Equipment
Incremental Pollution Controls
199.17
0
18.45
1,041.49
0
87.28
Total
217.62
1,128.77
External Financino
Baseline
Pre-1980 Pollution Control
Equipment1
Incremental Pollution Controls
151.78
(1.31)
18.17
857.63
(2.28)
70.46
Total
168.64
925.81
ODeratina Revenues
Baseline
Pre-1980 Pollution Control
Equipment
Incremental Pollution Controls
594.05
D.99
44.31
2,684.23
45.00
218.26
Total
652.35
2,947.49
Ooeration and Maintenance Exoenass
Baseline
Pre-1980 Pollution Control
Equipment
Incremental Pollution Controls
404.28
8.42
39.86
1,671.88
35.69
154.57
Total
452.56
1,862.14
Consumer Charoes2 (mills oer kWh)
Baseline
Pre-1980 Pollution Control
Equipment
Incremental Pollution Controls
44.35
0.91
3.65
51.15
0.67
4.34
Total
48.91
56.16
Note: See Chapter VI, pages VI- 36
cost measures used above.
to VI-39, for
a definition of the
1While there are no planfc. additions for pre-1980 pollution controls in
the 1980-1999 period, external financing requirements are reduced be-
cause of the greater amounts of plant in-service as of 1980 for the
pre-1980 equipment. This increases dspreciation and retained earnings,
and reduces external financing requirements.
^Consumer charge figures are not cumulative, but represent the annual
consumer chsrges for the lest year of the period indicated measured in
mills per kilowatt-hour.
Sources PTm(Electric Utilitiee).
-------
1-31
fact on the industry's balance sheets. Cumulative pollution
control operating revenues through 1999 are $263.3 billion, or
9 percent of the total of $2,947.5 billion, as shown in
Table 1-10. Cumulative pollution control operation and main-
tenance expences are $190.3 billion, slightly more than
10 percent of the total of $1,862.1 billion. Consumer charges
in 1999 for pollution controls are 5.01 mills per kWh, or
9 percent of the total 56.16 mills.
Table 1-11^provides a breakdown of plant additions by
pollutant and time period. SO2 controls represent $43.3 bil-
lion or about half of all the major pollution control-related
expenditures over the 1980-1999 period. TSP controls account
for $21.9 billion or 25 percent of total pollution control-
related plant additions, while water pollution and solid waste
control costs represent the remaining $22.0 billion or 25 per-
cent. Of the total of $87.3 billion of pollution control
Table I-11
CHANGES IN PLANT IN-SERVICE ATTRIBUTABLE
POLLUTION CONTROL REGULATIONS
TO
(billions of 1982 dollars)
Baseline Chanoes in Plant
In-Service
1980-1985
199.17
1980-1999
1,041.49
Pre-1980 Pollution Controls
Equipment
0
0
Incremental Pollution Controls-
Fuel Premium1: Pre-1980 Units
Fuel Premium1: Post-1979 Units
so2
TSP
Solid Waste
Water
0
0
8.91
5.68
1.85
2.01
0
0
43.32
21.94
10.98
11.04
Total Pollution Controls
18.45
87.28
Total
217.62
1,128.77
^uel premiums and other pre-1980 pollution controls do
not have capital charges associated with them in the
1980-1999 period. The post-1979 unit cstegory includes
any coal conversions.
Source: PTm(Electric Utilities).
-------
1-32
plant additions, 16 percent or $13.6 billion is attributable
to capacity penalties associated with new pollution control
equipment.
The external financing requirements associated with pol-
lution controls amount to $68.2 billion or about 7 percent of
the industry's projected total requirement (Table 1-12). The
contribution to external financing requirements by pollutant
corresponds closely to their contribution to plant additions.
External financing requirements will be higher in the early
years of the period as the industry raises capital to finance
control equipment retrofits and pollution control equipment
for oil-to-coal reconversions. This fact, coupled with
Table 1-12
EXTERNAL FINANCING EFFECTS OF
POLLUTION CONTROL REGULATIONS
(billions of 1982
dollsrs)
1980-1985
1980-1999
Baseline External Financina
151.78
857. 63
Pre-1980 Pollution Controls
Eauioment1
(1.31)
(2.28)
Incremental Pollution Controls
Fuel Premium^, pre-1980 Units
Fuel Premium^: Post-1979 Units
SO,
TSP
Solid Waste
Water
0
0
8.78
5.41
1.93
2.05
0
0
35.21
17.24
9.03
8.98
Total Pollution Controls
16.86
68.18
Total
168.64
925.81
While there are no plant additions for pre-1980 pollution
controls in the 1980-1999 period, external financing is
reduced because of the greater amounts of plsnt in-service
as of 1980 for the pre-1980 equipment. This increases de-
preciation and retained earnings, and reduces external
financing requirements.
^Fuel premiums are operating costs and do not have capital
charges associated with them. The post-1979 unit category
includes any coal conversions.
Sources PTm(Electric Utilities).
-------
1-33
capital constraints that currently exist in the industry,
could create difficulties for individual utilities.
Pollution control costs represent $263.3 billion, or
approximately 9 percent of the industry's total revenue re-
quirements during the 1980-1999 period (Table 1-13). Post-
1979 SO2 controls including all fuel premiums represent
62 percent of the total pollution control-related revenue
requirements. The price premium for low-sulfur fuels alone
represents the largest single component of the increase in
revenue requirements—almost 40 percent. The other pollution
control categories contribute less importantly to total cost
increases and therefore revenue requirements. Post-19 79 solid
waste disposal costs, however, do rise over the period and
become a significant fraction, 7 percent, of total cumulative
pollution control-related revenue requirements by 1999.
Table 1-13
OPERATING REVENUE
POLLUTION CONTROL
EFFECTS OF
REGULATIONS
(billions of 1982 dollars)
1980-1985
1980-1999
Baseline ODeratina Revenues
594.05
2,684.23
Pre-1980 Pollution Controls
EauiDment
13.99
45.00
Incremental Pollution Controls
Fuel Premium*: Pre-1980 Units
Fuel Premium1: Post-1979 Units
SO,
TSP
Solid Waste
Water
32.70
1.19
5.31
2.01
2.15
0.95
96.45
7.76
59.30
22.04
19.40
13.31
Total Pollution Controls
58.30
263.26
Total
652.35
2,947.49
^Fuel premiums are typically considered SO2 costs but are
shown separately here because of their large effect on
total pollution control costs. The post-1979 unit cate-
gory includes any coal conversions.
Sources PTm(Electric Utilities)
•
-------
1-34
Operation and maintenance expenses associated with pollu-
tion control equipment are expected to be $190.3 billion, or
10 percent of the total operation and maintenance expenses
(Table 1-14). The vast majority of pollution control-related
operation and maintenance expenses reflect the premium paid by
utilities for low-sulfur fuels. Costs associated with the
operation and maintenance of scrubbers (SO? controls) in-
stalled after 1979 also represent a significant portion of the
total, at 14 percent. Solid waste is the only other category
for which post-1979 operation and maintenance expenses are
significant, accounting for approximately 6 percent of total
pollution control-related operation and maintenance expenses.
Energy penalties resulting from scrubbers, TSP controls, waste
disposal controls, and .thermal controls installed after 1979
represent 3.4 percent of total pollution control operation and
maintenance expenses, or $6.5 billion.
Table 1-14
OPERATION AND MAINTENANCE EXPENSE EFFECTS
OF POLLUTION CONTROL REGULATIONS
(billions of 1982 dollars)
1980-1985 1980-1999
Baseline 0AM ExDense8
404.28 1
,671.88
Pre-1980 Pollution Controls
Equioment
8.42
35.69
Incremental Pollution Controls
Fuel Premium1: Pre-1980 Units
Fuel Premium1: Poet-1979 Units
S02
TSP
Solid Waste
Water
34.09
1.24
2.49
0.02
1.67
0.35
100.52
8.10
26.05
3.51
11.48
4.94
Total Pollution Controls
48.28
190.29
Total
452.56 1,
862.17
Fuel premiums are typically considered SO2 costs but are
shown separately here because of their large effect on
total pollution control costs. The post-1979 unit cate-
gory includes any coal conversions.
Sources PTm(Electric Utilities).
-------
1-35
Consumer charges attributable to pollution control expen-
ditures are shown in Table 1-15. The increased cost per kWh
is approximately 9 percent in 1999. As is the case with other
measures of the effects of pollution controls, post-1979 SO2
controls including fuel premiums represent the single largest
cost category, accounting for 57 percent of the total increase
in consumer charges attributable to pollution control regula-
tions. The remaining 30 percent is split relatively evenly
between costs for controls installed as of 1979, TSP controls,
water pollution controls, and solid waste controls.
Table 1-15
CONSUMER CHARGE EFFECTS OF
POLLUTION CONTROL REGULATIONS
(mills per kilowatt-hour in 1982 dollars)
1985
1999
Baseline Consumer Charaes
44.35
51.15
Pre-1980 Pollution Controls
Eauioment
0.91
0.67
Incremental Pollution Controls
Fuel Premium*: Pre-1980 Units
Fuel Premium*: Post-1979 Units
S02
TSP
Solid Waste
Water
2.12
0.13
0.71
0.30
0.26
0.13
1.00
0.17
1.70
0.59
0.49
0.39
Total Pollution Controls
4.56
5.01
Total
48.91
5 6.16
*Fuel premiums are typically considered SO2 costs but are
shown separately here because of their effect on total
pollution control costs. The post-1979 unit category
includes any coal conversions.
Source: PTm(Electric Utilities).
TBS examined two alternative scenarios in the course of
this study. The summary results of that examination are
-------
1-36
presented in Figure 1-5. The changes in assumptions used to
develop these scenarios are:
• Reduction in the growth rate during the 1980-
1999 period from 3.0 percent to 2.0 percent,
and
• Nuclear prohibition after 1989, with coal in
place of the nuclear additions assumed in the
base case.
A decrease in the industry's annual r*te of growth re-
sults in lower baseline plant additions and '
and lower pollution control expenditures. f
centage increase in consumer charges due to pollution controls
is essentially unchanged from the base case.
Baseline and total plant additions are slightly lower if
nuclear additions are assumed to terminal after 1989. How-
ever, cumulative industry pollution control additions to Plant
in-service through 1999 are slightly hl9her than hey would be
if nuclear additions were allowed to continue afte* 19®9*
Total operating revenues are virtually the same under both
scenarios. Consumer charges in 1999 are also essentially
unchanged under either scenario.
-------
Figure 1-5
COMPARISON OF CUMULATIVE PLANT ADDITIONS
AND OPERATING REVENUES
UNDER ALTERNATIVE SCENARIOS
CONSTANT 1982 DOLLARS
CUMULATIVE PLANT ADDITIONS
CUMULATIVE OPERATING
REVENUES
$1200
$1000
$800
BILLIONS
OF DOLLARS
$600
$400
$200
1129
1079
—
218
217
___
199
132
198
119
656
978
B
BASE 2% NO
CASE GROWTH NUCLEAR
1980-1985
pollution controli
bnssllna
$3000
$2500
$2000
BILLIONS
OF DOLLARS
$1500
$1000
$500
BASE 2% NO
CASE GROWTH NUCLEAR
1980-1999
2949
652
632
652
594
578
594
BASE 2% no
CASE GROWTH NUCLEAR
1980-1985
BASE 2% NO
CASE GROWTH NUCLEAR
1980-1999
Soiifc«: PTmlEloctric Utllitioi).
-------
-------
CHAPTER II
AN OVERVIEW OF
ENVIRONMENTAL REGULATIONS
AFFECTING ELECTRIC UTILITIES
-------
CONTENTS
INTRODUCTION II-1
THE CLEAN AIR ACT AND REGULATIONS
IMPLEMENTING THE ACT II-2
National Ambient Air Quality Standards II-3
New Source Performance Standards II-5
State Implementation Plans II-5
Attainment Policies II-6
Prevention of Significant Deterioration II-6
Visibility Standards II-7
Nonattainment Policies II-8
Offset Policy II-8
The 1977 Amendments II-9
SIP Revision Guidelines 11-10
Attainment and Nonattainment Interactions 11-10
Other Clean Air Act Provisions 11-11
Stack Heights 11-11
Section 125 Regional Coal Requirements 11-11
THE CLEAN WATER ACT AND REGULATIONS
IMPLEMENTING THE ACT 11-13
NPDES and Effluent Limitation Guidelines 11-15
1974 Best Practicable Control Technology
Standards
1975 Best Available Technology and
New Source Performance Standards
1977 Pretreatment Standards
Recent Developments Affect-
ing the Effluent Guidelines
1980 Proposed Effluent Limitation
Guidelines
Cooling Water Intake Standards
Water Quality Effluent Limitations
11-16
11-16
11-18
11-18
11-19
11-20
11-20
-------
CONTENTS
(continued)
REGULATIONS CONTROLLING THE
DISPOSAL OF SOLID WASTES 11-20
Resource Conservation and Recovery
Act and Regulations Implementing the Act 11-21
RCRA Section 3004—Hazardous Waste
Disposal Regulations 11-21
RCRA Section 4004—Nonhazardous Waste
Disposal Guidelines 11-22
Polychlorinated Biphenyls (PCBs)
Interim Control Measures 11-24
INTERACTIONS AMONG ENVIRONMENTAL REGULATIONS 11-24
Overlapping Regulatory Coverages 11-25
Cross-Media Effects 11-28
-------
II. AN OVERVIEW OF ENVIRONMENTAL REGULATIONS
AFFECTING ELECTRIC UTILITIES
INTRODUCTION
Environmental regulations applicable to the electric
utility industry are extensive because the industry is a major
generator of air, water, and solid waste pollution. They are
also complex and evolving because a multiplicity of interests,
objectives, and technical and scientific developments have
influenced and are influencing their development..
Although the electric utility industry traditionally has
had its own programs for controlling air, water, and solid
waste pollution, further requirements pertaining to each type
of pollutant have evolved separately through legislative,
regulatory, and legal processes at the local, state, and fed-
eral levels. The specific requirements often vary from plant
to plant, sometimes even from unit to unit in a plant, depend-
ing on a variety of considerations, including a generating
unit's age, location, fuel type, and technical configuration.
In addition to the air, water, and solid waste regulations,
the industry has to comply with other environmentally related
regulations, such as those that control and protect endangered
species and coastal zones.
In some geographic areas, it is arguable that regulations
affecting local utilities would be just as strict as they are
now even in the total absence of federal regulations. In some
other geographic areas, it is arguable that federal require-
ments are the sole driving force behind some existing regula-
tions. However, beause of the complexity of the interactions
among regulations, the appropriateness of these arguments
cannot readily be determined. Further, responsibility for the
detailed specification and enforcement of particular regula-
tions is often delegated from one level of government to'
another. Thus, this study does not attempt to partition envi-
ronmental regulations into those attributable to federal,
state and local initiatives.
A number of common themes apply to air, water, and solid
waste regulations. These themes are the involvement of num-
erous actors in the evolution of environmental regulations;
-------
II-2
the multiplicity of health, welfare, and economic considera-
tions to be met by the regulations; the paucity of conclusive
data on how well specific regulations meet these objectives;
and the tensions between flexibility in dealing with specific
situations, complexity, and predictability in their design.
So, in addition to discussing air, water, and solid waste
regulations separately, this chapter examines how they
interact.
THE CLEAN AIR ACT AND REGULATIONS
IMPLEMENTING THE ACT
The electric utility industry has been a major focus of
air regulation because of the large overall quantity of pollu-
tants it emits and because of the large amounts of certain
pollutants some plants emit. The regulated pollutants are all
combustion by-products. For example, through combustion,
natural, gas, coal, and oil form nitrogen oxides (N0„); sulfur
and sulfur compounds contained as impurities in coal and oil
become sulfur dioxide (SC>2>; and other solid impurities in
coal and oil emerge as particulate matter (TSP and fly ash).
Despite a shift to lower-sulfur fuels, the installation
of considerable amounts of pollution control equipment, and
changes in boiler design and operation already accomplished by
1977, the electric utility industry that year still emitted
about 18 million tons of SC>2» about 7 million tons of N0X'
and about 3 million tons of total suspended particulates
(TSP).1 These amounts accounted for about 65, 31, and 25
percent, respectively, of total mam-made emissions of each of
these pollutants. In the case of SO2# the average electric
utility plant had uncontrolled emissions substantially larger
than other industrial sources.
As reported in Chapter IV of this study (developed from
1979 utility submissions in the Energy Database), the industry
emitted about 17 million tons of SO2, about 7 -million tons of
N0X, and slightly less than 1 million tons of TSP in 1979.
During the late 1960s, Congress concluded that previous
state and federal initiatives to address the problems of air
lu.S. Department of Commerce, Bureau of the Census, "Air
Pollutant Emissions by Source, 1970 to 1979," Statistical
Abstract of the United States. 1979.
-------
II-3
pollution, including the Clean Air Act of 1964, were inade-
quate. So in 1970, Congress passed the Clean Air Act Amend-
ments (generally known as the Clean Air Act), which amended
the preexisting law into the overall structure it retains
today. The amended act established a new legal framework to
protect and enhance air quality and to oversee the implementa-
tion of air quality control programs.2 It directed EPA to
establish, and give states the responsibility for implement-
ing, nationwide National Ambient Air Quality Standards (NAAQS)
for both new and existing sources of pollutants and industry-
specific new source performance standards (NSPS) (see
Figure II-1).
In 1977, further amendments extended the deadline for the
attainment of all primary (health-related) standards. States
were to prepare and submit to EPA, by January 1979, revised
implementation plans for all nonattainment areas. The plans
were to provide for the implementation of all "reasonably
available control measures as expeditiously as practicable"
for existing sources and for "reasonable further progress,"
demonstrated on an annual basis, toward meeting standards.
The amendments also established a "prevention of significant
deterioration" (PSD) program to protect air that was cleaner
than the NAAQS. The amendments codified and expanded regula-
tions issued by EPA in response to a court order, and they
also changed the statutory standards under which NSPSs for
powerplants were issued. Congress is again reviewing the
Act.
The following section describes the major provisions of
the Act, along with the major decisions taken by EPA and the
courts to apply these provisions under changing conditions.
National Ambient Air Quality Standards
Promulgated by EPA in 1971, the NAAQS established ambient
air quality standards for seven pollutants during the 1970s.
Electric powerplants emit significant amounts, of three of
these pollutants—S02r NOxr and TSP. Although they also
emit another of these pollutants, carbon monoxide (CO), this
study do&s not discuss it because CO is predominantly asso-
ciated with motor vehicle emissions.
2The Clean Air Act (as amended), Public Law 91-604; Decem-
ber 31, 1970.
^Technical amendments to the Clean Air Act, Public Law 92-157;
November 18, 1971.
-------
II -4
Figure 11—1
OVERVIEW OF FEDERAL
AIR QUALITY REGULATIONS
CLEAN AIR ACT
1970
NATIONAL AMBIENT
AIR QUALITY STANDARDS
(NAAQS) (1971)
NEW SOURCE PERFORMANCE
STANDARDS (NSPS) (1971)
OFFSET
POLICY
(1976)
PSO
REGULATIONS
(1974)
STATE IMPLEMENTATION
PLANS XSIPs) (1972)
CLEAN AIR ACT
AMENDMENTS (1977)
FOR AREAS NOT IN
COMPLIANCE WITH NAAQS
_ BY 1977
FOR AREAS IN
COMPLIANCE WITH NAAQS
BY 1977
VISIBILITY
STANDARDS
(BART) FOR
EXISTING SOURCES
PSD
REQUIREMENTS
FOR NEW SOURCES
AND MODIFICATIONS
RACT FOR
EXISTING
SOURCES
OFFSET POLICY
FOR NEW
SOURCES
REVISED NSPS
(1979)
SIP REVISION GUIDELINES
(197B)
REVISED PSD REQUIREMENTS
(198D)
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II-5
The NAAQS affect both new and existing plants. Primary
NAAQS were designed to protect human health, "allowing an
adequate margin of safety." Secondary NAAQS were established
to protect "public welfare," defined as protecting such valued
things as vegetation, property, and scenery. For primary and
secondary NAAQS, the Agency promulgated both short-term
standards to protect against acute effects of exposure to high
pollutant concentrations as well as long-term standards to
protect against the effects of chronic exposure to lower
concentrations.
New Source Performance Standards
To ensure continuing improvements in air quality, the
Clean Air Act also required EPA's Administrator to set tech-
nology-based (or performance) standards for new plants. These
standards are based on the "best continuous system of ade-
quately demonstrated technology," considering cost, energy,
and nonair environmental effects. NSPS apply whether or not
an area meets the NAAQS.
NSPS for the electric utilities industry were first
established in 1971 and revised in 1979. The 1971 NSPS set
plant emission limits that could be met either by using low-
sulfur fuels or by installing pollution control equipment.
However, after Congress passed the 1977 amendments to the
Clean Air Act—which were intended to preserve the market for
higher sulfur coals and to minimize emissions from new plants
burning lower sulfur coals, especially in the West the 1979
NSPS required plants to use pollution control equipment to
reduce emissions regardless of the fuel burned.
State Implementation Plans
Under the Clean Air Act, all states must attain and main-
tain the NAAQS. The 1970 amendments directed them to submit
state implementation plans (SIPs) to EPA for approval and
promulgation before July 1972. Although it intended for these
plans to lead to attainment of the primary NAAQS by mid-1975,
the Act provided for a possible two-year extension to 1977.
To account for local circumstances, the country was
divided into 247 air quality control regions (AQCRs). In
essence the SIPs were intended to reduce overall emissions to
a level that ensured that all AQCRs within each state met the
NAAQS. Overall emission reductions within an AQCR would be
allocated by the states among plants in the AQCR.
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II-6
Attainment Policies
It is the responsibility of the states, with EPA review
and approval, to determine whether areas within the state are
attaining the NAAQS. The designation of an area as attainment
means that controls to prevent deterioration of the air qual-
ity will be required. This section discusses the applicable
attainment policies.
Prevention of Significant Deterioration
A major gap between the NAAQS and the NSPS concerned
areas of the country where air quality was already cleaner
than what the 1971 standards required. Under the NAAQS, air
quality in these areas, some of which were pristine, could
deteriorate to the level of the national standards. As a
consequence, industrial growth might tend to be directed
toward these regions because emission-related restrictions on
growth would be less extensive. Therefore, it was feared that
technology-based NSPS would not provide the framework for suf-
ficiently protecting areas with relatively pristine air
quality while not discouraging growth.
As the result of a 1972 suit that the Sierra Club brought
against EPA, the U.S. Supreme Court upheld the opinions of
lower courts and required the Agency to develop regulations to
prevent the significant deterioration of pristine areas.* In
December 1974, EPA issued its initial prevention of signif-
icant deterioration (PSD) regulations, which Congress later
modified and incorporated into the 1977 amendments to the
Clean Air Act.5
The PSD regulations directed the states to include in
their implementation plans limitations to building or modify-
ing sources of pollution in PSD areas. These areas were
divided into three categories:
• Class I—pristine areas with the tightest con-
trols ;
• Class II—moderate-growth areas capable of
tolerating some deterioration in air quality;
and
4Sierra Club v. Ruckelshaus. 4 ERC 1205 (1975)
539 PR 42510, 40 CFR 52.21, July 1, 1977.
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II-7
• Class III—areas designated for major indus-
trial growth where the deterioration in air
quality could be greater although still subject
to limits.
The PSD regulations set allowable increments, or limits
for increases in pollutant concentrations from baseline levels
in these areas (with the provision that the NAAQS be main-
tained). 6 They also subjected new and modifying plants to a
requirement that "b$st available control technology" to con-
trol emissions be installed. BACT was to be determined on a
case-by-case basis, but could not be less stringent than
NSPS.
In 1978, EPA revised its PSD requirements to, meet the new
requirements. Litigation followed and resulted in the invali-
dation of significant portions of these regulations. The
court decision resulted in major restructuring of the PSD
regulations in 1980, particularly regarding explicit defini-
tion of "major rnodification" and "stationary source," and
criteria for exclusion from full PSD review. Most important
from the standpoint of electric utilities was the exclusion
from full PSD review, under certain conditions, of a source
that voluntarily switched to a more polluting fuel (i.e., coal
conversions). This exclusion has been particularly signifi-
cant in such areas as the Northeast where extensive fuel
switching has occurred or is planned. An exclusion of poten-
tial future significance is that of federally mandated coal
conversions and natural gas curtailments.
Visibility Standards
In the 1977 Clean Air Act Amendments, Congress made pro-
visions for the protection of visibility in large national
parks and wilderness areas that, for the most part, enjoy the
benefits of very clean air. The Act states a policy against
visibility degradation caused by air pollution from human
activities and calls for controls on large^stationary sources
of pollution—both new and existing—-that impair visibility in
these Class I areas.
^Abstracting from many of the complexities, existing levels
are basically defined from a baseline of August 7, 1977.
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II-8
Visibility is impaired by atmospheric gases and small
particles either absorbing or scattering light. Powerplants
produce three pollutants that cause these effects. Nitrogen
oxides (N0X} emitted from the stack turn into NO2 gas and
absorb light at the blue end of the spectrum. This, in turn,
lends a brown or reddish color to the air. SO2 emitted from
the stack turns into sulfates that, together with the fine-
particle component of TSP, scatter light and produce a dulling
or hazy effect. Both discoloration and haze have degraded
visibility in Class I areas, particularly in western areas,
where the air is naturally so pristine that only a very small
amount of pollution produces a perceptible effect.
In December 1980, EP2V promulgated regulations to imple-
ment the visibility protection program called for by Congress.
In its supporting analysis, the Agency found no existing
sources that would have to add controls to protect visibility.
This finding does not mean that no existing sources are im-
pairing visibility. Rather, it means that the environmental-
energy-cost-balancing approach that the Act requires in these
decisions could not justify the addition of controls to those
sources identified.
Nonattainment Policies
As the 1975 NAAQS compliance deadline passed and as the
allowed two-year extension was also exhausted, it became ap-
parent that the Agency would have to deal with areas that did
not meet the NAAQS compliance schedule for particular pollu-
tants. Even the limited additional pollution allowed by the
NSPS would push these areas further out of compliance. The
Agency responded to this problem by developing the offset
policy.
Offset Policy
Originally promulgated in December 1976 and revised in
1979, the offset policy applies to new and modified facili-
ties.' Under the policy, EPA will grant a permit to build a
major new facility that will increase pollution in a non-
attainment area for a particular pollutant if the following
three criteria are met:
7Public Law 95-95, Section 129(A).
-------
II-9
First, the construction must result in a net reduction in
emissions in the area.' The permit applicant must provide the
emissions offset internally or must arrange with local sources
of pollution to reduce their emissions to more than offset the
emissions from the new source. Such a reduction is unnecessary
in an attainment area. Thus, a new plant in an SO2 nonattain-
ment area would have to negotiate an overall reduction in SO2
emissions but would be subject only to PSD requirements for
TSP.
Second, the new facility must use technology to realize
the lowest achievable emission rate (LAER). Like the best
available control technology (BACT), which is applied to new
sources in attainment areas, LAER cannot be less stringent
than USPS (either the 1971 or 1979 NSPS, depending on a
plant's commencement date). Permit writers are not, however,
instructed to account for energy and economic effects in mak-
ing LAER determinations, as they are in making BACT determina-
tions. In addition, they are required to set LAER emission
reduction requirements at the best level established for any
plant by any state's SIP. Consequently, while BACT is often
but not always equivalent to NSPS, LAER may impose more
stringent requirements.
Finally, other plants in the state owned by the applicant
must be in compliance with the applicable SIP guidelines.
The 1977 Amendments
When Congress enacted the 1977 amendments to the Clean
Air Act, it extended until December 1982 the deadline for
areas that had not yet attained the standards for the major
powerplant pollutants—particulates, N0X, and SO2. At the
same time, it required states to rewrite their implementation
plans for these pollutants. States that did not submit a
satisfactory implementation plan by July 1, 1979, were to be
forbidden to issue permits to new major stationary sources.
The new plans would have to contain new source review
procedures patterned on the offset provisions discussed above,
as well as a number of other provisions, including the instal-
lation of "reasonably available control technology" on exist-
ing sources.
-------
11-10
SIP Revision Guidelines
Implementing the 1977 amendments, the SIP revision guide-
lines were promulgated in 1978 to ensure nationwide attainment
of the NAAQS by 1982.8 They incorporated the offset policy
for new plants in nonattainment areas, and also, in some
cases, required emission reductions at existing plants.
States were to issue revised SIPs conforming to the guidelines
by June 1979. Until then, the offset policy would remain in
effect for new plants, and the 1972 SIPs would apply to exist-
ing plants. States that did not revise their SIPs in a timely
manner were to be forbidden to issue permits for new or modi-
fied major sources of air pollution.
To accomplish the objective of the guidelines, the 197 7
amendments established a tracking procedure called "reasonable
further progress," which had not existed in the original SIP
regulations.® As defined by the 1977 amendments, reasonable
further progress requires annual reductions in emissions of
nonattainment pollutants that are consistent with the attain-
ment of the NAAQS by 1982.
Applied to existing plants, reasonable further progress
is interpreted as reasonably available control technology
(RACT). This requirement has been defined as "the lowest
emission limit that a particular source is capable of meeting
by the application of control technology that is reasonably
available considering technological and economic feasibil-
ity. "1° In using this language, the Agency "has made it clear
that RACT calls for stringent or even 'technology forcing'
requirements that go beyond off-the-shelf technological con-
trols."3-1 For certain industries (primarily emitters of vola-
tile organic compounds), the Agency has issued RACT guidance
in the form of control techniques guidance (CTG) documents
describing state-of-the-art control technology. These docu-
ments, however, have not been developed for the electric util-
ity industry. Consequently, for electric utility plants,
states make case-by-case judgments of what constitutes RACT.
Attainment and Nonattainment Interactions
The offset policy for nonattainment areas and the PSD
policy for attainment areas interact in two major cases:
cross-boundary effects and pollutant-specific violations.
^Public Law 95-95, Section 129(a)
944 FR 3284.
^Jciean Air Act, Section 172(b)(3) (44 fr 20375).
-------
11-11
Cross-boundary effects increase the stringency of pollu-
tion control requirements if a source in an attainment area is
subject to the requirements of a neighboring nonattainment
area. As an example, a proposed source in an attainment area
that contributes to an NAAQS violation in a neighboring area
either would have to provide sufficient offsets to cover its
contribution to the violation (but only for its contribution
to the violation and not for its full emissions), or would
have to control its emissions so as to prevent the contribu-
tion.
Attainment and nonattainment status are determined for
individual pollutants. Consequently it is possible that a
plant in a nonattainment area will be subject to PSD require-
ments for attainment pollutants and to offset requirements for
nonattainment pollutants. Since the procedures (and the
permit-issuing authority) for offset and PSD programs may
differ, the level of a plant's emissions can subject it to two
full sets of preconstruction reviews.
Other Clean Air Act Provisions
Several other important provisions are included in the
Clean Air Act amendments. Two that have been the focus of
considerable recent attention are stack height requirements
and Section 125 regional coal use.
Stack Heights
In the 1977 Clean Air Act amendments, Congress stated
that sources of pollution could not use smokestacks taller
than good engineering practice (GEP) or other dispersion tech-
niques in place of constant emission controls to meet air
quality standards.
Emission limitations are set on the basis of ground-level
ambient pollutant concentrations. A tall stack releases emis-
sions into the atmosphere at a high level so that they can
disperse and become less concentrated by the time they reach
the ground than if they were released from a shorter stack.
If the ground-level concentrations are lower than the legal
limit, then the emission rate can be higher, and sources can
avoid putting on constant emission controls.
Section 125 Regional Coal Requirements
Section 125 of the Clean Air Act grants the President the
authority to prohibit large stationary sources of pollution
-------
11-12
from burning fuels other than locally or regionally available
coal to iheet SIP requirements. Such a prohibition can be made
if EPA's Administrator or the President_determines that it is
necessary to prevent or minimize significant local or regional
economic disruption or unemployment.
In effect, this section of the Act could potentially
limit switching to lower-sulfur coal as a compliance strategy
for utilities. For meeting a given emission limitation, this
strategy is generally preferred by utilities to the alterna-
tive compliance option—installing sophisticated pollution
control equipment (e.g., scrubbers).
Although Ohio and Illinois submitted petitions for action
on Section 125, EPA determined that such action was unwar-
ranted. One of the major factors impeding the use of 125 is
the fact that it requires the Agency to make difficult distri-
butional decisions. The absence of precise definitions for
such important terms as "local," "regional," and "significant
economic disruptions" makes these decisions particularly com-
plicated.
The inherent limitations of Section 125 can best be il-
lustrated by briefly analyzing the two potential responses
that can be applied to requests for action. First, by allow-
ing the utility to shift to lower-sulfur coal, the economic
disruption can simply be allowed to occur. Here, a large
portion of the costs would be borne (implicitly) by the dislo-
cated high-sulfur coal miners and other individuals whose
livelihoods depend upon the affected mines' operations.
The second alternative, whereby the utility would be
required to install pollution control equipment, would dis-
tribute the costs across the utility's customers. The conse-
quences of this choice, however, may prove to be more burden-
some than those associated with the first option: consumer
charges may increase considerably. In this instance, the
Agency inust first attempt to estimate the magnitude of the
increases and then, given the statutory requirement that the
final costs to consumers be taken into acount, judge th6ir
reasonableness. In addition, its application is likely to
give one segment of the coal market an advantage over another,
possibly resulting in miners in one state being employed at
the expense of miners in another state.
Although the possibility exists that a 125 action could
be taken and that the utility involved would be required to
continue to burn local coal and to install additional oollu-
tion control equipment, this section of the Act has not yet
been invoked.
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11-13
THE CLEAN WATER ACT AND REGULATIONS
IMPLEMENTING THE ACT
Water regulations have affected electric utilities less
than air regulations. Because the industry uses water prima-
rily for cooling, pollutants in most waste streams from elec-
tric powerplants tend to be similar and not highly concen-
trated. However, the volume of these streams can be very
large.
The electric utility industry is the nation's largest
industrial user of water, despite the fact that water use by
steam electric utilities has decreased dramatically over the
past decade. According to the Bureau of the Census, in 1975
steam electric plants used 89 billion gallons of water per
day; by the year 2000, this figure is expected to decrease to
80 billion gallons.12 Even with continuing declines in usage
per plant, electric utilities will account for more than one-
third of the nation's total water use over the next two
decades and for more than than twice as much water use as all
other industrial plants combined.
Plants with once-through cooling systems use the most
water. Once-through water is taken from a water body, used to
recondense spent steam that has passed through a turbine, and
discharged directly back into the water body after it has
passed through the condenser once. Pollutants potentially
subject to control in once-through cooling water are chlorine
(used to control algae growth within the condenser) and heat.
Recently, for environmental and water supply reasons,
electric powerplants have moved toward recirculating cooling
systems. In such systems, water used to recondense spent
steam is passed through a cooling tower or (less frequently) a
cooling pond. The waste stream, or blowdown, from such sys-
tems is the periodic discharge from the system needed to re-
move accumulated impurities. Pollutants potentially subject
to control in recirculating systems are chlorine, chemical
additives used to control scaling and corrosion within the
system, and heat.
l^u.s. Department of Commerce, Bureau of the Census, "Esti
mated Daily Water Use: 1940 to 1975 and Projections to
2000," Statistical Abstract of the United States, 1979.
-------
11-14
Ash transport water wastes are emitted by plants that
have wet-ash-handling systems to sluice fly ash from a boil-
er' s exhaust stack or ash from the bottom of a boiler. Pol-
lutants potentially present in ash-handling water include
total suspended solids, oil, grease, and trace elements from
ash.
Metal-cleaning and low-volume wastes are a third cktegory
of powerplant waste streams. Metal-cleaning wastes result
from occasional operations to remove scaling and corrosion
that can accumulate on boilers and condensers at all steam
electric plants. Low-volume wastes are a collection of small,
intermittent streams that also are present at all plants.
Wastewater from flue gas desulfurization systems is considered
part of low-volume wastes. Pollutants potentially present in
these waste streams include copper, iron, oil, grease, and
total suspended solids, as well as chemical preparations used
to clean metals.
Runoff, the final waste category, is greated when precip-
itation falls on various powerplant components, such as coal
storage, ash handling and disposal, construction, and chemical
handling equipment. Powerplants are required to have runoff
collection systems, and discharges from these systems are
subject to effluent limitations.
In 1972, Congress passed the Federal Water Pollution
Control Act. That act was amended by the Clean Water Act of
1977.13 The approach taken by regulations implementing the
Clean Water Act differs in important respects from that taken
by air regulations. Whereas ambient air quality standards
drive regulations controlling air pollution, technology
standards under section 301 of the Act dominate water
pollution control. Consequently, while air regulations have
imposed different standards for attainment and nonattainment
areas, federal regulations to control water pollution
generally have not differentiated among regions of the
country. States, of course, can and do impose additional
water-quality-related requirements.
The next section discusses the technology-based standards
governing the electric utility industry and other provisions
where these standards are insufficient to protect the environ-
ment.
13The Federal Water Pollution Control Act (p.l. 92-500) as
amended by the Clean Water Act of 1977 (p.l."95-217).
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11-15
NPDES and Effluent Limitation Guidelines
The basic mechanism for enforcing the requirements of the
Clean Water Act is the national pollution discharge elimina-
tion system (NPDES) permit required for all point-source dis-
charges into the navigable waters of the United States.H
NPDES permits incorporate specific pollution control require-
ments based on effluent limitation guidelines that EPA has
periodically issued. These guidelines fall into the following
major categories:
• Best practicable control technology (BPT),
specifying standards to be met by July 1, 1977;
• Best available technology economically achiev-
able (BAT), specifying standards for toxic
pollutants to be met by July 1, 1984;
• Best conventional technology (BCT), specifying
conventional pollutant standards to be met by
July 1, 1984;
• New source performance standards (NSPS), set-
ting requirements for plants commencing con-
struction after a given date (usually the date
of proposal of the regulations containing the
NSPS); and
• Pretreatment standards for existing sources
(PSES) and for new sources (PSNS) applying to
discharges to publicly owned treatment works
(POTWs).
In practice, the major standards applying to electric
utilities have been BPT, BAT, and NSPS (see Table II-l). Few
existing electric utility plants discharge to POTWs, and no
such discharges are expected in the future. Consequently,
14The NPDES permits do not cover two types of water dis-
charges: nonpoint discharges from such diffuse sources
as agricultural irrigation and runoff, and discharges to
publicly owned treatment works. Both have limited appli-
cability to the electric utilities industry.
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11-16
PSES and PSNS have limited applicability. BCT standards have
not been established because BAT standards cover waste streams
which also contain conventional pollutants.
1974 Best Practicable Control
Technology Standards
EPA promulgated BPT standards for the electric utility
industry in 1974. These standards, which had a compliance
deadline of July 1, 1977, applied to all the major waste
streams—cooling water, ash transport water, metal-cleaning
wastes, low-volume wastes, and boiler blowdown. In addition
to standards for specific waste streams, the 1974 BPT regula-
tions required all discharges to control acidity (pH) levels
and prohibited any discharge of polychlorinated biphenyls
(PCBs).
The technologies required to meet BPT standards were
relatively straightforward. Management practices, such as
increased care in the application of chlorine, could meet the
limitations on chlorine discharges in cooling water; sedimen-
tation in settling ponds could satisfy the standards for total
suspended solids (TSS), oil and grease, and metals in the
remaining waste streams; management practices using non-PCB
chemical additives could control PCBs; and adding chemicals
could enable plants to meet pH limits.
1975 Best Available Technology and
New Source Performance Standards
In 1975 the Agency promulgated BAT standards and NSPS for
plants beginning construction after 1974. The BAT standards
originally had a 1983 compliance deadline, but the 1977 amend-
ments extended it to 1984.
For most waste streams, the 1975 BAT and NSPS. limitations
reiterated BPT limits. There were some exceptions, however*
the BAT and NSPS requirements were considerably more stringent
for bottom-ash transport water; for fly-ash transport water,
BAT was the same as BPT, but NSPS mandated zero discharge; and
the 1975 BAT limited and the 1975 NSPS prohibited discharges
of certain corrosion inhibitors from recirculating cooling
water.
-------
labia 11-1
tvolution 977 AoMlidilw Power
v* train
fntafc* control*
reaended
Intake control*
remanded
1900 ProtntH Guide-
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BAT, NSPSt no chant)*
ftom 0p?
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change fro* BPI
(1979 Mr and
NSTS raacNad)
lero (tlftharfa
for na« plant*
only
Hora atringani
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saro dlacherga of
179 priority,
pollntanta
No llalt tatebllahed
Hora atrlngant
chlorine Halt
No Halt eatabllahnd
Dirr«n( €ff#ctt»e
197* flPT
1974 flrr
197* API
1975 W% NSPS
Beat Engineering
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1974 BPT
Beat Engineering
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M
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-4
-------
11-18
The fundamental change incorporated in the 1975 BAT and
NSPS concerned a pollutant that BPT had not regulated: heat.
The BAT regulations prohibited any discharge of water from
recirculating cooling systems at temperatures higher than that
of the intake water. Plants with other types of systems
(once-through cooling, cooling ponds, or lakes) could dis-
charge heat only if they could demonstrate that they had been
in service before the regulations were promulgated. The NSPS
standards included a thermal discharge prohibition for all
types of cooling systems.
Technologies to meet t.he additional BAT and USPS limita-
tions are considerably more complex than those to meet BPT.
The more stringent limits on oil and grease in bottom-ash
transport water require complex recirculation systems, the
zero-discharge limit for fly-ash transport water at new plants
calls for dry fly-ash handling (which for a new plant is no
more expensive than wet handling), and thermal discharge
limits in most cases require highly effective recirculating
cooling systems.
1977 Pretreatment Standards
In 1977 EPA promulgated pretreatment standards for the
few systems that discharge to publicly owned treatment works
(POTWs). The basic principle of pretreatment standards was
that pollutants that interfered with or passed through the
operations of a POTW were to be controlled. Applied to elec-
tric utility discharges, this principle meant that pretreat-
ment standards were equivalent to or less stringent than BAT
or NSPS. Chlorine and oil and grease were not controlled by
pretreatment standards because these pollutants could be re-
moved by POTWs, but limits for metals were the same as those
for BAT and ASPS. Pretreatment standards did not apply to
thermal discharges.
Recent Developments Affecting
the Effluent Guideline's
Several major developments since 1976 have altered water
pollution control regulations-for the electric utilitv indus-
try. in July 1976, as a result of a suit brought by Appala-
?Q7?naATW^dCNqpqtQf °*s* Court of.Appeals remanded to EPA the
1975 BAT and NSPS standards governing thermal discharges.
KSSa nalachian Pnuer °f 1VS re9ulati°ns also remanded
by Appalachian Power included the NSPS zero-discharae limit
for fly-ash transport water and limits on runoff Scharges.
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11-19
At approximately the time of the Appalachian Power deci-
sion, the Agency signed a consent decree settling another case
brought against it by the Natural Resources Defense Council
(NRDC). In essence, as applied to electric utility dis-
charges, the NRDC consent decree; (1) committed the Agency to
a schedule for promulgating effluent limitation guidelines for
point source categories (electric utilities were the second of
21 categories); and (2) specified 65 toxic pollutants, subse-
quently extended to 129 priority pollutants, that were ex-
pressly to be considered in the development of effluent limi-
tation guidelines.
In 1977 Congress amended the Clean Water Act, incorporat-
ing the major provisions of the consent decree. The Clean
Water Act amendments extended the BAT compliance date from
July 1983 to July 1984, but considerably increased the scope
of BAT and NSPS, reiterating the consent decree's directive
that standards be set for toxic pollutants.
1980 Proposed Effluent
Limitation Guidelines
In October 1980, the Agency proposed new effluent limita-
tion guidelines for the electric utility industry required by
the Clean Water Act, after the consent decree was incorporated
into the Act by the 1977 amendments. Major changes from BPT
standards in the proposed regulations were (1) an absolute
prohibition of discharges containing the 129 priority pollu-
tants, (2) a reduction in allowable chlorine discharges from
plant cooling systems, and (3) reinstitution for new plants
only of the standards for the zero discharge of fly-ash trans-
port water, which the Court of Appeals remanded in 1976.
(Runoff standards also remanded by the court had been reinsti-
tuted earlier in 1980 by an agreement between industry and the
Agency.)
The 1980 proposed effluent limitation guidelines were
perhaps more significant for what they did not propose than
for what they did propose (see Table II-l). No controls be-
yond those required by BPT were required for bottom-ash trans-
port water at existing plants. This rescinded the 1975 BAT
limitation of permissible discharges to levels below those
allowed under BPT. In addition although wash waters from
flue-gas desulfurization were included under low-volume waste,
the Agency asserted that it was reserving consideration of
specific standards for this waste stream.
-------
11-20
The 1980 proposed regulations also did not reinstitute
the thermal regulation that had been remanded in 1976. In the
absence of federal guidelines, individual permit writers apply
in each case "best engineering judgment" (B£J) to implement
the Clean Water Act's restrictions on environmental damage
from thermal discharges. Of course, individual states may
impose further limitations.
Cooling Water Intake Standards
In addition to the specific technology-based effluent
limitations under Section 301 of the Clean Water Act, Section
316(b) requires that "the location, design, construction, and
capacity of cooling water .intake structures reflect the best
technology available for minimizing adverse environmental
impact." In 1976 the Agency promulgated regulations imple-
menting this section which required case-by-case examinations
of the environmental effectiveness and economics of cooling-
water intake structures. This way EPA could determine the
best (i.e., most effective) structure whose cost was not
"wholly out of proportion to the magnitude of the reduction in
level of estimated damage." These regulations were remanded
in 1977. So, as in the case of thermal discharges, individual
permit writers implement the Clean Water Act's provisions by
applying case-by-case "best engineering judgment."
Water Quality Effluent Limitations
Section 302 of the Clean Water Act provides that where
technology-based standards are insufficient to "assure protec-
tion of public water supplies, agricultural and industrial
uses, and the protection and propagation of a balanced indige-
nous population of shellfish, fish, and wildlife and allow
recreational activities, effluent limitation . . . shall be
established which can reasonably be expected to contribute to
the attainment or maintenance of such water quality," Under
this requirement applicants for discharge permits must obtain
state certification that a discharge will not violate state
water quality standards.
REGULATIONS CONTROLLING THE
DISPOSAL OF SOLID WASTES
Until recently, how electric utilities have disposed of
solid waste has received little attention relative to how they
discharge pollution into air and water. Three factors, how-
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11-21
ever, have focused increasing attention on utilities: (1) the
increasing stringency of air and water pollution regulations
that have led to control techniques that themselves generate
solid waste; (2) the possibility that some or all of these
wastes may be designated as "hazardous" under the Resource
Conservation and Recovery Act (RCRA) and, therefore, will
require expensive disposal procedures; and (3) the increasing
awareness nationwide of solid waste disposal in the wake of
events at Love Canal and elsewhere.
Resource Conservation and Recovery
Act and Regulations Implementing the Act
The major federal regulations governing solid waste dis-
posal were mandated by the Resource Conservation and Recovery
Act of 1976. Under RCRA, EPA was required to develop an inte-
grated program for managing hazardous and solid wastes. As
provided by RCRA, the hazardous waste management aspect of the
program would be developed initially by SPA, but authority for
implementing it would be delegated subsequently to states with
programs equivalent to the federal programs. Programs for
managing nonhazardous solid wastes were to be developed by
individual states, providing that general minimum guidelines
promulgated by EPA were met or exceeded. Solid wastes from
electric utilities include; by-products of coal combustion
and flue gas cleaning, such as ash and scrubber sludges; chem-
ical wastes from metal cleaning, from degreasing, and from
wastewater and makeup water cleaning; and hazardous substances
(notably PCBs) contained in electrical equipment such as
transformers.15
RCRA Section 3004—Hazardous
Waste Disposal Regulations
Under RCRA, a waste can be designated as hazardous if:
(1) it fails tests specified by EPA for ignitability, corro-
sivity, reactivity, or toxicity; or <2) it is listed specifi-
cally as hazardous. A number of wastes and residues from
powerplants—such as metai-cleaning wastes and sludges from
chemical waste treatment—may fail one or more of the four
^Nuclear plants generate low- and high-grade radioactive
wastes; however, the National Regulatory Commission (NRC),
rather than EPA, regulates these wastes.
-------
11-22
tests, and certain degreasing compounds containing halogenated
solvents and PCBs have been listed as hazardous wastes.
Given their relatively small volumes of hazardous waste
(assuming ash and scrubber sludge are considered nonhazard-
ous), electric utilities in most cases find it more economical
to dispose of their hazardous waste off-site. Requirements
for on-site disposers of hazardous wastes are extensive, and
economies of scale in meeting these requirements are available
only to operators of large facilities.
RCRA requires off-site disposers to determine whether a
waste is hazardous and, if so, maintain records concerning its
disposition. The major single requirement for off-site dis-
posers is the completion of a manifest, or list, specifying
who generated the waste, what kind and quantity of waste was
shipped under the manifest, who transported it, and what EPA-
approved disposal facility was to receive it. This manifest
is used (1) to transfer responsibility for a hazardous waste
from the transporter to the disposal facility's operator, and
(2) to track the waste through its ultimate disposition.
However, RCRA clearly states that the generator has ultimate
liability for the long-term integrity of the disposal facil-
ity's operations.
RCRA Section 4004--Nonhazardous
Waste Disposal Guidelines
Large-volume waste from electric utilities, such as fly
and bottom ash and scrubber sludge, are currently treated as
nonhazardous wastes under section 4004 of RCRA. These wastes
are specifically excluded by statute from the hazardous waste
category pending an Agency study of the characteristics of and
disposal practices for ash. Though the Agency has not made
final decisions concerning disposal requirements for ash and
sludge, it is likely that these wastes will continue to be
treated as nonhazardous in virtually all areas.
Several important differences exist between RCRA require-
ments for hazardous and nonhazardous waste disposal. For
hazardous waste disposal, EPA develops regulations that the
states implement through EPA-approved programs. By contrast,
aside from incorporating EPA'b minimum criteria for solid
waste facilities, the states develop their own regulations for
nonhazardous waste.
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11-23
Since large-volume nonhazardous wastes are likely to be
disposed of on-site, electric utilities are directly affected
by requirements for the design and operation of nonhazardous
waste disposal facilities. The major requirements under EPA's
4004 guidelines for sanitary landfills are protection of:
• Environmentally sensitive areas—flood plains,
wetlands, and critical habitats for endangered
species;
• The quality of ground water drinking supplies
against contamination; and
• Surface waters.16
State regulations meeting these guidelines vary, at times
significantly, across regions of the country. In some cases,
these regulations respond to regional variations in soil per-
meability, dependence on ground water, or coal-ash character-
istics and are necessary to meet EPA guidelines. In other
cases, they vary because state attitudes toward ash disposal
differ.
A TBS study of fourteen major current and future coal-
consuming states reveals two major sources of differences
among state regulations governing ash disposal.The first
concerns the classification of coal ash: eight of the four-
teen states treat coal ash as any other nonhazardous solid
waste, four apply more stringent standards for coal ash than
for other solid wastes, and two consider ash an "inert nonde-
composible" material requiring less careful treatment than
other solid wastes. The second difference relates to ground
water protection: five states require specific measures,
while the remaining states establish requirements case by
case. The difference in regulations, coupled with regional
variations in ash characteristics and hydrological and geolog-
ical factors, results in considerable regional specificity in
ash-disposal practices and costs.
160ther 4004 requirements—such as daily cover, disease and
vector control, and access control—are less relevant to
electric utility wastes or are already met by electric util
ities.
I?Temple, Barker & Sloane, Inc., Analysis of Electric Utility
and Industrial Boiler Solid Waste Disposal Practices and
Costs (draft). for EPA's Energy Policy Division, Office of
Policy Analysis, June 1981.
-------
11-24
Polvchlorinated Biphenyls (PCBs)
Interim Control Measures
PCBs pose a somewhat different problem from other solid
wastes in that concern exists about both the operation and the
disposal of electrical equipment containing or contaminated by
PCBs. Disposal of PCBs is difficult because of their extreme-
ly hazardous nature and because they do not readily decompose
into less hazardous substances. For these reasons PCB dispos-
al in landfills is considered environmentally unsound. Ef-
forts are under way to develop alternative methods of dispos-
ing of PCBs. For example, two firms have bean authorized to
incinerate PCBs at very high temperatures.
While continuing to study the extent and the nature of
the PCB problem in cooperation with industry, EPA has estab-
lished a set of interim measures for inspecting and maintain-
ing electrical transformers containing PCBs.18 These measures
establish strict requirements for operators of transformers
located near food and feed products, including conducting
weekly inspections, reporting and servicing leaking equipment,
and maintaining records of inspections and service. For
equipment not near food and feed products, quarterly inspec-
tions are required.
INTERACTIONS AMONG ENVIRON-
MENTAL REGULATIONS
Although environmental programs for air, water, and solid
waste are distinct in a regulatory context, they intertwine at
individual plants. Air pollutants removed by wet systems to
comply with air regulations create waste streams controlled by
water regulations, which in turn generate sludges that must be
disposed of in compliance with solid waste regulations. This
section points out the overlapping coverages of the regula-
tions for air, water, and solid waste described in the previ-
ous sections and discusses some of the major cross-media
effects.
"Transformers containing PCBs are frequently not on utility
property, although the utility owns them.
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11-25
overlapping Regulatory Coverages
Regulations affecting a specific plant depend on its fuel
type, location, technical configuration, and in-service date.
As shown in Table II-2, coal-burning plants are subject
to the full range of air, water, and solid waste regulations.
Oil-burning plants are somewhat less affected by air regula-
tions and as a rule do not have either the ash transport
streams that constitute a major water problem or the ash and
scrubber sludge that contribute to solid-waste disposal con-
cerns. Gas and nuclear plants are affected predominately by
water regulations for low-volume streams and cooling water,
but not by EPA's air and solid waste regulations. (Nuclear
plant emissions are also regulated by Nuclear.Regulatory Com-
mission rules not discussed in this chapter.)
Teble II-2
POWERPLANT POLLUTION SOURCES
AS A FUNCTION OF PLANT FUEL TYPE
Coal
Sss
Nuclssr
Air
S02
TSP
M M
H *
M M
0
0
N
0
0
0
Water
Cooling
Ash Transport
Low-Volum
Runoff
M M
M «
M M
M m
H
0
M
n
M
0
M
«
Solid Waste
Ash, Scrubber Sludge
Chemical
PCB
M *
M M
H M
0
M
M
0
M
M
M * Major Source
* * Minor Source
0 s None
Plant location also influences the applicability o par-
ticular regulations. As noted above, air v ^ e°
attainment and nonattainment areas. Within atta »
-------
11-26
the applicability of Class I and II area PSD limits depends on
location. Cross-boundary effects and differing attainment
conditions for SO2 and TSP in the same location can result in
complex regulatory requirements for some plants. Location
also affects the applicability of water regulations, but only
indirectly. For example, in some areas of the country where
recirculating cooling systems are more prevalent, plants are
subject to standards for these systems. State solid waste
regulations implementing federal guidelines vary significantly
from state to state, depending on such local conditions as
hydrogeology and public attitudes. Consequently location can
greatly affect the standards applicable to ash and sludge
disposal.
Technical design factors strongly influence the portion
of water regulations that apply to particular plants. An
example is the distinction between once-through and recircu-
lating systems, which are subject to different chlorine stand-
ards under the 1980 proposed effluent limitation guidelines.
Another distinction exists between plants with dry-ash hand-
ling systems and plants with wet-ash handling systems and the
consequent ash transport waste streams. The applicability of
air regulations does not vary as a function of plant configu-
ration, but the 1971 and 1979 air NSPS have affected new plant
designs by making construction of new cyclone boilers virtual-
ly impossible because these boilers cannot be designed to meet
NOx limitations.
As more and more plants come into service under regula-
tory programs established over the past decade, an increasing-
ly critical factor determining the applicability of environ-
mental regulations to an individual plant will be the date on
which the plant "commenced construction."19 As shown in
Figure II-2, whether a plant is subject to specific air emis-
sion limitations depends on when construction of the plant
began relative to the effective dates of the 1971 and 1979
^Because of the effect of a plant's commencement date on the
applicability of specific regulations, its definition is
important. Generally, to claim that it should not be sub-
ject to regulation, a plant must demonstrate that before the
effective date of the regulation it had (1) received all
required permits and (2f either commenced on-site construc-
tion or established binding agreements for the plant's
completion.
-------
Figure 11—2
APPLICABILITY OF ENVIRONMENTAL REGULATIONS TO EXISTING
AND NEW ELECTRIC UTILITY PLANTS
Plant
Air Regulations
Watar Regulations
Solid Waste
Regulations
NAAQS
Attainment
NAAQS
Non-attainment
Low Volume ~
Malai Cli awing
Wattes, Bole
Runoff
Fly Ash
Treraport
Nria
Bottom
Aah
Transport
Watar
Caelini Watar
Larg*
Vnhnw,
Chemical,
PCBi
Date
Chemical
Pilrhaigai
Tkennet
Dhcharga,
fcMafca
Structures
ft*—1970
'////A
%
1971 NSPS
rm
1979 NSPS
Post-1983
1980
BAT
I
ISJ
-a
'Plants in some ami may be subject to BART iMMNy requirements.
2PSD Md Offset Policies war* revised in 1977 and 1978. respectively.
-H*ro()owd regulations.
*1975 BAT and NSPS Joe bottom ash tranipoft watar rescinded by I960 NSPS. which ara equivalent lo 1974 BPT.
51975 Thermal Standards apply to recirculating cooling system! only; other systems exempt.
"Regulations on intake structures and thermal discharges remanded In 1978 and 1977, reflectively. No new regulations
promulgated; therefore, permit writers apply case by case "best engineering Judgment."
-------
11-28
USPS air regulations. It also depends on the PSD and offset
regulations for attainment and nonattainment areas, respec-
tively, that were in force when it received its construction
permit. In general, because NSPS for water pollution control
have reiterated existing plant requirements, a plant's
commencement date is a less important factor in determining
water regulations applicable to it. Two exceptions concern
fly-ash transport water, for which a zero-discharge standard
was proposed in 1980, and bottom-ash transport water, for
which the NSPS promulgated in 1975 were rescinded in 198,0 in
favor of the 1974 BPT standards. Federal solid and hazardous
waste regulations do not differentiate between new and exist-
ing facilities; however, individual state solid waste regula-
tions may impose more stringent requirements or differentiate
between existing and new facilities.
Cross-Media Effects
The cross-media effects associated with environmental
regulations relate primarily to more stringent air regula-
tions, which jLn turn have resulted in greater water pollution
control and solid waste disposal burdens. State implementa-
tion plans to meet the NAAQS and the 1971 NSPS air regulations
required fly-ash collection systems with greatly increased
efficiencies. To the extent that wet-ash transport systems
have been used to sluice ash from these systems, utilities
have needed to comply with additional water pollution regula-
tions. In fact, concern over water pollution control require-
ments has fostered a trend toward dry-ash handling.
The 1971 NSPS air regulations effectively require scrub-
bers for plants not using low-sulfur coal, and the 1979 NSPS
require these systems at all new plants. In addition, SIPs
may in effect require scrubbers at existing plants. As has
been noted, the Agency has not determined how to handle waste-
water from wet scrubber systems. The solid-waste disposal
problems posed by scrubber sludges, however, are significant.
These sludges increase the quantity of wastes to be disposed
of and generally require some form of stabilization or
chemical fixation before disposal.
Some water pollution control measures may also result in
relatively small volumes of solid waste that require disposal
as hazardous wastes. Public comments concerning the 1980 pro-
posed effluent limitation guidelines have argued that strin-
gent application of these guidelines to metal-cleaning and
low-volume wastes may result in sludges that qualify as
-------
11-29
hazardous wastes. Since low-volume waste streams are often
intermingled, utilities may face the problem of either insti
tuting changes to segregate waste streams that do and do not
generate hazardous sludges or disposing of larger quantities
of sludge in facilities that meet the criteria for disposing
of hazardous waste.
-------
-------
CHAPTER III
THE EFFECTS OF ENVIRONMENTAL REGULATIONS
ON THE OPERATIONS AND PLANS OF ELECTRIC UTILITIES
-------
CONTENTS
INTRODUCTION AND MAJOR FINDINGS III-l
RESEARCH METHODOLOGY III-5
THE BUSINESS ENVIRONMENT OF ELECTRIC UTILITIES III-6
The Objectives, Rate Regulatory Environment, and
Financial Condition of Utilities III-6
Federal and State Energy Regulation 111-10
Market Uncertainties III-ll
EFFECTS OF ENVIRONMENTAL REGULATIONS ON EXISTING
POWERPLANTS 111-13
Compliance at Existing Powerplants 111-13
Sulfur Dioxide 111-14
Nitrogen Oxides 111-^16
Particulates 111-17
Water Pollutants 111-18
Extending the Operating Lives of Existing
Powerplants 111-19
Oil Displacement 111-20
ELECTRIC UTILITY CAPACITY PLANNING AND ENVIRONMENTAL
REGULATIONS" 111-22
Background on the Capacity Planning Process 111-23
Environmental Planning 111-24
Non-Coal Power Supply Alternatives 111-26
Oil- and Gas-Fired Powerplants 111-26
Nuclear Powerplants 111-26
Unconventional Capacity Alternatives 111-27
Purchased Power III-28
Synthetic Fuel for Powerplants 111-29
Power System Reliability 111-30
Conservation and Load Management 111-30
-------
CONTENTS
(continued)
Coal-Fired Powerplants 111-31
Environmental Requirements 111-32
Technological Concerns III-34
Siting Difficulties 111-36
UTILITY RECOMMENDATIONS FOR IMPROVING ENVIRONMENTAL
REGULATIONS 111-40
Formulating Environmental Regulations 111-40
Administering Environmental Regulations 111-41
Changing Environmental Regulations 111-43
IMPLICATIONS FOR THE QOANTITATIVE ANALYSIS 111-46
-------
III. THE EFFECTS OF ENVIRONMENTAL REGULATIONS ON
THE OPERATIONS AND PLANS OF ELECTRIC UTILITIES
INTRODUCTION AND
MAJOR FINDINGS
This chapter reviev/s the effects of environmental regu-
lations on the operations and plans of electric utilities and
sets environmental considerations into the context of the
industry's overall business environment. During the last
decader a large number of changes have occurred in the overall
business environment of utilities. On balance, the changes
greatly increased the complexity, uncertainty, and financial
difficulties associated with utility operations and plans. An
important element in the changed business climate of utilities
has been the marked increase in the scope and complexity of
environmental regulations.
In response to heightened uncertainties and increased
costs, utilities have adopted strategies designed to reduce
their risk exposure and to alleviate their financial difficul-
ties. To forestall further financial deterioration, utilities
have sought frequent rate increases to recover as quickly as
possible increases in operating and capital costs. Because of
their financial constraints, many utilities have also placed
increased emphasis on less capital-intensive alternatives and
methods for reducing the need for new capacity. The prospect
of greater uncertainty without commensurate earnings in the
regulated electric utility sector has also prompted some com-
panies to diversify into nonregulated business, and many
utilities are considering similar strategies.
Environmental regulations emerging during the 1970s—
covering air, water, and solid wastes—have introduced both
additional uncertainty and higher costs in the siting, plan-
ning, construction, and operation of utility powerplants.
Given the other difficulties affecting electric utilities, the
uncertainties and costs associated with environmental regula-
tions are having an increasingly important effect on utility
operations and plans. Perhaps not surprisingly, utilities
have developed plans and taken actions to reduce the costs and
uncertainty associated with environmental regulations.
-------
III-2
To understand how utilities have responded and are plan-
ning to respond to changes in their business environment, and
to determine the implications of these responses for compli-
ance with environmental regulations, TBS conducted case
studies of six electric utilities. Each case study involved a
series of interviews with company executives and technical
staff. These were supplemented with interviews with other
knowledgeable individuals in other utility companies and an
industry association.
The objective of the case studies was to identify both
the direct and the indirect effects and costs of environmental
regulations on utility operations and plans. The research was
intended first to describe obvious, direct effects such as the
installation of pollution control equipment or a switch to
low-sulfur fuels. TBS's research was also intended to identi-
fy and discuss any subtle, indirect costs of environmental
regulations—such as additional technological uncertainty
or reduced plant reliability—that increase costs, but that
are not highlighted in the usual utility financial reports or
in the engineering cost estimates that form the basis for the
quantitative analysis in subsequent chapters. The case
studies also were intended to provide EPA with candid reac-
tions of utility executives and technical staff to environ-
mental regulations and to highlight differences of opinion
among utilities and between utilities and EPA.
Interviews with the case study companies uncovered four
major conclusions regarding their compliance activities asso-
ciated with existing powerplants. First, the expense and
difficulty of achieving compliance at existing powerplants
varies greatly among utilities and appears to be a function
primarily of the ambient air quality near powerplants, the
types of fuel consumed, and the stringency of state implemen-
tation plans. Second, as is corroborated by the quantitative
unit-level analysis discussed in Chapter IV, utilities have
complied with the most costly regulations—those related to
sulfur dioxide—primarily by increasing the quality of their
fuels rather than by installing equipment. Third, utilities
fully accept their responsibility to monitor pollutant emis-
sions and report violations accurately to EPA or state envi-
ronmental agencies. Finally, to reduce capital and operating
costs, utilities have usually sought to reduce the stringency
of regulations they must meet through negotiation or
litigation.
Our interviews also revealed a pervasive concern that
financial considerations will become more influential in
-------
III-3
utility decision making and will hamper the ability and will-
ingness of utilities to meet the capital requirements associ-
ated with capacity expansion and pollution control. The full
impact of the industry's current weak financial condition has
not yet been felt, in part because load growth since 1974 has
fallen dramatically. Many utilities have continued the con-
struction of powerplants already under way before the falloff
in growth became apparent, but they have been able to pare
back other construction programs and lower their long-run
financing requirements. However, when future growth in demand
requires new capacity to be added, the large capital require-
ments associated with building new coal-fired powerplants may
be an obstacle for financially weak utilities. Perhaps as
important, even utilities that have relatively high bond rat-
ings will be reluctant to make investments that require the
issuance of additional common stock if they expect future
earnings to be inadequate. To the extent that environmental
regulations contribute to the capital and operating costs of
new capacity, both utilities and consumers may attempt to
modify environmental requirements in an attempt to lower elec-
tricity costs and to avoid reductions in service reliability.
While some case study companies with relatively good
ambient air quality are not greatly concerned with prevention
of significant deterioration (PSD) regulations, other com-
panies stated that, even in the absence of financial con-
straints, existing air environmental regulations will all but
eliminate their ability to site coal-fired powerplants in the
future. These companies are convinced that existing PSD regu-
lations are unworkable and are actively working to secure
passage of legislation to revise them. These utilities be-
lieve that PSD increments will be exhausted over time and that
the utilities will be required to obtain offsets—which may be
costly or unavailable at any price. These beliefs are a point
of contention with various environmental officials.
To avoid or to mitigate the financial and environmental
difficulties associated wi-th siting, building, and operating
new coal-fired powerplants, the majority of the case study
utilities are actively pursuing other capacity alternatives.
For example, some companies are exploring the use of synthetic
fuels to supplement or displace oil and natural gas. Utili-
ties also are reconsidering historical standards of reliabil-
ity with an eye toward lowering such standards and thereby
slowing the rate at which new capacity needs to be. added.
Some of the companies studied are actively considering pur-
chasing power to meet future demand, attempting thereby to
export both some environmental and financial problems. Sev-
eral of the companies are actively exploring greater use -of
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III-4
unconventional sources of power, such as the sun, the wind,
and wood, and are currently planning on them to contribute to
future electricity supply. However, reflecting the technolog-
ical uncertainty associated with these sources, these com-
panies have contingency plans that involve more traditional
sources of supply, such as new coal-fired powerplants.
As an alternative to building new capacity, all the case
study companies are evaluating, and some are aggressively pur-
suing, direct load controls, conservation programs, and new
pricing structures such as time-of-day rates. The attractive-
ness of these alternatives depends on situational factors.
Companies that currently have ample capacity tend to prefer
not to restrict demand. Other companies facing the prospect
of having to build new powerplants may vigorously try to hold
down demand but be unable to find cost-effective ways for
doing so.
While environmental considerations may not have been the
major factor in shaping the plans of the case study utilities,
environmental regulations have presented them with significant
challenges. Environmental regulations have increased the lead
time for new powerplants and have increased the uncertainty
associated with meeting all necessary permitting and licensing
requirements.
Technology-forcing regulations, such as best available
control technology (BACT) and lowest achievable emission rate
(LAER), also have increased the technological risk perceived
by utilities. Some of these regulations require state-of-the-
art pollution control equipment that may not perform well
enough to achieve compliance and may adversely affect a
plant's performance. The utilities interviewed believe that
the technology-forcing approach to environmental control is
undesirable because it may preclude the use of more certain
and cost-effective ways to control pollutants. Utilities
strongly prefer to be given performance standards, but to be
allowed to choose the best method for complying with them.
The case study companies also expressed concern that, as new
technologies are introduced, BACT and LAER standards will
change, thereby creating additional uncertainty and higher
costs.
Utilities have responded to the challenges presented by
environmental regulations in several ways. First, they have
made their environmental affairs departments an important
element in the utility planning process. These departments
are typically responsible for gathering and assessing informa-
tion on regulatory requirea&ents, costs, and risks and for
-------
III-5
trying to anticipate changes in environmental regulations.
The departments attempt to reduce the potential adverse conse-
quences of uncertainty about regulations by identifying key
environmental issues, preparing contingency plans, and at-
tempting to maintain as much flexibility as possible in the
utilities' supply plans. Utilities also have supported lobby-
ing efforts to change requirements from a technology-forcing
orientation to an approach that focuses on meeting pollutant-
loading goals. Finally, utilities have initiated research and
development activities that contribute significantly to their
ability to meet existing requirements in a cost-effective
manner and that develop technical expertise that can be used
to support negotiations and, when necessary, litigation.
RESEARCH METHODOLOGY
Six case studies were conducted to gather in-depth infor-
mation on the effects of environmental regulations on utility
operations and plans. Each case study comprised on-site in-
terviews of a utility's management and staff in a number of
functional areas/ including finance, capacity planning, power-
plant operations, engineering, and environmental affairs; a
review of public and internal company documents relating to
the company's business operations and environmental activi-
ties; and on-site interviews of state public utility commis-
sions (PUCs) and state environmental and siting agencies. The
case studies were supplemented with interviews with environ-
mental experts in an industry association, regional EPA staff
members, and other utility executives.
TBS informed the case study companies that their iden-
tities would be kept confidential to enable them to be com-
plete and candid in their responses. Therefore, to preserve
confidentiality, this chapter does not provide detailed
information that would associate responses with a particular
company.
The case studies were conducted in five regions of the
United States to reflect the broad range of business situa-
tions and environmental concerns characteristic of the elec-
tric utility industry. The companies were selected to provide
diversity along a number of dimensions, including: demand
growth, existing capacity fuel mxx, financxal condxtxon, and
existing air quality. This diversity ensured that a wide
variety of the major topics of environmental interest were
faced by one or more of the case study companies. These top-
ics include: compliance strategies for existing powerplants
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III-6
of all the major fuel types; oil-to-coal conversions; PSD,
nonattainment, and visibility regulations; and the siting of
new powerplants. Of course, despite the diversity of the case
study situations, six case studies cannot be viewed as cap-
turing the full range of responses to environmental regula-
tions in the electric utility industry.
THE BUSINESS ENVIRONMENT OF
ELECTRIC UTILITIES
To provide the background necessary for an understanding
of electric utility decision making and actions vis-a-vis
environmental regulations, this section reviews the most im-
portant influences on electric utilities and discusses how
changes in those factors have affected and will affect utility
decision making. The considerations influencing utility in-
vestment decisions and strategies for compliance with environ-
mental regulations include: the objectives, rate regulatory
environment, and financial condition of utilities; federal and
state energy regulation? and the market for electricity.
The Objectives, Rate Regulatory
Environment, and Financial
Condition of Utilitie¥
A utility's objectives typically are to provide adequate
and reliable electric service at reasonable cost to its cus-
tomers, to provide a reasonable rate of return to its inves-
tors, and to comply with societal objectives and regulations.
Differences in the interests of consumers, investors, and
society can result in conflicts between utility objectives
and therefore can require utilities and their regulatory com-
missions to make tradeoffs between objectives. For example,
consumers' rates can be reduced by allowing the reliability of
electric service to deteriorate or by lessening the stringency
of environmental controls. A balancing of objectives requires
a consideration of the effects of decisions not only on cur-
rent consumers, but also on future consumers. For example,
decisions to lower returns to investors may result in iower
rates for consumers- in the short run, but may lead to higher
costs for future consumers.
Because utilities are monopolies, state (and to a lesser
degree, federal) commissions have historically been given the
regulatory authority to ensure that utilities do not exploit
their monopolistic power. Regulatory commissions exercise
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their authority by regulating the level and structure of a
company's rates which, in turn, are key determinants of a
utility's revenues. The appropriate level of revenues is
commonly interpreted as the level that allows a company to
serve its customers and to provide its shareholders with an
opportunity to earn returns commensurate with those available
on investments of comparable risk.
A fundamental regulatory problem is that PUCs tend to
determine rates on the basis of procedures that do not accur-
ately reflect costs during the period in which the rates are
in effect. In an inflationary environment, these procedures
have generally resulted in electric rates that- have been in-
adequate to cover costs and to provide an acceptable rate of
return. As a result, in the last decade, most major electric
utilities have persistently failed to earn rates of return
consistent with those required by investors in common stock.
There is also considerable debate about whether PUCs
adequately adjust allowed returns to correspond to the risks
of particular projects, a debate with obvious implications for
the willingness of utilities to invest in state-of-the-art
technologies. Utilities are concerned that PUCs will not
reward their stockholders for the successful undertaking of
risky projects, but will force them to bear most of the unfa-
vorable consequences of an unsuccessful outcome. If an eco-
nomically attractive but risky project proves successful, the
PUC can hold the utility's rate of return constant and pass on
the economic benefits to consumers in the form of rates lower
than they otherwise would have been. If the project proves to
be unsuccessful, the PUC can reject it as an allowable compo-
nent of the cost of service, thereby reducing the rates of
return realized by company investors.
Mainly because of inadequate returns, the financial
health of the electric utility industry has declined precipi-
tously over the last decade and, as a result, many utilities
have become unable or reluctant to undertake new financings.
Inadequate returns have contributed to a general decline in
electric utility bond ratings, an important determinant of a
company's cost of debt and ability to access the credit mar-
kets Prom 1975 to 1979, Moody's Investor Service, a major
bond'rating agency, lowered utility bond ratings 41 times
while only raising utility bond ratings 17 times. Insuffi-
cient returns have also resulted in common stock market price
to book value ratios
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means that sales of new common shares dilute the common stock
book value per share and tend to depress earnings per share,
dividends per share, and the market price per share. Thus,
existing shareholders in companies with MBRs of less than one
tend to resist the issuance of common stock—and investments
necessitating such issues.
In response to inadequate rates of return and their
strained financial condition, utilities have aggressively been
seeking higher rates from their PUCs and some utilities have
diversified into unregulated businesses. Utilities are filing
for rate increases more frequently and are requesting higher
allowed rates of return. However, several of the utilities
studied are pessimistic about the chances of attaining ade-
quate rates of return and improving their financial health.
This lack of optimism stems from the intense pressure on PUCs
to insulate consumers from the enormous increases in fuel,
construction, and debt and equity financing costs during the
last decade. In an attempt to improve their profitability,
some utilities have also diversified into unregulated busi-
nesses and many utilities are considering doing so. However,
diversification into businesses other than the production and
transmission of electricity may be precluded for some utili-
ties by the Public Utility Holding Company Act. PUCs can also
influence utility diversification activities through the rate-
making process. Moreover, many utilities are concerned that
PUCs may use unregulated profits to subsidize electric rates,
thereby reducing the potential gains from diversification.
The prospect of continuing financial strains and inade-
quate returns has led most of the case study utilities to
place increased emphasis on the capital cost of a project.
This emphasis has led electric utility managements to explore
alternatives that reduce the need for additional capacity, to
select less capital-intensive methods for meeting particular
needs, and to resist environmental regulations that require
large capital outlays. Exaotples of alternatives that reduce
or defer the need for building new capacity includes purchas-
ing power instead of building new capacity, extending the op-
erating lives of existing powerplants, adopting.conservation
programs to reduce the need for new capacity, and relaxing
reliability criteria relative to historical levels.
The increased weight accorded to capital spending re-
quirements may result in the selection of alternatives that
have higher long-run costs for consumers than more capital-
intensive alternatives. For example, a company may not be
willing or able to convert an existing oil-fired generating
unit to coal, even though the conversion would result in lower
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costs to consumers, if it cannot get adequate returns on the
required capital investment or if it cannot raise capital.
Similarly, purchases of power, while avoiding capital costs,
may be more expensive for consumers than the construction of
new powerplants. The ability of utilities to avoid capital
costs, while passing along fuel and purchased power costs to
consumers via automatic fuel adjustment clauses, is by no
means unconstrained. PUCs can identify opportunities for
utilities to lower future costs and can employ blandishments
or threats, or both, in rate cases to enable and motivate
utilities to undertake such investments.
Although favorable financing, tax, and regulatory rules
for pollution control equipment can mitigate many of the ad-
verse effects of such equipment on a utility's financial con-
dition, they do not fully eliminate the bias against capital
investment when returns on investment are insufficient. For
example, some pollution control equipment can be financed
using tax-exempt debt financing (industrial revenue bonds)
issued by municipal authorities. However, because the pollu-
tion control bonds are backed by the credit of the utility
(and typically carry a lower bond quality rating than the
utility's other bonds because they have lower priority than
first mortgage debt), they cannot always be issued by util-
ities having a weak credit rating. Moreover, even if pollu-
tion control financing is available, the lower cost of such
debt, while improving a utility's interest coverage ratios,
produces interest savings that are passed on to consumers and
not retained by investors. As another example of an attempt
to alleviate financing problems, many PUCs and the Federal
Energy Regulatory Commission allow more favorable accounting
treatments for pollution control equipment than for other
utility expenditures, e.g., by including capital expenditures
for pollution control in the rate base during construction.
Many PUCs also permit normalization accounting for various tax
expenses associated with pollution control equipment, even
when they do not generally allow normalization for other types
of expenditures. These approaches can improve a utility's
financial condition by increasing internal cash flow. The
improvement in financial condition tends to reduce the riski-
ness of earnings but does not increase the level of earnings
and, consequently, may not entirely eliminate any existing
bias against capital-intensive investment decisions.
The rate regulatory environment and the financial condi-
tion of electric utilities have important implications for
utilities' responses to environinent&l regulations. The rapid
rate of increase in environmental and non-environmental costs
in the last decade has intensified utilities' resistance to
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more stringent environmental regulations. Reflecting their
objective of providing low-cost service to their customers and
reasonable rates of return to their investors, utilities tend
to resist costly environmental requirements just as they try
to control other cost increases—such as increased fuel
prices, higher construction costs, and higher wage rates.
Moreover, given the public and political pressures on PUCs to
try to hold costs down, increases in cost may not be covered
by increases in rates, adding to the utilities' difficulties
in providing an adequate rate of return to investors. To help
alleviate these problems, utilities resist costly environmen-
tal regulations, especially those having large capital costs.
Federal and State Energy Regulation
In recent years the scope of federal and state energy
regulation has increased dramatically, further constraining
electric utilities in their choices as to the amounts, types,
and locations of powerplants. Reflecting the federal govern-
ment's desire to reduce reliance on foreign oil, the Power-
plant and Industrial Fuel Use Act (FUA) was passed in 1978.
FUA has effectively eliminated new oil- and gas-fired units as
an alternative for new baseload capacity, restricted the use
of gas prior to 1990, and prohibited the use of gas in exist-
ing baseload units after 1990. FUA also authorizes the De-
partment of Energy (DOE) to prohibit the use of oil and gas in
certain existing oil- and gas-fired units. Even without the
statutory limitations imposed by FUA on the use of oil and gas
as boiler fuels, the current high cost of oil and gas makes
them economically unattractive as fuels for new baseload pow-
erplants compared with, for example, coal-fired powerplants.
Federal action and inaction have also helped remove nu-
clear powerplants as an alternative for capacity expansion.
Increasing concern over the safety of nuclear powerplants and
the disposal of nuclear wastes over the last ten years intro-
duced uncertainties that are so great that few, if any, util-
ities believe new nuclear powerplants to be a viable capacity
expansion option before the 1990s« Regulatory requirements
have become increasingly stringent over the last decade and
are viewed by utilities as likely to become even more strin-
gent as a result of the accident at Three Mile Island. The
resultant tightening of regulatory requirements increases the
cost of complying with safety requirements, introduces the
possibility of unknown but potentially costly design modifica-
tions, and increases the possibility of cos-tly delays in li-
censing and constructing new facilities. Perhaps even more
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important, obtaining public acceptance of sites for new nu-
clear powerplants, while difficult before, is likely to become
even more difficult. The lack of a federal program for dis-
posing of nuclear wastes introduces further uncertainty as to
the ultimate cost of nuclear power.
In addition to increased federal constraints on utility
actions, some state regulatory agencies have also introduced
further constraints by becoming more directly involved in
utility investment and operating decisions. In recent years,
a number of PUCs and state siting agencies have sought to
encourage investment in unconventional energy sources, the
conversion of oil- and gas-fired units to coal, and the insti-
tution of conservation programs. Some have also sought to
discourage the development of certain types of capacity such
as nuclear powerplants. PUCs often have the authority to
certify utility proposals for new powerplants and can influ-
ence utility investment plans by delaying or denying certifi-
cation of projects. PUCs can also influence utility decisions
through their ratemaking authority. For example, one PUC
explicitly ties utility rates to the achievement of conserva-
tion goals. Similarly, in a number of states, siting agencies
have the authority to approve powerplant sites and thereby can
affect a utility's investment plans. Criteria used by PUCs
and siting agencies to evaluate utility proposals generally
include the need for a new powerplant, environmental impact,
compliance with laws and regulations, and such social goals as
oil displacement and conservation.
Market Uncertainties
Utility investment decisions also have been importantly
influenced by uncertainties associated with forecasting the
demand for electricity, the cost of oil, and the rate of in-
flation. In attempting to provide adequate service at reason-
able costs to future consumers, utilities have to project the
need for generating capacity 10 to 15 years in the future
because of the increasingly long lags involved in the site
selection, permitting, design, and construction of a new
powerplant. Unfortunately, coincident with the increase in
the length and uncertainty of construction lead times, in-
creased difficulties in forecasting demand have arisen. Since
the mid-1970s, the growth in demand for electricity has sharp-
ly declined in amount and has greatly increased in uncertain-
ty. Steep rises in oil and other operating and construction
costs in the last decade have resulted in rapid increases in
the price of electricity. Customers have responded by cutting
their usage and doubtless will continue to respond, but in
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ways that are still hard to predict. In addition to reducing
their energy usage, customers may increasingly turn to natural
gas or, especially in the case of larger customers, turn to
unconventional energy sources and cogeneration projects.
The recent declines in demand have led to an excess of
total industry capacity, although much of the apparent excess
capacity in many regions is oil-fired and has been rendered
economically obsolete by the spectacular increase in 'oil
prices since 1973. As a result of the decline in demand
growth, the financial difficulties of many utilities will be
reduced over time because the need for new capacity is re-
duced. However, in many instances it is more economical to
complete new capacity under construction than to cancel or
delay it, so that many companies will continue to face high
near-term external financing requirements.
The changing patterns of demand have also increased the
risks faced by some utilities. There have been several recent
instances where PUCs have questioned whether consumers should
bear the costs of facilities cancelled due to the drop in
demand. Moreover, utilities that delay the operational date
of powerplants already substantially completed may also face
significant financial strains because consumers usually do not
contribute to the financial carrying costs of construction
work in progress (CWIP).
In addition to the uncertainties in forecasting demand,
utilities' investment decisions are further complicated by
uncertainty in future energy prices and the general rate of
inflation. For example, the economics of converting existing
powerplants from oil to coal are critically dependent on
future oil prices which, in turn, are extremely difficult to
predict. The general increase in price levels over the last
decade not only has contributed importantly to the deteriora-
tion of the electric utility industry's financial condition,
but also has introduced additional uncertainty in the plan-
ning, financing, building, and operating of new powerplants.
The increased uncertainties in forecasting * demand, oil
prices, and inflation—and PUC response to some of the
attendant consequences—obviously exacerbate the difficulties
involved in complying with environmental regulations. In an
era where forecasting is particularly difficult, utilities
naturally do not welcome tfie time lags and uncertainties in
the lead times for-new powerplants introduced by environmental
regulations.
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EFFECTS OF ENVIRONMENTAL REGULATIONS
ON EXISTING POWERPLANTS
Environmental regulations affect existing powerplants
directly by requiring more pollution control equipment or
higher quality fuels than utilities would install or use in
the absence of regulations and indirectly by influencing the
economics of different operating lives of powerplants and of
conversions of oil- and gas-fired powerplants to coal. This
section first reviews the ways in which utilities have
achieved compliance at existing powerplants, the costs and
problems associated with compliance to date, and possible
future compliance problems. It then discusses the influence
of environmental regulations on utility decisions about the
operating lives of existing powerplants and the environmental
issues associated with different powerplant lives. Finally,
the section reviews the impact of environmental regulations on
the oil displacement activities of the case study companies.
Compliance at Existing Powerplants
Four general conclusions regarding compliance activities
for existing powerplants emerged from interviews with the case
study utilities. First, the expense and difficulty of achiev-
ing compliance at existing powerplants varies greatly among
utilities and appears to be a function primarily of the am-
bient air quality near the powerplants, the stringency of
the applicable state implementation plans, the type of fuel
consumed by the powerplants, and the local cost premiums for
low—sulfur fuels. Second, as is corroborated quantitatively
in Chapter IV, utilities have complied with the most costly
regulations—those related to sulfur dioxide (SO2) "primarily
by increasing the quality of their fuels rather than by in-
stalling equipment. Third, utilities fully accept their re-
sponsibilities to monitor pollutant emissions and report vio-
lations accurately to EPA or state environmental agencies.
Lastly, in order to minimize additional capital and operating
costs, utilities seek to reduce the stringency of the regula-
tions they have to meet, especially when those regulations
require state—of—the—art equipment or when they are thought to
be poorly formulated or costly relative to their benefits.
Some utilities that face nonattainment air quality problems
assert that the cost of complying with stringent regulations
is sometimes so large that they effectively have no choice but
to resist the regulations to protect the interests of their
shareholders and customers.
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In comparison with the other utilities, one case study
utility has more willingly sought to comply with environmental
regulations and to operate units as cleanly as reasonably
possible. The company recognizes that its willingness to
comply leads to higher consumer costs, but adopted this ap-
proach primarily because it reflected the desires of citizens
and state regulators to protect scarce water supplies and
striking scenic vistas. The company was able to take this
approach in part because its rate regulatory environment al-
lowed it to meet its environmental objectives without seri-
ously compromising the interests of its investors or jeopard-
izing its capacity expansion plans. Company officials and
state regulators believe that the company's efforts to control
pollution and avoid conflicts with regulators is also a good
business policy. The company's willingness to comply has re-
sulted in a good working relationship between the company and
its state environmental regulators and has prompted these reg-
ulators to permit emission variances or relax standards when
the company encountered significant design or operating prob-
lems with pollution control equipment.
A detailed discussion of the compliance approaches adop-
ted by the case study utilities, and the costs and problems
associated with these approaches, is presented below. The
discussion is organized by the four major pollutants subject
to emission limits: SO2, nitrogen oxides (N0X), particu-
lates, and water pollutants.
Sulfur Dioxide
Compliance with SO^ regulations can be achieved through
using low-sulfur fuel oil and coals, by installing flue gas
desulfurization (FGD) systems (often called "scrubbers"), or
both. Either method can significantly increase generating
costs because low-sulfur fuels command a price premium and
scrubbers entail capital and operating costs. If both methods
are used, there is a tradeoff between the sulfur content of
the fuel and the percentage of SO2 in the flue gas that must
be removed. For example, to meet a given SO2 standard, low-
sulfur fuels require less effective, and therefore less
costly, scrubbing systems them high-sulfur fuels.
As noted above, the case study companies for the most
part complied with SO2 regulations for existing powerplants by
switching to lower.sulfur fuels. They have generally regarded
scrubbers as a compliance method of last resort because the
incremental cost of lower sulfur fuels has been outweighed by
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the decreases in powerplant reliability and efficiency and by
increases in capital, fuel, other operations, maintenance, and
sludge disposal costs that are due to scrubbers.
In isolated instances, scrubbers are the only way or the
most economical way for existing plants to comply with SO2
regulations. One case study company installed scrubbers be-
cause it had a favorable contract for high-sulfur coal that
made it more economic to install the scrubbers. This company
also noted that another company, one not included in the case
studies, may in the future be forced to install scrubbers on
some of its existing oil-fired powerplants because fuel oil
with a sulfur content low enough to meet stringent SO2 stand-
ards being considered by a local environmental authority is
generally not available. Another case study company installed
scrubbers in its coal-fired units, mainly as original equip-
ment, to meet a state requirement for scrubbers.
The latter company's experience tends to confirm some of
the other companies' concerns about FGD systems. Although the
scrubbers were designed to achieve removal efficiencies in
excess of environmental requirements, the advanced design of
the scrubbers has led to operating and design problems and to
actual removal efficiencies below the original state stand-
ards. The company has successfully negotiated with environ-
mental regulators to resolve many of these problems. Because
the company approach to environmental regulations is viewed as
positive, its regulators have agreed to significant delays in
the design and construction of scrubber modules. Moreover,
the company was allowed a relaxation of sulfur dioxide stand-
ards after its installed equipment could not continuously meet
the original standards. Largely because this company's regu-
lators have permitted variances and allowed the company to
operate units while repairing scrubbers, scrubber reliability
problems have not significantly affected the reliability of
the company's generating units.
Achieving compliance with SO2 regulations by switching to
higher quality fuels requires careful control of the fuel's
sulfur content. The variation in sulfur content, especially
for coal where sulfur content can vary substantially within a
mine, can create compliance problems because emission stand-
ards are based on time periods (averaging times) often as
short as one day, and sometimes less. If a quantity of fuel
with significantly above-average sulfur content is burned for
a large portion of the averaging time, an emission violation
can occur.
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Utilities usually try to deal with sulfur variability and
potential emission violations by specifying maximum sulfur
contents in their contracts with suppliers. To reduce the
risk of poor performance by coal suppliers, some companies
routinely inspect the suppliers' coal mines prior to signing a
contract, test coal samples before and after shipment, and
often use trial contracts to confirm the ability of a supplier
to meet contract specifications. To meet coal specifications,
suppliers—including those mines owned by the utilities—will
often blend high- and low-sulfur coals and in some cases will
physically clean high-sulfur coal. In deciding whether to
purchase low- or high-sulfur coal, the lower purchase cost of
high-sulfur coal must be weighed against the cost of cleaning.
Nitrogen Oxides
The costs of controlling N0X emissions for existing
powerplants generally have been small because they can usually
be controlled by relatively inexpensive changes in burner and
boiler designs. One of the case study companies—even though
located in a state with numerous Class I PSD areas, excellent
air quality, and relatively stringent state standards—
achieved compliance through burner design changes and by cy-
cling combustion gases to the boiler. However, where NOx
emissions have caused relatively severe air problems, util-
ities have had to resort to dispatching powerplants on the
basis of N0X emissions during periods of high ambient air
N0X concentrations. Dispatching to control N0X may in-
crease a utility's total annual energy costs if it increases
the loading of less efficient powerplants.
A possible future tightening of MOjj emission standards
by some states is of significant concern to some utilities
because a further tightening of standards could require the
installation of expensive, and as yet not commercially proven,
catalytic reduction systems. At least one state faced with
poor ambient air quality has already attempted to require
powerplants in some localities to reduce NOx emissions below
reductions already achieved through changes in burner design.
A number of utilities have taken legal actions to preclude
tightening NO* standards. Utilities have argued that the
need for further reductions in N0X emissions has not been
adequately demonstrated and the impact of further reductions
on the emission of other pollutants has not been studied.
Moreover, one utility indicated that some proposed visibility
regulations would require stringent control of N0X emissions
and would, if promulgated, impose such costs that a number of
utilities would have little recourse other than to initiate
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legal challenges to the regulations. It was also noted that
many utilities may be more inclined to contest visibility
regulations than other regulations because visibility regula-
tions are based on aesthetics, rather than health effects.
Other utilities do not anticipate a tightening of N0X
emission standards either because of new state initiatives or
because of existing federal visibility requirements in their
service territories. Although the cause of visibility prob-
lems is subject to considerable debate, one company stated
that it does not believe that N0X emissions from powerplants
contribute significantly to visibility problems in its state.
Furthermore/ it believes that methods of NOx control, other
than burner and boiler design changes, simply are not avail-
able at any reasonable cost and, as a result,, will not be
required.
Particulates
Particulate emissions can be controlled by limiting the
ash content of the oil or coal being burned or by installing
an electrostatic precipitator, baghouse, or mechanical collec-
tor. In designing compliance strategies, utilities consider
the tradeoff between the costs of fuels with alternative ash
and sulfur contents and the removal efficiencies and costs of
equipment. A number of case study companies noted that the
performance of precipitators declines with decreasing amounts
of SO2 in effluent streams. According to these sources, the
use of low-sulfur fuels or scrubbing systems to control SO2
emissions necessitates the use of high-performance precip-
itators or baghouses or, where possible, the routing of efflu-
ent streams through precipitators before scrubbing. However,
one case study company questioned the practical importance of
the interactions of total suspended -particulates (TSP) and FGD
systems. According to this company, the interactions of
precipitators and scrubbers are not a significant problem for
most existing powerplants and should be no problem for new
powerplants.
The case study companies expressed no great concern over
the requirements for controlling particulates at oil-fired
powerplants. This attitude reflects the relatively low levels
of cost and technological problems associated with controlling
particulates from oil-fired powerplants, compared with those
for SO2 and for particulates from coal-fired powerplants. The
case study utilities' compliance strategies generally involve
switching to higher quality fuels, although one company also
reduced the output range of one of its powerplants and another
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company installed a precipitator on an oil-fired unit to
achieve compliance.
Particulate emissions represent a greater problem at
coal-fired powerplants because of the high percentage of ash
in most coals. One case study utility installed electrostatic
precipitators as original equipment at each of its coal-fired
units to meet state particulate regulations, which were some-
what more stringent than federal regulations. Another case
study utility had to retrofit precipitators at a number of its
major coal-fired units to meet state implementation plans
(SIPs) promulgated pursuant to federal legislation. The com-
panies also noted that other utilities have been required to
add precipitators to oil-fired powerplants that have been
converted to coal.
A number of utilities expressed particular concern about
the costs of a tightening of particulate emissions require-
ments over time. One utility described the experiences of a
neighboring utility to provide an example of how changes in
emission standards over time can contribute significantly to
capital costs. As a result of a SIP change initiated by the
stater the utility was forced to add higher efficiency pre-
cipitators at one of.its large coal-fired powerplants, at a
cost of well over $100 million, after only five years of oper-
ation with the powerplant's original precipitator. The case
study utility also cited the experience of another company
whose state environmental agency tried to increase the strin-
gency of its particulate emission standards by an order of
magnitude after a company demonstration test showed that the
more stringent standard could be achieved—at least in the
short run and so long as there were no further reductions in
allowed sulfur emissions that would affect the precipitator's
efficiency.
Water Pollutants
Water regulations place limits on thermal emissions*
water intake damage to marine organisms, and the emission of
pollutants contained in waste streams. Thermal emissions can
be reduced with cooling towers or offstream cooling systems
such as spray ponds. Water intake damage can be reduced
through improved design of -water intake facilities. Effluent
wastes can be controlled with wastewater treatment facilities
or by reducing the use of water pollutants.
The costs of complying with water regulations have gen-
erally not been large relative to air costs, reflecting the
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fact that controlling water pollutants typically requires less
sophisticated control systems than those used to control SO2.
Some of the companies were able to avoid expensive retrofits
for water intake and discharge systems by demonstrating mini-
mal environmental impacts, as permitted under Sections 316a
and 316b of the Clean Water Act (involving effects of water
intake technology on marine organisms and involving thermal
discharge, respectively). One of the companies noted that,
because it had originally installed water pollution control
equipment in powerplants that exceeded the existing state
control requirements, it was able to avoid costly retrofits
when more stringent federal regulations emerged. However, one
case study company noted that another utility has had to
install costly off-stream cooling systems and sophisticated
wastewater treatment facilities at its coal-fired units to
meet state and federal effluent regulations and to reduce
water consumption.
In addition to direct capital, fuel, other operations,
and maintenance costs, water permit requirements can lead to
higher power production costs by restricting the use of water
pollutants. For example, chlorine or other biocides are com-
monly used in noncirculating cooling systems to reduce organic
growth on condenser tubes. Restrictions on the use of these
biocides tend to necessitate more frequent reductions in a
powerplant's output to allow physical cleaning of the conden-
ser and to result in additional organic growth which reduces
powerplant efficiency.
Exten(3in<^ the Operating Lives
of Existing Powerplants
Utilities concerned about siting problems or financial
constraints have considered and are considering extensions of
the remaining operating lives of existing powerplants, even if
such extensions could result in higher consumer costs. Envi-
ronmental regulations have increased the economic attractive-
ness of such extensions by increasing the costs and risks
associated with building new coal-fired powerplants and other
capacity expansion alternatives. Moreover, by continuing to
operate an existing powerplant, a utility can postpone siting
and other environmental difficulties and can reduce its cap-
ital outlays for new powerplants. The case study companies
did not provide any examples o£ actual decisions to extend the
operating life of a powerplant. Howiiver, one PUC staff member
believed that siting difficulties resulting from environmental
regulations and economic considerations will make such exten-
sions a necessity in his state—a state characterized by poor
air quality.
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Extending the operating life of an existing powerplant
can necessitate additional environmental controls if equipment
modifications result in a net increase in pollutant emissions
of sufficient size to classify the changes as a major power-
plant modification. In some circumstances, utilities may be
able to avoid a net increase in emissions by using higher
quality fuels. In other circumstances it may be necessary to
install pollution control equipment at the powerplant or,
alternatively, at other nearby generating units.
EPA is concerned that stringent new source requirements
will cause utilities to delay the retirement of existing
powerplants that do not meet the standards for new sources,
thereby increasing total pollutant loadings. However, with
respect to the case study companies, no consensus was apparent
concerning the environmental impact of extending the useful
life of an existing powerplant. The environmental effects, of
course, depend on the difference in pollutant emission rates
between the existing powerplant and the new powerplant whose
construction is deferred. Despite the increasing stringency
of requirements applicable to new powerplants, the retirement
of old powerplants is not always environmentally advantageous.
According to utility managers, extending the life of an exist-
ing oil-fired powerplant rather than constructing a new coal-
fired powerplant can result in either a net increase or de-
crease in SO2 emissions, depending on the situation.
Oil Displacement
A national energy policy goal is to displace oil consump-
tion to reduce the nation's dependence on foreign oil. Utili-
ties can displace oil by converting existing oil-fired units
to coal, by displacing generation from oil-fired units with
power from new coal-fired or nuclear units or from unconven-
tional sources of energy, and by substituting coal-oil mix-
tures for oil. This section reviews the factors influencing
utilities* decisions to reduce their consumption of oil, in-
cluding the role that environmental regulations have played in
those decisions.
The decisions to take actions that displace oil depend on
a number of economic, financial, and technical considerations.
Many prospective conversions are uneconomical because the
units were not originally designed to burn coal and would
require major or total boiler rebuilding to do so. Some re-
conversions of coal-capable units have been precluded by site-
specific technical problems, such as lack of adequate space
for fuel handling and storage. Financial constraints can also
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be a factor. Some utilities nay decide not to undertake con-
versions or the construction of new coal-fired powerplants to
displace oil because of the large capital investments in-
volved. Environmental regulations nay also discourage conver-
sions and the construction of new coal-fired units for oil
displacement by adding to the capital costs and risks of such
projects and by increasing unit operating and maintenance
costs.
Despite all the factors inhibiting oil displacement,
flexibility in implementing environmental regulations has led
to some conversions from oil to coal. One case study company
described successful conversions undertaken by two other com-
panies, not included in the case studies, where the companies
and various regulatory bodies acted in concert to reduce both
the cost and the uncertainty associated with environmental
regulations. The first company was able to achieve major fuel
cost reductions without incurring the environmental cost in-
creases associated with a full PSD review because the Depart-
ment of Energy issued a prohibition order that precluded the
continued use of oil at this unit. As a result of the prohi-
bition order, the company could meet the applicable sulfur
dioxide regulations by using low-sulfur coal, rather than a
scrubber. However, the company did add precipitators to the
converted units.
The second company taking action on oil displacement con-
verted an oil-fired powerplant based on projected cost savings
that were protected through negotiation. Before the conver-
sion, the company negotiated with EPA and its state environ-
mental agency for assurances that environmental requirements
for the powerplant would remain unchanged in the future. The
state agency agreed to exert its best efforts to place the
burden of any changes in pollution control requirements onto
new powerplants and EPA informally indicated its support of
this agreement. The company also negotiated with EPA for the
elimination of a requirement to install scrubbers. EPA
dropped its demand for scrubbers based on a company commitment
to maintain SO2 emissions equal to or below those previously
emitted by the unit. The installation of a precipitator was
required, but its costs are much less than expected fuel cost
reductions.
Some of the case study companies are pursuing alterna-
tives to displace oil other than converting boilers from oil
to coal. A number of companies are investigating unconven-
tidnal sources of energy such as wind, solar, and synthetic
gas. One of the companies, located in an urban area, is
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studying the economics of constructing a synthetic gas manu-
facturing facility to supply one of its oil-fired units,
rather than converting the unit to coal. The company believes
that displacing the oil with synthetic gas nay be the most
economical alternative for three reasons. First, converting
the powerplant to burn coal would be much more expensive than
making the minor modifications necessary to burn gas. Second,
there is inadequate space at the plant site for coalihandling
and storage and for a scrubbing system, making conversion very
costly if not impossible. Third, the company expects tbe
costs of controlling pollutants at the synthetic gas manufac-
turing stage to be substantially less than controlling pollu-
tants at the coal-burniog stage, thereby making synthetic gas
more economical. In addition to economic considerations, the
company noted that the urban location of the powerplants being
studied would create substantial public opposition to convert-
ing the powerplant from oil to coal.
Some case study companies are also analyzing the use of
coal-oil and coal-water mixtures in powerplants that were not
originally designed for coal and that wduld be prohibitively
expensive to convert." One company that hopes to convert some
of its oil-fired units to. coal-oil mixtures indicated that it
anticipates having to install precipitators, but expects that
it can avoid the need to install scrubbers by controlling the
sulfur content of its coal-oil mixtures. Other companies are
concerned that the use of coal-oil and coal-water mixtures may
be precluded by technical problems related to boiler designs.
In addition, they may be precluded by insufficient space at
powerplant sites for the addition of scrubbers and precipi-
tators or baghouses that would be required by state regula-
tions.
ELECTRIC UTILITY CAPACITY PLANNING AND
ENVIRONMENTAL REGULATIONS
Many factors, including environmental regulations, influ-
ence capacity decisions. The discussion is organized into
four parts. The first part presents a general description of
the capacity planning process in the case study companies.
The second part discusses the companies' efforts to anticipate
and manage the costs and risks associated with environmental
regulations. The thijrd part reviews the case study companies'
evaluation of non-coal capacity alternatives. The fourth oart
discusses the coal-fired powerplant alternative rourtn Part
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Background on the Capacity
Planning Process
Capacity planning is the process of determining a strat-
egy for expanding and modifying company facilities to meet
projected electricity demand. It includes the determination
of the amount, type, location, and timing of additions to a
company's generation (and related transmission) facilities, as
well as modifications to or retirement of such facilities.
The case study companies to some degree coordinate their
own generation capacity planning with that of other companies.
The degree of coordination depends first on the scale of a
company. If a company is itself large, it may by itself be
able to exploit the economies of scale and diversify opera-
tional and financial risks. The degree of coordination de-
pends also on geographical factors and on the availability of
other companies for whom joint activities would be beneficial.
The degree of interaction may also depend on a welter of other
considerations, such as regulatory constraints or regional
attitudes concerning public and private power companies.
The benefits of coordinated planning and operations, if
any, tend to be exploited because there typically is a con-
siderable exchange of information on demand forecasts and
capacity requirements between companies. This takes place
through regional electric reliability council activities,
industry association meetings (such as those organized by the
Edison Electric Institute or the Electrical Power Research
Institute), or a variety of informal gatherings (such as those
hosted by investment banking firms).
In addition, some companies have formed formal power
pools or coordinating groups. In New England and in the Penn-
sylvania-New Jersey-Maryland region, for example, central pool
staff dispatch the units owned and operated by the member
companies. In New England, the pool also determines the capa-
bility requirements (capacity or firm contracts for capacity
owned by others) of each member and levies penalties if a
company falls short of meeting its demand with an adequate
reserve margin. In the Ohio area, on the other hand, the
coordinating group does not dispatch its members' units, but
rather serves as a vehicle for companies to plan, construct,
and operate jointly owned facilities.
Although some of the companies in the case study sample
are members of relatively highly centralized power pools, the
capacity planning processes of the companies studied are
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basically sinilar. A company starts the process by examining
short- and long-term forecasts of demand. It then typically
formulates several different capacity expansion plans that
meet its forecast of average and peak electricity demands,
giving due consideration to the reliability of generation and
the uncertainty of demand. The company may consider joint
ownership of large powerplants to realize the economies of
scale associated with such powerplants and to match tlje size
of capacity additions with its needs. Next, each potential
expansion plan is screened with respect to a set of criteria
that reflect the company's objectives and priorities. For the
plans that pass the screening tests, detailed capital and
operating costs are then calculated and evaluated in terms of
their financial requirements and effects on consumer prices.
Since the resultant electricity prices may change demand, a
company may have to revise its load forecast and capacity
expansion plans. Thus, the process is iterative, although
many elements of the analysis are prepared concurrently using
detailed computer simulation models. Reflecting the import-
ance of investment decisions, senior management at each com-
pany is heavily involved in each step of the process.
Environmental Planning
The case study utilities have modified and augmented
their capacity planning processes in an attempt to reduce the
costs and uncertainties associated with environmental regula-
tions. All the case study companies have environmental de-
partments that help to develop feasible approaches to expand-
ing capacity and provide ongoing advice on the effects of
environmental requirements on the feasibility and costs of
each approach. Their activities include providing information
on specific environmental requirements, on the costs and risks
associated with compliance strategies, and on possible regula-
tory changes. They also engage in detailed environmental
planning, including participating in the search for acceptable
project sites, identifying critical environmental problems
that may force project cancellation, and planning various
permitting and licensing activities. These planning activi-
ties are often initiated many years in advance of actual plant
construction in order to secure necessary environmental ap-
provals and to protect against unexpected delays.
Despite their careful planning, all of the case studv
companies believe that delays related to environmental aoorov-
als have increased their planning and construction time scans
and, therefore, have increased their capacity expansion costs
However, none of the companies has performed the detailed '
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analysis needed to establish the magnitude of the costs of
environmentally related delays.
One company confronted with a particularly complex set of
federal, state, and local requirements has developed a system-
atic program for strategic environmental forecasting and plan-
ning. Key elements of this program include summarizing the
company's current environmental difficulties, examining trends
in environmental regulations, and forecasting the company's
environmental setting. This information provides a basis for
designing action programs to address critical environmental
problems and influence the course of regulatory developments.
Environmental planning has played an important role in
shaping some companies' capacity plans. The type, siting, and
size of powerplants have all been affected by environmental
considerations. In at least one instance, the planned in-
service dates of powerplants have also been affected; one
company has forecast a relaxation in the environmental re-
quirements it has to meet and, as a result, has delayed the
planned in-service dates of its conventional capacity expan-
sion alternatives.
Some companies have increased their spending on environ-
mental research and development as part of their strategy for
dealing with environmental regulations. They view these
efforts as extremely important, not only for developing cost-
effective ways to achieve compliance, but also for providing
technical information that can be used to support efforts to
change environmental regulations.
The case study companies plan for environmental contin-
gencies in a number of ways. Companies generally prepare and
apply for multiple sites for an individual project. One com-
pany designed a powerplant's pollution control facilities to
exceed the prevailing environmental requirements to protect
itself against future changes in environmental^regulations and
to reduce the risk of compliance problems. While this strat-
egy resulted in initial costs higher than they needed to be,
in the long run it resulted in considerable savings when regu-
lations did become more stringent. However, this approach may
result in costs that are higher than necessary if the strin-
gency of environmental regulations for a specific powerplant
remain unchanged or are increased even beyond the capabilities
of the powerplant's pollution control equipment. One company
has tried to hedge against regulatory changes by securing coal
supply options for coals of various qualities. The case study
companies also try to reduce the potential adverse conse-
quences of regulatory delays by spreading their risks over
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more plants, for example, by making arrangements for purchased
power and by participating in the joint ownership of power-
plants. One company is seeking to increase its flexibility by
developing unconventional sources of energy because some of
them have shorter lead times and fewer environmental and sit-
ing problems than conventional capacity alternatives.
Non-Coal Power Supply Alternatives
This section reviews the major factors influencing the
case study utilities' selection of ways to meet future demand
other than by the construction of coal-fired plants. The
alternatives discussed include conventional baseload units
fueled by oil, gas, and nuclear fuel, unconventional sources
of energy, and purchased power. In addition, the alternatives
of changing power system reliability criteria and conservation
and load management programs are discussed.
Because of the importance of coal as a capacity alterna-
tive and because of the substantial impact of environmental
regulations on coal-fired powerplants, the alternative of
building new coal-fired powerplants is discussed separately in
a later section.
Oil- and Gas-Fired Powerplants
FUA eliminates new oil- and gas-fired baseload units as
capacity expansion alternatives. Some of the case study com-
panies also indicated that they would not construct such base-
load units, even if this legislation were repealed, because
increasing oil and gas prices and supply uncertainties have
made new oil- and gas-fired units unattractive in comparison
with new coal-fired baseload units. Although FUA also re-
stricts the use of gas in existing baseload units, several
companies expressed an interest in continuing to bum gas in
existing gas-fired units or in converting oil-fired units to
gas because such actions would reduce or at le*st not increase
their reliance on foreign oil and would avoid the capital
costs and environmental difficulties associated with coal.
Nuclear Powerplants
All of the case study companies have
aax or cne case stuay companies have rejected the option
of starting new nuclear powerplants before the 1990s, although
the utilities plan to complete nuclear units presently under
construction. New nuclear units have been rejected despite
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the fact that the companies believe that the cost of nuclear
power is competitive with coal-fired powerplants, especially
after factoring in the costs of dealing with the air and solid
waste pollution problems associated with coal-fired power-
plants. The companies have rejected nuclear power in large
part because of uncertainties stemming from political and
public opposition to nuclear power, which opposition can lead
to the denial or delay of necessary permits and costly con-
struction delays or cancellations. The utilities noted that
the long lead times associated with new nuclear units, esti-
mated to be 10 to 15 years, create unacceptably large finan-
cial risks. Furthermore, the absence of a federal policy for
the disposal of nuclear wastes creates uncertainty as to the
methods to be used for disposal of wastes, the location of
waste disposal sites, and, ultimately, the cost of waste dis-
posal. Utilities are also highly adverse to the risks asso-
ciated with NRC regulations. These risks include possible
shutdowns, additional capital costs for equipment changes,
operating license suspensions, and increased operating costs
stemming from regulatory changes.
Unconventional Capacity Alternatives
The prospect of a continuation of increasing energy costs
and a desire to reduce dependence on foreign oil has motivated
many utilities, especially those with oil-fired powerplants,
to explore so-called "unconventional" technologies. These
include those that use wind, direct sunlight, wood, and geo-
thermal energy for generating power. They also include well-
known power-producing technologies such as cogeneration and
low-head .hydro. However, despite the new interest in these
technologies, unconventional capacity alternatives are ex-
pected to contribute only modestly to total capacity require-
ments. Moreover, even the companies interested in such tech-
nologies have contingency plans for conventional capacity
alternatives in the event that problems preclude the develop-
ment of unconventional alternatives at reasonable costs.
Some case study companies with a heavy dependence on oil
generation are actively studying or pursuing selected uncon-
ventional alternatives, not only because they have potentially
attractive economics, but also because they have fewer envi-
ronmental problems. Unconventional alternatives typically
involve smaller amounts of capacity, thereby increasing plan-
ning flexibility? they are politically popular; and they might
reduce capital requirements per kilowatt relative to conven-
tional plants. Unfortunately, some unconventional alterna-
tives are expected to remain uneconomic in the near-term,
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and possibly for the long-term. In addition, some unconven-
tional alternatives also have their environmental difficul-
ties. One company noted that a neighboring company's geother-
mal project has been significantly delayed as a result of
public and regulatory concern about the project's site in a
pristine area.
Some companies are trying to improve the economics of
unconventional capacity alternatives. One case study company
is actively encouraging vendors to develop new technologies by
providing a market for their products. It has also directly
committed funds to increase its own research and development.
Another company is trying to improve the economics of an un-
conventional project through DOE support.
Purchased Power
Purchased power can be an attractive way for a utility to
meet future demand because it typically does not require a
capital investment and because purchased power costs are usu-
ally passed through directly to consumers. Other reasons for
purchasing power include increased flexibility in capacity
planning, displacement of oil, and the avoidance of environ-
mental difficulties for the purchaser.
Sellers of power to other utilities are motivated by the
favorable economics of making better use of their capacity.
Sellers of power often enter into sales contracts for specific
time periods, after which they expect to use the powerplant to
meet increased demand in their own service territory. These
time periods may be for a number of years. In some instances,
the contract may run for the life of a unit.
Three major factors have caused most of the case study
companies to consider only moderate purchases of power.
First, opportunities to purchase power tend to be limited in
amount and may become more limited as the industry's reserve
margins and excess transmission capacity decline. Second,
purchased power may become less available as individuals or
organizations in states that currently export power exert
efforts to inhibit the movement of power out of their states
to avoid increased levels of air and water pollution. Third
PUCs may disallow purchased power expenses if such power is '
more costly to a company's consumers than power from additions
to the company's capacity.
purchases of power on the environment
depends on situational factors. In addition to changing the
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geographic location of the emission of pollutants, purchases
of power may increase or decrease the total level of emissions
of various pollutants. The net effect depends on the charac-
teristics of the seller's powerplants and the generation al-
ternatives available to the buyer.
Synthetic Fuel for Powerplants
The high cost of oil/ the risks of a heavy dependence on
foreign oil, and the environmental problems associated with
coal have prompted two of the case study utilities to consider
the use of synthetic fuels. One of the companies is partici-
pating in a demonstration project involving the use of meth-
anol as a boiler fuel. It is also considering a multi-company
project to produce synthetic gas from coal, but is concerned
because synthetic gas transported over state lines might be
subject to the Federal Energy Regulatory Commissions's prior-
ity rules for gas use, and therefore might be an undependable
source. Another case study company believes that a combined-
cycle powerplant fueled with synthetic gas may be its most
economical long-term capacity expansion alternative, 9*v®n the
relatively stringent environmental standards and the high
costs of low-sulfur coal in the company's service area. None-
theless, this company is concerned about the technological and
environmental risks associated with a commercial-size synfuels
plant, which would be an order of magnitude greater than cur-
rent demonstration plants. One alternative being considered
to help alleviate these problems is to build many small manu-
facturing units in place of one large unit.
The other four case study utilities, while
synfuels developments, have expressed little
in synfuels for several reasons. Pirst.,^yntihetic fuels re
presently not cost-competitive relative^ to °
and natural gas and may remain uncompetitive in the ^ture.
Manufacturing and using synfuels in either
powerplants are viewed as even more coal-fired
cally unattractive when compared with building new coal fired
Dowerolants Second, some of the companies interviewed were
concerned that their state regulatory crewt^tech-
adeauatelv reflect in their rate decisions the increased teen
nological and environmental risks
and using synfuels. Third, the companies,or«v£f uels
sibility of changes in environtwntalragulations for.yntuels
manufacturing, which have not yet been promulgated, to be a
significant source of uncertainty.
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Power System Reliability
Generally, the case study companies view reducing relia-
bility standards in order to postpone capacity additions as an
alternative of last resort because of the strong adverse pub-
lic reaction that would be likely to result from significant
reductions in the quality of service. Given the sensitivity
of consumers to service reliability, both utilities 'and their
PUCs tend carefully to monitor the frequency and duration of
service outages.
Even though a high level of reliability continues to be a
primary objective of each of the companies, their histories
and expectations of inadequate returns have led some of the
case study companies to lower or to consider lowering their
historical reliability standards to postpone capacity addi-
tions. To reduce its capital spending, one company, despite a
relatively strong current financial position, is carefully
evaluating whether it can lower its current reliability cri-
teria without incurring strong adverse customer reaction.
Another company's poor financial condition has already led it
to reduce its reliability criteria for its transmission and
distribution network. However, the company has not changed
its reliability criteria for generation capacity planning
because generation shortfalls affect much larger numbers of
customers and are less easily remedied than transmission and
distribution problems. Another company stated that it might
be unable to finance any capacity additions necessitated by
increases in demand beyond the modest growth it currently
forecasts. The company indicated that, if demand growth in-
creased and its regulators did not take steps to improve its
financial condition, it would be forced to let reliability
decline.
Conservation and Load Management
The increasing cost of producing electricity and building
new capacity has stimulated substantial interest in conser-
vation and load management programs. A number of the case
study companies are implementing ambitious conservation pro-
grams to reduce their capital expenditure requirements, envi-
ronmental problems, oil consumption, and consumer costs
These programs include customer education programs, customer
energy audits, promotion of solar water and space heatino
assistance in designing energy-efficient buildings, and ex-
panded use of interruptible rate structures. One company also
has a program to install insulation at customer sites How-
ever, some of the case study companies have undertaken only
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minor conservation efforts because they have not been able to
identify cost-beneficial opportunities for major programs. In
addition, one of these companies, which currently has a large
reserve margin, is not interested in pursuing a major conser-
vation program because reductions in demand could lead to
short-term declines in profitability.
Two of the case study companies are planning, or have
partly implemented, load management programs. These programs
are designed primarily to reduce peak demand (i.e., flatten
the pattern of demand), although they may also reduce energy
demand. Reduced peaking allows a company to meet a larger
portion of its demand with baseload units, which are more
efficient than peaking units, and reduce its total capacity
requirements. The two companies' load management programs
primarily focus on the use of alternative rate schedules, such
as time-of-use rates, and on experimental testing and develop-
ment of load management devices, such as energy storage sys-
tems, the use of solar energy at the customer site, and the
remote cycling of air conditioners, electric water heaters,
and other devices.
Other case study companies are also experimenting with
load management systems, but these companies have not been
able to justify significant programs on a cost-benefit basis
due to the shape of their demand pattern. For example, one of
these companies has a relatively even pattern of demand be-
cause its large and highly interconnected service territory
results in a diversification of weather-related demand and
because it has a relatively important industrial load.
Coal-Fired Powerplants
For two reasons, most of the case study companies view
coal-fired units as the primary alternative for baseload
capacity expansion—despite the significant environmental
problems associated with coal. First, the companies have
rejected the alternative of new nuclear units and FUA and
economic considerations have eliminated new oil- and gas-fired
powerplants as alternatives. Second, opportunities to meet
increases in baseload demand with the remaining alternatives
are limited; many of them, moreover, are in an early stage of
technological development and are presently uneconomical.
Coal-fired powerplants, even if economically attractive,
require large capital investments and present significant
environmental problems. The environmental problems include
problems in achieving compliance, the possibility of retrofit
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requirements, siting difficulties, the technological risks
associated with pollution control equipment, and problems in
securing high-quality coal. The requirements for pollution
control equipment also add substantially to the capital cost
of new coal-fired powerplants.
The range of choices made by the case study companies
regarding new coal-fired powerplants reflects their differing
economic, financial, and environmental circumstances: A num-
ber of the companies plan to meet increases in baseload demand
primarily with new coal-fired units because they result in the
lowest total customer costs. Although these companies are
concerned about the capital cost of new units, financial con-
cerns and environmental-regulations have not proven to be
critical constraints. Other companies are aggressively pursu-
ing unconventional sources of energy and have relegated new
coal-fired units to a contingency alternative for the long
term, despite the fact that new coal-fired units could poten-
tially be used as an economical means of displacing oil.
These latter companies have relegated new coal-fired power-
plants to a contingency role primarily because of the capital
expense of such units and secondarily because of difficulties
stemming from stringent environmental regulations. Lastly, as
previously discussed, one company believes that a combined
cycle plant fueled by synthetic gas may prove to be a more
economical alternative than new coal-fired powerplants largely
because of the pollution control costs associated with coal in
its service area.
The remainder of this section provides a more detailed
discussion o£ the environmental issues associated with coal.
The discussion covers pollution control requirements for new
coal-fired powerplants, utility concerns about technology-
forcing regulations, and siting difficulties. Utility con-
cerns regarding fuel prices and fuel quality are discussed at
length in Appendix D.
Environmental Requirements
New coal-fired units are subject to federal and state
environmental regulations. As discussed in Chapter II, feder-
al regulations include new source performance standards
(NSPS), PSD, and nonattainment regulations. PSD regulations
apply to regipns where thlf air is cleaner than the National
Ambient Air Quality Standards (NAAQS) for at least one cri-
teria^pollutant. Powerplants sited in PSD regions are re-
quired to employ best available control technology (BACT) for
controlling of emissions and to remain within the PSD air
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increments. Nonattainment regulations apply to areas that
violate NAAQS for at least one criteria pollutant. These
regulations require the utilities to use lowest achievable
emission rate (LAER) pollution control technology and to
secure enough emission offsets so that there is a net
reduction in total pollutant loadings. BACT and LAER are
determined on a case-by-case basis and must be at least as
stringent as NSPS. Since NSPS, BACT, and LAER requirements
often force a utility to employ an advanced level of pollution
control equipment, they are frequently referred to as technol-
ogy-forcing regulations.
For a number of the case study companies, state regula-
tions are somewhat more restrictive than federal requirements.
The stringency of a SIP is generally a function of the state's
ambient air quality and the environmental desires of the pub-
lic and the state's political leaders^ The stringency of a
SIP for electric utilities also depends in part on the extant
to which a state has placed the burden of pollution control on
electric utilities, as opposed to other industries and activi-
ties (e.g., transportation by automobile). In designing SIPs,
states essentially take an inventory of sources of pollution
and then allocate the burden of controlling pollution, taking
into consideration the technical and financial ability of
different industries to reduce pollutant loadings and the
effect of different control strategies on employment and other
socioeconomic variables.
One state's promulgation of standards more stringent than
federal requirements reflects a number of specific concerns.
First, the regulations were designed to compensate for what
was viewed as reluctance on the part of EPA to require ad-
vanced levels of control technology under NSPS. Second, the
regulations were designed to be stringent to provide an
incentive for utilities to develop pollution control technolo-
gies. Third, this state's regulators were concerned that the
uniform national standards, promulgated in the early 1970s,
provided an impetus for industry to move from other states to
exploit the state's air resources. Finally, the water regula-
tions affecting the state's utility plants were designed to
conserve scarce water resources to allow industrial growth.
Three case study companies currently building new coal-
fired powerplants have sited these plants in PSD regions.
These companies do not view environmental requirements mm
critical obstacles, although they result in significant capi-
tal and operating costs. Two companies expect that BACT for
the control of sulfur dioxide and particulate emissions will
require relatively advanced scrubbers and precipitators and
coals of at least moderate quality. The third company, which
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is subject to state environmental requirements which are some-
what more stringent than federal requirements, expects to
achieve compliance through the installation of state-of-the-
art pollution control equipment including a dry scrubber, bag-
house, cooling tower, and a zero discharge wastewater treat-
ment system. In addition, the company plans to meet N0X
requirements by contructing and installing boilers and burner
tips designed to control N0X emissions.
Of the three case study companies with powerplants under
construction, two were able to avoid or reduce the impact of
BACT standards. One company successfully litigated for the
exemption of a powerplant under construction from PSD regula-
tions that would have required the installation of a scrubbing
system. Scrubbers would have increased the capital cost of
the powerplant by approximately 20 percent and the company
believed it could meet air quality standards at a lower cost
by using low-sulfur coal. The other company reduced the im-
pact of BACT standards at one powerplarit by obtaining its PSD
permit before PSD regulations took full effect. The third
company, which has more willingly sought to comply with
environmental regulations, has successfully negotiated with
environmental agencies for the relaxation of environmental
standards on the basis of difficulties in designing and
operating its pollution control equipment.
Technological Concerns
SPA's adoption of technology-forcing regulations for new
powerplants reflects the idea that the most cost-effective way
to achieve a clean environment is to require stringent pollu-
tion controls for new sources. Although EPA is concerned that
stringent requirements for new sources may encourage utilities
to delay the retirement of relatively dirty, existing power-
plants, stringent new source requirements are intended to
ensure an increasingly clean environment as existing power-
plants are replaced by new plants. BPA's requirement of ad-
vanced technology for new powerplants also recognizes that
installing pollution control equipment during the construction
of new plants is much less costly than the retrofitting of
existing plants and that this equipment can be used for a
relatively long period of time.
The case study utilities are generally concerned about
the costs and risks of. pollution control technology for new
coal-fireS powerplants. A number of the companies argue that
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111-35
the technology-forcing nature of BACT and LAER creates signi-
ficant technological risks and uncertainties and unnecessarily
increases costs. For example, LAER standards can be changed
by EPA or state environmental agencies even for plants already
under construction. Thus, as new pollution control technolo-
gies are developed, utilities can be forced to adopt equipment
close to or at the state-of-the-art, creating uncertainty as
to the cost and reliability of the equipment. In response to
this line of reasoning, one state environmental agency argues
that the long lead time for new coal-fired powerplants will
provide enough time to further develop pollution control tech-
nologies, thereby increasing their reliability. This agency
attempted to ensure that one utility meet its standards by
requiring the utility to leave sufficient space in a new unit
during its construction to allow the installation of any of a
number of technologies. The agency believed that the technol-
ogies would be sufficiently developed by the end of the con-
struction period to meet its standards with a high degree of
reliability.
Largely because of the costs and risks associated with
pollution control technologies, one case study company rele-
gated the alternative of a new coal-fired powerplant to a
contingency status. This company is subject to relatively
severe technological requirements imposed by state and federal
regulations. EPA requires pollution control technology that
will meet its LAER standards for new powerplants in nonattain-
ment areas and the company's state regulations require a level
of technology for all new powerplants that is usually equiva-
lent to LAER technology even in attainment areas. LAER re-
quirements for new coal-fired powerplants in the company's
service territory include the use of state-of-the-art scrub-
bers, precipitators, and combustion equipment to control
nitrogen oxide. According to the utility, the cost of these
systems, plus closed cycle cooling, could account for 50 per-
cent of the total capital cost of a new coal-fired powerplant.
The company is also concerned that the combination of pollu-
tion control systems could significantly degrade a power-
plant's reliability. In fact, one state siting commission
pointed out that no powerplant in the world presently operates
with all three air pollution control systems at an advanced
level of technology.
The company that has more willingly sought to comply with
environmental regulations is also concerned about the poten-
tial for significant operating problems with state-of-the-art
pollution control equipment, but hopes to avoid significant
decreases in unit reliabilities. The utility's state environ-
mental regulators may assist the utility in its efforts to
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111-36
maintain unit reliabilities by continuing to allow it to oper-
ate a powerplant while repairing the plant's scrubbing system.
Even assuming that reliability problems do not necessitate
further investment in backup pollution control equipment or
generating capacity (or both), this company estimates that the
total capital cost of pollution control equipment will approx-
imate 30 percent of the total costs of a new coal-fired plant.
As is discussed further in Chapter VI, EPA also places
the total cost of pollution control equipment at about 30 per-
cent of total powerplant costs. EPA believes that scrubber
reliability problems will not be significant once a utility
gains experience with a -new scrubber. However, EPA's projec-
tion of minimal reliability problems is based on expectations
of highly reliable scrubbing systems, while the company's hope
for minimal reliability problems is based in part on its regu-
lators' allowing emission variances.
Siting Difficulties
The process used by the case study utilities in selecting
potential sites for new powerplants is generally the sane,
although the details of each company's specific procedures and
selection criteria vary somewhat. The first step in the proc-
ess typically involves a scanning of the company's region to
identify a relatively large number of potential sites with
sufficient space, water, and transportation to support a
plant. One case study company initially identified 40 poten-
tial sites; another company identified 12 sites. In the
second step, the potential sites are culled on the basis of
rough estimates of each site's economics and its possible
environment problems.
In evaluating the relative economies of sites, factors
such as distance from load centers, the need for new transmis-
sion facilities, adequacy of transportation links for fuel,
and availability of water are considered. Sites in nonattain-
raent areas or with inadequate PSD increments are screened out.
In effect, the second step of the. process attempts to identify
knockout factors. The third step in the process typically
involves detailed economic and environmental analyses of from
three to six sites. From these candidates, companies often
select not only the site tfiat appears to have the lowest
expected costs and.risks, but also one or two backup sites.
The case study utilities generally agree that siting a
coal-fired powerplant in an area subject to nonattainment reg-
ulations is nearly impossible due to difficulties in securing
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III—37
sufficient offsets. Although PSD regions are far more preva-
lent than nonattaininent areas, a significant number of coun-
ties in some states are nonattainment areas. Moreover, off-
sets in rural nonattainment areas are often difficult to
secure because their poor air guality is caused by wind trans-
port of pollutants. Offsets in urban areas are considered
generally to be too expensive, too diffuse, or simply unavail-
able in amounts sufficient to support a new coal-fired base-
load unit. One company noted that industries with a potential
for offsets are likely to save offsets for their own use.
The difficulty in locating new powerplants in nonattain-
ment areas and the greater number of PSD areas have led util-
ities to focus their siting efforts on PSD areas. Although
PSD regulations have not yet prevented any of the case study
companies from constructing new coal-fired powerplants, these
regulations present significant obstacles and, in the view of
some companies, may in the future preclude the construction of
such plants in some regions. Required modeling of powerplant
emissions is becoming very complex because .of increased over-
lapping of emissions from different powerplants in some indus-
trialized areas and the proximity of many sites to mountains
in nonindustrialized areas. Contests between utilities and
environmental agencies over the acceptability of models can
cause significant delays and possibly result in project can-
cellation. More importantly, inadequate PSD increments may
eliminate preferred sites or limit the size of a new power-
plant at a specific site, with a resultant loss of economies
of scale.
The case study companies are divided on the issue of
whether PSD increments will become a significant constraint in
the future. About half of the companies stated that PSD in-
crements may become a significant constraint as electric util-
ity and other industrial growth exhausts many of the existing
PSD increments. Potential siting constraints stemming from
insufficient air increments appear.to be caused mainly by
relatively poor ambient air quality. Some companies believe
that they will be forced to deal with severe environmental
constraints as early as the mid-1980s as they plan for power-
plants that will commence operation in the 1990s. For exam-
ple, one case study company stated that there are no PSD in-
crements left in its service territory large enough to support
a large coal-fired powerplant. In addition, an industry ob-
server has pointed out that, because of the state's poor am-
bient air quality, California may only have an "environmental
carrying capacity" of a few thousand megawatts--equivalent to
about one large coal-fired powerplant. One case study company
predicted that the utility industry's resistance to environ-
mental regulations will be-much greater in the future as a
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111-38
greater number of utilities encounter the siting and compli-
ance difficulties associated with new powerplants. The com-
pany believes that the present level of resistance has been
reduced by recent declines in demand growth that have resulted
in the cancellation or postponement of nany utilities' con-
struction programs.
The other case study companies do not view PSD increments
as a serious constraint to the siting of large, new coal-fired
units. This view is shared by some EPA officials who believe
that no acceptable evidence that PSD increments have prevented
or will prevent the siting of a powerplant has been presented.
The case study companies holding this view generally have
relatively good ambient air quality in and around their serv-
ice territories. One utility, in a state with relatively
pristine air quality and numerous Class I PSD areas, does not
view PSD increments as a serious siting constraint because the
large size of the state and the stringent control of emissions
from new powerplants contribute to a large number of poten-
tially acceptable sites. For this utility, water and coal
sources are more critical constraints to siting new coal
powerplants.
Another case study utility that does not view PSD incre-
ments as a serious constraint holds this view because of the
relatively good ambient air quality of its service territory.
This utility's state environmental agency observed that the
use of high-sulfur fuel oil since the 1974 oil embargo resul-
ted in emissions per megawatt greater than or equal to what is
expected from new coal-fired powerplants with precipitators
and scrubbers. Therefore, the eventual replacement of exist-
ing oil-fired powerplants with new coal-fired powerplants
could increase the air increments available to the operation
of new powerplants to meet increases in demand. This utility
also noted that another utility was able to use an offset
approach to enlarge a PSD increment so that it could site a
new coal-fired unit at an existing powerplant location. The
proximity of the location to a Class I PSD area and emissions
from the existing powerplant resulted in exhausting a PSD
increment, which precluded additional coal-fired units unless
offsets could be used. With the consent of EPA, the utility
enlarged the air increments to permit siting by taking steps
to reduce the sulfur dioxide and particulate emissions of the
existing powerplant. Particulate standards for the existing
units were determined in conjunction with those of the new
units and plans were established for reducing the sulfur con-
tent of the coal supply for the existing units as the new
units were placed in service.
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111-39
The regulatory process for siting a new powerplant is
complex, typically involving a number of state and federal
agencies, and can introduce uncertainty as to whether and when
approval will be given for the necessary permits. Recognizing
these problems, many states and EPA have taken steps to
streamline the siting process. However, some states do not
have central siting authorities and some state regulators are
not convinced that they are effective. One executive in a
state without a central siting agency argues that they create
additional siting complexity and delays and dilute the author-
ity of other state regulatory agencies. In this state, agen-
cies can reject sites, but do not formally approve sites.
Therefore, utilities are responsible for selecting acceptable
sites. Nonetheless, a number of states have implemented "one-
stop" permitting procedures whereby their siting agency coor-
dinates all of the permitting and licensing activities neces-
sary for a new powerplant or major modification of an existing
powerplant.
The effectiveness of one-stop permitting procedures var-
ies by state. One company has found its state's procedures to
be very effective, it credits this effectiveness to its si-
ting agency's efficient implementation of a one-stop proce-
dure, a statutory permitting time limit, and the assignment of
one hearing officer who is responsible for a siting request
until it has been acted upon. Using this approach the company
was able to site a large coal-fired powerplant in less time
than the statutory permitting time limit. Another state that
established a one-stop permitting process tried to give its
siting agency the authority to make tradeoffs between environ-
mental concerns and other siting criteria in order to increase
both the speed and effectiveness of response. The siting
agency has, however, encountered significant unwillingness on
the part of environmental agencies to agree to the tradeoffs
it considers necessary for the siting of coal-fired power-
plants in a state characterized by relatively poor air qual-
ity. The state environmental agency takes the position that
it cannot allow tradeoffs that violate its state implementa-
tion plan.
EPA is concerned about the efficiency and^effectiveness
of state permitting procedures and is encouraging and trying
to assist states in their efforts to improve their procedures.
Increased state permitting effectiveness is seen as improving
the ability of states to assume additional environmental res-
ponsibility and as leading to improved coordination between
EPA and state regulatory agencies. Improved procedures can^
also reduce permitting time delays; complexity, and uncertain-
ty. EPA surveyed and summarized state efforts to revis,®
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111-40
procedures and distributed the results to the states in the
January 1982 report "Streamlining the Environmental Permitting
Process: A Survey of State Reforms" (by TBS for EPA's Office
Management, June 1982). Furthermore, EPA is developing con-
solidated regulations for streamlining applications for facil-
ities that require a permit under national pollution discharge
emission system (NPDES), PSD, Resource conservation and Re-
covery Act (RCRA), and underground injection control' (UIC)
programs. Although primarily for EPA's use in cases where EPA
is the permitting agency, the consolidated regulations are in-
tended to serve as a model for state procedures.
UTILITY RECOMMENDATIONS FOR. IMPROVING
ENVIRONMENTAL REGULATIONS
The case study utilities have offered a variety of recom-
mendations for improving environmental regulations. These
recommendations relate to formulating, administering, and
changing existing environmental regulations. A recommendation
common to all three areas is that greater emphasis should be
placed
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111-41
Some executives in one of the case study companies be-
lieve that public pressure for regulatory change will result
in greater use of cost-benefit approaches in the setting and
administering of environmental regulations and in less regula-
tory resistance to conventional baseload capacity expansion
alternatives. They believe that increases in electricity
prices, in part due to environmental costs, and decreases in
reliability, due to siting and financing difficulties, will
focus public attention on regulatory costs and will result in
public pressure for less costly regulation.
Another unanimous recommendation for the formulation .of
environmental regulations is that regulators not change the
environmental compliance requirements for a powerplant after
it is constructed. This recommendation emerges because retro-
fits are generally more expensive than the installation of
pollution control equipment during powerplant construction.
It also reflects utility concerns about changes in environmen-
tal requirements that could result in plant shutdowns or ex-
pensive changes in operations.
Lastly, a number of companies have recommended that EPA
strengthen the factual and scientific research used as the
basis for designing new regulations. Many companies believe
that an inadequate understanding of the effects of pollutant
emissions has led EPA to adopt environmental standards with an
overly wide margin of safety for the protection of human
health and welfare.. In their view, more complete research on
the effects of powerplant emissions would allow EPA to more
properly balance costs and benefits in its formulation of
regulations and standards, thereby avoiding costly margins of
safety not justified by their benefits.
Administering
Environmental Regulations
The case study companies recommend a greater emphasis on
cost-benefit and cost-effectiveness approaches and analyses
also in the administration of regulations. The companies
generally believe that an overly strict administration of
environmental regulations by EPA and state environmental agen-
cies results in unnecessarily high costs, although they also
noted some instances where regulators have been flexible. As
an example of overly rigid administration, one company noted
that it was required to install a water cooling system at an
ocean site despite the fact that, in its view, thermal emis-
sions resulted in minimal, if any, harm to the environment.
On the other hand, the companies provided two examples or
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111-42
cases where other companies had successfully negotiated for
compliance strategies at what they believe to be a higher
level of cost-effectiveness. In one example, a company
reached a compromise with EPA that permitted it to install a
"helper" cooling system, to be used at certain times of the
year, in place of more expensive cooling towers. In the other
example, a company was able to achieve what it saw as a rea-
sonable level of cost-effectiveness in its treatments of
wastewater by negotiating for the elimination of a proposed
third stage of a wastewater treatment facility. The third
stage, a polishing pond, would have slightly increased the
effectiveness of the facility, but at a cost of over 15 per-
cent of total facility costs. The company's state environmen-
tal agency supported elimination of the third stage on the
basis of cost-effectiveness and EPA agreed to the elimination,
but on the basis of site limitations. Unfortunately, despite
eliminating the complexity of a third stage, the utility has
had significant operating problems with the facility because
even the two-stage process was a state-of-the-art design; the
utility may be forced to replace it.
Some EPA officials believe that a greater emphasis on
cost-benefit and copt-effectiveness analyses in administering
environmental regulations may conflict with some industry
recommendations to reduce uncertainty in the determining of
environmental standards. These officials argue that, in a
broad sense, EPA can either establish and enforce rigid emis-
sion or technology standards, thereby reducing utility uncer-
tainty as to the specific standards they will be required to
meet, or it can be flexible in its determination of standards
in specific cases, thereby introducing greater uncertainty
into utility environmental planning.
A number of companies support the use of emission trade-
offs since it creates opportunities for less costly compliance
strategies. One company is lobbying for greater state regula-
tory support of emission tradeoffs since it believes that
future compliance problems may present opportunities to use
tradeoffs effectively.
EPA officials are concerned that situations may arise
where emission reductions that would have occurred in the
absence of tradeoff policies will be used to offset require-
ments for controlling of emissions. However, EPA allows a
variety of offsets'and is working to encourage their use.
First, under PSD regulations, utilities can effectively avoid
BACT requirements by "rtetting" pollution emission increases
and decreases within a powerpiant. In addition, utilities can
"bubble" offsets external to a powerpiant to preclude retrofit
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111-43
requirements/ although the use of such offsets is limited by
ambient air quality standards and PSD and nonattainment regu-
lations. Third, EPA allows companies to "bank" (inventory)
offsets and awards credit for emission reductions beyond those
required. To encourage offsetting, EPA is promoting offset
markets and is conducting workshops for offset traders. EPA
also encourages states to formulate SIPs that facilitate
offsetting.
Many of the case study companies also commented on or
recommended changes in the administrative procedures and staf-
fing of environmental agencies. They suggested that EPA in-
crease its delegation of authority to the regional EPA offices
and staff these offices with more knowledgeable and experi-
enced people. These recommendations stem from the complaint
that the inability of regional EPA employees to supply infor-
mation or make major decisions has resulted in significant
project delays. Many of the utilities have also observed that
members of EPA's staff tended to be inexperienced and, as a
result, tended to be unrealistic in their desires and expecta-
tions. They noted that a high degree of turnover has contrib-
uted to the inexperience of the staff.
One case study company recommended that the operating
procedures for EPA and state environmental agencies be changed
to increase the level of state decision making and decrease
EPA's "second guessing" of a state agency's decisions. To
facilitate site permitting, this company also recommends that
utilities be allowed to inventory sites and that state siting
agencies be given greater authority to make tradeoffs between
environmental and other siting factors in their approval of
sites.
Changing
Environmental Regulations
Reflecting a variety of concerns about environmental
regulations, and their desire that regulators place greater
emphasis on cost-benefit and cost-effectiveness approaches,
the case study companies recommend a number of changes in
existing environmental regulations. Many of them recommend
longer averaging times in the national ambient air quality
standards and a greater allowance for emissions in excess of
these standards. Increased averaging times would reduce the
costs associated with controlling the variances in fuel qual-
ity and allow relaxation of pollution control equipment design
and fuel quality standards. One case study utility recommends
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111-44
that regulators not classify emissions in excess of air qual-
ity standards as violations if these events occur infrequent-
ly. Another case study utility pointed out that a greater
allowance for emissions greater than standards is almost man-
datory since a certain level of emissions peaking cannot be
avoided without incurring extreme capital and operating costs.
Some utilities also believe that existing scientific tevidence
on the health effects of pollutant emissions does not justify
a regulatory system effectively based on peak emissions. EPA
is concerned, however, that longer averaging times may result
in increased pollutant loadings. Some companies may have
lowered their average rate of pollutant emissions to reduce or
compensate for emission rate peaks that otherwise would have
violated standards based on short averaging times. An in-
crease in averaging times may allow these companies to in-
crease substantially their average emission rates by allowing
more frequent or more numerous emission rate peaks.
Many of the case study utilities recommend that PSD regu-
lations immediately be rescinded or altered to reduce limita-
tions imposed by air increments* monitoring and modeling dif-
ficulties, lengthy preconstruction review times, and the sheer
complexity of the regulations- Specific suggestions for im-
provement include enlarging PSD air increments and developing
state plans for allocating PSD increments, rather than having
them available on a first-corae-first-serve basis. Many util-
ity executives also believe that PSD regulations are redundant
or illogical based on the argument that established primary
and secondary ambient air quality standards should be suffi-
cient to protect human health and welfare. However, according
to EPA staff, this view reflects a narrow interpretation of
the objectives of the PSD program. While the PSD program is
intended in part to protect human health and welfare, it is
also designed to protect air quality in areas of special na-
tional or regional interest and to preserve existing clean air
resources while allowing economic growth.
The utilities were almost unanimous in their belief that
PSD regulations will be revised, at least as they apply to
some regions, as a result of the difficulties and expense
associated with complying with such regulations. One industry
observer believes that exhaustion of PSD increments in some
areas in the late 1980s or..early 1990s will force either the
enlargement of PSD increments or the repeal of the increment
system.
Although none of the case study utilities had specific
recommendations regarding visibility regulations, they noted
that a number of western utilities recommend that existina
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111-45
visibility regulations be rescinded or made less stringent and
that new visibility regulations not be considered until fur-
ther research has been completed- The western utilities are
particularly concerned about the possibility that either
existing or proposed visibility regulations will require cost-
ly reductions in N0X emissions.
Some electric utility industry executives also advocate
the abandonment or modification of technology-forcing regula-
tions to counteract what they perceive to be two major prob-
lems. First, technological decisions and constraints imposed
by EPA may be based more on developments in control technolo-
gies than on cost-benefit and cost-effectiveness considera-
tions. Second, technology-forcing regulations pay discourage
technological innovation and improvements. Utilities and
vendors of pollution control equipment may be reluctant to
invest in research and development for specific technologies
due to the risk that competing technologies will be chosen as
LAEA or BACT technologies, thereby eliminating their marxet.
This risk is exacerbated by the fact that .LAER doe®
to be chosen on the basis of cost-effectiveness. 0n® y
recommends that EPA not change BACT and LAER standardds
specified time periods to reduce the risk of technolog c
developments becoming obsolete as a result of regulatory
changes.
Some EPA officials and a number of utilities
about the use of technology-forcing regulations,
officials believe that utilities have little ^jjentive to
develop more advanced control technologies in the 1»
regulations that force such developments. In contrast, wniie
accepting that there is some need for a continual g 9
of standards, some utilities argue that a much more P®"* .
and effective regulatory approach to encouraging noiiution
innovation and the installation of state—of—the— P
control equipment is to provide economic incent
activities.
The changes to existing regulations^Recommended by^the^
case study utilities address niany, but noafii'0raanizations.
concerns espoused by electric utility J-hJ*1" J advocated two*
For example, the Edison Electric In^itute has advocated two
changes to the Clean Air Act that not surface in^TBS^s^
interviews. First, BACT, LAEK, and NSPS eliminate
be replaced with one set of NSPS *««oeiated with
uncertainty and reduce the time and efforts displace-
environmental regulation. Second,to enco)arage oil displace
ment, voluntary coal conversions should P
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m q
**•«
s£
2?
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CHAPTER IV
EFFECTS OF ENVIRONMENTAL
REGULATIONS ON ELECTRIC UTILITY UNITS
-------
CONTENTS
INTRODUCTION AND MAJOR FINDINGS Iv_!
Distribution of Units by Fuel Type and Age IV-1
Environmental Compliance Strategies IV-3
Pollution Control Costs IV-5
Pollutant Removal and Cost Effectiveness IV-10
RESEARCH METHODOLOGY AND DATA SOURCES IV-12
UNIT COMPLIANCE STRATEGIES IV-15
Air Pollution Control Strategies IV-16
Coal-Fired Unit Strategies IV-17
Oil-Fired Unit Strategies IV-21
Water Pollution Control Strategies IV-24
Solid-Waste Control Strategies IV-25
1979 UNIT-LEVEL COSTS IV-26
Technical and Financial Assumptions IV-26
Pollution Control Assumptions IV-27
Baseline Assumptions IV-35
Results of the Unit-Level Analysis IV-37
Distribution of Compliance Costs IV-37
Components of Compliance Costs IV-39
Variations in Compliance Costs Among Unit
Categories IV-42
Variations in Compliance Costs Within Unit
Categories IV-46
FUTURE UNIT-LEVEL COMPLIANCE STRATEGIES AND COSTS IV-47
Compliance Strategies IV-47
Compliance Costs IV-48
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CONTENTS
(continued)
COST-EFFECTIVENESS ANALYSIS IV-52
Existing Units IV-52
Quantities of Pollutants Removed IV-5 3
Cost of Removal IV-57
Future Units IV-57
Quantities of Pollutants Removed IV-59
Cost of Removal IV-61
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IV. EFFECTS OF ENVIRONMENTAL REGULATIONS ON
ELECTRIC UTILITY UNITS
INTRODUCTION AND MAJOR FINDINGS
This chapter examines strategies for and costs of compli-
ance with environmental regulations for individual electric
generating units. The objectives of the chapter are, first,
to determine average costs for pollution control incurred by
fossil steam units and, second, to compare compliance strate-
gies and costs among units. Such an analysis permits an iden-
tification of unit-level costs that would otherwise not be
apparent in an aggregate analysis that includes a large number
of minimally affected units.
The analysis in this chapter is based on data compiled in
the Energy Database concerning the characteristics, environ-
mental compliance strategies, and costs as of December 1979 of
steam-electric generating units burning fossil fuels for which
a Form 67 was submitted to the Department of Energy (DOE) in
19 79.^- These 2,277 units have a capacity of 395,868 MW, which
represents approximately 96 percent of total capacity of fos-
sil-fired steam-electric units reported in DOE's 1979 Inven-
tory of Powerplants.^ Units not included in the analysis are
primarily those in plants with capacities of less than 25 MW
that do not submit Form 67s.
Distribution of Units by Fuel
Type and Age
Coal-fired units account for nearly 60 percent of the
capacity of units in the Energy Database (Table IV-1). The
remaining 40 percent of capacity is relatively evenly distrib-
uted among units that burn oil, gas, and oil and gas com-
bined.
1Form 67s, "Steam-Electric Plant Air and Water Quality Control
Data," summarize unit-level pollution control data and are
submitted annually to DOE. For a description of the Energy
Database see Appendix A.
2U.S. Department of Energy, Inventory of Powerplants in the
United States, December 1979.
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IV-2
Table IV-1
DISTRIBUTION Of COSSIL-FUEL
UNITS BY FUEL TYPE1
Percent of
fuel Type Units
Percent of
Capacity
Coal
Oil
Gas
Gas/Oil
47
17
17
19
59
15
13
13
^Totals may not add to 100 percent
due to rounding.
Source: Energy Database.
Eighty-six percent of the units in the Energy Database
were in service by 1972 and thus predate the 1971 Clean Air
Act and the 1972 Clean Water Acts (Table IV-2). Environmental
compliance for these units has consisted of retrofitting pol-
lution control equipment to comply with regulations for exist-
ing sources promulgated under the Clean Air and Clean Water
Acts. Units that came into service in 1972-1976 have also
been subject to existing source air and water regulations, but
in most cases these units have not been required to retrofit
pollution control equipment as they generally were designed
taking air and water regulations into account. Finally, units
Table IV-2
DISTRIBUTION OF FOSSIL -FUEL
UNITS BY IN-SERVICE YEAR1
In-Service
Year
Percent of
Unit8
Percent of
Capacity
Pre-1972
1972-1976
1976-1979
86
9
5
63
25
12
totals may not add to 100 percent due
to rounding.
Source: Energy Database.
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IV-3
that have come into service since 1976 have as a rule been
subject to new source standards under the Clean Air and Clean
Water Acts.
Environmental Compliance Strategies
Strategies for compliance with sulfur dioxide (SO2) and
total suspended particulates (TSP) requirements among coal
units reflect increasingly stringent standards. Only 23 per-
cent of coal capacity that came into service before 1977
either burns coal with less than 0.8 percent sulfur and/or
has flue gas desulfurization (FGD) systems (Table IV-3). The
proportion of capacity in this category rises dramatically to
73 percent of 1977-1979 capacity and to 98 percent of capacity
that is projected to come into service in 1980-1984. This
increase reflects primarily the increasing use of scrubbers
from 5 percent of pre-1977 capacity, to 35 percent of 1977-
1979 capacity, and to 52 percent of 1980-1984 capacity.
Table IV-3
DISTRIBUTION OF COAL CAPACITY
BY REPORTED S02 COMPLIANCE STRATEGY
(percent of age-category capacity)
SO? Compliance Strategy In-Service Year
<0.8% Sulfur Coal
Pre-1977
1977-1979
1980-1984
With FGD
2
22
14
Without FGD
18
38
46
>0.8S Sulfur
With FGD
3
13
38
Without FGD
77
27
2
Total
100
100
100
Source: Energy Database.
Coal units of different vintages also reflect different
TSP requirements. Over 96 percent of the capacity in units in
all age categories has TSP collection systems whose removal
efficiencies are above 98 percent. Units that came into serv-
ice before 1972, however, have frequently retrofitted electro-
static precipitators alongside older, less efficient mechan-
ical collectors.
-------
IV-4
Air pollution control strategies at oil and gas/oil units
consist primarily of the use of low-sulfur oil to control SO2
emissions. Over 60 percent of the capacity in oil-fired units
burns oil with less than 1 percent sulfur by weight. A
further 30 percent of this capacity burns oil with 1 to 2 per-
cent sulfur, and less than 10 percent uses oil with more than
2 percent sulfur (Table IV-4). Particulate emissions are
reduced both by burning low-sulfur oil (because it is a
higher-quality fuel with fewer impurities) and by installing
TSP control equipment. However, only 40 percent of oil and
oil/gas capacity has particulate control systems and less than
a fourth of these systems have removal efficiencies greater
than 98 percent.
Table IV-4
DISTRIBUTION
REPORTED S02 AND
Of OIL CAPACITY BY
TSP CONTROL STRATEGY1
S02 Control
TSP Control Equipment
Fuel Percent Percent of
Sulfur CaDacity
TPS Collection Percent of
Efficiency (S)^ Caoacity
<0.9 63
1-1.9 29
>2.0 8
>98 B
90-98 17
<90 14
No equipment 60
1Includes gas/oil unite.
^One percent reported TSP equipment but did not apecify
control efficiency.
Source: Energy Database.
Water pollution controls at steam-electric units are much
less extensive than air pollution controls. Virtually all
plants have central treatment facilities to treat a number of
relatively low-volume waste streams simultaneously. In addi-
tion, some plants have installed ash transport water recircu-
lation systems which are no longer required by federal regu-
lations.
The use of cooling towers or ponds to control thermal
discharges is becoming increasingly prevalent. The share of
capacity with cooling systems increases from less than one-
third of pre-1972 capacity to two-thirds of 1977-1979 capacity
(Table IV—5). This shift reflects both environmental require-
ments and an increasing proportion of units sited in water-
constrained areas where recirculating cooling systems are used
primarily for economic rather than environmental reasons.
-------
IV-5
Table IV-5
DISTRIBUTION OF FOSSIL-FUEL CAPACITY
BY THERMAL CONTROL STRATEGY1
(percent of age-category capacity)
Pre-1972 1972-1976 1977-1979
With cooling tower
or pond 26 63 66
Without cooling
tower or pond 74 37 33
^Totals may not add to 100% due to rounding.
Source: Energy Database.
Pollution Control Costs
The average annualized cost of pollution control at fos-
sil-fuel plants is 3.88 mills per kWh of generation (Fig-
ure IV-1), although differences in plant age, capacity, fuel
type, control strategies, control levels, and other important
variables lead to a range of less than 1 mill/kwh to nearly
8 mills/kWh. The dominant contributor to the average cost is
control of SO2 emissions, which accounts for 2.72 mills per
kWh or 70 percent of total pollution control expenditures of
3.88 mills/kWh. The remaining pollution control expenditures
are relatively evenly divided among controls for TSP emissions
and chemical and thermal discharges. By cost component the
largest single component of pollution control cost is a pre-
mium paid by utilities for low-sulfur fuels. This premium
accounts for nearly 65 percent of the average cost of pollu-
tion control, and contributes more than three times as much as
do capital expenditures to pollution control costs.
Consumption of oil for steam generation results in great-
er pollution control expenditures than does consumption of
coal or gas because of the premium paid by utilities for low-
sulfur oil (Figure IV-2).3 The average 6.86 mills per kWh
^There are a number of ways of calculating the fuel premium.
Nonetheless, even if the methodology used in this report
somewhat overstates the oil premium, this basic conclusion
holds under alternative methods of calculating the premium.
-------
IV-6
Figure IV—1
COMPONENTS OF 1979 AVERAGE COST OF POLLUTION CONTROL
FOR FOSSIL FUEL UNITS
1879 DOLLARS
Enargy Panalty
Operations and Maintananca
Capital
Fual Premium
II il i
64%
'• r \
11*
70*
I ] Tharmal Control
Cham teal Control
WM TSP Control
IM'aaV'a'M
SO2 Control
National Average Cost: 3.88 mills par kWh
Sourca: Energy Database; TBS calculations.
3.88 mills per kWh
-------
IV-7
Figure IV—2
COMPONENTS OF 1979 NATIONAL AVERAGE COST OF POLLUTION CONTROL
FOR FOSSIL FUEL UNITS BY FUEL TYPE
1979 DOLLARS
.5*
17%
°
If**:
80%
5%
87%
COAL OIL
3.68 mills per kWh 7.89 mills per kWh
GAS
0.55 mills par kWh
] j Energy Penalty
1 | Operations & Maintenance
Capital Cost
Fuel Premium
Total (Gas Units Only)
i%
3%
GAS/OIL
4.72 mills par kWh
9%
13%
SE¥&18% :
-
COAL
3.68 mills per kWh
-5%~
6%
zzssszsr
2%
87%
OIL
7.89 mills par kWh
GAS
0.55 mills per kWh
Thermal Control
Chemical Control
TSP Control
[ SOj Control
V / J Total (Gas Units Only)
GAS/OIL
4.72 mills per kWh
Source: Energy Database; TBS calculations.
-------
IV-8
paid by utilities for low-sulfur oil is more than 3.5 times as
great as the low-sulfur coal premium and it exceeds total
pollution control expenditures by coal units.
Aside from the low-sulfur fuel premium, coal units incur
greater pollution control expenditures than do units burning
oil or gas. Coal units incur average expenditures of 1.85
mills per kWh for pollution control in addition to the fuel
premium while oil, gas and gas/oil units spend 0.5 to 1.0
mills per kWh. The major reasons for these greater costs
incurred by coal units are their expenditures for scrubbers
and TSP control systems.
The major trend in pollution control costs is a continu-
ing rise in capital expenditures. Coal plants, which will
increasingly dominate fossil-steam capacity, exhibit dramatic
increases in pollution control capital costs over time (Fig-
ure IV-3). Among pre-1972 coal units, capital costs account
for pollution control costs of 0.76 mills per kWh. This cost
increases by 270 percent to 2.81 mills per kWh for units that
came into service after 1976. In the future, with higher
costs for scrubbers required for all new coal units after 198 5
under new source performance standards (NSPS) II regulations,
capital costs will continue to increase. If eastern utilities
choose to burn high-sulfur coal with high-efficiency scrub-
bers, a decrease in the low—sulfur coal premium may partially
offset higher capital costs.
In the future scrubbers will increasingly dominate pollu-
tion control strategies and costs. Approximately one-half the
capacity that will come into service in the United States from
1980 through 1984 will meet NSPS II requirements. In the
West, 80 percent of this NSPS II capacity will install scrub-
bers with 70 percent removal efficiencies. The remaining
20 percent of western NSPS II capacity will be located at
sites where more stringent BACT limits will require scrubbers
with 90 percent removal efficiencies as well as low-sulfur
coal. In the East, about 90 percent of the NSPS II capacity
will install scrubbers with greater than 90 percent removal
efficiencies and burn high-sulfur coal. Thus only the 10 per-
cent of the eastern NSPS II units that burn low-sulfur coal
will incur a fuel premium..
Costs for future units meeting NSPS II requirements were
calculated using engineering cost assumptions supplied by EPA.
These costs will range from 9.4 mills per kWh for western low-
sulfur coal units to 13.4 mills per kWh for eastern low-sulfur
coal units. Given existing wet scrubbing technologies for
-------
IV-9
Figure IV—3
COMPONENTS OF 1979 NATIONAL AVERAGE COST OF POLLUTION
FOR COAL UNITS BY AGE CATEGORY
1979 DOLLARS
i Enwvv Penalty
] Operations & Maintenance
feal Cap*®* Co«t
I Fuel Premium
I??.;?
22%
57%
-IX
13%
15%
IWKWHW!!!
28%
talis
VMirVilii'
44%
10%
Pre—1972 Units
3.42 mill* |
kWh
1972-1975 Units
3.47 mlll» par kWh
Post—1976 Units
S.81 mills par kWh
Thermal Control
Chemical Control
filil TSP Control
SO2 Control
f< 1%
25%
10%
m%s
54%
i
17%
7%
o.:
iiiiM
63%
Pre—1972 Units
3.42 mills per kWh
1972-1976 Units
3.47 mills per kWh
Post-1976 Units
6.81 mills per kWh
Source: Energy Database; TBS calculations.
-------
IV-10
eastern units, 90 percent removal scrubbing on eastern high-
sulfur coal is slightly less costly than 70 percent removal
scrubbing on low-sulfur coal. If less costly dry scrubbing
technologies become generally available for eastern low-sulfur
coal, 70 percent removal dry scrubbing will become economical-
ly more attractive.
Pollutant Removal and Cost Effectiveness
Nationally, electric utility air pollution control meas-
ures in place in 1979 resulted in the removal from the atmos-
phere of approximately 42 percent of uncontrolled SO2 emis-
sions of 29 million tons and 98 percent of uncontrolled TSP
emissions of 46 million tons (Table XV—6). Coal units con-
tributed the dominant share of both uncontrolled emissions and
pollutant removals, reducing emissions of TSP by 98 percent
from over 45 million tons to less than one million tons and
SOo by 37 percent from 24 million tons to 15 million tons.
Oil units and gas/oil units reduced uncontrolled emissions of
SO2 by 70 percent from 5 million tons to 1.5 million tons.
Oil and gas/oil units had only minor TSP emissions and units
that only burn gas do not emit SO2 or TSP.
Table IV-6
TOTAL NATIONAL. POTENTIAL AIR POLLUTANT
EMISSIONS AND REMOVALS
BY FUEL TYPE IN 1979
(thousand* of tons)
50z
TSP
Fu^J Type
Potential
Emissions
Total
Removed
Percent
Removed
Potential
Eniaaiona
Total
Removed
Percent
Removed
Coal
Oil
Gsa/Oil
24,398
2,695
1,954
9,015
1,783
1,418
37
66
73
45,651
170
127
44,775
143
100
98
84
79
Total
29,047
12,2X7
42
45,948
45,018
98
Source: Energy Database and TBS'calculations.
As shown in Table IV-7, the average cost of removing
pollutants in 1979 varied significantly among unit categories
and pollutants. Nationally, the average cost of reducing SO2
emissions was $461 per ton. The cost of reducing these
-------
IV-11
Table IV-7
AVERAGE COST PER TON OF S02 AM) TSP REMOVAL IN 1979
AND FOR FUTURE NSPS II UNITS
(1979 dollars per ton)
Fuel Type
S02
Removal Strategy
Low-
Low-
1979
Sulfur
Sulfur
Weighted
TSP
Generation
Coal
Oil
Scrubbers
Avereae
Eauioment
Coal
229
412
418
263
20
Oil
N/A
737
N/A
737
534
Gas/Oil
N/A
742
N/A
742
a
National Average
229
721
418
461
22
NSPS II Units
Eastern Lew-Sulfur Coal 219
Eaatem High-Sulfur Coal 0
Western Low-Sulfur Coal 0
1,145
417
1,347
385
417
1,347
60
47
67
Note: See Table VI-17 and Figure VI-6 for escalation rstes for various components
of costs. An approximation to 1982 dollars can be msde using the GNP
escalation factor of 1.286.
N/A s Not applicable,
a = Insufficient observations.
^Scme coal units burn both coal and oil; these units attain rsductions in S02
from both fuels.
Source: EPA, Energy Dstabase, and TBS calculations.
emissions was more than three times as great at oil-fired
units as it was at coal-fired units. Among coal units, reduc-
ing SO2 emissions was on average nearly twice as expensive
using scrubbers as it was using low-sulfur coal. The national
average cost of reducing TSP emissions was $22 per ton.4 This
4lt should be emphasized that the costs described in this
chapter are average, not marginal costs. Marginal (incre-
mental) costs of moving to more stringent standards would be
significantly higher. To the extent, moreover, that utili-
ties would voluntarily control TSP emissions in the absence
of pollution control regulations, the cost per ton of TSP
removal would increase both because smaller quantities of TSP
would be removed in response solely to environmental regula-
tions and because cost3 would be based on the marginal costs
of control systems whose efficiency exceeds the levels that
would be adopted voluntarily.
-------
IV-12
average cost was dominated by the low average cost of removing
very large quantities of TSP at coal-fired units. Removal
costs for future, NSPS II, units are dominated by scrubbers
and are projected to be significantly greater than costs at
existing units. On a total national average removal cost
basis, SO2 and TSP removal costs will at least double or
triple.
The unit-level analysis is described below in three sec-
tions. The first section discusses the research approach and
data sources used in the analysis. The second section con-
tains a description of the unit categories selected for analy-
sis and highlights the strategies used by units in each cate-
gory to meet environmental regulations. The third section
contains the results of the cost analysis, comparing pollution
control costs both among unit categories and within these
categories. In this third section, unit-level costs that may
be incurred under future regulations are also discussed. The
final section of the chapter discusses quantities of pollu-
tants removed and the costs per ton of removal.
RESEARCH METHODOLOGY AND
DATA SOURCES
The unit-level analysis is based on actual compliance
strategies and costs for fossil-fired steam electric units.
These data are compiled in the Energy Database from Form 67
submittals to the Department of Energy for 1979 and were vali-
dated extensively prior to including them in this study. The
analysis was performed in four steps. First, units in the
Energy Database were categorized according to the two para-
meters that most significantly affect their environmental
compliance strategies and costs—fuel type and age. Next,
strategies used by units in each category to comply with envi-
ronmental regulations were examined. Third, 1979 compliance
costs at the individual unit level were determined on the
basis of reported environmental expenditures and, in a limited
number of instances, engineering cost estimates. Finally,
unit-level costs for units that will be coming into service in
the future were estimated from engineering cost estimates
provided by EPA.
The Energy Database contains 2,277 units with a capacity
of 395,868 MW, representing approximately 96 percent of the
total fossil-fuel-fired generating capacity in the United
States. The analysis of industry compliance strategies is
based on this full database. Data compiled in the Energy
Database were validated for reasonableness and consistency and
-------
IV-13
compared with external sources such as DOE's Generating Unit
Reference File, for 1979, and Cost and Quality of Fuels, for
19*79, and the National Coal Association's Steam Plant Factors.
In most instances it was possible to correct anomalous entries
in the Database (generally unreasonable heat rates that indi-
cate incorrectly reported fuel consumption or generation of
electricity). Form 67s for units representing approximately
8 percent of fossil-fuel capacity, however, contained incom-
plete or anomalous data that could not be verified. Where
necessary, these units were eliminated from the analysis and,
consequently, the results presented in this chapter are based
on a sample of at least 88 percent of total capacity.5
Environmental compliance strategies and costs vary with a
unit's age and the type of fuel it uses. For this reason the
units in the Energy Database were allocated among 12 unit
categories based on fuel type and plant age. Four fuel cate-
gories—coal, gas, oil, and gas/oil—and three age categories
—units in service before 1972, between 1972 and 1976, and
after 1976—were selected. The distribution of units and
capacity among these categories is shown in Table IV-8.
Tab la IV-8
DISTRIBUTION OF UNITS BY UNIT CATEGORIES
Fuel Type
In-Service
Year
Pre-1972
1972-1976
1977-1979
Total
Coal Oil Gas Gas/Oil Total Foaail Nuclear
Unita
MW
Units
MW
Unita
MW
Unita
MW
Units
MW
Units
MW
898
141,377
312
29,212
330
36,800
417
45,201
1,957
252 , 590
18
8,642
108
60,477
48
19,251
34
11,862
20
7,616
210
99,166
40
34,806
72
32 , 734
22
10,341
12
3,855
4
371
110
47,301
12
10,247
1,078
234 , 548
382
58,B04
376
52,517
441
53,188
2,277
399 , 057
70
53,695
Sources Energy Database for foaail-fuel data and Generating Unit Reference File (GURF DOE) for
nuclear fuel data.
^The analysis of compliance costs was performed on a smaller
sample representing approximately 69 percent of the total
capacity in the Database, of which 9 percent was eliminated
because of anomalous data. Subsequent to the completion of
the cost analysis described in this chapter, Form 67 data for
the remaining units were compiled in the Energy Database. An
analysis of cost data for these remaining units indicates
that there are no substantial differences between these units
and those on which this chapter's cost analysis is based.
-------
IV-14
Units in the Energy Database do not fall neatly into fuel
categories: only one-third burn exclusively coal, oil, or
gas.® Consequently it was necessary to develop a number of
decision rules to allocate units among the four fuel cate-
gories.
All units that burned appreciable quantities of coal in
1979 were considered coal units. These units, as shown in
Table IV-8, account for one-half of the units and nearly
60 percent of the capacity. Frequently these units burn some
oil or gas as starter fuel. Fewer than 2 percent of the coal-
fired units also burn oil or gas beyond that used for start-
up.
Coal-fired units that also burn oil or gas were not dif-
ferentiated in the analysis for two major reasons. First,
given the high cost of burning oil or gas as compared with
that of coal, units capable of burning coal can be expected to
use coal as their fuel source to the maximum extent possible.
Second, in terms of environmental compliance, these units are
more similar to other coal units than to oil or gas units.
Because of their distinct differences in environmental
compliance costs, units burning oil and gas are differenti-
ated. Oil-fired units, which account for 15 percent of the
total capacity, incur significant environmental compliance
costs as a result of burning low-sulfur oil. They also incur
some costs to operate TSP control systems. By contrast, gas-
fired units, which make up 13 percent of total capacity, have
low compliance costs because, unlike oil and gas units, they
are not affected by TSP, SC>2, and certain chemical standards.
A further 13 percent of the total capacity consists of
units that burn a combination of oil and gas, with neither
fuel accounting for more than 95 percent of the unit's total.
As oil units, these units bear significant environmental
compliance costs. To the extent that they burn gas, however,
their average costs per kilowatt-hour are diluted by the very
^Units in the Energy Database fall into seven fuel categories
which were compressed into the four categories used in this
analysis: 270 units with 40,768 'MW burn coal exclusively;
528 units with 149,823 MW burn coal and oil; 116 units with
18,882 MW burn coal, oil, and gas; 164 units with 25,075 MW
burn coal and gas; 347 units with 51,763 MW burn oil exclu-
sively; 227 units with 20,443 MW burn gas exclusively; and
625 units with 88,766 MW burn oil and gas.
-------
IV-15
minor compliance costs they incur when they burn gas. Because
there is no ready way to disentangle the oil and gas costs
that gas/oil units bear, this analysis considers them in a
single mixed category.
Nuclear units do not submit Form 67s and are regulated
primarily by the Nuclear Regulatory Commission. For these
reasons compliance strategies and costs for nuclear units are
not considered separately in the unit-level analysis. Both
strategies and costs, however, are similar to those for gas
units because nuclear units are not affected by EPA air regu-
lations, and nuclear unit waste streams affected by EPA water
regulations are similar to those for gas units.
The analysis divides the steam-electric units into the
following age categories:
• Units in service before 1972. These units
antedate regulations under the Clean Air and
Clean Water Acts and have complied with these
regulations by retrofitting pollution control
equipment.
• Units with in-service dates between 1972 and
1976. These units do not qualify as new units
for regulatory purposes, but generally were
designed taking air and water regulations into
account.
• Post-1976 units. These units are generally
considered new sources under both air and water
regulations. They do not fall, however, under
the revised new source performance standards
for air, which apply only to units beginning
construction after September 18, 1978.
On the average the in-service dates for pre-1972 units
are in the early 1960s and those for 1972-1976 and post-1976
units are in the midpoints for their age categories.
UNIT COMPLIANCE STRATEGIES
As noted in Chapter II federal environmental regulations
affecting the electric utility industry have focused on air
pollution resulting from SO2 and TSP emissions and on water
pollution caused by chemical and thermal discharges. Until
recently N0X emissions and electric utility solid wastes
-------
IV-16
have not been the subject of major regulatory attention, al-
though EPA will most likely direct increasing attention to
both areas.7
A utility's financial condition, its fuel purchasing
arrangements, and its anticipation of future developments, as
well as a unit's age and fuel type, dkn affect its choice of
environmental compliance strategies. In the case of utilities
facing financial constraints, the compliance strategy selected
may not always minimize annualized costs. Such utilities may
have to adopt a strategy that minimizes capital requirements,
rather than total annual revenue requirements. For example, a
capital-constrained utility earning an inadequate return on
its investments may be unable to finance an investment in
scrubbers and may have to burn low-sulfur coal instead.
Existing fuel contracts also affect compliance strategies.
Utilities with long-term arrangements for high-sulfur coal
supplies are more likely to pursue an equipment-intensive
strategy than utilities without such contracts. Utilities
anticipating more stringent future requirements may incur
higher costs than required in the short run in order to avoid
future expenses for retrofitting pollution control equipment.
Air Pollution Control Strategies
Air pollution controls, implemented through state imple-
mentation plans, for existing units in nonattainment areas
must comply with reasonably available control technology
(RACT) for units that commenced construction prior to the 1971
NSPS I date. In this analysis, in-service dates of 1976 or
earlier are considered existing units with respect to NSPS I
requirements. Standards under RACT are determined on a case-
by-case basis and depend both on local environmental condi-
tions and on economic considerations. All units that com-
menced construction after 1971 have generally been required to
comply with technology-based performance standards established
by EPA in 19.72. These standards specify emission limits for
air pollutants that may be met either by burning cleaner fuels
7Two trends apparent in the Energy Database are the decreasing
use of cyclone boilers, which are characterized by very high
N0X emissions, and increasing use of lined solid waste
disposal facilities. Cyclone units were widely installed in
the 1960s and early 1970s, but have been virtually discon-
tinued in later units. The use of lined disposal facilities
is projected to increase by 50 percent for units reporting
future plans in their Form 67s.
-------
IV-17
or by installing pollution control equipment. In this anal-
ysis, units with in-service dates of 1977 and later are con-
sidered new units subject to NSPS I requirements.
New source performance standards established in 1979 for
plants commencing construction after mid-1978 (NSPS II) spec-
ify both emission limits and emission reductions that require
pollution control equipment. New units in areas that meet
national ambient air quality standards are also subject to
best available control technology (BACT) requirements. New
units in areas that do not meet national standards are subject
to lowest achievable emission rate (LAER) requirements. Both
BACT and LAER incorporate NSPS as a minimum requirement; how-
ever, in specific instances they may be more restrictive than
NSPS.
Coal-Fired Unit Strategies
Coal units are potentially major sources of SO2 and TSP
as well as of N0X emissions. Controls of these emissions
have involved the installation of pollution control equipment
for SO2 and TSP control as well as the use of coal with lower
sulfur contents for SO2 control. To date major steps have not
been taken to control N0X emissions, although trends in
boiler design reflect a need to reduce N0X emissions.
SO? Control. Approximately 23 percent of the capacity in
coal-fired units that came into service before 1977 meets the
NSPS I requirement of 1.2 pounds of. SO2 per million Btu. For
post-1976 capacity, this figure has risen dramatically to 82
percent, indicating that most units that have come into ser-
vice since 1976 have been affected by NSPS I. Coal-fired
units are relying increasingly on pollution control equipment
to control SO2 emissions. While only about 4 percent of the
coal capacity in service before 1977 has flue gas desulfuriza-
tion (FGD) systems (scrubbers), approximately 36 percent of
the capacity that began operating in 1977-1979 has scrubbers,
and about 52 percent of the capacity that will- come into serv-
ice in 1980-1984 will use them (see Tables IV-9, IV-10, and
IV-11).
-------
IV-18
Table IV-9
REPORTED S02 COMPLIANCE STRATEGIES
PRE-1977 COAL UNITS
Sulfur Content *6f Fuel (percent)
FGD Scrubber
<0.8
0,
.8-2.0
>2
.0
Total
Efficiency (%)
Units
(MW)
Units
(MK)
Units
(MW)
Units
(MW)
96-100
2
(288)
3
(466)
0
(0)
5
(754)
90-95
0
(0)
2
(462)
3
(1,316)
5
(1,779)
70-89
9
(1,831)
0
(0)
20
(1,727)
29
(5,557)
< 70
6
(2.433)
0
JS)
_1
(147)
_7
(2.590)
Total with FGD
17
(4,562)
5
(928)
24
(5,189)
46
(10,679)
Total without FGD
174
(35,693)
373
(74,559)
413
(80,883)
960
(191,135)
Total
191
(40,255)
378
(75,487)
437
(86,072)
1,006
(201,814)
Source: Energy Database.
Nearly three-quarters of the 1977-1979 capacity that does
not have scrubbers burns low-sulfur coal. These units, pri-
marily located in the West, meet the NSPS I standards which
specify emissions limits but not SO2 control equipment removal
efficiencies. The remaining units (approximately 18 percent
of post-1976 coal-fired capacity) do not comply with NSPS I
limitations. Some of these units were commenced before 1971
but did not come into service until after 1976 and are not
affected by NSPS I standards. Others are currently violating
the limits, but in most cases are on EPA-approved compliance
schedules.
Coal units coming into service in the future will meet
increasingly stringent standards. Forty-eight percent of the
capacity coming into service in 1980-1984 will meet the
NSPS II requirements and all remaining post-1979 units will
meet NSPS I standards.8 As shown in Table IV-11, future units
will increasingly rely on FGD systems to comply with SO2
®NSPS II standards apply to units commenced after 1978. Some
of these units will come into service in 1980-1984 while
other units coming into service in 1980-1984 will be subject
to NSPS I because construction on them commenced before
1979.
-------
IV-19
Table IV-10
REPORTED S02 COMPLIANCE STRATEGIES
1977-1979 COAL UNITS
Sulfur Content of Fuel (percent)
FGD Scrubber
<0
.8
0.8-2.0
>2
.0
T otal
Efficiency (%)
Units
(MW)
Units (MW)
Units
(MW)
Units
(MW)
96-100
0
(0)
0 (0)
0
(0)
0
(0)
90-95
2
(1,059)
0 (0)
3
(2,109)
5
(3,168)
70-89
S
(2,705)
2 (510)
3
(1,208)
13
(4,423)
<70
J_
(3,528)
1 (280)
1
(12.5)
_9
(3,820)
Total with FGD
17
(7,292)
3 (790)
7
(3 , 329)
27
(11,411)
Total without FGD
30
(12,350)
9 ( 5,786)
6
(3,188)
45
(21,323)
Total
47
(19,642)
12 ( 6 , 576)
13
(6,517)
72
(32 , 734)
Source: Energy Database.
Table IV-11
REPORTED S02 COMPLIANCE STRATEGIES
1900-1984 COAL UNITS
Sulfur Content of Fuel (percent)
FGD Scrubber
<0,
.8
0.
,8-2.0
>2,
.0
T otal
Efficiency (S)
Units
(MW)
Unit 8
(MW)
Unit 8
(MW)
Units
(MW)
96-100
0
(0)
0
(0)
0
(0)
0
(0)
90-95
3
(2,062)
0
(0)
10
(5,781)
13
(7,843)
70-89
3
(1,315)
4
(.2,603)
2
(999)
9
(4,917)
<70
_0
L°)
0
_0
0
_0
(0)
Total with FGD
6
(3,377)
4
(2 , 603)
12
(6,780)
22
(12,760)
Total without FGD
38
(11,315)
2
(510)
0
0
40
(11,825)
Total
44
(14,692)
6
(3,113)
12
(6,780)
62
(24,585)
Source: Energy Database.
-------
IV-20
standards. Fifty-two percent of the coal-fired capacity com-
ing into service in the 1980-1984 period will have FGD sys-
tems. With the exception of a few western units that meet
stringent PSD limits, units with FGD systems that burn medium-
to low-sulfur coal will have scrubbers with removal efficien-
cies of 70 to 80 percent. Conversely units that burn high-
sulfur coal will have scrubbers whose removal efficiency is 90
percent or greater. This split reflects the sliding scale
standard contained in the NSPS XI regulations which allows
plants burning low-sulfur coal to install scrubbers with 70
percent removal efficiencies, but requires 90 percent removal
efficiencies at units burning high-sulfur coal.
All but one of the eastern units coming into service from
1980 through 1984 and meeting the NSPS II limits will burn
high-sulfur coal. This fact indicates that, given current
scrubber technologies and costs, plants locating in the East
do not have an incentive to burn low-sulfur coal to avoid a 90
percent scrubbing requirement. For these eastern units the
fuel premium associated with low-sulfur coal outweighs poten-
tial savings from the use of less costly FGD systems with 70
percent removal efficiencies.
TSP Control. Strategies for complying with TSP standards
reflect a tightening of standards similar to that observed in
SO2 controls, although the shift from earlier to later compli-
ance strategies is less dramatic. In the mid-1970s, electro-
static precipitators with collection efficiences greater than
98 percent were retrofitted on units and operate in conjunc-
tion with older mechanical collection systems. Units that
have come into service since 1972 generally have been built
with high-efficiency electrostatic precipitators; the most
recent units have electrostatic precipitators or baghouses
with collection efficiencies of 99.6 percent. As a result,
about 96 percent of the capacity that came into service before
1977 now has TSP collection systems with removal efficiencies
greater than 98 percent and about 97 percent of the post-1976
capacity has such systems (see Table IV-12).
Future SO? and TSP Controls on Existing Units. Data in
the Energy Database concerning future compliance actions for
units that currently are in operation indicate that 76 percent
of coal-fired units are in compliance with current SO2 stand-
ards and 87 percent with TSP standards. As shown in Table
IV-13, one-fourth of the units that are not in compliance with
SO2 standards will meet the standards by changing fuels, while
slightly less than one-fourth will retrofit scrubbers. More
than two-thirds of the units that do not comply with TSP
-------
IV-21
Table IV-12
REPORTED COAL UNIT
TSP COMPLIANCE STRATEGIES
Pre-1977 Units Post-1976 Units
TSP Collection
Number
Number
Efficiency (5)
of Units
MW
of Units
MW
>98
797
182,542
59
26,936
95-98
49
3,660
1
650
90-95
42
2,705
0
0
<90
44
2.027
_1
235
T otal-^
932
190,934
61
27,821
175 units with 15,793 Mlrf of capacity did not report TSP
control efficiencies.
5ource: Energy Database.
standards will retrofit more efficient TSP units will be
In addition, as also shown in T,able rv~13' . and a rela-
derated or retired to comply with air reg remedies vari-
tively small number of units will seek legal remed
ances or litigation.
Oil-Fired Unit Strategies
Oil-fired units emit both SO2 and TSP in lesser quanti-
ties than do coal-fired units. Control of SO2 emissions at
oil-fired units is achieved exclusively through the use of
low-sulfur oil while particulate emissions are decreased botn
by burning low-sulfur oil and by installing TSP control
equipment. Although the use of low-sulfur oil also results 1
decreased TSP emissions, it is a much more costly method or
TSP control than installing electrostatic precipitators.
Consequently, oil-fired units burn low-sulfur oil primarily
reduce SO2 emissions and reductions in TSP emissions from o
sulfur oil are incidental to SO2 control.
Nearly 30 percent of oil-fired capacity burns oil that
contains less than 0.3 percent sulfur by weight and over
60 percent of the capacity burns oil with- less than 1.0 per
cent sulfur. Units that burn very low sulfur oil are ^r®"*
quently older units located in heavily industrialized and
populated areas that have not met the National Ambient Air
Quality Standards (Table IV-14).
-------
IV-22
Table IV-13
FUTURE S02 AM) TSP COMPLIANCE STRATEGIES
BY EXISTING COAL UNITS1
so2 »
Strateqles (percent of units)
TSP
(percent of units)
Currently in Compliance 76
87
Will Change Fuel 6
0
Will Retrofit Pollution
Control Equipment 5
9
Derate or Retire 2
2
Legal Remedy 4
1
Not Specified 7
1
^An additional 2 percent of units will use lower sulfur fuels
and install scrubbers; these units are listed as installing
equipment.
Source: Energy Database.
Table IV-14
REPORTED SO? COMPLIANCE
STRATEGIES
OIL UNITS1
Percent Sulfur
in Fuel
Number of Units Capacity (MW)
<0.3
185
30,183
0.3-0.4
146
17,029
0.5-0.9
179
23 , 224
1.0-1.4
135
17,349
1.5-1.9
110
15,550
2.0-2.5
60
6,917
>2.5
B
1.740
Total
823
111,992
^Includes gas/oil units that burn substantial
quantities of oil
Source: Energy Database.
-------
IV-23
Particulate control systems, which are present at all
coal units, exist only on approximately 40 percent of oil-
fired capacity (see Table IV-15). Since uncontrolled TSP
emissions from oil combustion are lower than those for coal
combustion, removal efficiencies for TSP control systems are
generally lower for oil-fired than for coal-fired units. Less
than 10 percent of oil-fired capacity has systems with removal
efficiencies greater than 98 percent and nearly one-half have
efficiencies of less than 90 percent.
Table IV-15
REPORTED TSP COMPLIANCE STRATEGIES
EXISTING OIL UNITS
Tsp Collection
Number
Efficiency (%)
of Units
Caoacitv (MW)
>98
34
9,120
96-98
51
7,886
90-95
77
11,688
<90
96
15,655
Total with TSP control*
274
45,526
Total without TSP control
549
66,466
Total
823
111,992
^-Includes 16 units with 1,169 MW reporting TSP controls
but not reporting control efficiencies.
Source: Energy Database.
-------
IV-24
Water Pollution Control Strategies
The water discharges from electric utilities are regu-
lated by two general categories of environmental regulations—
chemical and thermal. The promulgation in late 1974 of efflu-
ent limitation guidelines required neve and existing units to
control chemical pollution by using best practicable control
technology (BPT). Occasionally since then the Agency has
attempted to revise the 1974 guidelines. However, legal chal-
lenges and reevaluations of regulations by the Agency itself
have precluded all but a few substantive changes in the regu-
lations. In addition, since 1977 the courts have remanded
federal thermal discharge regulations, and consequently, the
implementation of Section 316(a) of the Clean Water Act, which
requires thermal pollution controls, has been up to individual
permit writers applying best engineering judgments on a case-
by-case basis.
More and more electric utilities are using cooling towers
or ponds to control thermal discharges. While less than 30
percent of the steam-electric capacity that has been in ser-
vice since before 1972 has cooling towers or ponds, more than
60 percent of the post-1976 capacity uses these systems
(Table IV-16). This increasing use of thermal control systems
is not solely due to environmental requirements. Recent capa-
city additions have been heavily concentrated in the West
where water-supply constraints frequently require the use of
cooling towers. Siting for units located in the East has also
been determined increasingly by other considerations such as
air quality. Consequently, it has become more difficult to
locate sites that have plentiful cooling water and meet other
siting criteria.
Because the Form 67s offer no data concerning strategies
and costs of compliance with chemical discharge guidelines, it
was not possible to identify unit-level compliance strategies
by using the Energy Database. Instead, for purposes of the
cost analysis TBS assumed that all units meet the 1974 BPT
guidelines which requirfe sedimentation of bottom- and fly-ash
transport water, removal of oil and grease from various low-
volume waste streams at a central treatment facility, and
minimization of cooling-water chlorine discharges through
management practices. This approach somewhat understates
costs because some units have complied with requirements for
recirculation of bottom-ash transport water established in
1975 but rescinded in 1980. The cost analysis is not sensi-
tive to the assumption that all units meet BPT limits because
the cost of these systems on a unit basis is approximately
one-fourth that of a recirculating cooling system and an even
-------
IV-25
Table IV-16
TRENDS
IN COXING TOWER USE
Pre-1972
1972-1976
1977-1979
T echnoloay
Units
CaDacitv(MW)
Units
Caoacity(MW)
Units
Capacity(MW)
Coal-Tired Units
With cooling tower or
pond
201
38,999
82
45,112
55
21,404
Without cooling tower
or pond
660
101,063
21
11,119
12
11,329
Oil-f ired Units
With cooling tower or
pond
14
925.8
17
5,917
13
6,927
Without cooling tower
or pond
298
28,286
31
13,334
9
3,414
Gas-F ired Units
With cooling tower or
pond
213
25,680
22
7,945
9
2,516
Without cooling tower
or pond
117
11,120
12
3,917
3
1,339
Gas/Oil Fired Units
With cooling tower or
pond
107
7,833
8
1,788
4
371
Without cooling tower
or pond
310
37,368
12
5,828
0
0
Nuclear Units
With cooling tower or
pond
4
2,375
15
13,299
6
5,175
Without cooling tower
or pond
14
6,268
25
21,507
6
5,071
Source: Energy Database (coal,
oil, and
gas units) and (SURF (nuclear units).
smaller fraction of the cost of T3P or SO2 control systems.
The cost of recirculation systems for ash transport water, on
the other hand, is substantial and to the extent that utili-
ties have complied with this requirement they have incurred
costs for water pollution control that are higher than those
imposed by current regulations.
Solid-Waste Control Strategies
The electric utility industry is expected to generate
greatly increased volumes of solid wastes over the next decade
for two reasons. First, new coal capacity, which generates
large amounts of solid waste, will displace oil and gas
-------
IV-26
capacity. Second, since air regulations are becoming in-
creasingly stringent, TSP and SO2 removed from stack gases
will ultimately become fly ash and scrubber sludge requiring
disposal. However, to the extent that dry SO2 scrubbing be-
comes a generally accepted technology, smaller quantities of
more easily handled dry residues will^require disposal.
Compliance with solid waste regulations will vary as a
function of natural conditions and local regulations. Cur-
rently, utility solid wastes are regulated by individual state
regulations. In the future utility solid wastes will in all
probability be considered nonhazardous. Federal regulations
governing nonhazardous solid waste disposal establish minimum
criteria for solid waste disposal facilities, but individual
states develop and implement solid waste disposal regulations.
Consequently, regulations in states that have impermeable
soils and do not depend on ground water are not likely to
require major changes from current practices. Conversely,
states with permeable soil, extensive ground water aquifers,
and floodplains may require major changes from current prac-
tices. Such changes could involve clay or synthetic liners
for disposal facilities, diking as protection against flood-
ing, or increased transport distances to environmentally
acceptable disposal sites.
1979 UNIT-LEVEL COSTS
Once the units in the Energy Database were categorized
according to their in-service dates and fuel types, and once
pollution control strategies were analyzed, it was possible to
develop unit-level costs. This section reviews first the
technical and financial assumptions necessary to translate the
costs reported in the Energy Database into annualized costs on
a per-kilowatt-hour basis. Second, it reports the results of
the analysis of costs and cost-effectiveness for units repre-
sented in the Energy Database. Finally, it presents a model-
unit analysis of possible unit-level costs under future envi-
ronmental regulations. This model-unit analysis is based on
engineering cost estimates provided by EPA, rather than on
data from the Energy Database which are based on actually
incurred engineering costs.
Technical and Financial Assumptions
This section discusses the assumptions used in the unit-
level analysis to calculate (1) the costs to the electric
-------
IV-27
utility industry of complying with pollution control regula-
tions and (2) the baseline costs of operating units without
such restrictions.
Pollution Control Assumptions
A number of assumptions were necessary to translate costs
reported in the Form 67s into annualized pollution control
costs per kWh of generations. These assumptions concerned
technical and financial issues such as capital charges for
pollution control equipment, low-sulfur fuel premiums, capa-
city and energy penalties, pollution control costs not report-
ed or reflected in the Form 67s, generation-related costs, and
compliance status.
Capital Charges. Capital charges for pollution control
equipment were annualized to obtain level pretax revenue re-
quirements over an investment life of 20 years. A capital
recovery factor of 19 percent was used, based on an amortiza-
tion of the investment over 20 years at the weighted-average
marginal cost of capital during the 1973-1979 period of
18.32 percent.
Plausible alternative assumptions concerning capital
recovery factors do not change total capital charges by more
than 5 percent (see Table IV-17). In some cases the lifetime
of pollution control equipment exceeds 20 years. Increasing
Table IV-17
SENSITIVITY OF CAPITAL COST AN)
INVESTMENT LIFE ASSUMPTIONS
USED IN THE UNIT-CATEGORY ANALYSIS
Capital
Coat of Investment Recovery
Capital Life Factor
Percent
Cost* Change in
(milla/kWh) Cost per kWh
(years) J21
18.32
18.32
18.32
19.32
19.32
19.32
20
30
45
20
30
45
18.96
18.44
18.33
19.90
19.42
19.33
3.61
3.51
3.49
3.79
3.69
3.68
(2.93)
(3.55)
4.62
2.14
1.87
*Cost of $100 per kilowatt investment at a 60 percent capacity
factor.
Source: TBS calculations
-------
IV-28
the investment lifetime to 30 years results in a 2.9 percent
(0.1 mill) decrease in the pollution control equipment cost
per kWh. Conversely, raising the cost of capital by 1.0
percent to reflect higher interest rates that have existed
since 1979 would increase the cost of capital equipment by 4.6
percent (0.18 mills/kWh).
Low-Sulfur Fuel Premiums. Fuel premiums for low-sulfur
coal and oil were developed using data on costs of fuel deliv-
ered to steam-electric plants compiled by DOE from 1979 Form
423s. It was assumed that the differential between the cost
of coal or oil with less than 3 percent sulfur and that of
coal and oil with more than 3 percent sulfur is a premium
attributable to regulations limiting SO2 emissions (see Figure
IV-4). Potential emissions were also calculated assuming that
oil-fired units would burn 3 percent sulfur oil in the absence
of environmental regulations, that coal-fired units in the
East would use sulfur with 3 percent or more sulfur, and that
units in the West would use 1 percent sulfur coal. The low-
sulfur coal premium was based on a weighted average of the
East North Central, East South Central, and South Atlantic
regions. Western regions were not considered in developing
coal premiums since virtually all coal deliveries in these
regions have low sulfur contents. In the analysis a fuel
premium was not attributed to western units.
The use of the full differential between high- and low-
sulfur coal as the fuel premium probably overstates that pre-
mium because of uncertainty concerning the base cost of coal
in the absence of environmental regulations. The cost of
high-sulfur coal is lower than it would be in the absence of
environmental restrictions, which have diminished demand for
those fuels. Demand for coal from marginal high-sulfur coal
mines has decreased and production of high-sulfur coal has
been concentrated in more efficient mines. Conversely, demand
for coal from marginal and less efficient mines in areas that
produce low-sulfur coal has increased. If the base price of
coal were assumed to be the average price of 2 to 3 percent
sulfur coal reported in the Cost and Quality of Fuels, the
fuel premium for 1 percent sulfur coal would decrease by about
25 percent.
Similarly the price that utilities would pay for oil if
there were no environmental regulations is probably higher
than the price they currently pay for 3 percent sulfur oil. a
relatively small portion of oil consumed by steam-electric
utilities has a sulfur content greater than 3 percent, and it
could be argued that the average cost of 2 to 3 percent sulfur
-------
IV-29
Figure IV—4
LOW-SULFUR FUEL PREMIUMS
1979 DOLLARS
T20
of tlMl
FUEL PREMIUM
CENTS PER
MM BTU
tha
100
ON:
40
1.0
OIL PERCENT SULFUR BY WEIQHT
FUEL PREMIUM
CENTS PER
MM BTU
10 -
3.0
2.0
COAL PERCENT SULFUR BY WEIQHT
1.0
'•Ported in Cot and Quality of Fmti «r» for rangw in sulfur content. Valuta ihowi) in graph ar» for midpoint of ranpc;
tha I in* was fit wing a least-aquaras approach.
Sourea: 1879 Coat and Quality of Fual*.
-------
IV-30
oil reported in the Cost and Quality of Fuels provides a more
realistic base price. Alternatively the cost of desulfuriza-
tion of high-sulfur oil may provide a measure of the magnitude
of the oil premium. In either of tfce above cases, as dis-
cussed below, the magnitude of the low-sulfur oil premium
would decrease by approximately one-third for 1 percent sulfur
oil.
To the extent that environmental regulations will become
more stringent in the future, low-sulfur fuel premiums may
increase at a faster rate than the GNP deflator. Because
marginal low-sulfur coal mines will be increasingly used, the
costs of producing low-sulfur coal will rise. But new units,
unlike existing units, will have the option of locating closer
to sources of low-sulfur coal, thereby, reducing the transpor-
tation cost component of the premium.
Capacity and Energy Penalties. Capacity and energy pen-
alties of 3 percent were attributed to both recirculating
cooling systems and flue gas desulfurijsation systems. As
these penalties are not reported by utilities in the Form €7
submittals, it was necessary to use other sources of informa-
tion in the analysis. The cooling tower capacity penalty
reflects a penalty of 2 percent from increased turbine back
pressure and 1 percent from system operating requirements.9
The capacity penalty for flue gas desulfurization systems is
based on the mean of capacity penalties reported by PEDCo in
its July-September 1980 EPA Utility FGD Survey.10
Capacity losses associated with capacity penalties for
pollution control equipment are generally made up by sizing
new units larger than they would otherwise be. In the cost
analysis it was assumed that this replacement capacity would
^This assumption is based on EPA, The Economic Analysis of
Effluent Guidelines, Steam Electric Powerplants, 1974. As
noted in Chapter II, the thermal portion of these guidelines
was remanded in 1977 and has not been reinstituted. Conse-
quently more recent technical or economic analyses of cool-
ing towers have not been performed for EPA.
IOpedco Environmental, utility FGD Survey, July-September
1980. The standard deviation of the capacity penalties
reported by PEDCo is 1.46 percent. Using a 1976 in-service
date and a 60 percent capacity factor approximately 71 per-
cent of the plants fall within this range and will have a
capacity penalty within 1 mill per kWh of that calculated
using a 3 percent capacity penalty.
-------
IV-31
be of the same fuel type as the unit on which the pollution
control equipment was installed and would have the same in-
service year. Plant construction costs for replacement capa-
city were based on other analyses performed for EPA and are
shown in Table IV-18.
Table IV-18
PLANT
CONSTRUCTION COSTS USED
IN THE
UNIT-CATEGORY ANALYSIS
(current S/kW)
Type of Plant
In-Service . —.—
Year
Coal Oil Gas
1979
413 298 211
1978
389 280 199
1977
368 265 188
1976
341 254 174
1975
316 235 161
1974
270 201 138
1973
223 166 114
1972
210 156 107
Source:
TBS estimates based on
data provided by ICf, Inc.
In addition to this capacity penalty, an energy penalty
reflects fuel and operating expenses to generate power needed
to operate the equipment and to compensate for losses in ef-
ficiency . Fuel expenses were determined by adding a base cost
of high-sulfur fuel and the individual unit's fuel premium.
National average nonfuel operation and maintenance expenses
were computed at 2.57 mills per kWh.
Costs Not Reported or Reflected in the Form 67s. Al-
though the focus of this study is on federal environmental
regulations, the only actual cost data available in the Form
67s reflect total pollution control costs. To the extent,
therefore, that state or local requirements would exist in the
absence of federal regulations or that utilities would under-
take certain expenditures for other reasons, the costs identi-
fied in this analysis are not entirely attributable to federal
regulations. Costs attributed to environmental compliance can
be incurred as a result of federal, state, or local environ-
mental regulations or of measures taken by a utility for eco-
nomic reasons. In some cases, state air, water, and solid
-------
IV-32
waste pollution control requirements exceed the minimum stand-
ards necessary for compliance with federal regulations. In
other cases, pollution control equipment—for example cooling
towers or TSP control systems—may have been installed in the
absence of environmental regulations^.
Only total pollution control costs are identified in the
analysis and no attempt is made to differentiate federal and
state requirements. Data reported in the Form 67s do not
differentiate among costs incurred in complying with federal,
state, and local regulations, nor do they indicate whether
certain expenditures were undertaken for economic rather than
environmental reasons. To attribute costs in this way would
be difficult for individual plants to do, and the unit-level
analysis presented no reasonable principle for doing so.
Costs for meeting chemical effluent limitations guide-
lines are not reported in the Form 67s. Plants coming into
service before 1974 were assumed to retrofit equipment to meet
the chemical guidelines in 1976 at a cost of $2.75 per kW
(1976 dollars). Plants coming into service after 1974 were
assumed to meet the BPT guidelines in their in-service year
without a retrofit premium at an average cost of $2.28. These
costs are based on costs developed for the 1974 effluent
limitations guidelines. Operations and maintenance expendi-
tures for both categories of plants were assumed to be $.97
per kW.11
Finally, the Form 67s do not capture combustion modifica-
tions instituted to meet N0X limitations. Therefore, to
the extent that such modifications have been undertaken, this
analysis understates the costs of environmental regulation.
Generation-Related Costs. It was also assumed in the
unit-level analysis that quantities related to generation—
capacity factors, fuel consumption, and nonfuel operations and
maintenance expenses—were as reported in the Form 67s. Actu-
al 1979 fuel consumption and generation data were used because
these data are consistent with reported pollution control
operations and maintenance expenses. This approach meant,
however, that anomalous influences on generation and fuel
choices in 1979 (for example, weather patterns and oil
shortages) were incorporated into the analysis.
Hepa, The Economic Analysis of Effluent Guidelines, Steam
Electric Powerplants, 1974. The 1973 data used in the 1974
economic analysis were updated to 1979 dollars using the GNP
deflator.
-------
IV-33
The use of actual 1979 data may result in an understate-
ment of generation and fuel consumption by oil-fired units.
Two factors resulted in low oil-fired generation in 1979:
rapidly increasing oil prices and excess coal-fired capacity.
During 1979 the price paid by utilities for oil increased by
75 percent and the quantities of oil consumed decreased by 15
percent.12 That year it was more economical for eastern util-
ities to purchase power from the Midwest than to generate
their own power using high-cost oil. This alternative only
exists for oil-fired units so long as excess coal capacity is
available in the Midwest. Therefore, as growth in demand
diminishes excess coal capacity in the Midwest, oil-fired
generation in the East will increase despite the high cost of
oil.
The analysis also does not capture the effects of envi-
ronmental regulations that are manifested in changes in dis-
patch patterns rather than in increased costs of generating
electricity. Some plants are utilized less intensively be-
cause they are required to burn expensive low-sulfur fuels,
and others are dispatched on an environmental basis. The
decline in the economic value of these plants that results
from pollution controls is attributable to environmental regu-
lations. in the analysis of unit-level compliance costs,
however, a cost for pollution control is only attributed to
plants that burn low-sulfur fuels and not to plants that are
idle because of the high cost of low-sulfur fuel.
Finally, it is difficult to establish an approach that
correctly captures environmentally related costs of fuel
choice decisions in constructing, converting, or reconverting
electric utility generating units. Many studies have adopted
a subjective approach to the attribution of costs that over-
looks the real economic pressures for originally building oil-
fired units, for converting coal units to oil, or for not re-
converting to coal. On the other hand, the EPA approach used
in this study certainly fails to capture all the costs associ-
ated with environmental compliance. Refer to pages IV-43
through VI-50 for a more detailed discussion of the reasons
for fuel choices and the determination of environmental, costs.
Compliance Status. Inherent in the unit-category pollu-
tion control-anaTyiri-is the assumption that existing units
are in compliance with applicable emission standards or are
moving toward compliance using approved strategies and sched-
ules as reported by utilities in their Form 67 submittals. An
l^Cost and Quality of Fuels—1979, p. 14.
-------
IV-34
additional assumption is that state air pollution control
agencies enforce emission standards with equivalent levels of
enforcement activities across states and regions.
Although the second assumption is difficult to test,
compliance status can be examined by comparing a unit's allow-
able emissions with reported or calculated emissions. Based
on data provided by EPA, the ratio of annual calculated emis-
sions to annual allowable emissions was reviewed for all fos-
sil-fuel units that submitted 1979 Form 67s.13 The arithmetic
mean of the ratios (0.82) was interpreted by ICP and EPA to
mean that, on average, units were in compliance with SIP limi-
tations and had allowed a small margin of safety for unpredic-
table variations in fuel quality or in equipment efficiency.
A closer examination, however, reveals significant devia-
tions from the mean. Those units with SO2 ratios less tnan
0.8 generally reported higher actual emissions in their Form
67 submittals than wera calculated by applying the standard
formulas.14 Units with ratios that exceeded 1.0—implying
that they were out of compliance—fit into one of several
possible categories. Many units reported lower annual emis-
sions than were calculated. Other units were moving along
state-approved compliance schedules and had not achieved com-
pliance by the end of the year.
In other cases the 1979 fuel data are not consistent with
emission standards; some units had achieved compliance by
decreasing their fuel's sulfur content by year-end, even
though the average fuel quality reported for the entire year
implied noncompliance. For this reason, the analysis may
understate fuel premiums. Temporary exemptions or litigation
proceedings were a further reason for calculated emissions in
excess of allowable emissions. However, fewer than 4 percent
and 1 percent, respectively, of the units in the Energy Data-
base are not proceeding toward compliance with SO2 and TSP
standards, and these units do not substantially affect the
results of the analysis.
13icf Inc., Survey of Utility Power Plant Emissions and Fuel
Data; and Review of Calculated and Allowable Emissions for
Existing Utility Steam Power Plants, prepared for EPA,
October 1980.
14epa, compilation of Air Pollutant Emission Factors, August
1977.
-------
IV-35
Baseline Assumptions
Pretax revenue requirements in the absence of pollution
controls were developed for each unit category to provide a
basis of comparison for pollution control costs. These costs
were based on average characteristics for units in each cate-
gory developed from the Energy Database (Table IV-19) and on
unit-level capital and operating costs.
Table IV-19
UNIT CHARACTERISTICS USED IN DEVELOPING
BASELINE COSTS OF GENERATING ELECTRICITY
Fuel Type
In-Service —-——— ——
Year
Coal Oil Gas
Gas/Oil
Average In-Service Year
Pre-1972
1961 1962 1963
1963
1972-1976
1973 1974 1974
1974
1977-1979
1978 1970 1977
1977
Average Nameplate Capacity (>*0
Pre-1972
168 92 119
133
1972-1976
498 447 308
326
1977-1979
411 559 290
259
Average Heat Rate (Btu/kWh)
Pre-1972
10,380 10,549 10,739
10,774
1972-1976
10,324 9,771 9,617
10,602
1977-1979
10,856 11,072 10,282
10,524
Average
10,520 10,464 10,213
10,633
Average Capacity Factors (percent)
Pre-1972
56.8 36.9 54.5
49.7
1972-1976
62.9 46.3 61.3
45.7
1977-1979
52.2 33.8 20.2
44.8
Average
57 . 3 39.0 45.3
46.7
Source: Energy Database.
-------
IV-36
Costs considered in developing revenue requirements in-
cluded:
• Capital-related charges on the unit5' undepre-
ciated value. These were annualized on a pre-
tax basis using the capital recovery method.
This calculation assumed a total plant life of
30 years, an embedded cost of capital of 18.32
percent, and the same unit in-service dates
shown in Table IV-19. These charges were then
added to annual fuel, operations and mainte-
nance, and indirect expenses, along with state
and local taxes.
• Fuel expenses. Annual fuel expenses were based
on heat rates reported in the Energy Database
and average 1979 fuel costs. Heat rates used
in developing baseline costs are the average
heat rates for each unit-category shown in
Table IV-19. Fuel costs are the 1979 averages
reported by DOE in the Cost and Quality of
Fuels. Because a pollution control premium was
attributed to the use of low-sulfur fuels, the
fuel cost used in developing baseline costs was
that for high-sulfur fuel.
• Nonfuel direct operations and maintenance ex-
penses; indirect expenses (transmission, dis-
tribution, and administration expenses); and
taxes other than income tax. These remaining
annual expenses were based on industry averages
reported by DOE in the 1979 Statistics of Pri-
vately Owned Utilities. In 1979, the average
nonfuel operating expenses for the industry
were 2.57 mills per kWh, average indirect ex-
penses were 5 mills per kWh, and average taxes
other than income taxes amounted to 2.9 percent
of undepreciated plant value.
The resulting baseline costs of generating electricity as
shown in Table IV-20 provide a reference point for pollution
control costs that will be described in the next section of
this chapter.
-------
IV-37
Table IV-20
BASELINE COSTS or GENERATING ELECTRICITY
AT MODEL UNITS SELECTED TOR ANALYSIS
(1979 mills/kWh)
Fuel Type
Average
All
Fuels*
In-Service Year
Coal
Oil Gas
Gas/Oil
Pre-1972
1972-1976
1977-1984
22.4
24.9
34.9
32.9 28.1
37.3 29.2
50.2 38.0
30.1
32.6
43.1
25.4
27.9
38.1
Average all years*
24.2
37.4 28.5
31.3
27.2
Note: 5ee Table VI-17 and Figure VI-6 for escalation rates
for various components of costs. An approximation
to 1982 dollars can be made using the GNP escalation
factor of 1.286.
^Averages are across fuel types or in-service years
weighted by generation.
Source: Energy Database snd TBS calculations.
Results of the Unit-Level Analysis
This section discusses the results of the analysis of
pollution control costs at the unit level. It begins with a
discussion of the distribution of compliance costs among coal,
oil, gas, and gas/oil units. Then it examines the components
of pollution control costs by types of costs (capital, opera-
tions, and maintenance) and by pollutants controlled. The
discussion finally turns to an analysis of the costs incurred
by individual unit categories and to an examination of the
reasons for variations in costs within unit categories.
Distribution of Compliance Costs
As shown in Figure IV-5, pollution control costs incurred
by individual generating units range from less than 1 mill per
kWh to more than 12 mills per kWh. Most of the total genera-
tion—approximately 85 percent—incurs a cost of less than
6 mills per kWh while only 18 percent pays less than 1 mill
per kWh. While gas-fired units generally spend less than 1
mill per kWh for pollution control, 60 percent of oil-fired
generation bears a cost of between 3 and 7 mills per kWh and
-------
Figure IV—5
DISTRIBUTION OF FOSSIL-FIRED STEAM ELECTRIC GENERATION
AS A FUNCTION OF POLLUTION CONTROL COSTS AND FUEL TYPE
1979 DOLLARS
200,000
kWh x 106
150,000
100,000
50,000 \-
4.0- 5.0- 6.0- 7.0- 8.0- 9.0- 10.0- 11.0- 12.0
» 4.9 5.9 6.9 7.9 8.9 9.9 10.9 11.9 12.S
TOTAL POLLUTION CONTROL COSTS IN MILLS/kWh
Source: Energy Database.
Ga«/Oit
mm
iWM:;:
-------
IV-3 9
only 12 percent spends less than 3 mills per kWh. Gas/oil
units have similar characteristics to gas or oil units, de-
pending on which fuel they consume preponderantly.
Coal-fired units account for the preponderant share of
total generation and also display the greatest spread in pol-
lution control costs. Seventy-five percent of coal generation
incurs pollution control costs of less than 5 mills per kWh.
The remaining coal generation is spread among units that spend
up to 13 mills per kWh for pollution control. As will be
discussed below, the reasons for the spread in coal-fired unit
pollution control costs concern differences in pollution con-
trol standards and compliance strategies as well as dif-
ferences in the availability of low-sulfur coal.
Components of Compliance Costs
Control of SO2 is the dominant contributor to average
national pollution control costs (Table IV-21). Out of a
national average cost of pollution control for all fossil-fuel
types and age categories of 3.88 mills per kWh, SC>2 control
accounts for 2.72 mills per kWh or 70 percent of the total.
The remaining 30 percent is distributed relatively evenly
among controls for TSP and water pollution with solid waste
disposal included in SO2 and TSP control.
SO2 control costs consist primarily of a premium paid by
coal- and oil-fired units for low-sulfur fuels. Less than
one-tenth of the national cost of SO2 control as of 1979 was
attributable to the use of scrubbers. Although scrubbers are
costly on a unit basis, they are less prevalent than other
pollution control systems. For this reason, they contribute
only 6 percent to the average cost of pollution control, as
compared, for example, to 11 percent for TSP control. As will
be noted in subsequent chapters, however, the contribution of
scrubbers to national costs will increase substantially in the
future.
All units incur some costs to meet water pollution chem-
ical guidelines and about 20 percent of the capacity incurs
costs for control of thermal discharges. Thermal pollution
control costs are attributed only to units that have installed
cooling towers or ponds since 1972 because earlier units would
not have installed thermal discharge controls in response to
environmental regulations. The cost of meeting chemical
guidelines is approximately 0.44 mills per kWh and does not
vary significantly among unit categories. Although this cost
is slightly lower than the cost of meeting chemical guidelines
-------
IV-40
Table
IV-21
AVERAGE
ANNUALIZED COSTS
OF COMPLIANCE BY POLLUTANT
(1979 raillsAWh)
SO2 Control
Fuel Type and
TSP
In-Service Year
FGD1
Fuel
Control^
Thermal
Chemical
Total
Coal
Pre-19 72
0.16
1.96
0.75
0.05
0.51
3.42
1972-1976
0.3ft
1.53
0.40
0.86
0.35
3.47
Post-1976
1.92
1.71
0.76
1.02
0.42
5.81
Average Coal
0.38
1.82
0.67
0.34
0.46
3.67
Oil
Pre-1972
0
7.IB
0.10
<0.01
0.64
7.93
1972-1976
0
6.20
0.18
0.29
0.44
7.17
Post-1976
0
8.03
0.09
1.45
0.45
10.03
Average Oil
0
6.86
0.14
0.37
0.53
7.89
Gas
Pre-1972
0
0.07
<0.01
0.05
0.28
0.40
1972-1976
0
O.U
<0.01
0.49
•0.24
0.85
Post-19762
0
0.0ft
0.69
1.66
0.47
2.86
Average Gaa
0
0.08
<0.01
0.19
0.27
0.55
Gas/Oil
Pre-1972
0
4.47
<0.01
0.03
0.43
4.94
1972-1976
0
2.27
0
0.57
0.33
3.17
Post-1976
0
1.93
0
1.67
0.32
3.8ft
Average Gas/Oil
0
4.19
0
0.10
0.42
ft.72
National Average
0.2ft
2.48
0.43
0.30
0.44
3.88
Note: See Table
VI-17 and Figure
VI-6 for
escalation
rates for
various
components
of costs
. An approximation to 1982
dollars can be
made using the GNP escalation factor or 1.286.
^Includes solid waste disposal.
^Costs for post-1976 gas units are distorted by a very
limited
nunber
of observations.
Source: Energy Database and TBS calculations.
on an average basis, it is significantly higher on a unit
basis for those units that are required to install cooling
towers or ponds.
The premium paid by utilities for low-sulfur fuels is the
largest component of compliance costs (Table IV-22). This
premium accounts for 64 percent of pollution control costs and
-------
IV-41
Table
IV-22
AVERAGE ANNUALIZED COSTS OF COMPLIANCE BY COST
OWONENT— TOTAL AIR,
WATER, ANO
SOLID
WASTE
(1979 mills/kWh)
Total as
Percent
Increase
Fuel Type and
Capital
Energy
Fuel
Over
In-Service Year
Cost
O&M
Penalty
Bremium
Total
Baseline^
Coal
Pre-1972
0.76
0.69
0.02
1.96
3.42
15
1972-1976
0.97
0.51
0.46
1.56
3.47
14
Post-1976
2.81
0.71
0.57
1.72
5.81
17
Average Coal
1.02
0.64
0.18
1.82
3.67
15
Oil
Pre-1972
0.27
0.48
0
7.18
7.93
24
1972-1976
0.44
0.33
0.20
6.20
7.17
19
Post-1976
0.99
0.30
0.71
8.03
10.03
21
Average Oil
0.45
0.39
0.19
6.86
7.89
21
Gas
Pre-1972
0.05
0.26
0.02
0.07
0.40
2
1972-1976
0.14
0.22
0.38
0.11
0.85
3
Post-19761
2.12
0.35
0.36
0.04
2.86
8
Average Gas
0.10
0.25
0.12
0.08
0.55
2
Gas/O il
Pre-1972
Q.1Q
0.36
<0.01
4.47
4.94
16
1972-1976
0.42
0.27
0.21
2.27
3.17
10
Post-1976
0.80
0.37
0.76
1.92
3.84
9
Average Gas/Oil
0.14
0.35
0.03
4.19
4.72
15
National Average
0.72
0; 53
0.15
2.48
3.88
14
Note: See Table VI-
17 and Figure VI-6 for escalation
rates for
various
cooiponents of costs.
An approximation to 1982
dollars can be made
using the GNP
escalation factor of 1.286
•
^Costs for post-1976
gas units are distorted by
a very
limited
number
of observations.
^Baseline costs are
shown in
Table IV-21.
Source: Energy Database and
TBS calculations.
-------
IV-42
it is more than three times as large as capital costs (19 per-
cent) associated with pollution control equipment.
Capital costs are incurred primarily by coal-fired plants
that have TSP control systems and in some cases scrubbers as
well. Chemical and thermal pollution controls present at all
types of steam units also have capital cost components. Capi-
tal costs for chemical controls are lower on a unit basis than
for TSP and SO2 control but are distributed over a greater
number of systems.
Energy penalties of 3 percent of total generation are
associated with the use of both scrubbers and cooling towers.
These penalties contribute approximately 4 percent to pollu-
tion control costs.
Variations in Compliance Costs
Among Unit Categories
Pollution control costs vary as a function of both unit
age and fuel type. The national cost of pollution control
described above is a weighted"average of costs for coal, oil,
gas, and gas/oil units in three separate age categories. The
distribution of these costs by fuel type and unit age will be
discussed below.
Distribution of Costs by Fuel Type. The average cost of
pollution control for oil-fired units is two times as high as
for coal-fired units and more than ten times as high as it is
for gas-fired units. This is because a premium for low-sulfur
oil accounts for 6.86 mills per kWh or 87 percent of total
pollution control expenditures by oil-fired units as shown in
Table IV-22. Similarly, gas/oil units incur a premium to the
extent that they consume low-sulfur oil. This premium ac-
counts for nearly 90 percent of pollution control expenditures
by gas/oil units and results in high pollution-control costs
for units. Particulate, thermal, and chemical control costs
for oil and gas/oil units are generally lower than those for
coal-fired units, but these costs are dwarfed by the low-
sulfur oil premium.
As noted above, the assumptions used in developing the
low-sulfur oil premium may overstate it. To determine the
sensitivity of the results of the analysis, two alternative
assumptions were tested: (1) using the cost of 2.5 rather
than 3 percent sulfur oil as the base cost that utilities
would pay for oil in the absence of environmental regulations
and (2) basing the oil premium on the cost of desulfurization
of high-sulfur oil. For units burning 1 percent sulfur oil,
-------
IV-43
the low-sulfur oil premium would be 33 percent lower in the
first case and in the second it would be 11 to 36
lower depending on the cost of desulfurization and t
content of the oil. Although these differences are
tial, they do not alter the basic conclusions of thl? J
that the low-sulfur oil premium paid by oil-fired units
inates all other environmental expenditures and that oil •=
spend more than other categories of units for pollution con~
trol. For the 60 percent of oil-fired capacity that burns oil
with less than 1 percent sulfur, moreover, the percent ae
crease in the fuel premium would be lower than that no e
Control of SO2 also accounts for the dominant share
(60 percent) of the cost of pollution control for coal units.
Eighty-three percent of the cost of SO2 control among coal
units is a premium paid by utilities for low-sulfur coal. As
in the case of low-sulfur oil this premium could be overstated
because of the assumption that the price eastern utilities
would pay for coal in the absence of environmental regulations
is the price of coal with more than 3 percent sulfur. If the
base price of coal were increased, instead, to the average
price of 2.5 percent sulfur coal, the premium paid by eastern
utilities would be approximately 37 percent lower. The aver-
age fuel premium incurred by coal-fired units nationally would
be approximately 26 percent lower. Again, this result would
not alter the basic conclusion that the low-sulfur coal pre-
mium dominates other pollution expenditures for coal-fired
units.
Only coal and oil-fired units spend appreciable amounts
for TSP control. Because all coal units have TSP control
systems, coal units as a whole spend nearly two times as much
on TSP control systems as they do on scrubbers (although for
individual plants that have scrubbers the cost for scrubbers
is much higher than that of TSP controls). Oil-fired units
spend one-fifth as much as do coal-fired units for TSP control
per kWh of generation. This expenditure by oil units amounts
to 2 percent of their total pollution control expenditures.
TSP control for gas and gas/oil units amounts to less than
0.01 mills per kWh.
It should be noted that the use of low-sulfur oil also re-
sults in a reduction in TSP loadings. Since a plant would
not ordinarily incur a low-sulfur oil premium solely for TSP
control, however, the full cost of burning low-sulfur oil
has been attributed to SO2 control. Among gas and gas/oil
units the cost of TSP control is insignificant.
-------
IV-44
Total costs for controlling water pollution are evenly
distributed among fuel types. In the case of gas units, how-
ever, water pollution accounts for nearly 85 percent of total
pollution control costs because overall costs for these units
are lower. Chemical control costs are the same for coal and
oil plants and only slightly lower for gas plants. Thermal
costs remain relatively constant across fuel types because
they depend more on a plant's location near a source of plen-
tiful cooling water rather than on its fuel type.
Although total pollution control expenditures for coal-
fired units are less than one-half those for oil-fired units,
their capital costs associated with pollution control equip-
ment are two and one-quarter times as great as they are for
oil units and ten times as great as they are for gas units.
Coal units incur capital costs primarily from using TSP con-
trol devices and SO2 scrubbers. Since very few oil and gas
plants have extensive TSP control systems and none has
scrubbers, capital costs for oil and gas units are signifi-
cantly lower. The remaining capital costs for thermal and
chemical control are approximately equal for coal and oil
plants and only slightly lower for gas-fired plants.
The use of TSP control systems and scrubbers at coal
plants also results in higher operation and maintenance ex-
penses and energy penalties. Particulate control systems and
scrubbers have operational expenses associated with ash and
sludge disposal as well as system operation and maintenance
expenses. In addition, wet scrubbers incur an energy penalty
of approximately 3 percent of total unit generation. Oil and
gas units, by contrast, incur only the operation and mainte-
nance expenses associated with the use of thermal and chemical
pollution control devices.
Distribution of Costs by Unit Age. Legislation governing
air, water, and solid waste pollution was passed in the early
and mid-1970s. Thus, plants that came into service before
1972 incur capital expenditures attributable to the Clean Air,
Clean Water, and Resource Conservation and Recovery Acts only
to the extent that they have retrofitted pollution control
equipment. Units that have come into service since the mid-
1970s have been subjected to the more extensive new source
requirements of the Clean Air and Clean Water Acts.
Expenditures by older units for pollution control can in
some cases be disproportionately high. One reason for higher
costs incurred by older units is that these tend to be located
in more heavily industrialized and populated areas where rela-
tively stringent pollution control measures have frequently
-------
IV-45
been required to attain compliance with the national ambient
air quality standards. In meeting these standards units have
had to retrofit pollution control equipment at a cost that can
be significantly higher than that of installing equipment in a
new plant, or they have had to burn cleaner fuels to compen-
sate for their location in heavily populated areas. Some
older oil and gas/oil units that are used only occasionally
also have high heat rates, and incur a higher fuel premium
because they consume more fuel per kilowatt-hour of genera-
tion .
Oil-fired units that have come into service after 1976
have the highest pollution control costs of any category of
units. As a rule, these units are subject to the NSPS for air
promulgated in 1972 but applying to plants commencing con-
struction after August 1971. To meet the 0.8 pound per mil-
lion Btu, these units burn very low-sulfur oil.
The major age-related variations in pollution control
costs occur among coal-fired units. These variations result
from changes in environmental standards and pollution control
strategies as well as from differences i-n equipment costs.
Pollution control costs for coal-fired units are about the
same for pre-1972 and 1972-1976 units but increase by 67 per-
cent for units coming into service after 19 76. This increase
is attributable to an increase of 1.76 mills per kWh for SO2
control due primarily to scrubber systems (1.58 mills per kWh)
but also to increasing use of lower sulfur fuels. Plants
coming into service after 1977, it should be noted, are gener-
ally subject to the 1972 NSPS air emission limit of 1.2 pounds
of SO2 per million Btu.
Capital costs for pollution control triple for post-1976
coal units as compared to earLier units. Both the increasing
use and cost of scrubbers affect this increase in capital
costs for coal-fired plants. The use of scrubbers, for exam-
ple, has become more prevalent on newer units, increasing from
only 4 percent of the pre-1977 capacity to 36 percent of the
post-1976 capacity.
Despite the virtual absence of cooling towers and the
limited use of scrubbers on pre-1972 coal units, the contribu-
tion of capital costs to total pollution control costs is
relatively large for pre-1972 units, as compared to 1972-1976
units. This difference reflects retrofit premiums incurred
for TSP, S02< and chemical pollution controls required by
regulations under the Clean Air and Clean Water Acts.
-------
IV-46
Variations in Compliance Costs
Within Unit Categories
The main reason costs vary within an individual unit
category is SO2 control. Costs for thermal and chemical con-
trols are approximately the same tot high- and low-cost units
in the same categories. Particulate control costs are higher
for high-cost coal units, but contribute less to total costs
than do SO2 control costs for these units.
The fuel premium for oil-fired units exhibits much the
same variation as do total pollution control costs, indicating
that the variation in costs within oil-unit categories can be
attributed to SO2 control. Two factors affect S02 control
costs within oil-fired unit categories—the sulfur content of
the oil burned and the plant's heat rate. Generally, the
fuel/sulfur content dominates S02 control costs. For example,
units with less than 1.5 percent sulfur fuel have fuel pre-
miums of less than 5 mills per kWh and units with less than
1 percent sulfur oil have fuel premiums greater than 7 mills
per kWh. Some anomalies in this pattern arise in the case of
older, low-capacity factor, high heat-rate units that consume
more fuel per kWh of electricity generated. For example, the
54 oil-fired units that incur a fuel premium of more than
12 mills per kWh operate at an average capacity factor of
14 percent. Of these 54 units, 45 came into s-ervice prior to
1950.
Control costs for SO2 also account for the major vari-
ations within categories of coal units. Among units in ser-
vice before 1972, the highest costs are incurred by units with
S02 scrubbers. Thirteen of the 16 pre-1972 units with costs
higher than 10 mills per kWh have FGD systems. These units
also have fuel premiums and TSP control costs that are two
times as high as the average for pre-1972 coal units. In
contrast, pre-1972 units with slightly lower costs of 7 to
10 mills per kWh have fuel premiums and TSP control expenses
equivalent to those for higher-cost units, but only one of
these units has a scrubber.
Among 1972-1976 and post-1976 units, there is a greater
intermixing of control strategies than among pre-1972 units.
Scrubbers account for 62 percent of the total cost of pollu-
tion control for 1972-1976 coal units with pollution control
costs greater than 7 mills per kWh, while for 1972-1976 coal
units as a whole, scrubbers account for only 33 percent of
pollution control costs. These higher cost units, however,
incur a lower fuel premium than the category average, indicat-
ing the use of scrubbers rather than low-sulfur coal to meet
SO2 standards. High-cost units that have come into service
-------
IV-47
since 1976 have scrubber costs that are twice the category
average and fuel premiums that are 30 percent higher. This
indicates that both low-sulfur fuels and scrubbers are used to
comply with SO2 limits. Costs for controlling TSP among these
units are also 68 percent higher than the category average.
Low-cost units also exhibit distinct characteristics.
Eighteen percent of pre-1972 coal units burn high-sulfur coal
and do not have scrubbers. These units incur dramatically
lower pollution control costs than do units that either burn
low-sulfur coal or have scrubbers. Low-cost units that have
come into service after 1972, by contrast, tend to be located
in the western states and have readily available supplies of
low-sulfur coal.
FUTURE UNIT-LEVEL COMPLIANCE
STRATEGIES AND COSTS
The results of the unit-level analysis thus far reflect
costs incurred by units under regulations in effect in 1979.
Future plants and plants being reconverted from oil to coal
will incur certain additional expenditures resulting from more
stringent regulations that will affect units coming- into serv-
ice after 1980. In this section these costs, which form the
basis for the national-level analysis presented in Chapter VI,
will be examined at the individual unit level.
Compliance Strategies
; 0c!n!J! into service after 1980 will be built mostly
,that meet the national ambient air guality stand-
ards and will meet BACT standards. Definitions of BACT,
however, will vary as a function of unit-specific factors.
Regulations applying to PSD areas specify that BACT will not
5!LieTS* lnge?« than aPPlicable NSPS requirements--usually
NSPS I for pre-1985 units and NSPS II for most post-1984
units. Beyond NSPS requirements, some units, generally those
sited in the vicinity of Class I PSD areas or areas where
available increments are nearly exhausted, may be required to
install BACT pollution control technologies that exceed NSPS I
requirements.
Compliance strategies by future units will vary depending
on whether a unit is meeting BACT incorporating NSPS I, NSPS
II, or more stringent requirements. Since highly efficient
TSP control systems are increasingly being used, major differ-
ences will concern S02 control strategies.
-------
IV-48
Information concerning future units compiled in the Ener-
gy Database indicates that 48 percent of units coming into
service in the 1980—1984 period will meet NSPS II standards.
Among these units, those locating in the Ea3t will tend to
install high-efficiency scrubbers arjd those locating in the
West will burn low-sulfur fuels with lower efficiency scrub-
bers. Ninety percent of the NSPS II capacity coming into
service in the East between 1980 and 1984 will burn high-sul-
fur coal. This capacity will meet a standard of 1.2 pounds of
S02 per million Btu by installing high-efficiency scrubbers
with 90 percent or greater removal efficiencies. Only 10 per-
cent of the eastern capacity will meet a standard of 0.6 pound
of SO2 per million Btu by burning lower sulfur coal and in-
stalling less efficient scrubbers. Eighty percent of capacity
locating in the West, by contrast, will burn low-sulfur coal
and meet the 0.6 pound standard by installing scrubbers with
70-80 percent removal efficiencies. The remaining 20 percent
of western capacity is located in areas where BACT standards
exceed the minimum requirements of NSPS II. These units will
burn low-sulfur coal and install scrubbers whose removal
efficiencies are 90 percent or greater.
Compliance Costs
Costs of compliance with alternative regulatory scenarios
shown in Table IV-23 are significantly different for units
burning eastern and western coals. These costs are primarily
based on engineering estimates provided by EPA and not on
costs listed in the Energy Database. Western units are as-
sumed not to require scrubbing to meet NSPS I standards, al-
though in practice BACT standards applying to western units
have in some cases required scrubbers. Eastern units burning
low-sulfur coals also do not require scrubbers; however, these
units incur a fuel premium of 4 mills per kWh for 0.8 percent
sulfur coal (1.2 pounds per million Btu). Eastern units burn-
ing high-sulfur coal are assumed to meet NSPS I standards by
burning coal containing 2.4 percent sulfur and installing wet
scrubbers with 70 percent removal efficiencies. Both western
and eastern low-sulfur coal units comply with NSPS II limits
by installing scrubbers with 70 percent removal efficiencies—
wet scrubbers in the case of eastern units and dry scrubbers
in the case of western units. Eastern high-sulfur coal units
comply with NSPS II by installing wet scrubbers with 90 per-
cent removal efficiencies. Finally, it is assumed that both
western and eastern low sulfur coal units will install wet
scrubbers with 90 percent removal efficiencies to meet more
stringent BACT standards that may apply on a case-by-case
basis.
-------
IV-49
Table
IV-23
FUTURE COSTS OF OWLIANCE WITH
ALTERNATIVE
REGULATIONS FOR A
500-MW COAL PLANT
(1979 dollar*)
Mora
Strlngant
Standard*
NSPS I
NSPS II
BACT
Si
Meatern Coal
F® Capital (»/kW)
-
69.01
95.60
Kaate Olapoeal Capital (J/MO
-
3.67
20.00
Oparatlon and
Maintenance (allla/kWi)1
-
1.24
1.47
Energy Penalty (percent)''
-
1.43
3.43
Capacity Pwtalty (percent)1
-
0.J9
1.53
Eaatam Coal2
Fffi Capital (SAW)
0/0.01
69.01/104.7
104.7
Naete Olapoeal Capital (S/kW)
0/3.47
3.67/46.00
46.00
Operation and
Maintenance (allla/kKh)1
0/1.2A
1.24/1.71
1.71
Energy Penalty (percent)
0/1.43
1.43/3.57
3.57
Capacity Panalty (percent)1
0/0.39
0.59/2.21
2.21
Fuel Prealua (aiUa/kKh)1
4/0
4/0
2.3#
TSP
Meatarn Coal
Capital (SAW)
36.34
56.34
61.03
Operation and
Halntananoe (ailla/ktfli)
0.54
0.56
0.2S
Energy Panalty (percent)
0.95
0.95
0.21
Capacity Panalty (percent)
0.95
0.95
0.21
Eaatam Coal2
Capital (S/kM)
35.36
X.34/35.36
35.36
Operation and Halntananoe
0.16
0.56/0.16
0.16
Energy Panalty (percent)
0.21
0.95/0.21
0.21
Capacity Penalty (percent)
0.21
0.95/0.21
0.21
Theraal Standard*
Capital
11.20
11.20
11.20
Operation end Malntanence
(¦Ula/ktth)
0.23
0.23
0.23
Energy Penalty (percent)
0.65
0.65
0.65
C«>*city Panelty (percent)
1.65
1.65
1.65
Chemical Standard
Capital
6.16
6.16
6.16
Operation and Maintenance
0.07
0.07
0.07
Energy and Capacity Panalty
0.0
0.0
0.0
Notei Energy penalty la enpraaaed a* percent or generation;
capacity penelty la expreaaad aa pai
¦cant of capi
eity.
See Tabla VI-17 and Flguri
VI-6 for
aacalation rata*
for varioua components of coat*. An approxiaation
to 1982 dollara can be aede uelng the OKP aacalation
factor of 1.286.
^Includee eolid mate diapoaal coeta for 01M and capacity and
energy penaltlee.
Koeta pre*anted ae loe-aulfur coal/hl0»-«ilfur coal.
Thia
walyaia aaauaaa that 10 percent of aaatacn capacity u
•aa dry
ecrubbing of loa-aulfur coal.
Source1 EPA (NSPS II engineering eoet eatl
aataa)i Energy Date-
baa* (Theraal Standards
¦nd NSPS I
FGD coate);
and EEI
(Cheaieal Standarda).
-------
IV-50
Costs for meeting TSP, chemical, and thermal standards do
not vary across regulatory scenarios. In all cases western
units are assumed by EPA to install baghouses for TSP control;
eastern units install high-efficiency electrostatic precipita-
tors. Costs of meeting chemical standards are those required
to meet 1974 BPT regulations that ar'fe currently in effect for
the industry.16 In the analysis of unit costs, all units are
assumed to install cooling towers for thermal discharge con-
trol, although thermal controls may not be required in all
cases.
Particulate and SO2 standards add 3.6 to 14.6 mills per
kWh to pollution control costs under alternative regulatory
scenarios. As shown in Table IV-24 compliance with NSPS I
limits is approximately 1.0 mills per kWh less costly for low-
sulfur coal eastern units than it is for high-sulfur coal
units. Although in specific instances advantageous coal pur-
chasing arrangements may make scrubbers more attractive, this
result is generally consistent with the results of both the
case study portion of this report and with the analysis of
compliance strategies based on the Energy Database presented
earlier in this chapter. Utilities contacted in the case
studies indicated that where possible they prefer a low-sulfur
strategy on the basis of costs. The analysis of costs com-
piled in the database indicated that eastern low-sulfur coal
units subject to NSPS I have costs that are 3 to 4 mills per
kWh lower than do high-sulfur coal units that are required to
install scrubbers to meet NSPS I. A full discussion of issues
relevant to future coal prices and quality appears in Appen-
dix D.
Given current scrubber technologies, costs of compliance
with NSPS II limits will be somewhat lower for eastern high-
sulfur coal units than for eastern low-sulfur coal units. The
difference in cost between wet scrubbers with 90 percent and
70 percent removal efficiencies fails to compensate for the
higher fuel premium incurred by low-sulfur coal units. The
comparative advantage of a high-sulfur coal 90 percent removal
strategy is reflected in the fact that 90 percent of 1980-1984
eastern units that meet NSPS II listed in the Energy Database
will select this strategy. Successful introduction of a less
costly dry scrubbing technology capable of 70 percent removal
l^The Agency is currently reconsidering chemical NSPS guide-
lines; however, considerable uncertainty concerning these
guidelines continues.
-------
IV-51
Table IV-24
TOTAL UNIT-LEVEL COSTS PER KWH
UNDER ALTERNATIVE FUTURE REGULATIONS
(1979 mills per kWh)
NSPS I
Baseline
Air
Only (1985)
NSPS I (1985)
NSPS
II (1990)
BACT
(1990)
Coal TvDe 1985 1990
Total
Percent of
Baseline
Percent of
Total Baseline
Total
Percent of
Baseline
Total
Percent of
Baseline
Eastern Low-
Sulfur 61.6 60.9
6.2
10
7.6 12
13.4
22
14.6
24
Eastern High-
Sulfur 61.6 60.9
6.9
11
tO
CD
12.3
20
N/A
N/A
Western Low-
Sulfur 57.5 56.3
3.6
6
5.3 9
9.4
17
11.5
20
Note: See Table VI-17 and Figure VI-6 for escalation rates for various components of costs
approximation to 1982 dollars can be made using the GNP escalation factor of 1.286.
An
N/A = Not applicable.
Source: EPA; TBS calculations.
efficiencies on eastern low-sulfur coal could, however, shift
the comparative advantage to low-sulfur coal.*'
For the purpose of this analysis, EPA projected that
western units will meet NSPS II limits by burning low-sulfur
coal and installing dry scrubbers with 70 percent removal
efficiencies. Two factors contribute to the low cost incurred
by western units: the ready availability of low-sulfur coal
and the applicability of dry scrubbing technologies to western
coal.
Costs under more stringent BACT standards involve 90
percent wet scrubbing on low—sulfur coal for both western and
eastern units. These standards are not expected to be gen-
erally applicable, but for affected units more stringent BACT
17The base pollution control scenario in the national analysis
incorporates the assumption that the use of dry scrubbing
technologies in the East will not become widespread in the
near term.
-------
IV-5 2
standards would raise pollution control costs by 11.5 to
14.6 mills per kWh or more than 20 percent of baseline costs.
Information compiled in the Energy Database concerning 1980-
1984 units that meet or exceed NSPS II standards indicates
that none of these units located in the East will meet BACT
standards that are more stringent than NSPS II, but that
20 percent of these units locating in the West will meet BACT
limits that are more stringent than NSPS II.
COST-EFFECTIVENESS ANALYSIS
TBS also calculated quantities of S02 and TSP removed and
the cost-effectiveness of removals for units in the Energy
Database and for future units. The figures given in this
section concerning quantities of pollutants removed and the
costs of removing those pollutants give a rough approximation
of the cost-effectiveness of pollution control costs. They do
not address the more complex issue of benefits associated with
these costs. An analysis of the latter issue would require an
examination of where emissions take place and what populations
are affected. It may be, for example, that the higher costs
of pollution control at oil units are justified given the
location of these units in urban areas. The analysis does
indicate that with a shift from oil to coal units, the cost-
effectiveness of environmental regulations will increase
dramatically, particularly for TSP control, it does not
indicate whether environmental quality will benefit or deteri-
orate as a result of this shift.
Existing Units
Uncontrolled unit-level emissions of both SO? and TSP
were calculated assuming that no pollution contro? equipment
existed and that coal units in the East would burn 3 pefclnt
sulfur coal and all oil units would burn 3 percent sulfur on
in the absence of environmental regulations? To detemine
quantities of pollutants removed, calculated unit-lev™ Mis-
sions based on actual sulfur and ash contents and pSllutiSi
Snir^is!?r?ntc^cpuirtio^r:fsrrsti^!
odologies developed by EPA.^8 based on meth-
ISu.S. EPA, Compilation of Air Pollutant Emission Factors,
AP-42 Part A, Third Edition, August 1977.
-------
IV-53
Both fuel and equipment pollution control strategies were
evaluated on the basis of the cost of removing one ton of
pollutant. Most coal units burn coal exclusively or only a
very small proportion of oil. Consequently, for coal units,
fuel-related SO2 removals generally consist of emission reduc-
tions obtained by burning coal with less than 3 percent sul-
fur. Since SO2 emissions are also reduced by using scrubbers,
the cost-effectiveness of using scrubbers was also calculated.
Particulate removal at coal units was attributed entirely to
equipment on the assumption the ash content of coal for reduc-
ing TSP emissions is not a determining factor in coal pur-
chases. Since all coal units have highly efficient TSP con-
trol systems, incremental removals from burning lower-ash-
content coal are insufficient to affect coal purchases.
Although oil units burn low-sulfur oil primarily to re-
duce SO2 emissions, this also decreases TSP emissions. Conse-
quently, for oil and gas/oil units, reductions in TSP emis-
sions were calculated as a function of both the sulfur content
of the fuel and the efficiency of TSP collection devices.
Since oil and oil/gas units do not have scrubbers, reductions
in SO2 emissions at these units depend solely on the fuel
sulfur content.
Quantities of Pollutants Removed
Nationally, as shown in Table IV-25, in 1979 steam-
electric pollution controls reduced SO2 emissions by 12 mil-
lion tons and TSP emissions by 45 million tons. These reduc-
tions in emissions represented approximately 42 percent of
potential SO2 emissions and 98 percent of potential TSP emis-
sions.-^ Coal-fired units accounted for 85 percent of poten-
tial SO2 emissions but for only 75 percent of the reductions
in SO2 emissions. Coal units also accounted for more than
99 percent of potential emissions and reductions in emissions
of TSP. Oil and gas/oil units reduced SO2 emissions by
70 percent to 3.2 million tons from total potential emissions
of 4.6 million tons for both categories of units.
should be noted that to the extent that utilities would
install TSP control systems to protect plant equipment even
in the absence of environmental regulations, the full extent
of reductions in TSP emissions should not be attributed to
environmental regulations. It has been suggested, for ex-
ample, that utilities would install TSP control equipment
with 80 percent removal efficiencies to protect preheaters.
If this is the case, only about 20 percent of TSP. removals
can be attributed to environmental regulations, and the
cost-effectiveness of TSP removal declines comensurately.
-------
IV-54
Table IV-25
TOTAL 1979 NATIONAL POTENTIAL AIR POLLUTANT
EMISSIONS AND REMOVALS
BY UNIT CATEGORY
(thousands of tons)
so2
TSP
Unit Cateaory
Total
Removed
Potential
Emissions
Percent
Removed
Total
Removed
Potentisl
Emissions
Percent
Removed
Coal
Pre-1972
1972-1976
Post-1976
6,106
1,882
1,027
16,961
5,535
1,902
36
34
54
29 , 958
11,231
3,586
30 , 569
11,460
3,622
98
98
99
Total Coal
9,015
24,398
37
44,775
45,651
98
Oil
Pre-1972
1972-1976
Post-1976
776
706
320
1,078
1,197
421
72
59
76
58
65
20
67
77
26
86
84
76
Total Oil
1,783
2,695
68
143
170
84
Gas/Oil
Pre-1972
1972-1976
Poet-1976
1,258
160
a
1,700
254
a
74
63
a
89
11
a
108
19
a
82
59
a
Total G8s/0il
1,418
1,954
73
100
127
79
National Total
12, m
29,047
42
45,018
45,948
98
a s Insufficient observations.
Source: Energy Database and TBS calculations.
As shown in Table IV-26 substantial differences exist
among unit categories in quantities of pollutants removed. As
a group, coal units reduced potential S02 emissions by 37 per?
cent. More recent coal units, however, famoved a significant-
ly greater proportion than earlier units of potential SO?
emissions (54 percent as opposed to 34 and 36 percent)
Two factors contribute to the higher percent of total
emissions removed by recent coal units. First, potential
-------
Table IV-26
AVERAGE UNIT
POTENTIAL AIR POLLUTANT
-CATEGORY
EMISSIONS
AND REMOVALS
(tons per ml 11 ion kWli)
S02
TSP
Removal Strategy
Removal Strategy
Unit Cateoorv
Low-
Sulfur
Coal
Low-
Sulfur
Oil1
Scrubbers
Total
Potential
Emissions
Percent
Removed
Low-
Sulfur
Oil
Equioroent
Total
Potential
Emissions
Percent
Removed
Coal
Pre-1972
1972-1976
Post-1976
7.92
5.95
4.22
0.19
0.08
0.10
0.33
1.04
4.96
8.48
7.07
9.28
23.25
20.62
17.03
36
34
54
0.01
<0.01
0.01
41.69
42.22
40.40
41.70
42.22
40.40
42.53
42.95
40.81
98
98
99
Total Coal
6.65
0.14
1.35
8.14
21.93
37
<0.01
41.11
41.11
41.88
90
Oil
Pre-1972
1972-1976
Post-1976
0
0
0
9.74
8.20
1.61
0
0
0
9.74
8.20
11.61
13.53
13.92
15.33
72
59
76
0.56
0.52
0.74
.18
.23
a
0.74
0.75
0.74
0.86
0.89
0.97
86
84
76
Total Oil
0
9.46
0
9.46
13.96
66
0.57
.17
0.74
0.88
84
Gaa/Oil
Pre-1972
1972-1976
Post-1976
0
0
0
5.76
5.20
a
0
0
0
5.76
5.20
a
7.81
8.32
a
74
63
a
0.37
0.33
a
0.04
0
a
0.41
0.33
a
0.50
0.56
a
82
59
a
Total Gas/Oil
0
5.70
0
5.70
7.87
72
0.36
0.03
0.39
0.51
79
a = Insufficient
Conl units that
observations,
also burn oil
can attain
502 reduction by burning both fuels.
Source: Energy Database and TBS calculations.
M
<
I
tn
Ui
-------
IV-56
emissions are lower because a larger share of units are lo-
cated in the West where their potential emissions are based on
1 percent rather than 3 percent sulfur coal because they would
burn low-sulfur coal even in the absence of environmental
regulations. This means that reductions in emissions at west-
ern units are a higher percent of potential emissions. Sec-
ond, scrubbers are much more prevalent among post-1976 coal
units. On average, reductions in SO2 emissions attributed to
scrubbers are nearly five times greater among post-1976 units
than among 1972-1976 units. In turn SO2 reductions due to
scrubbers are more than three times greater among 1972-1976
units than among pre-1972 units.
While the use of scrubbers to attain reductions in SO2
emissions has been increasing, the relative importance of low-
sulfur coal in achieving emission reductions has decreased.
Ninety-four percent of SO2 reductions among pre-1972 units
resulted from the use of low-sulfur coal. This proportion
decreases to 84 percent for 1972-1976 units and 45 percent for
post-1976 units. The decline in the use of low-sulfur coal
reflects the fact that utilities with units in the East have
relied increasingly on scrubbers rather than on low-sulfur
coal to meet SO2 standards.
At oil-fired units, the use of low-sulfur coal results in
reductions of 66 percent in potential SO2 emissions. Post-
1976 oil-fired units have both potential emissions and emis-
sions reductions that are higher than earlier units. These
quantities indicate that a substantial number of the most
recent oil units are still in a "shakedown" period where their
high heat rates account for both their high potential emis-
sions and their high emissions reductions per million kWh.
As would be expected from the high efficiencies of TSP
control systems among coal-fired units noted in the discussion
of compliance strategies, reductions in TSP emissions at these
units amount to 98 percent of potential emissions. Recent
coal-fired units exhibit smaller reductions in TSP emissions
than do earlier coal units. The fact that potential emissions
from these more recent units are also lower, however, indi-
cates that a substantial portion of these units burns coal
with lower ash contents than do earlier units. (Particulate
emissions depend on coal ash content and the quantity of coal
burned).
Oil and gas/oil units attain reductions in potential TSP
emissions of 84 and 79 percent respectively. Most of these
reductions (77 percent for oil units and 92 percent for gas/
oil units) result from the burning of low-sulfur oil, and only
relatively small reductions are attributed to TSP control
-------
IV-57
systems, which are not generally utilized at oil and gas/oil
units. In most cases reductions in TSP emissions from burning
low-sulfur oil are incidental to the primary objective of
reducing SO2 emissions.
Cost of Removal
The cost of removing the quantities of pollutants dis-
cussed above varies significantly among unit categories. As
shown in Table IV-27, for coal units as a whole the average
cost of removing SO2 was nearly two times as high using scrub-
bers as using low-sulfur fuels ($418 per ton as compared to
$229 per ton). For individual units, however, the relation-
ship between equipment and fuel-based removals may be quite
different, depending on their access to low-sulfur fuels.
(These results do not include western coal-burning units, as
no sulfur premium is incurred by these units.)
Sulfur dioxide removal at coal units, whether using a
fuel or equipment strategy, is less costly than it is at oil
units. Reducing emissions by one ton of SO2 at coal units
costs an average of $229; an equivalent reduction at an oil
unit costs $737. Even equipment-based SO2 removal by using
scrubbers at coal units costs slightly less than 60 percent as
much as SO2 removal at oil units.
Although the difference in TSP removal costs appears to
be especially dramatic between coal and oil plants, these data
must be compared cautiously. Because of the relatively large
quantities of TSP removed by the fuel choice and attributed to
SO2 removal strategies, and the small quantities of TSP re-
moved by the equipment choice at oil units, the cost of par-
ticulate removal at these units averages $534 per ton. This
is compared to $20 per ton to remove TSP at a coal plant. The
simultaneous reductions in TSP and SO2 attributable to the use
of low-sulfur, high-quality (e.g., with fewer impurities) oil
may make it difficult to properly allocate control costs to
the removal of the individual pollutants.
Future Units
As with the analysis of existing units, uncontrolled
unit-level emissions of both SO2 and TSP were calculated
assuming that no pollution control equipment would be
installed and that coal units in the East would burn high-
sulfur coal containing 5 pounds SO2 per million Btu in the
absence of environmental regulations. (The analysis excluded
oil-fired units, as it was assumed that only coal would be
-------
IV-58
Table IV
-27
AVERAGE
COST PER
TON OF
S02 AND TSP REMOVAL
(1979 dollars per ton)
902
TSP
Removal Strategy
Low-
Su If ur
Coal
Low-
Sulfur
Oil1
Scrubbers
Total Equipment
Coal
Pre-1972
1972-1976
Post-1976
228
236
222
371
576
646
455
330
393
240
254
318
21
12
38
Total Coal
229
412
416
263
20
Oil
Pre-1972
1972-1976
Poet-1976
N/A
N/A
N/A
738
756
692
N/A
N/A
N/A
738
756
692
495
561
a
Total Oil
N/A
737
N/A
737
534
Gas/Oil
Pre-1972
1972-1976
Poet-1976
N/A
N/A
N/A
780
436
a
N/A
N/A
a
780
436
a
a
a
Total Gaa/Oil
N/A
742
N/A
741
a
National Total
229
721
418
461
22
Note: See Table VI-17 and Figure Vl-6 for escalation rates
for various components of costs. An approximation
to 1982 dollars can be made using the GNP escalation
factor of 1.286.
^Coal units that
both fuels,
a = Insufficient
also burn oil attain S02 reductions using
observations.
N/A = Not applicable.
Source: Energy Database and TBS calculations.
-------
IV-59
burned in fossil-fuel boilers installed in the future.) To
determine quantities of pollutants removed, calculated unit-
level emissions based on anticipated compliance strategies
(combination of fuel quality and pollution control equipment
choices) were subtracted from uncontrolled unit emissions.
Calculations of emissions were based on methodologies
developed by EPA.
Quantities of Pollutants Removed
Table IV-28 shows potential emissions and calculated
removals for SO2 and TSP among eastern and western units for
various standards. The underlying assumptions are that:
Table IV-28
AVERAGE UNIT-CATEGORY
POTENTIAL AIR POLLUTANT EMISSIONS AND REMOVALS
(tons per million kWh)
SO,
TSP
Coal Type
Eastern Low-
Sulfur
NSPS I
NSPS II
BACT
18.3
18.3
10.1
Removal
Strategy
Fuel Equipment Total
0
4.0
12.5
18.3
22.3
22.6
Potential
Emissions
24.0
24.0
24.0
Percent
Removed
76
93
94
Removal
Strategy
Equipment
40.1
40.4
40.4
Potential
Emissions
40.5
40.5
40.5
Percent
Removed
99.0
99.6
99.6
Eastern High-
Sulfur
NSPS I 0 19.2
NSPS II 0 21.6
BACT N/A N/A
19.2 24.0 80
21.6 24.0 90
N/A N/A N/A
40.1 40.5 99.0
40.4 40.5 99.6
N/A N/A N/A
Western Low-
Sulfur
NSPS I
NSPS II
BACT
0
3.4
4.4
0
3.4
4.4
4.9
4.9
4.9
0
70
90
48.1
48.4
48.4
48.6
48.6
48.6
99.0
99.6
99.6
N/A = Not applicable.
Source: EPA.
-------
IV-60
• USPS I apply to units whose boilers were
ordered before September 1979. (For purposes
of this analysis, in-service date is prior to
1985.) These units will meet a standard of 1.2
pounds SO2 per million Btu.
• NSPS II apply to units whose boilers were
ordered after September 1979. (In this
analysis, in-service date is 1985 or later.)
These units must comply with the standard by
scrubbing high-sulfur coal with 90 percent
removal efficiency (for S(>2> or by scrubbing
low-sulfur coal with 70 percent removal effi-
ciency .
• More stringent BACT requirements dictate that,
on a case-by-case basis, removals will exceed
NSPS II requirements. Generally, this is
accomplished through full scrubbing (90 percent
removal) of low—sulfur coals.
Three types of model facilities are presented in
Table IV-28. The first uses a control strategy that combines
eastern low-sulfur coal and scrubbers. The quality of coal
varies from 1.2 pounds SO2 per million Btu for NSPS I and II
compliance to 2.9 pounds SO2 per million Btu for BACT com-
pliance, while equipment choices vary from no scrubbing to
partial or full scrubbing. The eastern high-sulfur coal
strategy combines local bituminous coal containing 5.0 pounds
SO2 per million Btu with scrubbers that remove 80 to 90 per-
cent of the SO2• The western low-sulfur coal facility uses a
lignite/sub-bituminous coal that is representative of western
coal regions. It contains 1 pound SO2 per million Btu and, to
meet standards that exceed NSPS I, it is combined with dry-
scrubbing equipment choices that range from 70 percent to
90 percent removal.
Potential, uncontrolled, emissions are based on the
emissions factors described above for eastern high-sulfur and
western low-sulfur coals, and heat rates of 9,600 and 9,800
Btu per kWh, respectively. As shown in Table IV-28, these
specifications lead to substantial differences among model
facilities and standards in uncontrolled and controlled
quantities of SO2.
Potential emissions of TSP are based on ash contents of
12 percent for eastern coals and 9.2 percent for western
coals. The highly efficient TSP control systems remove at
-------
IV-61
least 99 percent of potential emissions, whether the equipment
is a baghouse for western low-sulfur coals or an ESP system
for eastern coals.
Cost of Removal
Table IV-29 presents the average costs of removing a ton
of SO2 and TSP for the strategies described above. The costs
are not for incremental controls, that is, moving from NSPS I
to NSPS II to BACT. Rather, they are the costs of alternative
levels of stringency from uncontrolled emission levels.
Table IV-29
AVERAGE COST PER
TON OF S02
AND TSP
REMOVAL
(1979
dollars per
ton)
Removal Strategy
SO 2
TSP
Coal Type
Low-
Sulfur
Fuel
Eauioment
Total
Eauioment
Eastern Low-
Sulfur
NSPS I
NSPS II
BACT
219
219
236
0
1,145
721
219
385
504
47
80
42
Eastern High-
Sulfur
NSPS I
NSPS II
BACT
0
0
N/A
261
417
N/A
261
417
N/A
47
47
N/A
Western Low-
Sulfur
NSPS I
NSPS II
BACT
0
0
0
0
1,547
1,663
0
1,347
1,663
68
67
58
Note: See Table VI-I7 and Figure VI-6 for escalation
rates for various components of costs. An
approximation to 2982 dollars can be made using
the GNP escalation factor of 1.286.
N/A = Not applicable.
Source: EPA and
TBS calculations.
-------
IV-62
Removal costs for future units are dominated by scrub-
bers. This is particularly apparent in the NSPS II and BACT
strategies for low-sulfur coal. However, these data must be
considered with caution; while the cost-effectiveness analysis
for existing units was based on actual utility submissions in
the Energy Database, this projected analysis is based on engi-
neering estimates, and it is estimated that engineering con-
trol costs are only accurate within plus or minus 30 to
40 percent.
-------
31
m
ci
m
¦n
n
m
o
-------
CHAPTER V
REGIONAL EFFECTS OF ENVIRONMENTAL
REGULATIONS ON THE ELECTRIC UTILITY INDUSTRY
-------
CONTENTS
Page
INTRODUCTION AND MAJOR FINDINGS V-l
Existing Capacity: Costs of Compliance V-l
New Coal-Fired Capacity. Costs of Compliance V-3
National Issues That Affect Compliance V-4
RESEARCH METHODOLOGY V-5
Selection of Regional Boundaries V-5
Development of Baseline Costs V-5
Development of Pollution Control Costs V-7
REGIONAL DISTRIBUTION OF CURRENT
CAPACITY AND COSTS V-7
Current Capacity by Region V-7
Baseline Costs V-9
Compliance Cost3
REGIONAL DISTRIBUTION OF FUTURE
CAPACITY AND COMPLIANCE COSTS; 1980-1990 V-16
Key Assumptions V-17
Retired Capacity
Reconverted and New Coal-Fired Capacity V-20
Reconversions to Coal
New Coal-Fired Capacity: 1980-1985 V-24
New Coal-Fired Capacity: 1985-1990 V-26
OTHER REGIONAL ISSUES V"29
Regional Growth Patterns and Their Effect
on Emissions
PSD and Regional Air-Quality-Related Values V-30
Regional Siting
V-29
V-30
V-31
-------
V. REGIONAL EFFECTS OP ENVIRONMENTAL
REGULATIONS ON THE ELECTRIC UTILITY INDUSTRY
Tv|TPODUCTI0N AND
jTrna FINDINGS
Building on the unit-category analyses of the previous
chapter, this chapter highlights the effects environmental
regulations are likely to have on EPA's ten regions and the
differences among regions. It presents methodology and as-
suJnptions used in this regional analysis, the regional distri-
bution of current and future capacity, and compliance costs
among units. It shows the components of costs by pollutant
control!^ and by types of costs. The chapter closes with a
mialitative discussion of pollution control requirements under
attainment and nonattainment programs.
Each of the ten EPA regions has a unique profile of
fisting capacity by age of unit and fuel type and, therefore,
is affected differently by environmental regulations. Each
rg-ion's profile, and the changes in the mix due to growth
within a region over time, influences the most likely range of
lotion control strategies for the region. The strategies,
whether they involve equipment or fuels upgrading, are trans-
lated into costs that the average regional customer pays for
service.
Generally, units in the eastern regions are older than in
„he western regions. More than 30 percent of eastern capacity
vas installed before 1960; only 6 percent of western capacity
is of that vintage. Seventy-five percent of coal-fired capac-
ity and 45 percent of oil- and gas-fired capacity is in the
East.
Regional variations in the average costs of compliance
«or unit categories capture the effects of differing fuel
mixes, fuel quality, and preferred compliance strategies.
These'are summarized in Table V-l. Although the national
average cost of pollution control across all units is
i 88 mills per kWh, regional costs range from a high of.
8*35 mills per kWh in Region I to a low of 1.07 mills per kWh
in Region VI. In every region except Regions VI and VIII
(which have relatively low average costs), low-sulfur fuel
premiums dominate the costs•
Existing Capacity:
casts of Compliance
Oil-fired units rely exclusively on low-sulfur fuel to
achieve compliance with sulfur dioxide (SO2) standards. This
-------
V-2
i«i> y-i
XTtmiN/wrs in
ICC10NM. fOU-UTIO" CONtMX. COSTS
CM
Ssaue.
i
Oaalnartt Caoacj tr fvoa
ftwaan* for Casta
(In arOar of ral.tlva aaonUwu)
aaiqhtad Avaraqa
Unit-Catagary
Coat* af Coap liana
(allla/ltWO
rr»-77 all uMta
Tu«l (all) praalua
1.35
u
^ra-77 om! ana oil iiilU
fu»l (coal ana oil) praaluai fffl capital
M ooaratlng eaati
t.l*
hi
Fra-77 eaal ana all unit*
F«al (eaal and all) pr»aiu«( pr»-72 aoal
rtS, tSf, and eftaaical control
4.M
IV
Coal iMlti, and fm-Ti all unit*
fual (eaal <"* oil) pfwlw 1 coal tf-Tl
TST and rhaolral control
4.«1
V
Coal uAlta eeeeelelly pf»~7J
T\m 1 (eaal) nr—lnai Ttf control 1
eftaaical cnttgl
3.7J
*1
Poat-7? eaal uAlta, qmtm unita
rharaal and eftaaical control
1.07
*11
Cad iniiUi pit-Tt }aa maiu
fual (all) praaUua for 00al ual6a tftot
•las burn all) TSP ewtrol
*.3J
via
Coal unit*, aaeactlaU? paat-lt
rV aentrol: POD fat paot-7t unitai
tlmcaal and eftaaical aonttal
1.M
a
rt»*TZ oil 0t gad wlUI pt*>77
ooai wMita
fml (all) praaUuai tftaraal and cftaaioal
control far oaal and all unit*
4.3)
X
rt-H ad pra-77 all unit*
Fual (ail) pnaiwi W aonttal< tftoraal
and rtwlBol control for coal unlta
x.yi
Sauraai Cnarqy OataA«a Md IBS oaloulatlana.
is reflected in the national average fuel oil premium of 6.86
-ills per kWh, and substantially affects the eastern regional
costs. Region I, with 99 percent of its fossil-fuel capacity
in oil units, faces a low-sulfur oil premium of 7.56 mills per
JcWh, more than 90 percent of Region I's average pollution
control costs. Without a change in capacity mix in the fu-
ture, Region I's utility customers will face an even greater
differential in costs if/ as projected/ the fuel oil premium
escalates at a more rapid rate than the cost of alternative
compliance methods.
The relatively high costs in Region II are driven by so2
control strategies at both oil-fired and coal-fired units.
More than half of Region II's generation is provided by'oil-
fired units; one-quarter of that capacity was in service be-
fore 1972. The costs of SO2 control at coal units in Region
II demonstrate the evolution of compliance strategies over
time, units installed before 1972 depend exclusively on im-
proved fuel quality, while units installed after 1972 reflect
the influence of new source performance standards (NSPS I)
requirements in environmental standards. These units combine
lower sulfur (but not compliance) coal with flue gas <*esulfUr_
ization (?GD) equipment. Costs for the 1972-1976 units are no
-------
V-3
greater than for the pre-1972 units, but units installed after
3.976, in meeting the NSPS I emissions limit of 1.2 pounds of
S02 ?er Btu, face a tripling of costs for SO2 control.
Coal-fired capacity in Region VIII accounts for three-
fourths of its total fossil-fuel capacity, with nearly one-
tni-d of tile coal capacity in NSPS I units. Control costs for
units with in-service dates after 1976 are 150 percent greater
chan the average costs for units of all vintages. The compo-
nents of the high pollution control costs include total sus-
pended particulate (TSP) control systems, FGD equipment, ther-
mal control equipment, and energy penalties and operating
costs associated with the capital strategies. These costs
reflect/ at a minimum* the compliance requirements of the next
wwo decades/ as new coal units are subject to NSPS I, NSPS II/
at times even stricter best achievable control technology
(3ACT) requirements.
Expansion plans for utilities during the 1980s are pro-
jected to favor nuclear and coal capacity. All regions will
oarticipate in the growth of nuclear capacity, which will
nearly double by 1990 if units currently under construction
are completed as planned. Pollution control requirements for
nuclear units resemble gas units in their emphasis on thermal
and chemical control and in their low costs of compliance.
Oil and gas conversions to coal will contribute to a substan-
tial increase in coal capacity in Regions I, II, III, and IV,
and new coal capacity will dominate total additions in all
regions except IX and X.
New Coal-Fired Capacity;
r.osts of Compliance
The emphasis on new coal-fired capacity will present
significant environmental concerns during the 1980s. Although
SSPS I standards can be met without installing scrubbers, it
is expected that eastern units generally will install FGD
equipment with removal efficiencies of 85 to 90 percent and
will bum high-sulfur coal. In the West, approximately-one-
third of all new capacity in Regions VI and VII will be
scrubbed, and nearly all new capacity in Region VIII will be
scrubbed.
The national average cost of compliance for SO2/ TSP/
-hernial and chemical control for new 1980-1984 coal-fired
capacity is 7.4 mills per kWh. The range is broad, from a low
-------
V-4
of 5.3 mills per kwh in Regions IX and X where using low-
sulfur coal is the preferred strategy and scrubbers are infre-
quently installed, to a high of 8.6 mills per JcWh in Re-
gion VIII where scrubbers with removal efficiency of 90 per-
cent are combined with fuel that has less than 0.3 percent
sulfur content.
Specific compliance strategies- for NSPS II additions in
the latter half of 1980 and beyond are more difficult to pre-
dict, although scrubbers will be required on all coal-fired
units. Individual units may choose a strategy of higher qual-
ity coal and 70 percent removal efficiency in the scrubber
design or lower quality coal and 90 percent design removal
efficiency. On the basis of the assumptions described in
Chapter IV, eastern NSPS II compliance strategies are pro-
jected to cost 12.4 mills per kWh, while western compliance
strategies will cost 9.4 mills per kWh.
National Issues That
Affect Compliance
Several issues that are national in scope may have a
bearing on future regional compliance requirements and costs.
These include regional growth patterns and their effects on
emissions, PSD and regional air-quality-related values, and
regional siting in attainment and nonattainment areas.
Changes in growth patterns can have a noticeable effect
on air quality and on the level of control necessary to
achieve and maintain the National Ambient Air Quality Stand-
ards (NAAQS). The Clean Air Act requires that states incor-
porate in their state implementation plans (SIPs) the applica-
tion of appropriate controls based on growing or diminishing
emissions. If industrial growth occurs at a higher than pre-
dicted rate in the Southeast or Southwest, or if conversions
to coal increase SO2 emissions in the East, powerplants may be
required to meet more stringent emission limitations by in-
stalling complex and costly equipment.
Visibility impairment, particularly in the West, and acid
precipitation, particularly in the East, are two air-quality-
related values that may be the focus of much attention over
the next few years. An important element of the PSD program
i3 the consideration of these values during review of a permit
application. To the extent that objectives in these areas
change, and lead to changes in PSD requirements, compliance
strategies and costs will change over time.
-------
V-5
aent areas is less stringent than the JOf sou^e in attain-
tainment areas. Further, the of5.if re<3?ir eaten t in nonat-
ifl nouattainment areas, m oraiif^ r®<3u^«ment exists only
tions have been similar in the technology determina-
available. Therefore, to dStl si?i™ ** o£d offseta have been
occurred at the expanse of9 in PSQ areas *•« oot
tare, growth may £ inL ' ar*as' In tile
are unavailable or extremely costly fi?h« v,a*eas i£ of£sets
effects are difficult to quLtlfy & JJiS
aSSEARCg METHODOLOnv
sion of ani'-cate9orytdataeto°reaionaiy'ia incluiies -he «*tan-
Mnt of region-specific baseband ^KSIoSioS&ol'Sig:
Selection of Regional Boundaries
rathef thlnt^t"^nIia|?r?^™li12bIi!?"cV-1'. «•!•=«
gions because the EPA regions are ™ii™T™°Unc^VNroC) re'
daries. In addition, ZCF's Coal an? pf i? st*te boun-
(CSOM), from which TBS derived reaionfl8^^ • Jta,iltlea Model
erates data that are consistent with state boundaries' 9Sa
regions were preferable to Census regions? which also*fof?L
state boundaries? while Enmrov n», follow
orovided by the itiiitl V£2t Databas« ^formation and data
of r«=io" tha °*2 be *99regated for either
as.svs.a £
Development of Basalin* rnc+»«
wi-h Sef|oststofe0L?°?^ri-0nvSf P°Uuti®n control costs
^i^ula?ioS« to- ^ P 2gwia tee abs^e environmental
nut d*Zel°2e(i feline unit-category pretax reve-
nue requirements. Pretax revenue requirements are an acoro-
th9y include «a"|e"t!Sr
pikers non"uel> cos" that are ultimately paid by the rate-
-------
I
Fiyuro V-1
EPA REGIONS
<
i
o\
r^ F Nofth 6'ak'
J;.; South Dako
iildiiconilA
mickhi*
Ml""*""'*
low*
^Wvemfcg]
' D»Uwm<
Muyltnl
NabiaOta
Kiiiui
it •¦>«"'
j *'hoiM
1 .
*r» t***
T««ii I
Oklahoma
N»~ M««ico
.¦ .• • • • • ¦ . .
I oullMlK
f loi «!•
Mitllitlppl
-------
V-7
The methodology described in Chapter IV for the unit-
category analysis was applied to the regional analysis with
one modification: the baseline fuel price for high-sulfur
coal in the East is greater than the baseline price for low-
sulfur coal available in the West. That differential, amount-
ing to 1.2 mills per kWh, is incorporated in the eastern and
western unit-category costs of generation at coal-fired units.
Development of Pollution
Control Costs
The approach used to develop the regional pollution con-
trol costs for coal-, oil-, and gas-fired units parallels that
used for the .unit-category analysis. Each region's costs of
compliance were derived from the Energy Database using the
same computational logic and types of assumptions as those
described in the previous chapter. Wherever possible, data
were incorporated that reflected differences among regions;
examples include the use of location-specific fuel premiums
and the distributions of capacity additions to appropriate
regions by fuel type. Some data, such as capital charge
rates, were available only at the national level. These were
applied uniformly to all regions.
REGIONAL DISTRIBUTION OF CURRENT
CAPACITY AND COSTS
The following paragraphs discuss the distribution of
current capacity, and the baseline revenue requirements and
pollution control compliance costs among the EPA regions.
Current Capacity by Region
Table V-2 shows the distribution of regional capacity by
prime mover. Included in these data are fossil-fuel, nuclear,
and hydro (including pumped storage) units. Omitted from the
table are the megawatts of internal combustion/gas turbine
(IC/GT) power, which account for approximately 8.6 percent of
total U.S. electric utility capacity. These data were not
available on a regional level in a form consistent with data
for other fuel types.
An examination of the distribution of capacity among
regions shows that all regions differ markedly from the na-
tional distribution of 44.6 percent coal, 31.4 percent gas and
-------
V-3
oil, 9.5 percent nuclear, and 14.5 percent hydro. The great-
est deviations from the national average occur in Region I,
where 32.3 percent of the capacity is provided by oil-fired
and nuclear units; Region VIII, where 98.5 percent of capacity
is provided by coal-fired and hydro upiits; Region IX, where
34.5 percent of capacity is provided by oil-fired, gas-fired,
and hydro units? and finally Region X, where 91 percent of
capacity is hydro.
Table V-2
1979 REGIONAL CAPACITY BY RJEL TYPE1
(MW and percent of total)
Fuel Typ«2
Coal Oil and Gaa Nuclear Hydro Total
t?A
Region
MK
S
MW
5
m
S
S
HW
S
I
486
2.7
10,684
59.1
4,199
23.2
2,708
15.0
13,077
100
II3
4,286
11.0
20,630
53.0
7,537
19.4
6,487
16.6
38,940
100
III4
33,611
63.0
11,941
22.4
5,948
11.2
1,318
3.4
53,318
100
IV
62,363
57,8
20,158
18.7
12,831
11.9
12,475
U.6
107,827
100
V
72,498
75.0
8,602
8.9
12,425
12.9
•3,075
3.2
96,600
100
VI
14,941
19,2
59,592
76.5
850
1.1
2,524
3.2
77,907
100
VII
20,278
75.5
3,620
13.5
1,773
6.6
1,181
4.4
26,832
100
VIII
12,023
68.8
262
1.5
0
0.0
5,196
29.7
17,483
100
IX
5,231
12.2
24,259
56.4
1,411
3.3
12,089
28.1
42 , 990
100
X
1,300
4.5
44
0.2
1,130
3.9
26,299
91.4
28,773
100
Total
227,015
44.6
139,792
31.4
48,104
9.5
73,852
14.3
508,763
100
^Capacity aa of and of 1979.
•excludes combined cycle and geotheiml.
^Includes eaatern Pannaylvania.
Exclude* eaatern Pannaylvania.
Source: ICF, Inc., Alternative Strategies for Reducing Utility 50* and VP
-aiaaiona. Jurm 1931; and Energy Oatabate.
Each of the ten EPA regions has a unique profile of
existing fossil-fuel capacity by age of units and fuel type.
This profile, as shown in Table V-3, and the changes in the
mix due to growth within a region over time, influence the
most likely range of pollution control strategies for the
region. The strategies, whether they are capital-intensive or
-------
V-9
fuel choices, are translated into costs that the average re-
gional customer pays for its service. Nationally, current
coal-fired and noncoal-fired units contribute approximately
53 percent and 42 percent, respectively, to all fossil-fuel
capacity. Coal is the predominant fossil fuel in Regions III,
IV, v, VII, VIII, and X; gas is dominant only in Region VI;
and oil is dominant only in Region I but is important in Re-
gion II as well.
As shown in Table V-3, in more than half the regions (II,
III, IV, V, VI, VII, and IX) at least 55 percent of the units
were installed prior to 1972. The Snergy Database further
reveals that, based on in-service year, Region V has the larg-
est share of units that would be candidates for replacement
during the 1980s, followed closely by Regions III and IV.
Regions VII and VIII have added the largest percentage of NSPS
I coal-fired units to their inventories since 1976; these
units and units planned for start-up in the early 1980s con-
tribute substantially to the fossil-fuel capacity in their
regions.
Baseline Costs
Based on the Energy Database, generation in the East
(Regions I-V) is dominated by oil- and coal-fired units while
generation in the West (Regions VI-X) is spread more evenly
across coal-, gas-, and gas/oil-fired units. This results in
a slightly higher baseline cost of generation for western
units than for eastern units, as shown in Table V-4. Speci-
fically, the weighted average baseline costs for eastern and
western regions are 26.7 mills per kWh and 27.7 mills per IcWh,
respectively.
Compliance Costs
The previous chapter discussed the components of the
average costs within unit categories of controlling pollution.
The national average cost of 3.88 mills per IcWh is composed of
air, water, and waste pollution control costs. These costs
are the aggregation of capital, operating, energy penalty, and
fuel premium costs, and incorporate strategies adopted by
operating units throughout the country. This section discus-
ses regional variations in the average costs of compliance
within unit categories to capture the range of effects caused
by differing plant ages, fuel mixes, fuel quality, and pre-
ferred compliance strategies.
-------
National
Average
Initio V-3
fOSSIl Sit AM UNI IS
ivre or capacity by in-schvicc yeah
(purceut of total fouall capacity In region in 1979)
Coal Unite
In-Service Year
Oil Unite
In-Service Yeer
Unit Categorlea
Cae Unite
In-Service Year
Gee/Oil Unita
In-Service Year
All Tousll-fuel Unlta
ll*A
Hmiitxi
Pre-72
72-76
77-79
Pre-72
72-76
77-79
Pre-72
72-76
77-79
72-76
77-79
Coal
Oil
Cub
Can/Oil
I
0
0
0
48.1
50.9
0
0
a
a
1.0
0
0
0
99.0
0
1.0
11
14.5
4.1
4.1
21.6
19.6
1.9
4.5
0
0
24.8
3.0
0
22.6
45.1
4.5
27.8
III
59.J
17.9
J.8
8.3
8.2
2.4
0
0
a
0
0
0
81.1
18.9
0
0
IV
49.7
17.8
5.5
3.5
5.8
2.6
1.2
0.1
0
12.5
0.8
0.5
73.0
11.9
1.3
13.8
V
66.9
11.7
8.4
J.2
1.2
6.1
0.2
0
0
2.3
0
0
87.0
10.5
0.2
2.3
VI
5.7
3.3
4.7
0.3
0.3
0
48.9
16.8
2.0
10.1
7.9
0
13.7
0.6
67.7
16.0
VII
41.5
9.8
32.2
0
0
0
2.2
0.5
0
13.3
0.6
0
83.4
Q
2.7
13.9
VIII
18.5
34.6
21.J
0
0
0
11.3
4.)
5.0
3.1
0
0
76.3
0
2U.6
3.1
IX
7.6
10.2
2.6
6.1
1.0
1.5
4.6
2.1
0
61.1
3.2
0
20.4
8.6
6.7
64.3
X
0
69.7
0
15.1
15.1
0
0
0
0
0
0
0
69.7
30.2
0
U
38.2
12.7
6.7
6.3
5.6
2.5
9.2
3.0
0.5
13.3
2.0
0.1
57.6
14.4
12.6
15.4
Source! Liturgy Database.
-------
v-ll
Table V-4
3ASELIte COSTS OF GEfCRATING
ELECTRICITY IN 1579 AT UNIT CATEGORIES
SELECTED TOR ANALYSIS
(1979 allia/kMO
fuel Type
EPA Reaione
Coal Oil Gas Gas/Oil
Average
All Fuels-1
I-V
(Eastern)
24.2 37.A 28.5 31.3
26.7
VI-X
(Western)
23.0 77.4 28.5 31.3
27.7
Nate: See Table Vl-17 and figure VI-6 for escalation rates for
various components of costs. An approximation to 1982
dollars can be made using the GNP escalation factor of 1.286.
^Weighted average based on generation in each fuel category.
Source: Energy Database and TBS calculations.
Table V-5 arrays the determinants of regional pollution
-ontrol costs. The major causes of compliance costs across
all regions are the fuel oil and coal premiums that are paid
to upgrade the quality of the fuel by reducing the sulfur
content. Oil-fired units rely exclusively on low-sulfur fuel
to achieve compliance with 502 standards. At coal-fired
-nits, a fuel-switching strategy is used more frequently than
an equipment strategy, although sometimes a switch to moder-
ately improved fuel quality will be combined with PGD equip-
ment that removes less sulfur from the fuel (see Tables IV-9
and IV-10 in the previous chapter).
-------
7-12
Table V-5
DETERMINANTS IN 1979 REGIONAL POLLUTION CONTROL COSTS
EPA
3eqion Dominant Foagil-Tuel Strategy
I Pr*~77 oil unit#
II Pre-77 coal and oil units
III Pre-77 coal and oil units
IV Coal ui\its and pre-72 oil units
v Coal units especially pre-72
VI Post-72 coal units, pre-72 gas units
VII Coal units; pre-72 gaa unita
VIII Coal units, especially post-76
IX Pre-72 oil and gaa unita; pre-77
coal unita
X 72-76 oael units; pre-77 oil units
Reasons for Costs
(in order of relative magnitude)
Fuel (oil) preaiua
Fuel (coal and oil) preauua* FSO capital
and operating costs
Fuel (coal and oil) preaiua; pre-72 coal
FGD, TSP, and chenicsl control
Fuel (coal md oil) prenium coal pre-72
TSP and chaaical control
Fuel (coal) praaiua; TSP control;
cheaicsl control
Theraal and chaaical control
Fuel (oil) prsniua for coal units that
also burn oil; TSP control
TSP control; Fffi for post-76 units;
theraal and chemical control
Fuel (oil) preaium; theraal and chemical
control for coal and oil units
Fuel (oil) praaiuai TSP control; theraal
and cheaical control for coal units
Sourest Energy Database and TBS calculations.
As shown in Table 7-6, pollution control costs incurred
by each region range from a low of 1.07 mills per )cWh in Re-
gion VI to a high of 8.35 mills per kWh in Region I. The
associated percent increase over average baseline costs at
each end of the range is 4 percent and 31 percent, respective-
ly. Gas-fired units incur the smallest incremental costs;
generally they are at or below 1 mill per JcWh and represent an
increase of no more than 4 mills per IcWh across all regions.
Gas/oil units would show low costs but for the fuel oil pre-
mium associated with lower sulfur oil. Although more than 50
percent of the generation from gas/oil units is gas-fired, the
oil premium carries a disproportionately large share of total
-------
V-13
incremental costs and yields effects as high as 26 percent
over baseline in Region I and 22 percent over baseline in
Region II.
Table V-6
SKiaVAL AVERAGE ANNJALIZED COSTS OF C0M»tYlNG WITH AIR, WATER, MO SOLID WASTE REGULATIONS IN 1979
(1979 aillaAWh ind parcant increase
ovar busline coats)
Fusl Type
?«icn
Coal
Oil
Gas
Gas/Oil
All fuels
millsAWh
*
¦llla/lcMh
S
¦ills/kWh
S
mills/kWh
%
nills/kWh
%
•
3
0
8.35
22
0
0
8.04
26
8.35
31
rr
5.24
22
6.50
17
0.02
0
6.30
22
6.18
23
r -r
3.30
16
8.73
23
0
0
0
0
4.36
16
:v
4.10
17
7.71
21
0.34
3
4.11
13
4.41
17
V
J.44
14
8.74
23
0.74
3
5.00
16
3.73
14
VI
2.03
9
4.38
13
0.56
2
2.50
8
1.07
4
5.02
22
0
0
1.08
4
1.71
5
4.53
16
• :::
3.28
14
0
0
0.50
2
2.49
8
2.94
11
:x
1.76
3
9.93
27
0.33
1
5.48
18
4.53
16
X
1.31
6
12.14
32
0
0
0
0
2.35
3
'aiianal
'v»rage
3.63
15
7.39
21
0.55
2
4.72
15
3.88
14
'•«•: See Taole VI-17 and Figurs VI-6 for escalation ntn for various components or costs. An approximation
:o 1982 dollars can ba nads using the CM* escalation factor of 1.286.
Source: Energy Database and TBS calculations.
Oil-fired units in all regions experience increases of at
least 13 percent over baseline and reach a high of 32 percent
in Region*X, where there is very little oil-fired capacity but
where the fuel premium is more than 10 mills per JcWh on -a base
of 3.74 mills per JcWh. The effects of the fuel premium on
average costs of generating electricity in Region X would be
even more dramatic than they are, but coal-fired capacity,
which is relatively less expensive in terms of meeting envi-
ronmental compliance requirements due to the absence of a fuel
premium, is used more extensively than oil-fired capacity.
-------
V-14
Coal-fired unit compliance costs range from a low of 1.31
mills oer kWh to a high of 5.24 miilj per JcWh, or 6 percent to
22 percent, respectively, over baseline operating costs. The
differences are a function of the compliance strategies cho-
sen, availability of low-sulfur coal (which carries a premium
in the East but not in the West), and the extent to which low-
sulfur oil (which carries a premium in every region) is burned
in units that also burn coal. For example, at coal-fired
units in Region VII, the high costs relative to baseline are
caused prixaarily by oil premiums, not by the use of low-sulfur
coal, for those units that have multifuel capabilities.
Table V-7 shows the range of costs associated with S02#
TSP, thermal, and chemical pollution control strategies across
the regions. Region I, with 99 percent of its fossil-fuel
capacity in oil units, pays an unusually high fuel premium
associated with SO2 compliance. In fact, its fuel premium
exceeds the national average by more than 200 percent.
Tabic V-7
AVERAGE ANNUALIZES COSTS OF C0H*lIANC£ 8Y POLLUTANT
FOH TYPICALLY AFFECTED FOSSIL STEAM UNITS IN 1979
(1979 ailla/kMh)
Pollution Control Strategy Coata
SO2 Control
EPA
TSP
Theraal
Chaaical
Region
Fffl
Fuel
Control
Control
Control
Total
I
0
7.36
0.24
0.02
0.53
8.35
II
0.59
4.56
0.30
0.13
0.48
6.18
III
0.35
2.93
0.41
0.28
0.40
4.36
IV
0.13
3.01
0.42
0.38
0.48
4.41
V
0.28
1.85
0.80
0.28
0.53
3.73
VI
0.07
0.38
0.05
0.27
0.30
1.07
VII
0.36
2.65
0.88
0.19
0.45
4.53
VIII
0.44
0.05
1.26
0.72
0.47
2.94
IX
0.11
3.72
0.10
0.21
0.4O
4.53
X
0
1.00
0.51
0.44
0.39
2.35
National
Avarage
0.23
2.48
0.43
0.30
0.44
3.88
sot., 5m Tabla vi-17 and Figure VI-6 for aacalation rata* for
varioua conponenta of coata. An approximation to 1982 dollara
can ba mad# using tha GNP aacalation factor of 1.286.
Source: Energy Database and TBS calculations.
-------
7-15
Compared to the fuel premium component of SO2 control,
FGD strategies account for a lesser portion of the total costs
of control. Regions II and VIII have relatively high costs
for similar FGD strategies but for different reasons: Re-
gion II's units are older and located in more densely popu-
lated areas with poorer air quality, and Region VIII's units
are newer—almost one-third of the coal capacity is in NSPS I
units—and current control costs are 150 percent greater than
che average costs for units of all vintages. Region IX's
costs for SO2 control are much lower than average because the
coal-fired generation is not scrubbed and the coal that meets
the emission standards carries no fuel premium, as low-sulfur
coal is generally available in the West at prices equal to
those of eastern high-sulfur coal.
TSP control accounts for a relatively large share of
total costs in regions with a dependence on coal-fired units,
as all coal capacity is subject to TSP control. Region VIII
is a particularly good example, where the fossil-fuel capacity
is split between coal and gas (and gas/oil)—76 percent and
24 percent, respectively, with no oil-fired units. While the
national average contribution of TSP control costs to total
control costs is about 11 percent, TSP costs in Region VIII
account for 40 percent of the total.
As a percentage of total costs, thermal and chemical
control costs in Region X exceed the national average by 100
percent. This is because these environmental regulations
affect all coal and oil units, and Region X's fossil capacity
is exclusively coal and oil.
An examination of the data in Table V-8 indicates that
there is wide regional variation from the national average
distribution of capital, operating, energy penalty, and fuel
premium component costs. Nationally, capital costs account
for 19 percent, operations and maintenance for 13 percent,
energy penalties for 4 percent, and low-sulfur fuel premiums
for 64 percent (see Table IV-22 in Chapter IV). Regionally,
nonfuel costs of control contribute 98 percent to Re-
gion VIII1s total costs (2.89 mills/kWh out of a total of
2.94 mills/JcWh), due to the lack of a fuel premium on low-
sulfur coal. Alternatively, nonfuel cost contribute 10 per-
cent to Region I's total costs, as oil-burning units dominate
the generation.
-------
V-16
Tab Is V-fl
It
1979 UNIT -CATEGORY COSTS OF
~miANCE BY COST COMPONENT
TOTAL AIR, WATER, AN) SOLID WASTE
(1979 BillsAWh)
Coat Cooponenta
EPA
Energy
Fuel
eoion
Capital
QAM
Penalty
Premium
Total
I
0.37
0.41
0.12
7.56
8.35
II
0.30
0.73
0.08
4.56
6.18
III
0.66
0.63
0.13
2.93
4.36
IV
0.76
0.47
0.17
3.01
4.41
V
1.U
0.71
0.1A
l.as
3.73
VI
0.22
0.29
0.18
0.38
1.07
VII
1.28
0.45
0.13
2.65
4.53
VIII
1.33
0.70
0.36
0.05
2.94
IX
0.32
0.38
0.12
3.72
4.53
X
0.63
0.44
0.27
1.00
2.35
National
Average 0.72 0.53 0.1S 2.48 3.38
Natei Saa Tabla VI-17 and Figura VI-4 for aaealation rataa
for varioua eoaponenta of coats. An approximation to
1982 dollars can ba made uaing tha GNP aaealation factor
of 1.286.
Sourcat Energy Oatabaaa and TBS calculationa.
REGIONAL DISTRIBUTION OF FUTURE
CAPACITY AND COMPLIANCE COSfsT"
1980-1990
Current compliance strategies and costs present an incom-
plete picture of the effects of environmental regulations on
the electric utility industry. Measuring the full effects
also requires assessing the costs associated with future
requirements of those regulations on both existing and new
capacity.
-------
V-17
Kev Assumptions
This analysis depends on estimates of changes in energy
demand growth—the year-to-year change in the total kilowatt-
hours of generation; peak demand--the maximum rate of demand
during a time period, usually a year—and reserve margin—the
diffarence between the system's capacity and the anticipated
annual peak demand. A reserve margin is maintained so that
power can still be provided at the time of peak demand, even
though the system's capacity may be temporarily reduced be-
cause of the failure of one or more generating units.
In a related study, EPA developed estimates of electri-
city demand growth and other key capacity assumptions.
According to EPA, aggregate demand will grow 3.0 percent per
year during 1979-2005. (That reflects a change from earlier
forecasts of 3.4 percent per year during the period 1979-
1990.) ICP, Inc., allocated the near-term growth to regions,
based on responses of representative utility companies and
state utility commissions, to a survey of projected 1979-1985
plans. TBS then revised the regional growth forecasts to
reflect the lower aggregate demand growth estimates.
Growth rates in regional demand for the periods 1979-1985
and 1985-1990 are shown in Table V-9. The particularly high
projection in Region VIII is driven by EPA/DOE assumptions re-
garding the completion of major energy projects. The rela-
tively low estimate in Region I assumes adequate existing
capacity in 1979 and little growth in the industrial, commer-
cial, and residential sectors in the Northeast. Growth in
peak demand is assumed to be the same as growth in energy
demand throughout the forecast period. Underlying assumptions
are that transmission and distribution losses remain at
10 percent of total generation, and that the reserve margin
varies from 36 to 20 percent nationally and within regions.
These key assumptions, in concert with the industry's
plans for reconversions, additions, and retirements, provide
the basis for EPA's projections of 1979 capacity estimates to
future periods. As shown in Tables V-10 and V-ll, nuclear
capacity should nearly double by 1990 if units currently under
construction are completed as planned, and all regions will
participate in that growth. The strategies for gradually
decreasing oil and gas use will lead to a substantial increase
in coal capacity in Regions I through V, and new coal capacity
will be the dominant strategy in Region VI.
-------
V-L8
labia V-9
/t
PROJECTED GROWTH OF REGIONAL
DEMAND TOR ELECTRICITY
1579 TO 1590
(percent)
Annual Growth Rats
EPA
Region 1979-1963 1985-1990
I
1.80
1.80
II
1.99
1.99
III
2.01
2.02
IV
3.11
3.12
V
3.26
3.26
VI
3.88
3.85
VII
2.99
2.98
VIII
5.21
4.19
IX
1.94
1.95
X
3.73
3.72
Average
All Region*
3.00
3.00
Sourest EPA—aggregate forecaet;
end ICF, Inc., Alterna-
tive Strateoiee for Re-
ducing Utility SO* and
NO Enieaione. June
1981.
Retired Capacity
Retirements will play a minor role in capacity expansion
plans during the 1980s. Although EPA and DOE estimated for
the purpose of their earlier study that about 3,500 MW of
coal-fired capacity would be retired during that period, ICF's
regional distribution of capacity changes did not reflect that
change. The Energy Database sheds some light on the question
of the expected turnover of coal-fired units. Assuming, as
EPA and DOE did, that the average life of a unit is 45 years,
units in service before 1945 would be retired by 1990. Less
than 1 percent of the capacity—about 1,200 MW—would be can-
didates for retirement. Virtually all capacity older than
45 years is small (less than 50 MW each), in the eastern re-
gions, and concentrated in Region V. Since other capacity
changes occurring simultaneously would have far more impact on
the cost of generation, no attempt has been made to account
for specific regional changes resulting from retirements.
-------
V-19
Teflle V-10
1985 REGIONAL CAPACITY 8Y FUEL TYPE
(HW and percent of total H#)
Fual Typ#-
Coal QU and Gas Nuclear Hydro Total
£?A ' - . —-——
Region
OL
5
xt
5
HW
5
HW
5
MW
S
I
2,258
12.5
8,912
49.3
4,199
23.2
2,708
15.0
18,077
100
II2
.6,074.
15. 6
18,842
48.4
7,537
19.4
6,487
16.7
38,940
100
III3
39,086
68.7
8,9J7
15.7
7,048
12.4
1,318
3.2
56,989
100
IV
68,722
59.9
15,701
13.7
13,96.4
13.9
14,378
12.5
114,767
100
V
78,179
74.0
3, £02
8.1
15,916
15.0
3,075
2.9
105,672
100
VI
23,930
28.2
59,529
64.7
4,077
4.4
2,524
2.7
92,060
100
VII
23,470
75.2
3,520
U.6
2,923
9.4
1,181
3.8
31,194
100
VIII
14,403
74.5
262
1.2
0
0
5,350
24.3
22,017
100
IX
5,471
12.9
24,259
43.7
4,011
8.1
15,105
30.3
49,806
100
X
1,330
5.5
44
0.1
2,223
6.7
29,105
87.7
33,202
100
Total
268,385
45.7
148,708
26.0
63,900
14.0
81,731
14.3
562,624
100
^Excludes combined cycla and gaothenaal.
^Includes eastern Pennsylvania.
^Excludes eastern Pennsylvania.
Scurca: ICF, Inc., Alternative Strateoiee for Kaduclno Utility SO? and MQ^
Fmi»*innm, June 1981, and CPA revised capacity expanaion plan.
Table V-ll
1990 REGIONAL. CAPACITY 3Y FUEL TYPE
(MM **d percent af total MX)
fuel Type*
Coal Oil and Gas Nudaar Hydro Total
EPA
fteclon
tSL
X
m
<•
m
•r
*»
MW
*
m
X
I
4,431
22.9
6,739
34.9
5,349
27.7
2,303
14.5
19,322
100
ll\
13,713
31.2
14,311
32.5
9,205
20.9
6,767
15.4
43,996
100
III3
42,236
70.2
5,787
9.6
9,037
15.0
3,134
5.2
60,194
100
IV
77,672
61.4
9,860
7.8
23,785
18.9
14,378
11.4
125,695
100
V
86,209
73.5
6,775
5.3
21,234
18.1
3,073
2.6
117,293
100
VI
38 , 839
36.1
59,592
55.4
6,577
6.1
2,524
2.4
107,532
100
VII
26,363
74.7
3,620
10.3
2,923
3.3
2,403
6.3
35,309
100
VIII
19,479
77.6
262
1.0
0
0
5,350
21.3
25,091
100
IX
10,308
17.6
24,259
41.4
3,361
15.1
15,105
25.3
58 , 533
100
X
2,170
6.0
44
0.1
4,713
13.1
29,105
80.3
36,032
100
¦
¦
¦
i • ii
-
¦ii
¦
Total
321,420
43.9
131,249
22.6
91,684
17.4
84,644
14.1
623,997
100
^Excludes combined cyela and geotharaal.
^In'cludee eaatarn Penneylvania.
'Swludta aaatam Pennayivania.
Sauna: ICf, Inc., Altomative Strategies fop Reducing Utility 50? and NO^
gfltisalona. June 1981, and CPA revised capacity expansion plan.
-------
V-20
Reconverted and New Coal-
Fired Capacity
Coal-fired units will be the primary alternative for
adding baseload capacity during the 1980s and beyond. Regula-
tory requirements will vary for new coal-fired units, depend-
ing on the boiler order date and whether the unit is recon-
verted or new. -Reconversions will be required to meet SIP
emissions limits. New capacity coming into service will con-
form to NSPS I if the units commenced construction after 1971
and before September 12, 1979. For the purposes of this anal-
ysis, it is assumed that the in-service year for NSPS I units
will be prior to 198S. Units with in-service dates of 1985
and beyond will meet NSPS II requirements, including the use
of scrubbers on all capacity. Again, due to construction
lead-time, it is assumed that this is consistent with the EPA
cutoff date for NSPS boiler orders of September 12, 1979.
Reconversions to Coal
DOE's programs to phase out oil and gas capacity are
intended to carry out the National Energy Plan without sacri-
ficing the nation's air quality. Reconversions to coal capac-
ity from oil and gas capacity resulting from federal mandates
or voluntary actions are projected to account for slightly
less than 19,000 MW of coal-fired capacity during the 1980s.
Though conversion entails major modifications to existing
boilers, EPA and DOE have agreed that under mandatory conver-
sion orders sources of pollution will not be required to apply
for a PSD permit in attainment areas. Rather, to protect the
air resource, units will be subject to the same requirements
as existing plants, that is, SIP emission limits and PSD in-
crements. Voluntary conversions may enjoy the same exemption
if they were capable of burning coal before January 6, 1975.
The economic attractiveness of converting to coal rather
than continuing to burn oil at any existing unit is a function
of the anticipated rate of increase in the price of oil, the
age of the unit, the region of the country in which it is
located, the stringency of the SIP, the compliance strategy
selected for the coal unit, the availability and quality of
coal, the cost of necessary modifications for coal handling,
and the financial condition of the utility. Prior studies
demonstrated that coal-capable units with at least 10 to 15
years of remaining life are economically attractive candidates
-------
V-21
for conversion.1 All units included in this current analysis
have in-service dates in the 1950s through 1970s. Assuming
that a fossil-fuel unit has a useful life of 45 years, and
that at least half the conversions would be completed by 1985/
units with in-service years of 1960 to 1975 would be particu-
larly attractive candidates.
Table V-12 shows the distribution of anticipated conver-
sions across ZPA's regions. All conversions are located in
the East, with the northern, mid-Atlantic and south-Atlantic
states heavily represented. Regions II and IV account for
about two-thirds of the capacity. EPA identified the current
302 emission standards for coal for these plants. For the
purpose of this analysis, the standards are grouped in "low-
SIP" and "high-SIP" categories, where low-siP is below
1.66 pounds per million Btu and high-SIP is at or above that
level*. Specifically, low-SlP ranges from 0.4 pounds per mil-
lion Btu (pounds/mmBtu) for a plant in Region II to a high of
1.2 pounds/mmBtu in Regions I and II. High-SIP ranges from a
low of 1.66 pounds/mmBtu in all regions to a high of 3.34
pounds/mmBtu in Regions I and IV.
Tabl. V-12
ESTIMATED 1980-1990 RECONVERSIONS TO COAL
Capacity Affected (MO*
Low SIP
High SIP
EPA Region*
(<1.66 oounds/mnBtu)
(>1.66 Dounda/mnBtu)
Total
I
1,372
2,573
3,945
II
897
4,181
5,078
III
0
3,339
3,339
IV
0
6,098
6,098
V
0
300
500
Total
2,269
16,691
18,960
ar« no anticipated convtrsiona froa ail or gas to coal in Regions VI-X..
*Unit capabilities after conversion.
Source: ICF, Inc., Alternative Strategies for Reducing Utility S0^ and NO
Eaisslons. June 1981; and EPA revised capacity e^ansion plan. x
:G. Martin Wagner, "Substituting Coal Power Plants for Oil
Plants," U.S. EPA, Energy Economics Branch, November 21,
1980. Edison Electric Institute has provided an alternative
analysis of the economics of reconversion. That discussion
appears in Chapter VI in this report.
-------
V-22
Pollution control strategies for converted units are
designed to respond to changes in SO2 and TSP emissions as a
result of a shift in fuels. Thsrm&l and chemical guidelines
that were part of the oil-burning environment are unchanged.
Therefore, the costs of compliance to be included in a compar-
ative analysis are air program costs—SO2 and TSP reduction
and collection costs. Two strategies are likely. A utility
may choose to burn low-sulfur coal if the SIP limit allows .and
if there is a dependable source of fuel of appropriate qual-
ity either run-of-mine or after preparation. Alternatively, a
utility may choose to install a scrubber and burn higher sul-
fur coal, a fuel that is cheaper and more readily available to
some eastern plants.
This study analyzed the comparative air pollution control
costs (including waste disposal) of reconverted and oil-fired
units. It did not repeat the previous analysis of the overall
economics of conversion. Table V-13 presents the results of
this study. For comparative purposes, compliance costs for
existing oil-fired units .are shown. For the oil-fired units,
the costs of compliance with air program requirements are
based on those developed in the unit-category analysis for oil
capacity in service before 1972.
Tstole v-u
1980-1990 RECONVERSIONS
AVERAGE ANNUALIZED UNIT-CATEGORY COSTS OF COWIIANCE
AM) REGIONAL EFFECTS
(1979 aillaAWh)
Units Reconverted to Coal
I
II
III
IV
V
Average
Regions I-V
Low-Sulfur Coal Stratagy
Scrubber Strategy
EPA Reoion Oil Units1 allla/kWh % difference milla/kWh % difference
12.63
9.37
10.39
10.45
13.59
10.66
5.58
5.49
5.40
5.40
5.40
5.45
-56
-45
-49
-48
-60
-49
8.95
3.78
8.60
8.60
8.60
3.76
-29
-U
-19
-IB
-37
¦ 18
Note: See Table VI-17 and Figure VI-6 for escalation rates for various consonants
of costs. An approximation to 1982 dollars can be made using the GNP escala-
tion factor of 1.286.
Wudes air pollution control costs for pre-1972 oil unit, and fuel premium'for dif-
ferential between baseline (hiqh-aulfur) oil and high-sulfur coal prices.
Source: Energy Database and T8S calculations.
-------
7-23
Assuming that all units choose a low-sulfur coal strat-
egy, the capacity located in low-SIP areas will require coal
with less than 1 percent sulfur and will face an average fuel
premium of 4 mills per kWh. Capacity located in high-SIP
areas will be able to burn coal with a sulfur content above
1 percent and will pay an average premium of 3.5 mills per
:
-------
V-24
New Coal-Fired Capacity; 1980-1985
In addition to the reconversions from oil to coal, an
estimated 34,888 MW of coal-fired capacity will come into
service during 1980-1985. The distribution of that capacity
is shown in Table V-14 and is based on a survey of utility
company managers conducted by ICF, Inc., for EPA. Regions I
and II will increase their coal-fired capacity during the
early 1980s, but only by reconverting oil-fired units that
originally burned coal. Region VI will contribute approxi-
mately one-third of all new additions, with most of the growth
located in Texas.
Table V-14
ESTIMATED 1980-1985 USPS I COAL-FIRED
CAPACITY AOOITIONS AND
AVERAGE UNIT-CATEGORY COSTS OF COMPLIANCE
New Coal-Fired Capacity Average Coat of Compliance
EPA Sag-ion (MW) (1979 sillaAWh)
li 0 0
III 0 0
III 2,357 8.1
IV 6,359 7.8
V 5,681 8.1
VI 10,989 6.5
VII 3,192 6.4
VIII 4,380 8.6
IX 1,200 5.3
X 530 J.3
All Regiona* 34,888 7.4
Nota: Saa Tabla VI-17 and Figura VI-6 for sacalation rata* for tha varioua
components of coata. An approximation to 1982 dollara can be mde
using tha QUP escalation factor of 1.286.
Uu Region I and II cosl-fired capacity additions are accounted for by
rsconveraiona.
*No regional data were available for retirements; new capacity nay be
understated if retirements actually occur.
Sources Capacity data: ICF, Inc., Alternative Str»t»oi«. for Reducing
Utility Ejniaa^ns, June 1981; and EPA revised capacity
expansion pl
-------
V-25
Since the majority of areas are meeting the primary SO2
and TS? standards, pollution control strategies at these new
units will be designed primarily to meet applicable NSPS I
requirements. Some units may be required to install pollution
control equipment that exceeds NSPS I requirements if they are
sited near Class I PSD areas or in areas with limited avail-
able increments. NSPS I requirements specify that a unit must
not exceed an emission rate of 1.2 pounds of SO2 per million
Btu and must meet a TSP limit of 0.1 pounds per million Btu,
which is usually achieved through installation of high-effi-
ciency TS? control systems. Eastern coal-burning units can
meet the SO 2 requirements by installing scrubbers and burning
high-sulfur coal or by burning low-sulfur coal. Western units
have a ready supply of low-sulfur coal that allows them to
meet the standard without installing scrubbers.
Although NSPS I standards can be met without installing
?GD equipment, nationwide approximately 52 percent of 1980-
1985 new capacity will be scrubbed. According to the Energy
Database, eastern units generally will install PGD equipment
with design removal efficiency of 83 to 90 percent and will
burn coal as high as 3.8 percent of sulfur. In addition,
approximately one-third of the new capacity in western Regions
VI and 711 will use scrubbers with removal efficiencies of 70
to 80 percent and will burn coal with a sulfur content of 0.5
to 0.9 percent. Nearly all new capacity in Region VIII will
be scrubbed with equipment designed to remove 80 to 95 percent
of the flue gases, while burning coal with less than 0.8 per-
cent of sulfur. (Refer to Appendix E for conversion factors
to obtain sulfur contents in pounds of sulfur per ton. )
Average annualized unit-category costs of meeting envi-
ronmental compliance requirements on new capacity between 1980
and 1985 include the costs of SO2 and TSP control strategies
for meeting NSPS I, as well as thermal, chemical, and solid
waste control programs. As developed in Chapter IV (see Table
IV-24), and based to a large extent on EPA estimates, the
unit-category costs of compliance are 7.6 mills per kWh for
the eastern low-sulfur coal approach, 8.6 mills per kWh for
the eastern and western scrubber approach, and 5.3 mills per
kwh for the western low-sulfur coal approach. (These are
stated in 1979 mills for comparison with other unit-category
analyses in this study.) The new capacity in each region
pursues a mix of scrubber and coal quality strategies that
yields a weighted-average cost of compliance, as shown in
Table V-14. ?or example, it is assumed that all capacity in
Region VIII will be scrubbed; therefore, the average cost of a
scrubber strategy, at 8.6 mills per kWh, appears in the table
as Region VIII's NSPS I unit-category cost. In contrast, all
capacity in Regions IX and X will follow a low-sulfur coal
-------
V-26
strategy oriced at 5.3 mills per !lSPS II
requirements with scrubbers designed for 90 percent removal
ef-iciency^(wet scrubbers) and the use of eastern high—sulfur
coal, or with scrubbers designed for 70 percent removal effi-
ciency (dry scrubbers) and the use of lower-sulfur coal. The
-------
V-27
Tsble V-15
ESTIMATED 1985-1990 NSPS II COAL-TIRED
CAPACITY ADDITIONS MO
AVERAGE
UNIT-CATEGORY COSTS OF
COMPLIANCE
Now Coal-Tired
Average Cost of
Capacity
Coopliance
EPA Region
(HW)
(1979 mills/kWh)
ii
0
0
II
4,J49
12.4
III
2,729
12.4
IV
2,852
12.4
V
7,330
12.4
VI
12,909
9.4
VII
2,893
9.4
VIII
3,074
9.4
IX
3,877
9.4
X
340
9.4
All Regions*
40,553
11.5
Note: Sh TaOls VI-17 and flgur* VI-3 far escalation
rata* for the varioua components of costs. An
approximation to 1982 dollars can ba made using
tha Gf»P aaealation factor of 1.286.
*AH Region I coal-fired capacity additione are accounted
for by reconversions.
^No regional data ware available for retirements; new
capacity my ba understated if retirements actually
occur.
Sourcet Capacity datai IFC, Inc., Alternative Strat-
egies for Reducing Utility Stb and NO
Emissions. June 1981; and CPA revised cspacity
expansion plan. Coat data: Energy Database and
TBS calculations.
Energy Database contains utility submittals of planned scrub-
ber strategies for units coming into service during 1980-1985.
Of the several units that will meet the NSPS II requirements,
90 percent will use wet scrubbers and high-sulfur coal. EPA
assumes that western units will use dry scrubbers because of
their access to low-sulfur coal and the compatibility of that
coal with dry scrubbing technology.
-------
V-28
The compliance costs for meeting NSPS II'requirements
accompany the regional capacity dat£ in Table V-15. Incor-
porated in these costs are the assumptions thac 90 percent of
eastern units will scrub high-sulfur coal and 10 percent will
scrub low-sulfur coal and that all western units will scrub
low-sulfur coal. It is also assumed that TSP control in the
East will be accomplished with electrostatic precipitators,
while western units will install baghouses. Thermal and chem-
ical standards will be met with traditional control techniques
in both eastern and western units. Based on these assump-
tions, the average cost of NSPS II compliance in the East is
anticipated to be approximately 12.4 mills per JcWh (in 1979
dollars), while western strategies carry a lower cost of
9.4 mills per kWh. Capital costs associated directly with
FGD, TSP,-and thermal equipment and indirectly with replace-
ment capacity account for about 75 percent of total costs.
Operation and maintenance activities carry a relatively small
burden, and only in the eastern dry scrubbing approach is a
fuel premium of 4 mills per JcWh applied to account for higher
priced fuel.
Several potential changes in the next few years would
affect the approaches utilities would select for complying
withMSPS II. Currently, EPA's engineering estimates of the
costs of. dry and wet scrubbers show that dry scrubbers with 70
percent removal efficiency are about 20 percent less expensive
than wet scrubbers with 90 percent removal efficiency. How-
ever, the addition of a fuel premium causes dry scrubbers to
be mora expensive for controlling SO2 emissions. Dry scrub-
bers have not been used successfully on eastern units burning
eastern coal, although the technology has been effective when
applied to western coal. That difficulty explains the trend
reported in the utility Form 67 data. If and when engineering
advances respond to the demand for dry scrubbers in the East,
the orders for dry scrubbers may exceed those for wet scrub-
bers.
EPA had previously estimated that the dominant share of
eastern NSPS II capacity would use dry scrubbers and would
burn eastern coal containing 1.7 percent sulfur. That esti-
mate has been revised due to technical problems, although EPA
anticipates that dry scrubbing technology will be compatible
with eastern low-sulfur coals in the near future. In that
case, the use of dry scrubbers introduces an associated issue
—the availability of eastern low-sulfur coal in quantities
sufficient to meet demand created simultaneously by NSPS II
requirements and rapidly expanding coal-burning capacity. The
diversity of choices in compliance strategies may be con-
strained by coal supplies for eastern units. The longer term
-------
V-29
fuel pricing effects are difficult to predict at this time but
deserve careful observation as NS?S II becomes increasingly
important in the operating environment of utilities.
OTHER REGIONAL ISSUES
During the next 20 years, electric utilities will face
new environmental influences that will affect their capacity
expansion plans, capital costs, needs for external financing,
and ultimately the amount their customers pay for the services
provided. Unlike the compliance requirements of the 1970s,
many of the future requirements are difficult to predict and
ever, more difficult to quantify. However, several national
issues including regional growth patterns and their effects on
emissions, PSD and regional air-quality-related values, and
regional siting, may have a bearing on regional compliance
requirements and costs.
Regional Growth Patterns
ana Their Effect on Emissions
Changes in growth patterns can have a noticeable effect
or. air quality and on the level of control necessary to
achieve and maintain the NAAQS. Yet local regulatory agen-
cies, in the interest of attracting new growth, may be reluc-
tant to require the ultimate in controls for proposed facili-
ties. The Clean Air Act requires that states project growth
and development in their areas and estimate the emission and
air quality impacts of that growth. SIPs must then demon-
strate that the NAAQS will be met or maintained by applying
appropriate control measures based on growing or diminishing
emissions. If industrial growth occurs at a higher than pre-
dicted rate in the Southeast or Southwest, for example, or if
conversions to coal increase SO2 emissions in the East, main-
tenance of NAAQS may require powerplants to meet stringent
emission limitations by installing complex and costly equip-
ment.
Other patterns of change might lead to reduced emissions.
Even with increased coal-fired generation, energy conservation
could limit the growth in emissions. A study of the New York
metropolitan area showed that under a high-conservation ap-
proach the existing TS? exceedance would be mitigated.2 in
2GCA Technology Division and Temple, Barker 6 Sloane, Inc.,
Evaluation of Alternative Development Scenarios, New York-New
Jersey-Connecticut Regional Study for the National Commission
on Air Quality (NCAQ), (July 1980).
-------
V-30
California, one of the largest utilities in the state an-
nounced plans to expand its use»of renewable resources and
energy conservation programs to improve the quality of the air
and support national energy initiatives.
PSD and Regional Air-
Quality-Related Values
An important element of the prevention of.significant
deterioration (PSD) program is the consideration, during
evaluation of a permit application, of air-quality-related
values such as visibility, odor, vitality of flora and fauna,
and acidity of precipitation.
Visibility impairment takes the form of regional haze—a
uniform reduction in visibility in all directions? plume
blight—a clearly distinguished plume from a source; and
layered discoloration—bands of discoloration observable above
the surrounding laud. While the relationship between SO2 and
TSP emissions and visibility is only indirect, it is known
that some of the SO2 emissions may be transformed into fine
sulfate particulate matter that might degrade visibility, it
is thought that emissions from coal-fired powerplants and
smelters contribute more to regional haze than do any other
sources of pollution, although other sources may contribute
considerably.
Some evidence suggests that certain regions are harmed by
acid precipitation and that emissions of SOj and N0X from
powerplants may be contributors. Acid precipitation is of
less concern in the West than in the Cast. Nitric acid pre-
dominates over sulfuric acid in western precipitation; alka-
line dust particles that are found in western air neutralize
the acidity. In addition, western soils are relatively alka-
line, creating a natural buffer in western lands and lakes to
counteract the effects of acid precipitation. Finally, the
large, sparsely populated western regions can absorb a large
quantity of emissions and still maintain a low rate of emis-
sions per unit area.
The East is not as fortunate. Eastern acid precipitation
is two-thirds sulfuric acid and one-third nitric acid. Eas-
tern soils and rock have high levels of acidity and poor buf-
fering capability. The levels of acidity in the soils and
lakes seem to be rising in many parts of the East and may
continue to increase. The main contributors to electric util-
ity industry SO2 emissions in the 1990s will be powerplants
-------
7-31
that were already in service by 197 6. Therefore, to the ex-
tant that utility emissions contribute to an acid problem in
the 2ast, stringent control strategies for new sources may not
mitigate the problem.
The current PSD program may be largely ineffective in
reversing regional air quality problems, such as visibility
and acid precipitation, that are caused by pollutants that
travel long distances and are the combination of emissions
from several sources. Modeling cannot identify individual
influences of sources of pollution hundreds of miles away, and
institutional arrangements do not exist to deal with multi-
state problems.
Regional Siting
Selecting a site for a new facility is complex and in-
volves consideration of many variables, including the availa-
bility of land, access to water, proximity to transportation
systems and raw materials, supply of a trained labor force,
favorable economic and tax climates, acceptance by the local
population, environmental climate, and attractiveness of local
hydrology and geology.
During the development of the Clean Air Act amendments of
1977, many states expressed concern that the existing air
quality of an area not unnecessarily affect the traditional
competition for growth. In response to this concern, the PSD
increment program was designed with equal air quality degrada-
tion allowed in all areas that met the NAAQS and BACT technol-
ogy review for all siting permit applications.
To date, PSD's influence has been less significant in
interregional siting decisions than more traditional factors
such as fuel and water supplies, transportation, taxes, wages,
and union posture.
In the future, the PSD increment program may create in-
terregional inequities, particularly in areas where fue-1 con-
versions from relatively clean oil or natural gas to dirtier
coal consume the available increments, and in areas dominated
by hilly terrain where the need for complex modeling may cause
a site to be unattractive. EPA is cognizant of the potential
problems in achieving national uniformity and is conducting
modeling workshops as well as developing guidance documents in
an effort to promote consistency in carrying out the.intent of
the PSD program.
-------
7-32
Related to the issue of competition among clean air re-
gions is the relationship between attainment and nonattainment
areas and its effect on economic development. In theory,
review of a major source in nonattainment areas is more strin-
gent than in PSD areas. In practice, however, technology
determinations have been similar in the two areas, especially
where EPA has issued guidance documents or has promulgated
NSPS. Therefore, to date PSD siting has not occurred at the
expense of nonattainment areas. In the future, growth may be
limited in nortattaixusent areas if offsets are unavailable or
extremely costly, although it is difficult to quantify the
potential effects on interregional growth.
-------
CHAPTER VI
NATIONAL EFFECTS OF ENVIRONMENTAL
REGULATIONS ON THE ELECTRIC
UTILITY INDUSTRY
-------
CONTENTS
INTRODUCTION AND MAJOR FINDINGS
RESEARCH METHODOLOGY
HISTORICAL PERSPECTIVE AND
BASELINE INPUT ASSUMPTIO"NS
Electricity Demand
Capacity and Generation Profiles
Cost Factors
Financial and Accounting Policies and
Assumptions
BASELINE FINANCIAL PROFILE
Baseline Projections
Alternative Scenarios
UNIT POLLUTION CONTROL COSTS
Units Existing as of December 31, 1979
Units Reconverted from Oil to Coal
During the Period 1980-1990
Units Coming into Service During
the Period 1980-1984
Units Coming into Service After 1984
RESULTS OF THE NATIONAL ANALYSIS
Base Case Scenario
Base Pollution Control Costs
By Unit In-Service Date
Pollution Control Expenditures
By Pollutant
Alternative Scenarios
vi-1
VT-11
VI-12
71-13
VI-17
VI-22
VT-28
VI-3 5
VI-36
Vl-39
VI-42
VI-42
VI-43
VI-50
VI-52
VI-55
VI-56
VI-59
VI-63
VI-67
-------
VI. NATIONAL EFFECTS OF ENVIRONMENTAL REGULATIONS
ON THE ELECTRIC UTILITY INDUSTRY
INTRODUCTION AND MAJOR FINDINGS
This chapter describes the financial effects of pollution
control regulations on the U.S. electric utility industry as a
whole. The U.S. electric utility industry is defined here to
include both investor and publicly owned segments of the
industry. Because of the greater availability of data on
investor-owned utilities, projections for that portion of the
industry are used as the basis for extrapolating to the indus-
try level. Previous chapters have described the effects of
environmental regulations at the levels of individual units,
individual companies, and geographic subregions of the coun-
try. The national-level analysis of this chapter focuses
primarily on the period 1980-1999. The "base case" scenario,
described in detail in this chapter, reflects EPA's assump-
tions concerning the pollution control capital and operation
and maintenance costs required to satisfy current and expected
environmental regulations.
The national financial effects of pollution control regu-
lations are estimated using TBS's Policy Testing Model of the
electric utility industry, PTm(Electric Utilities). The model
draws on projections of demand, capacity expansion plans,
capacity utilization, and unit costs as inputs. The model
then develops detailed financial and fuel use projections.
PTm's financial and other results are sensitive to the input
assumptions about demand growth and capacity expansion plans.
To evaluate the effect of these assumptions on the estimate of
total pollution control costs, alternative scenarios of demand
growth and capacity expansion plans are considered. The re-
sults of the analyses of the base case and alternative scenar-
ios are described briefly in the following pages and in more
detail in the "Results of the National Analysis" section.
Pollution control regulatory requirements are typically
related to the in-service or construction start date of a par-
ticular plant or boiler. In this analysis, costs are account-
ed for by unit in-service date. The year-end 1979 financial
profile of the industry used for this study includes pollution
control expenditures made prior to January 1, 1980. In order
to determine a "baseline" projection excluding all environ-
mental costs, these pre-1980 environmental capital costs
-------
VI-2
which for the investor-owned portion of the industry accounted
for $6.55 billion of plant in-service and $5.95 billion of
construction work in progress (CWTP)—were subtracted from the
December 31, 1979, financial profile. Two distinct categories
of pollution control costs are then added to the baseline
projection—costs associated with pollution control equipment
installed prior to 1980; and pollution control expenditures
for equipment installed after 1979 plus any fuel premiums
incurred after 1979.
Figure VX-1 shows the mapping of unit in-service dates
onto pollution control cost categories. The separation of the
components of the total pollution control costs, particularly
costs associated with units installed before 1980, is impor-
tant for assessing the effect of specific pollution control
regulations. The capital costs, and to some extent the opera-
tion and maintenance costs, associated with pre-1980 pollution
control equipment cannot be altered and therefore can be con-
sidered "sunk." These historical costs are the costs analyzed
figure VI-1
POLLUTION CONTROL COST CATEGORIES AND UNIT IN-SERVICE DATES
IMtt Xn-Sarviea Bat*
Cost CfttagorlM
-------
VI -3
in detail in Chapters IV and V. In contrast, the fuel pre-
miums associated with pre-1980 requirements and the fuel,
other operation and maintenance, and capital costs of post-
1979 requirements can, to a considerable degree, change
depending on the shape of future regulations. The focus of
this chapter is on these "incremental pollution control"
costs.
Table VT-1 provides a comparison of the baseline finan-
cial projections, pre-1980 pollution control equipment costs,
and incremental pollution control costs, expressed in 1982
dollars. Incremental pollution control changes in plant in-
service amount to $87.3 billion over the forecast period, or
approximately 8 percent of projected industry changes to plant
in-service of $1,128.8 billion. Incremental external financ-
ing requirements are $70.5 billion. When pre-1980 pollution
control equipment costs are included, external financing in
the 1980-1999 period is reduced relative to the baseline pro-
jection by $2.3 billion. Credits for depreciation and re-
tained earnings associated with the equipment already on the
industry's balance sheets are responsible for the decline.
Cumulative pollution control operating revenue requirements
through 1999 are $263.3 billion, or 9 percent of the total of
$2,947.5 billion, as shown in Table VI-I. Cumulative pollu-
tion control operation and maintenance expenses are
$190.3 billion, slightly more than 10 percent of the total of
$1,862.2 billion. Consumer charges in 1999 for pollution
controls are 5.01 mills per kilowatt-hour (JcWh), or 9 percent
of the total of 56.16 mills.
Table VI-2 provides a breakdown of plant additions by
pollutant and time period. Sulfur dioxide (SO2) controls
represent • $43.3 billion or about half of all the major pol-
lution control-related expenditures over the 1980-1999 period.
Total suspended particulate (TSP) controls account for
$21.9 billion or 25 percent of total pollution control-related
plant additions, while water pollution and solid waste control
costs represent the remaining $22.0 billion or 25 percent. Of
the total of $87.3 billion of pollution control plant addi-
tions, 16 percent or $13.6 billion is attributable to capacity
penalties associated with new pollution control equipment.
-------
V X -•»
Table Vl-1
SUMMARY OF IMXJSTRY CUMULATIVE EXPEfOITURES
WITH ANO WITHOUT POLLUTION CONTROLS
(billions of 1982 dollars)
Changes in Plant In-Service 1980-1985 1980-1999
Baseline 199.17 1,041.49
Pre-1980 Pollution Control
Equipment 0 0
Incremental Pollution Controls 18.45 87.28
Total 217.62 1,128.77
External financing
Baseline 151.78 857.63
Pre-1980 Pollution Control
Equipment^ (1.31) (2*28)
Incremental Pollution Controls 18.17 70.46
Tqtal 168.64 925.81
22eratinj^Revenues
Baa* line 594.05 2,684.23
Pre-1980 Pollution Control
Equipment 13.99 45.00
Incremental Pollution Control! 44.31 218.26
Total 652.35 2,947.49
Operation and Maintenance Cxoenees
Baseline 404.28 1,671.88
Pre-1980 Pollution Control
Equipment 8.42 35.69
Incremental Pollution Controla 39.86 154.57
Total 452.56 1,862.17
Consumerj£hs£2ee£>_(iBl^£j2erJ<)^
Baseline 44.35 51.15
Pre-1980 Pollution Control
Equipment 0.91 0.67
Incremental Pollution Controls 3.65 4.34
Total 48.91 56.16
^While there are no plant additions for pre-1980 pollution controls in
the 1980-1999 period, external financing requirements are reduced be-
es use of the greeter amounta of plant in-eervice ea of 1980 for the
pre-1980 equipment. Thia increases depreciation and retained earnirtga,
and reducea external financing requirements.
^Consumer charge figures are not cumulative, but repreaent the annual
coneumer charges for the laat year of the period indicated measured in
mills per kilowatt-hour.
Source: PTnKElectric Utilities).
-------
VI-5
T*>le VI-2
chances in plant in-service attributable to
POLLUTION CONTROL REGULATIONS
(billions of 1982 dollars)
1980-1985
1980-1999
Baseline Chenaes in Plant
In-Service
199.17
1,041.49
Pre-1980 Pollution Control
Eauiomnt
0
0
Incremental Pollution Controls
Fuel Preaiutr11 Pre-1980 Units
Fuel Premium^! Poet-1979 Units
S02
TSP
Solid Waste
Water
0
0
8.91
5.68
1.85
2.01
0
0
43.32
21.94
10.98
11.04
Total Pollution Control*
87.28
Total
217.62
1,128.77
Ifuel premiums and other pre-1980 pollution eontrole do
not have capital charges aaaociated with thM in the
1980-1999 period. The post-1979 unit category iricludea
any coal conversions.
Source: PTo(Electric Utilities).
The 1980-1999 external financing requirements associated
with pollution controls amount to $68.2 billion or about
7 percent of the industry's projected total requirements
(Table VI-3). The contributions to external financing re-
quirements by pollutant correspond closely to their contribu-
tion to plant additions.
-------
VI-6
Table VI-3
EXTERNAL- FINANCING EFFECTS OF
POLLUTION CONTROL REGULATIONS
(billions of 1*62 dollar*)
1980-19B5
1980-1999
Baseline External Finencina
151.78
857.63
Pre-1980 Pollution Control
Eauiwasnt*
(1.31)
(2.28)
Incremental Pollution Control*
Fuel Prwaiusr1: Pre-1980 Units
Fuel Premiums Post-1979 Units
®2
TSP
Solid Masts
Water
0
0
8.78
5.41
1.93
2.05
0
0
35.21
17.24
9.03
B.98
Total Pollution Controls
16.86
68.18
Total
168.64
925.81
*Fuel preaiuas are operating easts and do not have capital
charges sssociatsd with the*. The post-1979 unit cstegory
include# any coal conversions.
2While there ars no plant additions for pt»-1980 pollution
controls in the 1980-1999 period, sxtsrnal financing is
reduced because of the greater aaounts of plant in-eervica
as of 1980 for ths pre-1980 equipment. This increases de-
preciation snd retained earningt, and reduces external
financing requirements.
Source: PT«(Electric Utilities).
Pollution control costs represent $263.3 billion, or
approximately 9 percent of the industry's total revenue re-
quirements during the 1980-1999 period (Table VI-4). Post-
1979 SO2 controls including all fuel premiums represent 62
percent of the total pollution control-related revenue
requirements. The price premium for low-sulfur fuels alone
represents the largest single component of the increase in
revenue requirements—almost 40 percent. The other pollution
control categories contribute less importantly to total cost
increases and therefore revenue requirements. Post-1979 solid
waste disposal costs, however, do rise over the period and
become a significant fraction. 7 percent, of total cumulative
pollution control-related revenue requirements by 1999. Water
-------
VI-7
-he1oeriSdC°?»D?esini?nedRreVenUe re
-------
VI-8
Energy penalties resulting from scrubbers, TSP controls, waste
disposal controls, and thermal controls installed after 1979
represent 3.4 percent of total pollution control operation and
maintenance expenses, or $6.5 billion.
Table VI-5
OPERATION AND MAINTENANCE EXPENSE EFrECTS
OF POLLUTION CONTROL REGULATIONS
(billions of 1962 dollar*)
1980-1985
1980-1999
Saaeline 0&M Exoenaes
404.28
1,671.88
Pre-1980 Pollution Control
Equipment
8.42
35.69
Incremental Pollution Controls
fuel Premium*1: Pre-1980 Units
34.09
100.52
fuel Premium^: Post-1979 Unit*
1.24
8.10
S02
2.49
26.05
TSP
0.02
3.51
Solid Waste
1.67
11.48
Water
0.35
4.94
Total Pollution Controls
48.28
190.29
Total
452.56
1,862.17
Ifuel preaiuwe art typically considered SOj coats but art
¦town separately here beceuae of their large effect on
total pollution control easts. The post-1979 unit cetegory
includes any coal conversions.
Source! PTm(Electric Utilities).
Consumer charges attributable to pollution control expen-
ditures are shown in Table VI-6. The increased cost per kWh
is approximately 9 percent in 1999. As is the case with other
measures of the effects of pollution control, post-1979 SO2
controls including fuel premiums represent the single largest
cost category, accounting for 57 percent of the total increase
in consumer charges attributable to pollution control regula-
tions. The remaining 30 percent is split relatively evenly
between costs for controls installed as of 1979, TSP controls,
water pollution controls, and solid waste controls.
-------
VI-9
T«ble VI-6
CONSUMER CHARGE
POLLUTION CONTROL
EFFECTS OF
REGULATIONS
(ailla per kilowatt-hour in 1982 dollars)
1983
1999
Bsseline Consumer Charms
44.35
51.13
Pre-1980 Pollution Control
Couioownt
0.91
0.67
Incremental Pollution Controls
Fuel Premium1: Pre-1980 Units
Fuel Pramiurn1; Post-1979 Units
®2
TSP
Solid Masts
Water
2.12
0.13
0.71
0.30
0.26
0,13
1.00
0.17
1.70
0.59
0.49
0.39
Total Pollution Controls
4.36
5.01
Total
48.91
5$. 16
*Fuel premium are typically considered SO2 coata but are
shown separately here because of their effect on total
pollution control costs. Th» post-1979 unit category in-
cludes sny coal conversions.
Sourcet PTm(Electric Utilities).
As previously discussed, TBS examined two alternative
scenarios in the course of this study. The summary results of
that examination are presented in Figure VI-2. The changes in
assumptions used to develop these scenarios are:
• Reduction in the growth rate during the 1980-
1999 period from 3.0 percent to 2.0 percent,
and
• Nuclear prohibition after 1989, with coal
replacing the nuclear additions assumed in the
base case.
A decrease in the industry's annual rate of growth re-
sults in lower baseline plant additions and consumer charges,
-------
I
Figure VI—2
COMPARISON OF CUMULATIVE PLANT ADDITIONS
AND OPERATING REVENUES
UNDER ALTERNATIVE SCENARIOS
CONSTANT 1982 DOLLARS
CUMULATIVE PLANT ADDITIONS CUMULATIVE OPERATING
REVENUES
$1200
$1000
$800
BILLIONS
OF DOLLAnS
$600
$400
$200
10/9
IM
$3000
$2600
$2000
BILLIONS
OF DOLLARS
(1600
$1000
$500
?•«>
7949
<
M
I
o
n
OA St 2X NO
CASE GROWTH NUCLEAR
19B0 ioon
|ioltialion control*
htfllti*
BASE 2% NO
CASE GROWTH NUCLEAR
1980 -1999
BASE 2% NO
CASE GROWTH NUCLEAR
1980 -1986
BASE 2X NO
CASE GROWTH NUCLEAR
1980 -1999
-------
VI -11
and lower pollution control plant additions. However, the
percentage increase in consumer charges due to pollution con-
trols is essentially unchanged from the base case.
3aseline and total plant additions are slightly lower if
nuclear additions are assumed to terminate after 1989. Bow-
ever, cumulative industry pollution control additions to plant
in-service through 1999 are slightly higher ($13.81 billion)
than they would be if nuclear additions were allowed to con-
tinue after 1989. Total operating revenues are virtually the
same under both scenarios. Consumer charges in 1999 are also
essentially unchanged under either scenario.
RESEARCH METHODOLOGY
The general approach used in the study has been first to
project conditions in the industry in the absence of pollution
controls (baseline case), then to project conditions with the
controls and, finally, to measure the effects by contrasting
one set of projections with the other. The projections are
based whenever possible on published data. TBS used, to the
maximtun extent possible, actual operating data through 1979
and announced industry plans. Where announced plans were
unavailable, which is generally the case beyond 1989, TBS
reviewed various projections by industry observers and deter-
mined reasonable estimates for items such as future capacity
and fuel costs. In addition, an attempt was made to use fore-
casts which are consistent with other recent EPA studies. In
the area of pollution control costs and rates of implementa-
tion, a significant amount of original research was conducted
based on data presented in FERC form 67. The pollution con-
trol cost estimates and coverage assumptions developed from
those data reflect actual experience and plans of the
industry.
TBS used the model PTm(Electric Utilities) to project the
financial implications of the load growth, cost, coverage, and
other assumptions used in this study. PTm develops detailed
year-by-year financial forecasts for the industry in both
constant and current dollars. The level of detail within PTm
enables a comprehensive financial analysis that includes ac-
counting, tax, regulatory, and financial considerations. The
approach, however, does not provide the capability to address
supply or demand changes due to changes in costs. PTm is
described in detail in Appendix B.
-------
VI—12
Five summary statistics descriptive of the detailed fi-
nancial and operating projections are used to capture the
major financial implications of alternative sets of assump-
tions. The summary statistics are:
• Changes in plant in-service,
• External financing,
• Operation and maintenance costs,
• Operating revenues , and
• Average consumer charges.
The indicators are more fully explained later in this chapter
in the discussion of the baseline projections.
HISTORIC**^ PERSPECTIVE AND
BASELINE INPUT ASSUMPTIONS
As discussed in Chapter III/ until the mid-1960s the
as discus indu-irv -nioyed a record of steady and
predictable growth accompSied by declining unit cost., rela-
tively assured profitability, and easy access to capital.
Since that ti», «gu!ftSrT™vi-
roS^nt!anThe changes have encompassed almost every aspect of
the utility business, including sharp changes in demand pat-
terns? radically, different relative power supply costs and
options, an increasingly 8t?ained.fl^°f^Lnts Theie
escalating regulatory scrutiny and requirements. These
cSISgSs hive markedly increased the uncertainty confronting
utility decision makers and have led to a
over the most appropriate way to meet the demands and chal
lenges now facing the industry.
The specifics of the changing utility business and regu-
latory environment are further discussed in the course of
presenting the major input assumptions. That presentation is
separated into four sections:
• Electricity demand,
• Capacity and generation profiles,
-------
VI-13
• Cost factors, and
• Financial and accounting policies and
assumptions.
Electricity D«»w»n^
Future electricitv
P°^nt of the olectrifruti?^' t0 a l4rg® e*tent.
Established goals of system reliahi t i process,
ture demand dictate thi amount of ?nd est^tes of f u-
to maintain targeted Pliability iSSl"ty *dditions necessary
Two measures of electric*,
system load =h«acteristics-~L ^d/rVsed to describe
demand. Peak demand refers to mL'®??a?d and total energy
of consumption of alectricit^ within1! !" fnst«taneoufrate
tine, measured in kilowatts
-------
VI-14
Table VI-7
HISTORICAL AND fORECAST ANNUAL GROWTH
IN PEAK DEMAND AND ENERGY SALES
Total Electric Utility Industry
1960-2005
Annual
Growth in Peak Demand
in Kilowatts
Annual
Growth in
Kilowatt-Hour
Sales
Year
(percent)
(percent)
1961-1965
Growth Rate
7.0
4.7
1965-1966
9.2
6.9
1966-1967
5.0
9.0
1967-1968
11.5
6.5
1966-1969
8.3
8.6
1969-1970
6.6
8.7
1970-1971
6.4
6.4
1971-1972
9.3
5.4
1972-1973
7.8
7.6
1966-1973
Growth Rata
8.1
7.1
1973-1974
1.6
-0.6
1974-1975
2.2
1.5
1975-1976
4.0
6.3
1976-1977
6.9
5.1
1977-1978
3.0
3.5
1978-1979
0.9
2.9
1973-1979
Growth Rata
3.4
3.1
1979-19901
Growth Rata
3.0
3.0
1990-1995
Growth Rata
3.0
3.0
1995-2005
Growth Rata
3.0
3.0
r
Based on 1979 peak demand of 409,000 megawatts and
sales of 2,070.3 billion kilowatt-hours.
Source: Forecasts provided by EPA; Edison Electric
Institute, Stjtisti«UJfeBrbook_o^
Electric Utility Industry, 1979.
-------
VI-15
Table VI-8
NUMBER OF CUSTOMERS AN) AVERAGE
KILOWATT-HOUR
USAGE PER CUSTOfCR
Total
Electric Utility Industry
1960-1979
Total Number
Average kWh
Year
of Cuatoaar**
per Custoaar
1960-1965
Growth Rat*
•*-2.22
+4.75
1966
66,910,000
15,678
1967
68,168,000
16,384
1968
69,716,000
17,445
1969
70,929,000
18,563
1970
72,485,000
19,380
1966-1970
Growth Rata
+2.03
+5.48
1971
74,265,000
19,956
19 72
76,150,000
20,964
1973
78,461,000
21,955
1974
80,102,000
21,448
1975
81,845,000
21,417
1971-1975
Growth Rata
+2.55
+1.85
1976
83,615,000
22,361
1977
85,590,000
23,052
1978
87,668,000
23,315
1979
89,514,000
23,454
1976-1979
Growth Rata
+2.3S
+1.65
iIncludea all cuatoawr categories (a
.g., residential,
commercial, and
induatrial).
Sourcat Ediaon Elactric Institute,
Statiatical
Yearbook of the Elactric Utility
Induatrv
, 1979.
Since 1974, many industry observers have consistently
overestimated future demand, and the EPA forecast used in this
study could also represent a high-side projection. However,
the projection of growth of 3.0 percent per year to 1990 cor-
responds closely to many other industry projections; as indi-
cated in Table VI-9, other widely circulated forecasts range
-------
VI-16
from 2.8 to 4.3 percent per year. If actual demand is lower
than expected, then the total baseline and pollution control
costs will be below the projections of this study. The base-
line and pollution control cost estimates, therefore, might be
viewed as conservatively high to the extent that the forecast
growth rate is at the upper end of the range of growth expec-
tations.. Of course, the cost estimates presented in this
study could prove to be less than actual if growth outstrips
the EPA projections.
Tabic VI-9
COMPARISON OT FORECAST ANHJAL
growth in electricity demand
1979-1990
(percent)
1979-1990 Average Annuel
Source Growth in Electricity D—nd
EPA1 3.0
Oete Reeourcee, Inc. 2.8
Energy Information Administration 3.2
Electric Power Research Institute 3.5
Edison Electric Inetltute 3.2-4.3
Electrical World 4.2
^Projection used in this study.
Source: EPA; Oats Resources, Inc., Energy Review, Winter 1980;
DOE, 1979 Annuel Report to Congress. Voluas III (prelimi-
nery); EPRI Planning Director, reported in Electrical
Week. April 20, 1981; Edison Electric Institute,
Econowic Growth in ths Future. Hay 1980; Electrical
World. Ssptsabsr 13, 1980.
Sensitivity analyses showing the effect of a change in
the growth rate are presented later in this chapter. The
modeling approach used assumes that growth in demand is not
sensitive to changing pricing conditions. The base forecast
is founded on an underlying set of assumptions with respect to
future electricity prices, demographic shifts, etc. This
study does not attempt to model the extent to which changes in
electricity prices (including those caused by pollution con-
trol expenditures) will affect consumer demands.
-------
VI-17
Capacity and Generation Profiles
The capacity and generation projections used in this
study are based on the requirements implicit in the electric-
ity demand estimates. Capacity represents the instantaneous
generation capability, measured in kw, of all plants in
service at a given point in time. Generation is the number of
kWh produced during a given period of time.. This section
presents forecast changes in capacity by fuel type and the
generation by fuel type required to satisfy future demand. As
was the case with the demand forecasts, these data are derived
primarily from information provided by EPA.
The mix of capacity by fuel type is important in estimat-
ing both future power costs and pollution control require-
ments. Figure VI-3 depicts that mix over the period 1980—
2010. Coal's contribution to total capacity is projected to
increase from 41 to 61 percent, while oil and gas units are
expected to decline from 29 to 6 percent of total capacity
Nuclear power is expected to contribute significantly to new
generation capacity, moving from 9 percent of total capacity
in 1979 to 15 percent in 2010. Many of the additions to
nuclear capacity occur in the post-1990 period, reflecting the
EPA assumption that many of the current regulatory and finan-
cial barriers to new nuclear plant construction will be over-
come. One of the sensitivity analyses presented later in this
chapter evaluates the effect of a complete moratorium on new
nuclear plants after 1989. Hydro and pumped storage capacity
additions are also expected to occur; however, their contribu-
tion to total capacity is expected to decline over the period
from 13 percent in 1980 to 9 percent in 2010. This reflects
the depletion of readily available sites for the construction
of such facilities. Coal and nuclear account for approxi-
mately 88 percent of all projected capacity additions over the
study period.
The specifics of the projected industry capacity expan-
sion plan are provided in Table VI-10. Additions and retire-
ments by fuel type and conversions from oil to coal contribute
to the changing capacity mix over time. Total capacity is
expected to increase at an average of 2.72 percent per year,
which is lower than the rate of growth in demand. However,
the rate, of growth in new, non-oil and gas capacity is
3.68 percent, which is substantially above the average demand
growth rate over the 25-year period of 3.00 percent. The
implication is that utilities are expected to move rapidly to
reduce their dependence on oil and natural gas.
-------
Figure VI —
3
DISTRIBUTION OF GENERATING CAPACITY BY FUEL TYPE
1900 2010
100%
IC/GT
Pumped Storage
Nuclear
Xv*vy*'vYi>V»>Y
1900 1985 1990 1995 2000 2005 2010
Some*: FwhhI rial* |>tovl>l»
-------
VI-19
Table VI-10
U.S. ELECTRIC UTILITY CAPACITY,1 AOOITIONS, RECONVERSIONS,
AW RETIREMENTS BY FUEL TYPE
1980-2010
(aegaaatta)
Puaped
Coal
Oil
Gaa
Nuclear
Hydro
Storeoe
IC/GT
Total
Capacity 1980
Additione
Raconveraione
Retireaenta
227,019
37,315
6,478
(2,427)
105 , 463
(6,851)
(2,787)
54,329
(1,446)
48,104
15,696
59.QB0
6,305
14,770
1,576
m
47,800
11,928
556,565
72,820
(373)
(6,660)
Capacity 198S
Additiona
Raconveraione
Retirements
268,385
41,429
12,482
(876)
95,825
••
(14,248)
(2,119)
52,883
(1,092)
63,800
27,884
65,3B5
2,330
16,346
583
59 , 728
3,882
622,352
76,108
(1,766)
(4,087)
C^acity 1990
Additiona
Retireaenta
321,420
61,015
(1,326)
79,458
(1,492)
51,791
(768)
91,684
23,371
67,715
8,656
16,929
2,164
63,610
692,607
95,208
(3,586)
Capacity 1995
Additiona
Retireaenta
381,109
114, 729
(11,393)
77,966
(6,282)
51,023
(4,267)
115,055
22,688
76,373
6,801
19,093
1,700
63,610
4,607
784,229
150,525
(23,942)
Capacity 2000
Additiona
Retireaenta
484,445
357 , 020
(74,807)
69,684
(30,472)
46,756
(15,698)
137,743
50,294
83,174
6,278
20,793
1,570
68,217
39,452
910,812
454,617
(120,977)
Capacity 2010
766,658
39,212
31,058
188,037
89,452
22,363
107,669
1,244,449
^Capacitiae ara for beginning of year.
e .t J.*. bv EPA: OOE, Statistic* of Privately Owned Utilities in the
°UrC#! un^l°rst!tea~1979; DOE, Wmtie* of Publicly 0»ned Utilitiea in the United Statee-1979.
m u, rrr 11 ^nirts the historical and forecast reserve
Table dJJ fors and load factors. The reserve mar-
margins, capacity fact between total capacity and
gin, a measure of the v^-her than both historical and pro-
peak demand, is current y |ilities attempt to maintain re-
jected levels. TyPiCPHyAn nercent to ensure system reliabil-
serve margins of un?ertainty and generator "downtime"
ity in _ the face of demand cJre»t excess reserve
for maintenance or forcea o y
-------
VI-20
margin situation is due to the industry's inability to fore-
cast the recent falloff in demand and the shifting of oil
prices. Because of ten-year (or more) construction lead
times, many units were and axe being completed because comple-
tion is economically preferable to stopping construction al-
ready under way. Also, the rise in oil and gas prices has re-
sulted in many units that are technically operational and are
therefore included in the industry's capacity figures, but
that are economically obsolete. Therefore, reserve margins
are expected to decline as oil and gas units are retired and
as demand catches up with existing capacity.
Table VI-U
SELECTED OEWM), ENERGY, AW CAPACITY STATISTICS
Total Electric Utility Industry
1960-1999
1960-1979
Capacity at
Noncoincident
Tina of Sumar
Suaaar Paak
Output
Reeerve
Capacity
Load
Paak Load
Load1
(kWh in
Margin
Factor
Factor
Year
USD
(MX)
¦dlliona)
(percent)
tomant)
(percent)
1966
240,700
203,350
1,152,900
18.4
54.7
64.7
1967
257,950
213,450
1,221,500
20.8
54.1
65.3
1963
278,950
238,000
1,327,200
17.2
54.2
63.5
1969
>00,300
257,650
1,446,000
16.6
55.0
64.1
1970
326,900
274,650
1,536,400
19.0
53.7
63.9
1971
353,250
292,100
1,617,100
20.9
52.3
68.2
1972
381,700
319,150
1,752 , 200
19.6
52.3
62.5
1973
415,500
343,900
1,868,800
20.8
51.3
62.0
1974
AM, 400
349,250
1,871,700
27.2
48.1
61.2
1975
479,300
356,800
1,919,500
34.3
45.7
61.4
1976
498,750
370,900
2,039,500
34.5
46.7
62.6
1977
516,000
396,350
2,13:,300
30.2
47.2
61.4
1978
545,700
408,050
2,218,700
33.7
46.4
62.1
1979
560,200
411,550
2,266,500
36.1
46.2
62.9
1905-
604,600
488,400
2,716,500
23.8
51.3
63.5
1990
675,400
566,200
3,149,200
19.3
53.2
63.5
1995
769,100
656,300
3,650,700
17.2
54.2
63.5
1999
865,300
738,700
4,108,900
17.1
54.2
63.5
iNoneoincid«nt «j«aer peak low! ia the ui of individual utility peak dananos. These
denends do not have to occur during the aama denand interval (a.g.. paak bay) but
throughout*tha'suomar^ °' ^ d~nd>
Sources
Ediaon Electric Inatitute, Statistical Yearbook th. rlr^riP ,Pt4M.v
Industry 1979; PT«(£l.etric Utilities)i ' metric
-------
VI-21
Capacity factors are a measure of the percentage of time
a unit is used. For many of the same reasons cited above,
capacity factors are expected to reverse their downward trend
and eventually reach levels approximating those that existed
prior to the 1973-1974 oil embargo. The data in Table VI-12
clearly indicate the increasing reliance on coal and nuclear
for the bulk of the country's generation needs. The relative-
ly low 1979 nuclear utilization factor reflects in part the
effects on the operations of numerous plants across the coun-
try of the nuclear plant mishap at Three Mile Island. Oil and
gas capacity utilization is expected to decline dramatically
because of continually rising fuel costs.
Coal
1979 58.0
1985 61.6
1990 61.5
1995 61.5
2000 60.9
2005 59.9
Teble VI-12
PROJECTED CAPACITY UTILIZATION
/"ACTORS BY FUEL TYPE
1979-2005
(percent)
Internal
Puaped
Combustion/
m
See
Nucleer
Hydro
Storeoe
Gee Turbine
47.0
57.0
59.8
52.0
52.0
6.9
42.3
42.3
70.8
48.2
48.2
6.6
41.4
41.4
71.2
48.0
48.0
7.5
36.7
36.7
71.3
47.8
47.8
7.6
28.6
28.6
71.4
46.3
46.3
5.0
24.0
24.0
71.6
45.6
45.6
5.0
Source: EPAj DOE, Gee Turbine Electric Plant Construction Coet *r>d
Annuel Production Expense*—1978: 00E, Uodste-Nucleer Power
Program Information end Pete. July/August, 1980 j DOE,
Hydroelectric Plsnt Construction Cost end Annuel Production
£xoeneee~197B; TBS/EPA Energy Dstebese.
The TBS analysis and Pita model distinguish between pub-
licly and privately owned electric utilities because of their
different financial and regulatory treatment. Therefore,
figure VT-4 provides the 1979 split of capacity by fuel type
between publicly and 'privately owned utilities. The major
difference is the much higher reliance—48 percent—on hydro
and pumped storage by publicly owned utilities, compared to
6 percent for privately owned systems. Privately owned
systems depend on fossil fuels for 77 percent of their total •
Opacity, while the same figure for publicly owned systems is
39 percent.
-------
VI-22
Figure VI—4
1979 GENERATING CAPACITY
BY FUEL TYPE AND OWNERSHIP CATEGORY
THOUSANDS
OF
MEGAWATTS
250
200
180
100
SO
!¦ A* fr<
li.nr.'
public
tt'lT-tt*
Coat
Oil
Om
»c/nc( Anmtol Production
Cost Factors
This section outlines the estimates used by TBS of the
capital costs of new plant, fuel costs, and nonfuel operation
and maintenance costs. These costs, combined vith projected
changes in the amount of utility plant, provide the informa-
tion necessary to estimate changes in the industry's financial
profile over time.
Unit construction costs of the electric utility industry
have increased significantly in the last decade and are pro-
jected to continue to escalate more rapidly than the general
rate of inflation. The causes of recent and projected con-
struction cost increases include inflation in the cost of
labor and materials, increases in the complexity of generating
units, licensing delays, slippage in construction schedules,
-------
VT-23
and the cost and difficulty of financing. The unit costs by
plant type assumed in this study are provided in Table VI-13,
both including and excluding allowances for funds used during
construction (AFDC) and pollution control costs. Both are
typically included in industry data. The costs reflect an in-
service date of 1979 and are based primarily on data from the
Technical Assessment Guide published by the Electric Power
Research Institute.
Table VI-13
NEW PLANT CONSTRUCTION COSTS1
BY FUEL TYPE
(1982 dollars par kilowatt)
Capital Cost Capital Coat
Including AFDC 2 and Excluding AFDC and
fuel Type Pollution Control Capital Coat Pollution Control Capital Coat
Coal3
Oil3
Gas3
Nuclear3
Hydro4
Pumped Storage3
Internal Combustion/
Gaa Turbine
Tranamiaaion and Distribution^
Nuclear Fuel6
Coal Conversion?
1,283
903
841
693
533
479
1,575
1,124
1,996
1,739
947
806
290
281
427
383
38
38
277
96
koats are reported for a 1979 in-service year expressed in 19S2 dollars.
2Aaau«es the allowance for funds used during construction (AFDC) rate of a percent for
data derived from EPRI, otherwiee the AFDC rate is based on the weighted coat of
capital.
3EPRI, Technical Aaaeaaaent Guide. July 1979. (Coats wars inflated from 1978 to 1979
dollars using the Handy Whitman Index.)
*6. 0. Marlor, S—11 Scale Hvdro Power: Economic and Flnencial Analysis. BSLES-ASCE
Hydro Iscture Series for 1980.
'DOE, Statistics of Privately Owned Utilities in the United Ststea—1979.
*D0E, Updste-Nuclesr Power Proorsa Informstion and Data. July/Auguet 1980.
7TBS estimate based upon review of utility coal conversion plana for unite identified
by DOE as candidates for required reconversions snd information provided by EPA.
Source: EPRI,
T»rhnie«l nt Guide, July 1979¦
-------
VX-24
The cost of new coal capacity has been estimated by £*£i-
ous sources at 51,025 to 51, 385 1 » "n9®T^'^co" of
the Si 283 oer lcW estimate used in this study. Tne cost or
lltlllzcapfcftyhas been estimated by other sources at be-
tween $1?3 85 and $1/449 per kW, a narrow range slightly above
the cost of §1,375 per lew used in thls will increase
ably the case that future nuclear capacity costs will increase
more rapidly than those for new coal capacity.
Fuel costs represent the largest component of total oper-
ation ^d maintenance costs. implct of
t-< costs over the period 1960-1980. Tne impact or.
the 1973-1974 Arab oil embargo is cl«a^ «Y;^lectric^tili-
the data also reflect the ongoing f o^^rily cotl
ties to shift from oil to lower-priced fuels, primarily coal.
Current expectations are that the growth in energy prices
will slow (or even decline in real terms) in the
However, over the entire forecast period energy prices are
expected to continue to escalate. Figure VI-6 shows price
projections for the major fossil fuels that are based on as-
sumptions provided by EPA. The EPA projection assumes that
the price of natural gas will rapidly converge on that of
high-sulfur residual oil since they are close substitutes; in
fact, in many applications natural gas is considered the su-
perior fuel. However, because of limitations on the use of
natural gas, the existence of price controls, and the current
surplus situation, the price of natural 9as is expected to be
roughly equivalent to that of su.lfu.r- resid.ua.1 oil during
the latter part of the forecast period (1985 and beyond). The
price of fossil fuels includes any premiumspaid for lower-
sulfur-content fuel. Finally, as is evident from the figure,
the price advantage of coal over other »£°
grow over time. As discussed in Chapter III, the price advan-
tage of coal—coupled with the regulatory inhibitions or pro-
hibitions to nuclear, oil, and gas capacity is the primary
^Electrical World, September 15, 1979, reports the costs, of
coal capacity in 1979 dollars at $766 per kW and nuclear at
$1,035 per kW in 1979 dollars, which translate in 1982 dol-
lars to $1,025 and $1,385, respectively. ICF, Inc., Alterna-
tive Strategies for Reducing Otilitv SO? and Emissions^
June 1981, reports capital costs (in 1979 dollars) or coal at
approximately $800 per kW, which excludes the cost of a
scrubber estimated at $165 per kW and nuclear at $1,083 per
kw and which translates to $1,272 per kW for coal plants and
$1,449 per kW for nuclear plants in 1982 dollars. Costs,
however, may reflect different in-service date, pollution
control, inflation rate, and AFDC rate assumptions.
-------
VI-25
1960
1961
1962
1963
1964
19®
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Figure VI—5
AVERAGE INDUSTRY FUEL COST PER NET KILOWATT-HOUR
TOTAL ELECTRIC UTILITY INDUSTRY
1960-1980
rrrn
¦20
X]
-28
.26
.26
.26
JT7
J1
JS
.41
.48
_B9
1.12
1.20
138
1.53
1.62
2.03
1 1 '
.1 2 2 A £ £ .7 £ 2 1.0 1.1 12 12 1.4 15 1.6 1.7 IB 1.9 2.0 2.1
CENTS PER KILOWATT-HOUR
Wo.: Editor Et«cTric Irwtitut., Satit.gl Y-rfaook of th« E>«cmc Utility Indugpi Imfctmi ymn\
-------
VI -2 6
Figure VI—6
PROJECTED FUEL PRICES
1979-2005
DOLLARS
PER
MILLION Btu $30
(CURRENT
DOLLARS)
/ , NATURAL GAS
I I
DISTILLATE OIL
RESIDUAL OIL
COAL
1979
1985 1990 1995 2000 2005 2010
NOTE: Prieaa indud* awrtgt sulfur premium*.
So urea: DOE/EIA Con & Qualify of Pu«l» for E)«ctric Utility P1»nt»—1979: DOE/EIA Con & Quality ol Fu»t» tor
E)»ctric Utility Plana—1980; raal growth ritM w»«ri provided by EPA, and prioat wrt inflrtM to nominal
dolltn using rh« TBS prot«ct«d GNP deflator.
-------
VI-27
reason that the majority of capacity additions are expected to
be fueled by coal. Appendix D explores issues of future coal
prices and quality and their impacts on utility operation and
construction decisions.
Given fossil fuel prices, total fuel costs can be derived
as the product of fuel prices, heat rates, and generation
requirements. Heat rates represent the amount of heat re-
quired to generate enough steam to produce 1 kWh of elec-
tricity. TBS assumed that the average heat rates (not includ-
ing energy penalty effects) for existing units would approxi-
mate actual 1979 levels and that all capacity additions would
be more efficient. The average heat rates in terms of Btu
required per kWh of production are presented in Table VI-14.
Table VI-14
AVERAGE HEAT RATES1
(Btu per kilowatt-
hour)
Unit Tvdb
Existing
Units
Capacity
Additions
Conventional Steam Electric
Units
Coal-F ired
Oil-F ired
Gas-F ired
10,000
10,077
10,593
9,700
9,600
9,200
Internal Caabuation/Csa Turbine
14,200
12,500
Reported heat rates do not reflect energy penalties
resulting froa pollution control equipment.
Sources TBS/EPA Energy Database; EPA.
The last area of costs to be reviewed is associated with
nonfuel operation and maintenance. These costs (Table VI-15)
are derived from the Statistics of Privately Owned Utilities
in the United States published by DOE. The costs labeled
"without pollution control" reflect the same information minus
those costs associated with pollution control equipment in
place as of 1979. The pollution control costs were derived
from the Energy Database developed by TBS. Fuel costs are
also shown in Table VI-15 on a mills'per kWh basis to provide
-------
71-28
a comparison of the relative costs by plant type. Sulfur
premiums are not included in the coal-and oil fuel prices;
both sets of fuel prices are for high-sulfur fuels.
Tsble VI-15
1979 OPERATION AND MAINTENANCE
EXPENSES BY FUEL TYPE:
NONTUEL AND FlQ. EXPENSES
(mills par kilowatt-hour in 1979 dollars)^
Nonfuel Expenaee
With
Without
Pollution
Pollution
Fusl Tyoe
Control
Control
Fuel Exoenaas^
Coal
2.57
1.90
11.25
Oil
2.57
2.17
22.07
Cae
2.57
2.30
18.54
Nuclear
6.77*
6.66*
4.01
Hydro
2.05
2.05
N/A
Pumped Storage
2.05
2.05
N/A
Internal Combustion/
Gas Turbine
9.25
9.25
57.08
Transmission, Distribu-
tion A Other Expenses
5.03
5.03
N/A
figures can be inflated to 1962 dollar* using the GNP in f la tor
projections in Table VI-17.
^Oofts not include coats aaaociated with ¦ sulfur preaiun or
antrqy penalty.
^Includes the coat of nuclear decomisaioning.
N/A s Not applicable.
Sautess DOE, Statistics of Privately Owned Utilities in the Unlfa»d
States—1979; DOE, Cost snd Quality of Fusls for Electric
Utility Plants—1979: TBS.
Financial and Accounting
Policies and Assumptions
This section briefly describes the assumptions and input
data concerning financial policies and costs employed in the
PTm projections. These financial assumptions are important
because of the electric utility industry's capital intensity,
the long lead time for construction of generating plants, the
high financing costs currently in force, and the prevailing
-------
VI-29
uncertainties regarding regulatory and tax treatment. The
section first describes the input data used to arrive at the
baseline projection and then presents selected financial as-
sumptions that drive the financial module of PTm.
While providing essentially the same service, the public
and private segments of the industry need to be treated sepa-
rately because they differ significantly in their financial
characteristics. In terms of generating capacity, generation,
direct costs of new capacity additions/ and operation and
maintenance costs, the publicly owned systems account for
approximately 22 percent of the U.S. total, while investor-
owned systems account for the remaining 78 percent. Because
the publicly owned systems have lower financing costs and tend
to have a high percentage of hydroelectric generation, they
account for only 12 percent of total operating revenues of the
industry, while investor-owned systems account for approxi-
mately 88 percent. In terms of total assets, the public and
private sectors hold about 10 percent and 90 percent shares,
respectively.
TBS assumed that the 1979 ownership structure of the
industry would be maintained throughout the projection period.
Moreover, because there is a paucity of readily available
information on the financial characteristics of those organi-
zations in the public sector, the private sector is modeled in
detail and serves as a basis for estimating certain character-
istics of the public sector. The percentage distributions
described above were used by TBS to extrapolate a total indus-
try beginning balance sheet and income statement from avail-
able data for the privately owned portion of the industry.
Changes to the publicly owned segment of the industry attrib-
utable to environmental regulations are modeled in the same
manner as for the privately owned segment but take into ac-
count the differences in fuel type between public and private
sectors.
A major input to the baseline financial projection is a
set of 1979 balance sheet items, drawn primarily from the
statistics of Privately Owned Utilities in the United States,
published by the Department of Energy (DOE). Table VI-16
indicates the data used, differentiated according to whether
or not pollution control equipment is included. The dif-
ference reflects the effect of pollution control expenditures
through 1979, which account for approximately $6.55 billion in
plant in-service and approximately $5.95 billion in CWI? for
the privately owned portion of the industry at the end of
1979.
-------
VI-30
Tabic
VI-16
U.S. PRIVATELY OWNED ELECTRIC UTILITIES:
ELECTRIC PUNT LONG-TERM ASSETS AND LIABILITIES
WITH AND WITHOUT POLLUTION CONTROL EOJIPfCNT-1
AS OT DECE«ER 31, 1979
(millions of 1979 dollars)2
Lono-Tern Assets Accounts
With Pollution
Control Eouionent
Without Pollution
Control EauiD»ent
Gross Plant In-Service
- Acorn. Depreciation
182,514
47,606
175,966
46,298
Nat Plant In-Service
+ Nuclaar Fuel (Net)
* Construction Work in Progreas
134,906
3,715
53,991
129,668
3,715
48,044
Nat Electric Plant
192,612
181,427
Lono-Tarn Liability Accounts
Long-Tarn Oabt
Preferred Stock
Owners Equity
90,499
22,284
67,741
88,365
21,758
66,144
Total Capitalization
180,'524
176,267
Deferred I tana
Defarrad Investment Tax Credit
13,170
6,318
12,859
6,169
Total Lcng-Tara Liabilities
200,012
195,295
^•Includes pollution control equipment installed ss of Oecenber 31, 1979.
figures can ba inflated to 1982 dollare uaing GNP inflator projections in
Teble VI-17.
Source; 00E. Statietice of Privmtmlv Owned Utilitiee in the United States—
1979; TBS/EPA Energy Database.
The projections used in this study presume a continuation
of different rates of inflation for the various cost compo-
nents. Those rates are provided in Table VI-17 and are de-
rived primarily from information provided in Data Resources,
Inc.'s P.S. Long-Term Review (Fall 1981). Note that the rates
-------
VI-31
Table VI-17
PROJECTED INFLATION RATES
1979-2007
Annual Utility Construction Coat Inflation Ratea
Annual GNP
Pollution Control
Nuclear Fuel^
Year
Inflation Rate^
Utility Plant Eouionent
1979
8.5*
9.7* 6.5*
18.5
1980
9.0*
9.8* 6.5*
19.1
1981
8.7
U.l 7.3
19.9
1982
8.2
9.7 7.2
19.7
1983
8.5
10.9 7.7
19.3
1984
9.1
12.5 7.9
19.2
1985
10.0
13.5 9.1
19.4
1986
9.5
11.8 9.0
12.9
1987
8.9
9.7 8.7
12.2
1988
8.1
8.8 7.7
U.6
1989
8.1
10.9 7.3
12.0
1990
8.5
11.9 7.5
12.3
1991
8.A
10.7 7.6
9.5
1992
8.0
8.6 7.2
8.9
1993
7.4
8.4 6.5
8.4
1994
7.9
10.4 6.5
8.8
1995
8.0
10.2 6.7
8.8
1996
7.9
8.9 6.8
10.2
1997
7.3
7.8 6.4
9.7
1998
7.6
9.4 6.3
9.9
1999
7.6
9.4 6.2
9.9
2000
7.4
8.3 6.3
9.7
2001
6.9
7.1 6.0
7.7
2002
7.2
8.6 5.8
7.9
2003
7.3
8.5 5.0
7.8
2004
7.0
7.A 5.9
7.7
2005
6.4
5.8 5.7
7.8
2006
6.5
5.8 5.8
7.8
2007
6.6
5.8 5.8
7.8
l{j»#d for nonfuel and pollution control operation and aaintenanca expenaee.
2foracaata of nuclaar fuel price eacalation ratea have been reduced eub-
atantially ainca thia forecaat was prepared.
•Actual.
Sources Data Raaourcea, Inc., U.S. Long Term Review. Fall 1981; Handy
Whitman Index of Public Utility Canatruction Coata projected
by TBS uaing data provided by Data Reeoureee, Inc.; DOE,
Preliminary 1985. 1990. 1995 Enerov Forecaat for Annual Report
to Conoreaa. 1980; DOE, Analvaia of U.S. Nuclfr Pot
Production Coeta for 1979.
-------
VI-32
of inflation applied to utility plant capital costs are above
the rate of growth in GNP. Pollution control capital costs
are assumed to rise more slowly than the general inflation
rate, primarily because of technology change and greater
operating experience. If the rate of increase in pollution
control capital costs is closer to or above the rate of growth
in GNP, the relative effect of pollution control equipment
cost will be increased. Since pollution control expenditures
represent a greater portion of total plant additions in the
early periods, an increase in the general rate of inflation
would increase the relative effect of pollution control plant
additions.
PTm uses a number of financial indicators, ratios, and
percentages in making projections. Table VI-18 provides data
on 1979 actual returns and projected returns on various forms
of capital. With regard to the cost of equity, TBS assumed
that regulators will in the future allow average consumer
charges per JcWh that yield returns consistent with investors
required rates.of return. As discussed in Chapter III, this
has not been true in the last decade. However, recent indi-
cations are that regulatory agencies are beginning to adjust
allowed returns upward in response to the industry's manifest
financial difficulties. The input data reflect this assunqp-
tion. If returns do not increase relative to underlying rates
of inflation, the industry is likely to be unwilling or unable
to meet its projected external financing needs. Under such
conditions, both pollution control-related and. other expendi-
tures for plant in-service will be reduced.
In projecting external financing, the model relies on
inputs indicating the appropriate proportions of common
equity, preferred stock, and long-term debt. Those propor-
tions have been set for future periods at 40, 10, and 50 per-
cent, respectively.
Internal cash generation in an industry as capital-inten-
sive as the electric utility industry depends importantly upon
the accounting procedures employed. As previously mentioned,
this analysis assumes that the electric utility industry is
segmented into public- and investor-owned firms. The latter
group of utilities is further divided into those that are
required to use flow-through accounting procedures and those
that normalize their tax expenses. While alternative regula-
tory accounting practices significantly affect reported ex-
penses and revenue requirements, they typically do not affect
actual taxes paid.
The tax expense used by regulators in setting rates for
consumers is not necessarily the same as the taxes paid by a
utility. Utilities have the option, as do most companies, of
-------
VI-33
Table VI-
18
FINANCIAL ASSUMPTIONS
(percent)
Caoital Costs
1979
1985
1990
1995
Interest Rats, Long-Tarn Debt
7.6
12.6
11.3
10.3
Return on Equity
11.2
15.6
14.3
13.3
Dividend Payout Ratio
75.0
75.0
75.0
75.0
Dividend Rate, Preferred Stock
8.0
12.6
11.3
10.3
Caoital Mix
Pifalic Sector
Financing from Internal Sources
40.0
40.0
40.0
40.0
Private Sector
Common Equity
37.5
40.0
40.0
40.0
Preferred Stock
12.4
10.0
10.0
10.0
Long-Term Debt
50.1
50.0
50.0
50.0
Tax Rates
Federal Income Tax
46.0
46.0
46.0
46.0
State Income Tax
4.6
4.6
4.6
4.6
Other Taxes on Operating
Revenues
7.6
7.6
7.6
7.6
Investment Tax Credit
10.0
10.0
10.0
10.0
Plant Eligible for Investment
Tax Credit
66.6
66.6
66.6
66.6
Source: DOE. Statistics of Privetelv Owned Utilities in
the
United States—1979: TBS.
using either accelerated depreciation or straight-line depre-
ciation in determining their tax liability. Over the life of
an asset, the sane taxes are paid regardless of which method
is used. Most firms use accelerated depreciation, however,
because it tends to postpone tax payments. When a utility
uses accelerated depreciation to determine its tax expense and
its consumers are charged for a tax expense based on straight-
line depreciation, the tax benefits of accelerated depreci-
ation are said to be "normalized." If, on the other hand,
rates for consumers are based on the tax expense actually
incurred by the utility, the tax benefits of accelerated de-
preciation are said to be "flowed through" to current con-
sumers .
-------
VI-34
In normalized accounting, consumer rates include an
amount equal to the tax rate times the difference between
accelerated tax depreciation and straight-line tax deprecia-
tion. This amount is referred to as deferred income taxes
and, like depreciation, represents a non-cash expense for the
utility. In the early years of an asset's life when the de-
ferred income taxes associated with the asset are positive,
deferred income taxes represent, in a sense, an interest-free
source of funds to the company. In the later years when the
income tax deferrals associated with that asset are negative
and, hence, represent a credit against the cost of service,
the company in effect liquidates the funds provided by tax
deferrals in the early years. However, on a companywide
basis, the normalization process will always result in posi-
tive deferred income taxes during periods when a utility has
increasing or constant growth in assets.
The rates of return in Table 71-18 represent the weighted
average returns required by investors for various forms of
capital in normalizing and flow-through utilities. In the
model, however, those companies are treated separately, in
the detailed analysis, it is assumed that required returns for
the normalized sector average 0.5 percentage points below the
returns required by investors in flow-through companies, re-
flecting observed capital marJcet differences in those compa-
nies' debt and equity capital costs.
TBS's projections assume a continuation of the industry's
current regulatory accounting practices. In particular, it is
assumed that 30 percent of the investor-owned utilities will
continue to utilize flow-through accounting, while 70 percent
will use normalized accounting. For regulatory and financial
accounting purposes, TBS assumes straight-line depreciation
over the life of the plant. For tax purposes, depreciation
figures are based on the asset depreciation range and the
double-declining balance depreciation provisions within the
tax code. An exception to the above is nuclear fuel, which is
depreciated on a four-year, straight-line basis for both tax
and regulatory purposes. In addition, a 10 percent investment
tax credit is permitted on 66 percent of capitalized expendi-
tures. These assumptions and the other tax rates are speci-
fied in Table VI-18. The financial assumptions do not reflect
recent changes in the tax code that allow for more rapid
depreciation of most classes of equipment.
The final area to be reviewed in this section is the
timing of construction expenditures for a given capital proj-
ect. This information is used to calculate CWIP and APDC and
is provided in Table Vl-19.
-------
VI-35
Table YI-19
PATTERN OF CASH FLOWS FOR CAPITAL PROJECTS!
ANNUAL EXPENDITURES OF FUNOS (EXCLUDING AFDC)1
FOR YEARS PRIOR TO AND INCLUDING THE IN-SERVICE TEAR
(percent per yes)
T
T-6
In-Service
Capital Prolect.
T-5
T-4
T-3
T-2
T-l
Year
Fossil Steaa Plants
4.0
1.1
7.2
28.8
41.9
15.0
2.0
Nuclear Planta
15.0
20.0
25.0
15.0
15.0
9.0
1.0
Nuclear Fuel
-
-
-
.
25.0
25.0
50.0
Hydro Plant*
9.9
13.5
17.9
18.9
23.9
11.6
4.3
Puoped Storage Plants
9.9
13.5
17.9
18.9
23.9
11.6
4.3
Internal Coabuation/Gaa Turbine
P lants
-
-
5.0
5.0
8.7
59.0
22.3
Transaisaion and Distribution
-
-
-
-
50.0
50.0
Pollution Control Cepital Equipment
-
-
-
10.0
30.0
40.0
20.0
P!t8ntt!l C0°'trUCtr P"10* t0 y«r». However, .light adjuet-ent.
Mre «ede to produce the eppropnete Mount. of constructs work in progress (CWV>) ,nd
¦1lo*ance for fund. u«ed durxng construction (AFDC) over the ter. of theproject where lead
tiflwe we expected to exceed sever years.
Sources TBS eetiwatee baeed on the examination of repreaentative utility coapany expendituree.
baseline financial profile
The baseline financial projections reflect the effect of
the numerous assumptions described earlier and represent a
most likely scenario of the future of the electric utility
industry in the absence of any pollution control costs. Be-
cause this chapter's focus is on the effects of pollution
control strategies being implemented in the post-1979 period,
the capital and nonfuel operation and maintenance expenses
associated with pollution control equipment in place by i979
are, for the purpose of this analysis, treated essentially as
fixed or irreversible costs. In fact/ of course, the energy
penalties and nonfuel operation and maintenance expenses of
such equipment would be reduced, if not necessarily eliminated
entirely, if it were not utilized. Moreover, that portion of
capital costs associated with capacity penalties is also
largely reversible.
-------
VI-36
Sales growth rates and levels of capacity are particu-
larly critical assumptions. As discussed previously, TBS has
used an annual growth rate in sales of 3.0 percent for the
entire forecast period. These rates are well below the growth
rates of the decade prior to 1974 and the Arab oil embargo.
The capacity additions projected for the next ten years re-
flect the industry's effort to reduce its dependence on oil
through new coal and nuclear capacity additions. Capacity
additions that replace oil are expected to continue despite
the current excess capacity situation. However, because of
cancellations and postponements of new capacity in response to
declining growth rates and financial constraints, the indus-
try's generating capacity is projected to grow more slowly
than demand through 2000.
To capture the major financial implications of alterna-
tive sets of assumptions, TBS developed statistics for the
following categories: changes in plant in-service, external
financing, operating revenues, operation and maintenance ex-
penses, and average consumer charges. Table VX-20 and the
discussion below summarize these financial projections. £x-
hibits VI-1 through VI-7, at the end of this chapter, provide
financial and operating data for specific years in greater
detail.
Baseline Projections
Changes in Plant In-Service are defined to be total cash
outlays for plant construction during a year (both for plant
that goes into service by year-end and that remains in the
construction work in progress [CWIP] account), plus AFDC (the
carrying charges on the.past cash outlays still in CWIP),
minus the year-to-year change in the cash amounts in CWIP.
This definition corresponds closely to what many studies refer
to as "capitalized expenditures." For a more complete discus-
sion of the accounting methods used and the relationship be-
tween the various construction-related accounts, refer to
Appendix C.
The baseline projections through 1999 indicate that
changes in plant in-service will total $1,041.5 billion in
constant 1982 dollars. In addition, cumulative cash outlays
still in the CWIP account will increase from $60.9 billion at
the end of 1979 to $191.0 billion at the end of 1999, an in-
crease of 3.9 percent per year. The changes in the CWI?
account are not included in the changes in plant in-service
reported in this study. Thus, total cash outlays and the
associated construction carrying costs for plant equipment
during the next two decades will be $1,171.6 billion, or the
sum of plant additions and the change in the CWIP account.
-------
VI-37
Table VI-20
SUMMARY OF BASELINE FINANCIAL PROJECTIONS:
BASE CASE SCENARIO
(billions of 1982 dollars)
Changes in Plant In-Service1 1980 1985 1990 1999
Total for Year 28.50 40.75 51.12 B7.36
Total since 1979 28.50 199.17 419.47 1,041.49
External Financing
Total for Yaar 10.52 31.44 38.35 82.10
Total since 1979 10.52 151.78 327.35 857.63
Operating Revenues
Total for Year 91.13 109.64 134.46 191.26
Total since 1979 91.13 594.05 1,214.87 2,684.23
Operation and Maintenance Expenses^
Total for Year 64.53 71.18 83.31 109.90
Total since 1979 64.53 404.28 794.50 1,671.88
Consumer Charges (mills/WWh)
Average for Year 42.73 44.35 46.92 51.14
^Excludes changes in construction work in progress.
^Excludes nuclear fuel.
Source: PTm(Electric Utilities).
External Financing requirements are the sum of long-term
debt, preferred stock, and common stock issues in any given
year, including the refinancing of maturing long-term debt.
The baseline capital market requirements. during the next -, dec-
ade are expected to total $857.6 billion in constant 1982
dollars—approximately 82 percent of plant additions during
the same period. The remaining funds required to finance the
industry's expenditures for additions to plant in-service and
to CWIP will be generated internally in the form of retained
earnings, depreciation, and tax deferrals. If utilities are
-------
VI-38
unable to earn the specified returns on equity, external fi-
nancing requirements will be even higher (due to lower re-
tained earnings) and the industry's attractiveness to poten-
tial suppliers of capital will be lower. The resulting deter-
ioration in the industry's financial condition would make it
increasingly difficult and costly to secure external financ-
ing.
One of the key financial measures which bond investors
use to assess their risk exposure is pretax interest coverage.
Pretax interest coverages are projected to average about 2.9
times, which is at or above the industry's recent levels.
Although no significant change in pretax interest coverage is
projected,.it should be noted that the projected coverage
ratios are highly dependent on the assumed earned return on
equity, which is higher than the industry has achieved in
recent years. If earnings fall short of projected levels,
equity will be harder to raise and debt will be more expensive
and less available than projected. Utilities which currently
have low bond ratings would be particularly vulnerable to the
adverse effects of lower earnings and could find it impossible
to raise all of their capital needs at acceptable rates.
Operating Revenues or revenue requirements represent the
total amount of money paid by utility customers for electric-
ity in a given period. To put it another way, operating
revenues are the amount required by the utilities to cover
fuel, other operating, and capital-related costs. This repre-
sents perhaps the best single statistic for measuring the
total effects of pollution control regulations. The baseline
projections for total utility operating revenues are
$2,684.2 billion in the 1980-1999 period.
Operation and Maintenance Expenses consist of all the
direct costs of the operation of the electric utilities, in-
cluding both fuel- and nonfuel-related expenses. Fuel repre-
sents the largest single component of these costs. One result
of the rapid escalation in fuel prices since 1974 has been to
increase the fuel-related share of operation and maintenance
expenses to approximately 62 percent in 1979 from 50 percent
prior to 1974. The TBS projection is that total baseline
operation and maintenance expenses will amount to
$1,671.9 billion through 1999.
Average Consumer Charges are obtained by dividing operat-
ing revenues by total sales to utility customers. Thus, this
measure represents the average cost of electrical energy per
-------
VI-39
)cWh. This average charge is projected to increase in real
terms from 42.7 mills per kWh in 1980 to 51.2 mills per kWh in
1999, a 0.6 percent compound rate of growth.
The cost of pollution controls will be measured against
this base of financial results. However, before discussing
those costs, it is helpful to consider briefly the financial
results based on two alternative projections of additions to
capacity and sales growth. They are included, in part, to
illustrate how sensitive the financial indicators are to
changes in the operating projections.
alternative Scenarios
As previously discussed, the capacity expansion plan used
in this study contains a significant amount of nuclear capac-
ity additions in the post-1990 period. However, the future of
nuclear power beyond the completion of currently planned fa-
cilities is quite uncertain given the rapidly escalating cap-
ital costs of nuclear plants; increasing reluctance of the
investment community to support companies with nuclear con-
struction programs; increasingly complex regulatory control;
and heightened public resistance following Three Mile Island.
Therefore, one of the alternative projections to be evaluated
assumes no new nuclear capacity is placed in service after
1989, with coal replacing that required capacity.
The second alternative projection is based on a change in
the rate of growth of electricity demand. The previous sec-
tions indicated that the study forecast was well within the
range of industry projections, but that many industry analysts
have consistently overestimated demand in the past five years.
Therefore, a 2.0 percent growth rate in demand is assumed for
the entire period in lieu of the study projection of 3.0 per-
cent. None of the alternative scenarios or pollution control-
related cost analyses presented in this study considers chang-
es in demand in response to changes in relative prices.
The baseline financial forecasts of the two alternative
scenarios are summarized in Tables VI-21 and VI-22. The com-
parison of plant additions, presented earlier in Figure VI-1,
indicated that the 2.0 percent growth rate assumption substan-
tially reduced the total baseline estimates. The cumulative
change in plant in-service through 1999 exceeds $439 billion.
External financing requirements for this scenario are negative
-------
VI-40
in the first year as PTm adjusts to a substantially lower
growth rate assumption. T3S assumed an instantaneous change
in the capacity expansion profile? however the 1979 balance
sheet reflects construction in progress. In fact, that con-
struction would not be cancelled as rapidly as assumed for
this scenario, which would smooth the trend in external fi-
nancing requirements. The 2 percent growth rate scenario
results in lower revenue requirements throughout the forecast
period when compared to the base case scenario.
Table VI-21
SUMMARY OF BASEIIIC FINANCIAL PROJECTIONS:
2 PERCENT GROWTH RAJE SCENARIO
(billi
ons of 1982 dollars)
Chanoes in Plant In-Service1
1980
1985
1990
1999
Total for Year
Total ainee 1979
18.82
18.82
22.69
118.76
28.60
242.02
46.30
601.96
External Financing
Total for Year
Total since 1979
(17.69)
(17.69)
15.87
53.33
21.06
146.92
24.24
409.08
Qoeratino Revenues
Total for Year
Total since 1979
Operation and Maintenance Expenses2
91.42
91.42
101.14
577.83
111.96
1,112.64
148.99
2,268.03
Total for Year
Total sines 1979
64.07
64.07
67.90
393.29
76.78
757.97
93.26
1,530.89
Consumer Charoea (mills/kWh)
Average for Year
43.29
43.38
43.49
48.43
Excludes changes in construction work
^Excludes nuclear fuel.
in progress.
Source: PTm(Electric "Utilities).
-------
VI-41
Table VI-22
SI>WARY OF BASELINE FINANCIAL PROJECTIONS:
NO POST-1989 NUCLEAR SCENARIO
(billions or 1982 dollars)
rhanoes in Plant In-Service1 1980 1985 1990 1999
Total for Year 28.50 40.12 45.69 81.51
Total since 1979 28.50 198.41 403.87 977.71
r«ternal Financing
Total for Year 10.52 28.14 33.10 77.32
Total since 1979 10.52 147.24 297.32 785.83
fine rati no Revenues
Total for Year 91.13 109.99 135.46 188.03
Total since 1979 91.13 594.45 1,220.99 2,672.56
feneration and Maintenance Expensed
Total for Year 64.53 71.18 83*64 113.72
Total since 1979 64.53 404.28 794.83 1,691.93
Consumer Charges (mills/kWh)
Average for Year 42.73 44.49 47.27 50.31
^Excludes changes in construction work in progress.
^Excludes nuclear fuel*
Source: PTm(Eleetric Utilities).
A prohibition on new nuclear plants after 1990 also re-
duces future plant in-service, by approximately $63 billion
through 1999/ because coal plants require a much greater pro-
portion of the total capital cost in the form of pollution
controls (costs which are not included in the baseline).
The reduction in plant additions in 1985 relative to the base
case scenario is an artifact of the PTm methodology for com-
puting plant in-service. It reflects the shorter lead times
and lower CWIP balances and, therefore, the lower capital-
carrying charges associated with coal plants relative to nu-
clear plant carrying charges. In the case of the prohibition
on new*nuclear plants after 1989, the baseline operating re-
venue requirements are slighty less than in the base case
-------
VI-42
scenario. However, these costs do not include pollution con-
trol equipment costs associated with the replacement coal
capacity.
UNIT POLLUTION CONTROL COSTS
This section outlines the unit costs and rates of imple-
mentation associated with the various pollution control regu-
lations. As discussed in Chapter II, the regulations vary
across a number of dimensions including: federal, state, and
local government requirements; the medium (air, water, or
solid waste) being regulated; the timing of pollution control
expenditures; and the requirements linked to a particular
unit's in-service date. The discussion below details the cost
and implementation assumptions, categorized according to the
following unit in-service dates:
• Units existing as of December 31, 1979,
• Units reconverted from oil to coal during the
period 1980-1990,
• Units coming into service during the period
1980-1984, and
• Units coming into service after 1984.
Within each of these categories, pollution control costs are
presented by medium and time of implementation. No attempt is
made to determine the relative effect of federal versus state
and local requirements.
Units Existing as of December 31, 1979
Pollution control costs are associated with equipment
existing as of 1979 for continuing capital-related charges and
operating expenses and with pollution equipment retro-
fits on plants placed into service as of 1979. The capital-
related and operation and maintenance expenses (including fuel
premiums) associated with pollution control equipment in place
in 1979 are reported separately from the baseline financial
projection—as pre-1980 pollution controls. Information in
the Energy Database indicates that the pollution control cap-
ital expenditures for existing units averaged a total of 518
per lew over the period 1972-1979. Capital-related charges for
-------
VX-43
these expenditures will continue after 19 79. Continuing pol-
lution control operation and maintenance expenses, other than
fuel, average 0.67 mills per kWh of generation by fossil-steam
plants, in addition, 72 percent of coal capacity incurs a
low-sulfur fuel premium of 2.7 mills per kWh and all oil-fired
units incur an average low-sulfur premium of 9.8 mills per
kWh. Energy penalties associated with pollution control
equipment average 0.23 mills per kWh and are incurred by all
fossil-fired capacity constructed before 1980.
In addition to the continuing costs described above, a
number of existing units will incur additional costs in the
future to bring plants into compliance with air pollution
control regulations. The retrofit costs described here are
not included in the pre-1980 pollution control costs, but are
included in the incremental pollution control costs. As shown
in Table VT-23, utility Form 67 submittals indicate that
6 percent of coal capacity will retrofit scrubbers at a cost
assumed to be $167.12 per kW.2 Eight percent of coal capacity
existing as of December 1979 will retrofit more efficient TSP
control systems at a cos-t of $73.90 per kW. Units retrofit-
ting SO2 and TSP control systems will also incur additional
solid waste disposal costs. These costs are estimated to be
1.16 and 0.64 mills per kWh, respectively, for operating
costs, and $20.86 and $5.35 per kW, respectively, for capital
costs.
Onits Reconverted From-Qj-l-±a-Coal—
During the Period 1980-1990
A number of units that were converted from coal to oil in
the late 1960s or early 1970s have incurred and will incur
costs attributable to pollution control regulations. In many
cases, units were originally converted to oil in the early
1970s as a means of complying with air pollution control regu-
lations. In other cases, however, such actions occurred sole-
ly for economic reasons, e.g., because of low oil prices, the
convenience of oil, or a desire for flexibility. Because
economic and environmental influences could not be partitioned
satisfactorily/ two categories of costs, attributable in part
to pollution controls, were not included in this analysis.
First, none of the costs of converting plants from coal to oil
^insufficient data were available in the Energy Database to^
determine retrofit scrubber costs * Consequently these costs
were determined by applying a 1.3 retrofit factor to reported
scrubber costs at new units.
-------
VI-44
Table Vl-ZJ
incremental pollution control costs for units
EXISTING IN 1979 ANO 1980-1990 RECONVERSIONS
(1982 dollars)
Type of
Pollution Control
Scrubber*1
TSP Control
Scrubber Waste Disposal
TSP Waste Control
Low-Sulfur Fuel
Premium
Coal
Oil
Gas
Thermal Control
Chemical Control
Capital
(dollars
per WW)
167.12
73.90
20:86
5.35
0
0
N/A
N/A
O&M
(milla/kWh)
2.83
N/A2
1.16
0.64
2.74*
9.773
0
N/A.
N/A
Energy Penalty
(percent of
oeneretion)
3.9
0
0
N/A
N/A
Affected_Planti»
6S of 1979 existing coal capacity
(45.5S of reconversions)
8% of 1979 existing coal capacity
(ail reconversions)
Ssme as scrU»bers
Ssme es TSP Control
725 of 1979 exinting coal cspscity
plus 54.5% of reconversions
All oil capacity
In addition to the scrubber capital cost, a capacity penalty of 3 percent is incurred by units with
serubbers.
Included as TSP waste disposal.
Weighted average for all plants from the unit level analysis.
n/a s Not applicsble.
Source: TBS/EPA Energy Oatabass.
in the past, or of reconverting back to coal are included as
pollution control costs. Second, none of the costs of oil
consumption in plants that/ in the absence of environmental
regulations, would have burned coal are captured in this
study's definition of pollution control costs.
Regarding conversion and reconversion costs, one industry
study sponsored by Edison Electric Institute (SEX) assumed
that approximately 37,000 megawatts (MW) of the capacity th*t
once burned (or has the capacity to burn) coal converted to
-------
VI-45
oil because of environmental regulations. EPA agrees that
conversions, at least during the 1970s, occurred in part be-
cause of environmental regulations. Circumstantial evidence
supporting that opinion can be cited; a DOE profile of recon-
version candidates showed that conversions to oil took place
largely during the late 1960s and early 1970s, at the same
time that states and the federal government were moving toward
greater stringency in emissions allowances. For example, of
76 candidates for reconversion, 45—nearly 60 percent—con-
verted between 1969 and 1972. ,
To assess the importance of economic factors, one would
also need comparisons of the delivered costs and the operation
and maintenance expenses associated with the high-sulfur coal
and high-sulfur oil that utilities would have been using as a
basis for decision making in the absence of environmental
regulations. Given the drastic change in oil prices at the
end of 1973, it can safely be assumed that most of the 1974-
1980 coal-to-oil conversions were dictated by environmental
concerns. However, many of the pre-1974 conversions may have
occurred for purely economic reasons. In sum, it remains
unclear what portion of the costs associated with coal-to-oil
conversions and reconversions is attributable to federal (or
state) environmental regulations. Thus, even for the 19,000
MW of capacity that EPA assumes will reconvert to coal, it is
unclear what portion of the reconversion costs are attribut-
able to environmental regulations.
In addition to conversion and reconversion costs, a num-
ber of units in this time period were constructed with multi-
fuel capabilities. This design feature is, in part, a re-
sponse to environmental regulations and provides the utility
with the flexibility to adapt to changing regulations and
pollution control technologies. A portion of these incre-
mental costs of attaining this flexibility should be attrib-
uted to pollution control regulations. This study does not
include such costs in the total costs attributable to pollu-
tion control regulations.
The industry study further argued that, in addition to
the 19,000 MW that EPA assumes will reconvert, all (or most)
of the remaining 18,000 MW would already have converted (or
would convert) back to coal if there were no environmental
regulations. Accordingly, the EEI study contends that it is
environmental requirements that dictate continued oil burning
in 18,000 MW of capacity. Again, there is circumstantial
evidence in support of this assertion.
The DOE profile cited above also contains data provided
by utilities regarding environmental and other impediments to
reconversion:
-------
VI -46
Number of
Reconversion Constraints Stations^-
Lack of trained personnel 6
Lack of low-sulfur coal supply 1
Space constraints for coal and
ash storage 20
Lack of coal-handling equipment 9
Requirement for crane, crusher,
pulverizer, etc. 5
Requirement for desulfuri2ation
equipment 9
Lack of emissions waivers 5
Requirement for wastewater treatment 2
Lack of ash disposal site 8
Noise abatement rules 2
Unspecified environmental issues 8
Financial constraints 5
^Many stations indicated more than one constraint.
This list contains a number of non-environmental impediments
that may be decisive for a substantial portion of the total
universe of coal reconversion candidates. Thus, even assuming
that all the original coal-to-oil conversions were for envi-
ronmental reasons, one cannot assume that all the costs asso-
ciated with the continued burning of oil are attributable to
environmental regulations. The sulfur premiums associated
with the continued burning of low-sulfur oil--which costs
are included in this EPA final report—are, of course, es-
sentially all attributable to state or federal environmental
regulations.
In determining the costs of environmental compliance, the
industry study included in its baseline as coal-fired capacity
10,400 MW that was actually built as oil rather than coal
and 37,000 MW of converted coal-capable oil-fired capacity
that may not have converted to oil in the absence of environ-
mental regulations. Environmental compliance costs were then
computed at those units as the difference between coal-fired
generation without environmental controls and oil-fired gen-
eration with environmental controls.
EPA's analytical approach was different. Because of the
uncertainties in alternative assumptions such as baseline fuel
costs, compliance oil costs, capacity utilization, and the
type and timing of new capacity additions, EPA induced the
47,400 MW of existing oil-fired capacity in the PTm(Electric
Utilities) baseline and calculated compliance costs as the
-------
VI-41
increase over baseline oil-fired generation costs caused by
environmental regulations. Those costs are dominated by th^
premium for low-sulfur oil. In this analysis it accounts for
approximately 90 percent of the 1980 costs of compliance for
oil units and is projected to increase. However, this ap-
proach produces impacts that are smaller than an approach
that assumes that some or all of those units would be coal-
fired in the absence of regulations.
The differences between the EPA and the industry ap-
proaches are substantial. Presuming no switch in fuel type,
compliance costs of units complying with pollution control
regulation are approximately 20 percent and 15 percent, re-
spectively, above baseline generation costs. However, the
cost of operating a complying oil-fired unit is estimated to
be about 8S percent more than operating a noncomplving coal-
fired unit.
It is difficult to establish an approach that correctly
captures environmentally related costs of constructing, con-
verting, or reconverting utility units. Many studies have
adopted a subjective approach to the attribution of costs that
overlooks the real economic pressures for building oil-fired
units, for converting coal units to oil, or. for not reconvert-
ing to coal. On the other hand, the EPA approach used in this
study certainly fails to capture all the costs associated with
environmental compliance. Figure VI-7 demonstrates the many
issues and decision points associated with allocating genera-
tion capacity decisions to environmental or economic reasons.
The decision tree in Figure VI-7 begins with the decision
to add oil-fired generating capacity. These capacity addi-
tions were either new oil-fired units or units converted from
coal to oil. For each category, the decision to add oil-fired
capacity can be classified as a decision driven by either
environmental or economic reasons. In each case there are
environmental costs associated with the capacity additions;
however, the magnitude of costs varies greatly.
With the dramatic changes in fuel prices in the 1970s,
utilities were then confronted with the decision of whether to
convert these oil-fired units or to reconvert them to coal.
The attribution of the cost differentials between oil- and
coal-fired units, the costs of conversions and reconversions,
and the costs of pollution control equipment to pollution
control regulations depends on the original reason for adding
the oil-fired unit and the subsequent reason for either con-
verting (or reconverting) to coal or continuing to burn oil.
Two end-points of the decision tree, labeled "A" and "B", have
-------
figure VI-)
Nw oil
(*,000)
Declelen te
odd ell-fired
capacity
Mill Ml ION IT I HE COSIS OF INTMASTD Oil CONaiirilON,
CONVCRSION ro OIL, MO KCOHtlHSIO* 10 COM SINtt l»ti
10 ECONOMIC OH CMVIMNtCNfM. OCCISION
(nulwra in perentheeee Indicate CCI'a oetlaated capacity In aogeuettel)
a
tnvl ronaental
(10,400)
tea eon for
new all capacity
addition
¦facialon
Cenverelen ta all
fro* eaal
(17,000)
\
Reeeon far
converelen
¦tec l«ion
Cconaale^
(14,000)
Declelen ta
(10,400)
Doc!¦lan to
convert to coal
Cnvirenaentel
(n.ooo)
Declelen to
reconvert to
Vee
(•i
No
(14,000)
Veo
(14,000) e~
(21,000)
tee eon for
decision to
continue to
burn ell
(•aeon for
dacleton to
continue to
burn all
Declelen to
Meeeon for
declelen to
continue te
burn ell
•0
Cnvt rwinUI
(14,000)
I
CD
•0
(nvlronaantel
(11,00P>-
Eiwlr
'flaned m information provided In ICf, Inc., Iho Iconpnlc end financial luecto of tnvlronnenlal KeguloUono on the tloctrlc Utility Inductiy. prepered
for the (dleon Electric Inetttute, febniery 19(0.
-------
VI-4 9
been chosen to illustrate the pollution control costs associ-
ated with those particular sets of decisions.
End-point^"A" of the decision tree represents a new oil-
fired unit designed for oil burning because of environmental
reasons, and an oil—fired unit that has continued to burn oil
(rather than converting to coal). The environmental costs
associated with this type of unit include the capital and
operation and maintenance cost differential between coal- and
oil-fired^units (negative), plus the fuel price differential
between high-sulfur coal and low-sulfur oil, plus any pollu-
tion control equipment costs associated with oil-fired units.
In short, the pollution control cost is the difference between
the annualized cost of an uncontrolled coal unit and a con-
trolled oil unit.
End-point "B" of the decision tree represents a unit that
was converted from coal to oil for environmental reasons and
was subsequently reconverted to coal. The pollution control
costs for such a unit include reconversion costs, plus the
coal fuel premium, plus any pollution control equipment costs.
In addition, there are the costs that were incurred during the
period the unit burned oil. These costs include the fuel cost
differential between high-sulfur coal and low-sulfur oil,
minus the operation and maintenance cost differential between
coal and oil units, plus the conversion costs, plus any pollu-
tion control equipment costs-. In general, the pollution con-
trol costs for such a unit include direct pollution control
costs associated with coal units, plus conversion and recon-
version costs, plus the cost differential of operating an
uncontrolled coal-fired unit versus a controlled oil-fired
unit during the period the unit burned oil.
The decision tree highlights the difficulties and issues
involved in allocating costs to pollution control regulations.
The numbers in parentheses indicate the allocation of mega-
watts of capacity implicit in a recent study conducted for
EEI.3 This particular allocation attributes a large share of
the difference in constructing and operating coal- versus oil-
fired units to the total costs of pollution control-related
decisions. On the other hand, this study understates the
pollution control-related costs associated with the conversion
and reconversion of utility generating capacity. The appro-
priate allocation lies somewhere between the two estimates.
3ICF, Inc., The Economic and Financial Impacts of Environ-
mental Regulations on the Electric Utility Industry: Draft
Final Report, prepared for Edison Electric Institute,
February 1980.
-------
VI-50
In the future, units converting to coal will be required
to upgrade air pollution control equipment to meet environ-
mental standards, but are expected to comply with chemical and
thermal discharge guidelines with existing equipment. Costs
for these units are listed in Table VI-23. EPA provided TBS
with the basic assumption that 45.5 percent of units recon-
verting from oil to coal will install scrubbers. These costs
are assumed to be equivalent to the retrofit scrubber costs
reported for coal units in the Energy Database. The remaining
units that do not retrofit scrubbers are assumed to incur a
fuel premium equal to that paid by 1980-1984 units that are
required to meet new source performance standard (NSPS I)
limits. All reconverting units are also assumed to upgrade
TSP controls at a retrofit cost of $73.90 per kw since TSP
control systems on oil-fired units are less extensive than
those on coal-fired units.
Onits Comino Into Service
During the Period 1980-1984
Units coming into service in 1980-1984 are required to
comply with air pollution limitations established by NSPS I,
as discussed in Chapter IZ. Cost and coverage assumptions for
these units, shown in Table VI-24, are derived from the Energy
Database and are used to estimate control costs for 1980-1984
capacity. New coal units will comply with air, water, and
solid waste regulations and new nuclear units will be affected
only by water regulations. There is no new oil or gas capa-
city expected to come into service after 1980. Analysis of
the Energy Database indicates that 52 percent of coal capacity
coming into service in the 1980-1984 period will comply with
NSPS I limitations on SO2 emissions—1.2 pounds per million
Btu—by installing scrubbers at an average cost of $128.55 per
kw. in addition, 44 percent of 1980-1984 capacity will incur
a low-sulfur coal premium. Some units will burn coal with
less than a 0.8 percent sulfur content, while others will burn
coal with a medium sulfur content and also use scrubbers. The
fuel premium applied to these units (3.06 mills per kWh). is
based on the average fuel premium paid by similar units that
came into service during the 1977-1979 period and are subject
to NSPS 1 regulations.
Particulate limits under NSPS I require the use of high-
efficiency scrubbers at all coal plants coming into service
during the 1980-1984 period. TBS used an average TSP control
system cost of $47.52 per kW derived from the Database. This
cost is applied to all 1980-1984 coal capacity.
-------
VI-51
Table VI-24
WEIGHTED AVERAGE POLLUTION CONTROL COSTS1 FOR UNITS
COKING INTO SERVICE DURING 1980-1904
(19B2 dollarj)
Type of
j1..»ior Control
Po.
5e^v#bders
TSP Central
Scrubber #a»ts Di»po#4i
TSP *m»te Control
^o^^Sulfur ruai
p re«iu«
Cml
Oil
Gm*
Ttwrmi Control
Fo*sil
Hocleui
Crmmieml Control
Fossil
Nuclear
Capital
(dollars
per kWh)
128.55
47.52
20.86
5.35
0
0
0
13.63
10.71
7.50
1.29
0&M
(ailli/kWh.)
2.63
1.16
0.64
3.06
0.30
0.42
0.09
0.00
Capacity
Penalty
(percent of
capacity)
1.95
0.50
0
0
0
0
1.65
3.05
Energy Penalty
(percent of
aeneration)
1.95
0
0
0
0
0
0
0
0
0.65
2.05
0
0
Affected Plants
52% of 1980-1984 capacity
All 1980-1984 capacity
Sane aa scrubbers
Same as TSP
44S of new coal capacity*
60S of ne«* capacity
33.83% of new capacity
All new capacity
All new capacity
l£0«ta are weighted by the anount of capacity uaing apecific typea of equipment (e.g., high- and low-
efficiency scrubber*). Discuaaion of equipwent-specific coats can be found in Chapter IV.
2jnclud** units burning low-«jlfur coal without scrubbing and units burning lo*-sulfur coal with scrubbing.
Source: TBS/EPA Energy Database; EEI (non-capital thermal costa and cheaical eoeta).
The magnitude of the costs of complying with solid waste
regulations depends significantly on whether units have. SO2
scrubbers. Units in the Database that do not have scrubbers
and therefore dispose only of fly ash and bottom ash incur an
average capital cost of $5.35 per kw and annual operation and
maintenance expenditures of 0.64 mills per kWh. Costs for
combined ash and scrubber sludge disposal facilities are
nearly four times the cost for ash disposal facilities alone.
This difference results from the greater volumes of ash and
sludge requiring disposal and the need, in most cases, to
construct a lined pond for ash-sludge co-disposal. Lined
ponds are not typically required for ash disposal without
sludge disposal.
-------
VI-52
Chemical and thermal pollution control expenditures apply
to both coal and nuclear capacity. The cost of cooling towers
for fossil plants is based on Energy Database information for
1977-1979 units (cooling tower data are not reported for fu-
ture units). Nuclear plant cooling tower costs are based on
costs used in EPA's 1974 Economic Analysis of Effluent Guide-
lines, Steam-Electric Powerplants (Economic Analysis) that
assumed installation of cooling towers. Operation and main-
tenance costs and capacity and energy penalties for both coal
and nuclear units are those established during joint review of
the draft version of this report with EPA, TBS, EEI, and ICF.
Regulations requiring cooling towers on all new sources
were remanded in 1977, and cooling tower requirements are cur-
rently left up to the "best engineering judgment" of permit
writers on a case-by-case basis. For this reason the extent
of use of cooling towers on future units is somewhat uncer-
tain. To establish a coverage for future cooling towers, TBS
examined the extent of use of cooling systems on recent fossil
units in the Energy Database and recent nuclear units in the
Generating Unit Reference File (GURF) database, and projected
these coverages to future units. As noted in Chapter IV,
cooling towers in water-constrained regions are frequently
installed in response to economic rather than environmental
requirements. To the extent that cooling towers are installed
for economic reasons, this analysis overstates the cost'of
cooling towers associated with environmental compliance.
EPA is currently revising its chemical effluent limita-
tions guidelines and, therefore, considerable uncertainty re-
mains concerning these guidelines. The costs used in this
analysis are costs of compliance with guidelines currently in
effect—essentially the best practicable control technology
(BPT) standards established in 1974. The costs of complying
with chemical guidelines for both coal and nuclear units are
not reported in the Energy Database and are based instead on
the results of a joint review with EPA, TBS, and EEI.
Pnits Coming Into Service After 1984
Cost and coverage assumptions for post-1984 units were
provided by EPA on the basis of past studies and engineering
cost estimates. These costs provided by EPA are shown in Ex-
hibit VI-8. Table VI-25 indicates the weighted average of the
costs shown in Exhibit VI-8. Data in the Energy Database do
not provide projections beyond 1984 and consequently those
data were used only to validate assumptions provided by spa.
-------
VI-53
Table Vl-25
WEIGHTED AVERAGE POLLUTION CONTROL COSTS1 FOR UNITS
CONING INTO SERVICE AFTER 1984: BASE CASE SCENARIO
(1982 dollars)
Type of
Pollution
Control
Capital
(dollara
oer kWh)
0&M
(mills/WWh)
Capacity
Penalty
(percent of
caoacity)
Energy
Psnalty
(percent of
oeneretion)
Affected Plants
Scrubber
Eastern
Western
123.08
90.13
1.75
1.32
2.02
0.79
1.58
1.81
632 new
375 new
coal
coal
TSP Control
Eastern
Western
45.59
69.65
0.26
0.66
0.28
0.81
0.28
0.81
635 new
375 new
coal
coal
Wast* Disposal
Eastern
Western
50.84
8.24
0.39
0.46
0.03
0
0.03
0
635 new
37% new
coal
coal
Low-Sulfur Fuel
Premium
0
3.06
0
0
65 new
coal
Thermal Control
Fossil
Nuclear
13.63
10.71
0.30
0.42
1.65
3.05
0.65
2.05
60S new
392 new
capacity
capacity
Chemical Control
Fossil
Nuclear/Gaa
7.50
1.29
0.09
0
0
0
0
0
All new
All new
capacity
capacity
^Costs are weighted by the amount of capacity using specific types of equipment
and low-efficiency scrubbers). Discussion# of equipment-epecific costs can be
Chapter IV.
(e.g., high-
found in
Source: TBS/CPA Energy Database (fuel premium, thermal control capital); General Utility
Reference File (GURF) (nuclear coverage); EEI (thermal noncapital costs and
chemical coats); EPA (other costs).
Units coming into service after 1984 are assumed to com-
ply with NSPS II air regulations, disposal facility guidelines
under Resource Conservation and Recovery Act (RCRA section
4004--nonhazardous waste disposal), and current water regula-
tions. Costs of compliance and coverage assumptions concern-
ing water regulations are the same for those units as for
units that will come into service in 1980-1984.
-------
VI-54
Emission limitations under NSPS II air regulations re-
quire new units to meet an emissions rate between 0.6 and
1.2 pounds with an SO2 removal rate of 90 percent. Those
plants able to attain an emissions rate below 6 must still
remove at least 70 percent of the SO2 in their coal. In addi-
tion, new units are required to install high-efficiency TSP
control systems and nitrogen oxide (NOx> controls based on
combustion modifications. Some units siting in the vicinity
of Class I prevention of significant deterioration (PSD)
areas, or PSD areas where increments are nearly exhausted, may
be required to meet best available control technology (BACT)
standards that are more restrictive than NSPS II. Solid waste
guidelines under RCRA section 4004 will require lining of
disposal facilities as well as special precautions for facili-
ties locating in flood plains.
The assumed weighted average control costs for the base
case scenario, shown in Table VI-25, are based on the follow-
ing assumptions provided by EPA:
• In the West, 81 percent of new units will in-
stall scrubbers -with 70 percent removal effi-
ciency and will burn low-sulfur western coal,
while the remaining 19 percent will install
equipment that will achieve more stringent BACT
requirements of 90 percent removal efficiency
on similar-quality coal.
• In the East, 90 percent of new capacity will
choose to burn high-sulfur coal and install
scrubbers with 90 percent removal efficiencies.
• A relatively inexpensive dry scrubbing tech-
nology that can be used to obtain 70 percent
removal efficiencies on low-sulfur eastern
coal will not be available widely, and will be
the selected strategy at only about 10 percent
of eastern capacity installed after 1984.
Sufficient quantities of coal with an SO2 con-
tent of 2.8 pounds per million Stu (approxi-
mately 1.7 percent sulfur by weight), will be
available to supply 10 percent of capacity
additions in the East.
EPA estimates that wet scrubbing and 90 percent removal
will cost $127 per Jew, while dry scrubbing technologies with
removal rates of 70 percent will become available in the East
at approximately $84 per kW by 1985. As noted in Chapter'IV,
the difference in cost between wet scrubbing at 90 percent
removal efficiencies and dry scrubbing at 70 percent removal
efficiencies is important in determining the utility decision
-------
VI-55
between high-sulfur coal strategy and a low-sulfur coal strat-
egy. These two strategies represent the extreme ends of a
spectrum of possible combinations. The choices presented
here, then, represent two potential combinations of removal
efficiency and sulfur content. Other combinations may, in
fact, be selected and may be economically desirable. In this
analysis, dry scrubbing with a removal rate of 70 percent
using low-sulfur coal is slightly more attractive economical-
ly, but is selected by only 10 percent of post-1984 units in
the East because the technology is still in its early stages.
Only 10 percent of new eastern capacity is assumed to use
low-sulfur coal with its associated fuel premium. The premium
is assumed to remain constant in real terms at 3.06 mills per
JcWh. Western units do not incur a low-sulfur coal premium.
Solid waste disposal costs differ between the scrubber
technologies for two reasons. The higher sulfur contents and
the higher removal efficiencies implicit in the high-sulfur
coal scrubbing approach result in approximately six times as
much scrubber sludge requiring disposal as in the low-sulfur
coal approach. A second important consideration is that the
scrubber sludge resulting from a wet scrubbing process is more
difficult to dispose of than residues from dry scrubbing. For
example, the capital cost for sludge and ash co-disposal for a-
unit with 90 percent wet scrubbing is $56 per kW, compared
with about $4 per kW at a plant with 70 percent dry scrubbing.
Table VI-25 shows the weighted average of these costs.
Particulate matter control costs are lower under the
high-sulfur scrubbing approach. Assumptions provided by EPA
indicate that low-sulfur coal units with dry scrubbers will
choose to install baghouses to control TSP—at a cost of ap-
proximately $69 per kW. The cost of electrostatic precipita-
tors used by units that burn high-sulfur coal is $43 per kW—
$26 per kW lower. Consequently, the lower cost of TSP control
associated with high-sulfur scrubbing partially compensates
for the higher cost of the scrubber itself.
RESULTS OF THE NATIONAL ANALYSIS
This section presents the TBS estimates of the national
costs of pollution control regulations for the period 1980-
1999. The costs associated with the base case scenario, des-
cribed in the initial section of this chapter, are presented
first, arrayed along a number of dimensions. Next, two alter-
native scenarios are evaluated to determine the effect of
particular input assumptions on total pollution control costs.
All of the scenarios use a starting financial profile which
excludes all pollution control expenditures.
-------
VI-56
Base Case Scenario
1 Hi
The base case scenario reflects the base assumptions
regarding pollution control costs and coverages presented
earlier, as well as assumptions concerning demand growth,
etc., reflected in the baseline financial projection. The
results of the base case analysis are summarized in Fig-
ure VX-8. Additional detail on pollution control costs is
provided in Table VI-26. Among other things, these data indi-
cate that pollution control expenditures under the base case
scenario result in consumer charge increases of 5.01 mills per
kWh by 1999. Cumulative plant additions during the 1980-1999
period are $87.28 billion, or 8 percent, over what would have
been spent in the absence of pollution control regulations.
Table VI-26
FINANCIAL EFFECTS OF ALL POLLUTION CONTROL EXPENDITURES
BASE CASE SCENARIO
(billion* of 1982 dollar*)
1980
1985
1990
1999
Chanaea in Plant In-Service*
Total for Year
Total since 1979
2.76
2.76
3.39
18.45
3.98
35.84
7.36
87.28
External Financino
Total Tor Yaar
Total ainca 1979
5.36
5.36
2.29
16.86
2.50
28.43
6.86
68.18
Ooeratina Revenues
Total For Yaar
Total ainca 1979
8.44
8.44
11.27
38.30
13.23
120.41
18.72
263.26
Osaration and Maintenance Exoanaee^
Total for Yaar
Total ainca 1979
7.39
7.39
& CD
9.42
93.58
12.02
190.29
Conauner Charaea (ailla/kWh)
Average for Yaar
3.97
4.56
4.62
5.01
^A* defined in thia atudy.
Exclude* change# in conatruetion work in progreaa.
Exclude* nuclear fuel.
Source: PTa(Electric Utilitiea).
-------
Figure VI—0
CUMULATIVE CHANGES TO PLANT IN SERVICE
AND OPERATING REVENUES:
BASE CASE SCENARIO
CONSTANT 1982 DOLLARS
CUMULATIVE CHANGES
TO PLANT IN SERVICE
CUMULATIVE OPERATING
REVENUES
BILLIONS
OF DOLLAnS
$1200
SHOO
$1000
$100 —
nn
n
1080 1905
pollution conttoli
hatallna
1980 1990
1900 1999
$3000
$2600
$2000
BILLIONS
OF DOLLARS
$1600
$1000
$500
\ r' v . .
• r
I
tn
I960 1985
1080 1990
1900 1999
Somen: PTmlFlorlrlc Ullllllml.
-------
VI-58
Annual plant additions increase after 1985 primarily- as a
result of increased expenditures associated with scrubbers and
solid waste disposal. Capacity penalties are a significant
portion of total changes in plant in-service, representing
$13.6 billion by 1999. The increase in expenditures related
to new scrubbers, TSF controls, and solid waste controls more
than offsets a decrease in expenditures after 1985 that re-
sults from the completion of pollution control equipment
retrofits to bring 1979 capacity into compliance with state
implementation plans. As a result, the portion of total plant
additions related to pollution control remains relatively
constant over the forecast period.
External financing requirements are high in 1980 as the
industry raises funds to retrofit pollution control equipment
on 1979 capacity and to convert units from oil to coal, but in
subsequent years external financing requirements for pollution
control decline from 50 percent of total requirements in 19 80
to approximately 6.5 percent in 1990, rising again to 8 per-
cent of the industry's total external financing needs in 1999.
Although 6 to 8 percent is perhaps not dramatic, it is none-
theless significant. Investor-owned electric utilities will
require over $1,128.8 billion of external financing, excluding
short-term debt, between 1980 and 1999. Over the 1980-1999
period, investor-owned utilities will account for about
25 percent of total external financing requirements for all
nonfinancial corporations, as projected by DRI in their Fall
1981 D.S. Long-Term Review. By comparison, over the 1970-1976
period, investor-owned electric utilities accounted for
23 percent of all nonfinancial corporate external financing.
Thus, the investor-owned electric utility industry's external
financing requirements are likely to represent a large propor-
tion of all external capital demanded by nonfinancial corpora-
tions. Projected pretax interest coverage ratios do not
change significantly with the inclusion of pollution control-
related external financing requirements. However, because of
generally poor market conditions and a declining confidence in
the security of utility investments, raising the capital re-
quired may be difficult even if the assumed rates of return
are achieved. Financing any utility capital expenditures,
then, tends to exacerbate an already difficult financing
situation.
The major component of the increase in operation and
maintenance expenses attributable to pollution controls is the
low-sulfur, fuel premium. In 1980 the low-sulfur fuel premium
accounts for almost 80 percent of pollution control operation
and maintenance expenses. This percentage decreases to about
68 percent in 1985 as oil-fired capacity with a very high fuel
premium is phased out. In 1990 and 1999 the fuel premium
decreases to 60 and 39 percent, respectively, of operation ana
maintenance expenses. By 1999, much of the remaining oil
-------
VI-59
capacity is phased out, reducing the total sulfur premium
attributable to oil units. In addition, new coal units rely
increasingly on scrubbers to attain reductions in SO2 emis-
sions; units that have high-sulfur scrubbers to achieve SO2
emission reductions do not incur a sulfur premium since they
use high-sulfur coals.
The remaining increase in operation and maintenance ex-
penses is attributable to the expense of operating pollution
control equipment and to increased plant operating expenses
due to pollution control equipment energy penalties. Opera-
tion and maintenance expenses for energy penalties total
$6.5 billion by 1999. In the base case scenario, energy
penalties are attributable primarily to thermal control sys-
tems and dry scrubbers. The major increases in pollution
control operating expenses are due to scrubbers and waste
disposal operations. Water pollution and TSP control equip-
ment account for a smaller portion of the increase in oper-
ating expenses.
Pollutant removal costs are higher for oil-fired units
than for coal-fired units when they are measured on a dollar-
per-ton basis. Further, the pollutant removal costs for new
units (NSPS II) are double or triple the removal costs of
existing units. Refer to page IV-10 for a discussion of per-
ton pollutant removal costs, and the cost-effectiveness of
alternative removal strategies and pollution control
equipment.
Base Pollution Control Costs by
Onit In-Service Date
Total pollution control costs in the base case scenario
have three separate components based on regulatory coverage:
• Units in place as of December 31, 1979, plus
reconversions,
• Units coming into service during the period
1980-1984, and
• Units coming into service after 1984 and thus
subject to NSPS II air pollution limits as well
as chemical and thermal guidelines.
The following paragraphs examine the components of pollu-
tion control costs attributable to each of these classifica-
tions. To facilitate the discussion, only the breakdown of
capital expenditures, operating revenues, and consumer charges
is analyzed. Exhibits VI-9, VI-10, and 71-11 provide more
detailed information.
-------
VI-60
Three types of changes in plant in-service—equipment
retrofits on existing coal capacity, retrofits on reconverted
coal units, and equipment installation on new units—contri-
bute to high expenditures in 1980. As indicated by Figure
71-9, plant additions associated with retrofit pollution con-
trol equipment for units installed as of 1979 plus pollution
Figure VI—9
CUMULATIVE POLLUTION CONTROL ADDITIONS
BY UNIT IN-SERVICE YEAR:
BASE CASE SCENARIO
CONSTANT 1982 DOLLARS
SI00 f—
S90 -
S80 -
$70 -
S60 -
BILLIONS
OF ®0
DOLLARS
$40 -
$30 —
$20 -
$10 -
Units coming into sarvica
tfrwr 1984
Units coming into sarvica
during 1980-1984
Units in axtstanca as of
1979. plus coal convarstons
and ratrofits
U 90
t?.2t
I 'I
1980-1985 1980-1990 1980-1999
Sourca: PTmfElactric Utilltm).
-------
VI-61
controls for reconverted units are $6.8 billion in the 1980-
1985 period, but total only $8.78 billion by 1999. By 1985,
retrofits have been completed and the only remaining expendi-
tures are those associated with reconversions. Units coming
into service during 1980-1984 incur total pollution control
plant additions of $8.07 billion over the forecast period.
Units coming into service in 1985 and after incur the largest
portion of pollution control additions to plant in-service,
$70.43 billion. These expenditures, which represent 81 per-
cent of total pollution control expenditures over the study
period, are primarily related to compliance with NSPS II air
regulations and solid waste disposal requirements that are
increased due to the removal of air pollutants.
In the base case scenario, operating revenue requirements
for units in place as of 1979 plus reconversions amount to
$8.21 billion in 1980, increasing to $9.03 billion in 1985,
and declining to $7.37 billion by 1999. Like the previous
unit category, pollution control operating revenues reach a
height of $2.18 billion in 1985 and then decline to $1.09 bil-
lion in 1999. Pollution control operating revenues required
for units coming into service after 1984 are $0.06 billion in
1985., increasing to $10.26 billion-in 1999. In the early
period, operation and maintenance expenses dominate operating
revenue 'requirements. Subsequently, in 1985 and 1990, the
effect of the capital expenditures during the period 1980-1984
becomes more significant. By 1999, the contribution of
capital-related charges to total operating revenue require-
ments is approximately 28 percent. The effect of all pollu-
tion control-related expenditures for post-1984 capacity addi-
tions on operating revenues grows substantially by 1999, as
indicated by Figure VI-10, accounting for 55 percent of the
total 1999 revenue requirements. This increase is primarily
due to capital-related charges on pollution control equipment
installed after 1984.
Consumer charges show much the same pattern as operating
revenues. Consumer charges for units in existence as of 1979
(including reconversions) decrease over time as the sulfur
premium is spread over more kilowatt-hours, as indicated by
Figure VI-11. Pollution control costs for units coming into
service between 1980 and 1984 rise initially as units come on
line and then decline. The effects on consumer charges of
pollution control expenditures for units coming into service
after 1984 are barely perceptible in 1985, but account for
more than 55 percent of the increase in consumer charges due
to pollution control equipment by 1999. This increase in
consumer charges results primarily from capital-related charg-
es on pollution control equipment installed after 1985.
-------
VI-62
Figure VI—10
ANNUAL POLLUTION CONTROL OPERATING REVENUES
BY IN-SERVICE YEAR:
BASE CASE SCENARIO
520 f—
CONSTANT 1982 DOLLARS
BILLJONS
OF DOLLARS
S15 r—
S10 H
ss t—
Urn a coming into tmnct during 1980-1984
Units in eximnci as of 1979, plus coal
conversions ana rwtrofits
10.12
i».7:
t«£
7.r
1980
1985
1990
1999
Source: PTm(EI«etric UtfittM.
A decrease in the low-sulfur fuel premium compensates
partially for the effect on consumer charges or increased
capital expenditures for pollution control equipment. Fewer
NSPS II units than pre-1985 units incur a low-sulfur .uei
premium both because more capacity additions after ^985 are
located in the West, and because mcst_eastern units install
scrubbers with 90 percent removal efficiencies and burn high-
sulfur coal, and therefore do not incur fuel premiums.
-------
VI-63
Figure VI-11
ANNUAL POLLUTION CONTROL CONSUMER
CHARGES BY UNIT IN-SERVICE YEAR:
BASE CASE SCENARIO
CONSTANT 1982 DOLLARS
MILLS
PER kWh
Units coming into service after 1984
Units coming into service during 1980• 1984
Units in existence as of 1979, plus coal
conversions end retrofits
1980
1985
1990
1999
Sourca: PTm
-------
VI-64
The largest component of total pollution control plant
additions is SO2 control/ which represents 48 percent of total
costs in 1980 and 50 percent in 1999. Based on Figure VT-12,
TSP plant additions also increase over the period, represent-
ing 26 percent of total expenditures by 1999. Solid waste
Figure VI—12
CUMULATIVE POLLUTION CONTROL ADDITIONS BY POLLUTANT:
BASE CASE SCENARIO
CONSTANT J982 DOLLARS
Si00 r—
S90
$80
S70
S60
BILLIONS
OF DOLLARS
S50
SAO
S30
S20
S10
*«*?
$$$$$&&
. ,*U•
yVttar Pollution Control
Solid Warn Control
TSP Control
SO2 Control
43 jj
35*4
1980-1985 1980-1990
1980-1999
Sour cm: PTm(EI«ctnc Lhilrti**/.
-------
VI-65
disposal expenditures consist of the costs incurred in dispos-
ing of wastes generated by TSP and SO2 removal systems.4
These expenditures account for 13 percent of the.total change
in plant in-service; water pollution controls are also 13 per-
cent of the total pollution control plant additions. Total
capacity penalties associated with SO2, TSP, and water pollu-
tion controls amount to $13.6 billion by 1999.
The dominant cost element in SO2 control is the low-sul-
fur fuel premium. In 1980, when incremental SO2 control is
more than 69 percent of total operating revenues/ the fuel
premium accounts for more than 97 percent of SO2 control
costs. In subsequent years, the contribution of the fuel
premium to incremental SO2 control costs declines steadily as
new coal units install scrubbers to control SO2 emissions and
oil units are taken out of service. By 1999 the fuel premium
accounts for 41 percent of SO2 control costs.
Included in the revenue requirements are funds necessary
to recoup the cost of energy penalties associated with the
installation of pollution control equipment. Those penalties,
totaled•through 1999, are $6.2 billion, or 33 percent of the
total. Energy penalties are associated with scrubbers, TSP
controls, waste disposal, and water pollution controls.
Control of incremental TSP constitutes an increasing
share of total costs under the base case scenario. The con-
tribution of TSP control to operating revenues' in 1980 is
small because of the way pollution control expenditures are
reported by utilities. In virtually all cases, utility Form
67 submittals attribute TSP-related operation and maintenance
expenses to waste disposal rather than to particulate control
system operations. Engineering cost estimates used to develop
post-1985 costs, in contrast, attribute a portion of solid
waste-related operation and maintenance expenses to particu-
late collection system operations. As indicated by Fig-
ure VI-13, solid wastes and water pollution control require-
ments constitute a much smaller share of total operating reve-
nues associated with pollution control equipment.
The discussion related to consumer charges follows much
the same pattern as that for operating revenues. Figure VI-14
details the cost components of consumer charges by pollutant.
As is the case for operating revenues, incremental SO2 and TSP
4Since solid waste disposal facilities accept both ash and
scrubber residues, the contribution of SO2 arid TSP controls
to solid waste costs cannot be readily disentangled.
-------
VX-66
controls are the primary source of consumer charges associated
with pollution controls. Together they account for 69 percent
of the pollution control-related consumer charge increase in
1999. However, the contribution of incremental solid waste
and water pollution controls grows over time from 1 percent in
1980 to 18 percent in 1999.
Figure VI—13
ANNUAL POLLUTION CONTROL REVENUES BY POLLUTANT:
BASE CASE SCENARIO
CONSTANT 1982 DOLLARS
szo r-
SI 5 —
W«r*r Pollution Control
Solid Warn Control
TSP Control
SO2 Control
Port 79 Units. Full Prwmium
Prr-'SO Unitx, Otffr
Prr-'SO Units. Full Prtmium
8.44 Wnr Pollution Gomrt*
&42 Sol 10 W«n» Control
L34 TS* Comroi
8.30 SO7 Control
ft. 13 Pott '79 Umu. Puol Prwrnum
M.T2
17.2S
1&.40
BILLIONS
OF DOLLARS
*10 —
SS f
. 'J
T*. ¦¦¦¦r'TTTT*
'sssissi7,:;
1980
1385
1990
1999
Souroa: PTm< Electric Utiiitias).
-------
VI-67
Figure VI—14
AVERAGE POLLUTION CONTROL CONSUMER CHARGES BY POLLUTANT:
BASE CASE SCENARIO
CONSTANT 1982 DOLLARS
Wire/- Pollution Control
Solid Wmstt Control
TSP Control
SO2 Control
Pott 79 Units. Fuel Premium
Pre- "80 Units. Other
Pre- "SO Units, Fuel Premium
5 —
1(7 Wntr *o*iuien Control
IN Solid Whu Control
1>2 TS* Control
190 SO} Control
1(2 ~or 79 Uwu ~rwnsini
4 —
MILLS
PER kWh
3 —
2 —
iWkVs:
nn
1980
lYlVAiYlY'
**********
lYVVfVroV
~~******~~
VfffffM M
**********
**********
****** ** *4
**********
********M
**********
**********
**********
**********
**********
**********4
**********
**********
**********
**********
**********
1985
*8*5*8*!
i®A®A
WiVAV
mvAV
mm4
>**********
**********
***********
**********
>**********
**********
***********
~IfflVAWl
~v»y»v*y»v
1.00
1990
1999
Sourca: PTmlEloctnc Utilftm).
Alternative Scenarios
TBS tested two key assumptions in the base case scenario
by developing alternative hypotheses and identifying the ef-
fects of these hypotheses on the results of the analysis. The
two key assumptions tested were, lower industry growth and ter-
mination of nuclear capacity additions after 1989. The ef-
fects of the alternative scenarios on pollution control plant
-------
VI-68
additions and operating revenues are _ il/iTiifl S"Exhi-
arid VI-16. These effects are shown in further detail in Exhi
bits VI-19 and VI-20. All pollution control effects jje
measured against a corresponding base financial projection.
?5he base financial projections for these two scenarios were
Figur* VI—15
COMPARISON OF CUMULATIVE POLLUTION CONTROL
PLANT ADDITIONS UNDER ALTERNATIVE SCENARIOS
CONSTANT 1982 DOLLARS
*105 r~
$100 -
$70
$80
BILLIONS BO
OF
DOLLARS
$40
$30
$20 -
$10
101.»
VM
IMt
IMi
2% MO
CASS GROWTH NUCLEAR
1M0-1MS
2% NO
CASE GROWTH NUCLEAR
10M-1MO
IAS* 2K NO
CASi GROWTH NUCLEAR
Swm: PTm(E>aetric UtHHtal.
-------
VI-69
presented earlier in Tables Vl-21 and VI-22.) The comparisons
provide an indication of the change in pollution .
lated costs, recognizing that the underlying cos.s and finan
cial profiles also vary between scenarios.
Figurt VJ—16
COMPARISON OF CUMULATIVE POLLUTION CONTROL
OPERATING REVENUES UNDER ALTERNATIVE SCENARIOS
CONSTANT 7982 DOLLARS
$300 r"
$200 -
BILLIONS
OF
DOLLARS
$100
7JIM
aui
130.41
1J0J»
H.1J
St.30
10133
ZJ0J1
BASE 2% "O
case growth nuclear
mo-ims
Sown.: PTmiEtMtrte Utilitiwl.
BASE 2% NO
CASE GROWTH NUCLEAR
1MO-1M0
BASE 2% NO
GROWTH NUCLEAR
-------
VI-70
A decrease in the industry's near-term annual growth
rate, from the 3.0 percent assumed in the base case to 2 per-
cent, decreases the industry's total costs, both with and
without pollution controls. Total pollution control plant
additions through 1999 are $33.64 billion lower as a conse-
quence of a slower annual growth rate. Similarly, total pol-
lution control operating revenues through 1999 decrease by
$44.95 billion from the base case. As operating revenue re-
quirements decrease, however, so do total kWh of generation.
Consequently, consumer charges do not decline as significant-
ly. The largest decrease in pollution control consumer charg-
es takes place in 1999, but even then it decreases by less
than 0.4 mills per kWh (7 percent).
Termination of nuclear additions results in increases in
all pollution control-related expenditure categories. Cumula-
tive pollution control plant additions of $101 billion are $14
billion greater than under the base case scenario. Annual
pollution control plant additions are $8.7 billion by 1999.
Cumulative revenue requirements associated with pollution
controls are $276 billion by 1999, $11 billion greater than
under the base case scenario. Average consumer charges in-
crease by 0.64 mills per kWh over the case of continued nu-
clear additions, representing a total of 5.7 mills per kWh by
1999 for all pollution control-related expenses. This in-
crease amounts to approximately 10 percent of the baseline
cost of generating electricity, assuming no nuclear additions
after 1989. This corresponds to 9 percent for the base case
scenario.
-------
PU(fL£CrHIC UflLUIlS) HHHL
BM.ANCC SMEE1 FIM INVtSlOR-OWNED CUC1R1C UULII1ES
ASSETS
CURRENT ASSETS
LONG TERM ASSET ACCOUNTS
GROSS TLAN1 IN SERVICE
ACCUIt. DEPRECIATION
NET TLANT IN SERVICE
IMOC. FUEL
-------
Exhibit VI-2
pMaccutic uiiuuts) wm
INCOME SIATCMEN1 FOR INVCSfOft-ONNCD ELECTRIC UTILHICS
(billion* of currant, dollar*)
If BO
1*81
1982
1983
1784
1789
1784
1787
1708
1709
1770
OPCRATIMO RCVENUC
74.0
•3.1
72.7
184.9
117.7
134.3
196.7
178.0
201.0
226.S
753.2
-OTCR. « MINT. EXP.
47.J
92.4
57.8
44.0
71.3
77.7
70.2
101.6
113.7
126.0
142.0
-O/M EXP. - THERMAL
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
-O/H IXP. - CHEMICAL
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
-USAGE VAX
.0
.0
.0
.8
.8
.0
.0
.0
.0
.0
.0
-TAXES
9.6
4.3
7.1
7.?
8.7
10.4
11.7
13.5
19.3
17.2
17.4
-DEPRECIATION - PLANT
4.9
S.S
4.1
4.8
7.4
8.4
7.7
11.0
12.4
44.0
15.7
-frCPRECIATIflN - MtfC FUEL
1.8
2.1
2.T
3.3
4.3
S.4
6.8
O.S
10.3
1?. I
40PT. 1 CREBI T
.0
.0
.0
.8
.9
.0
.0
.0
.0
.0
.0
IAFK
6.7
7.9
9.2
11.3
14.1
17.1
18.4
17.8
22.3
26.6
30.0
C»IT
21.t
24.7
20.9
.14.2
4©» 7
90.4
90. O
44.7
73.4
04.7
73.0
-interest oh long terh pe*t
4.5
7.4
9.0
10.0
13.3
14.1
17.1
22.2
23.7
27.7
34.4
-tKfEKSf ON SHORT TERM DEBT
t.O
1.0
1.1
1.2
1.3
1.5
1.4
1.8
2.0
2.3
2.3
cor
13.7
14.1
18.7
22.2
24.1
32.8
37.3
41.0
43.7
32.8
50.7
-TAXES (INCOME)
.0
.5
.8
1.0
1.1
2.9
2.7
3.2
3.5
3.7
3.4
DCrr:RRCI> TAXES
!<•
1.7
2.0
2.2
2.4
2.8
3.2
3.6
4.1
4.6
3.4
-KFCMM 1TC8
.0
.7
.9
1.0
1.1
1.5
1.7
1.7
2.0
2.2
2.7
NET INCOME
11 .1
12.0
13.1
17.*
21.4
24.5
27.4
32.3
34.1
42.1
47.2
V(VIDf.NP5 (PRCri
t .0
1.7
2.2
2.9
2.8
3.2
3.8
4.4
5.1
5.9
6.8
-ftlVlOENPS (COHM)
7.9
8.4
10.1
11.7
14.1
17.4
17.4
20.7
23.3
27.1
30.3
RETAINER EARNINGS
1.7
1
. 1
1
• |
W I
2.0
3.4
4.9
9.8
4.9
7.0
7.8
7.0
10.1
COVERAGE RATIOS
ECiI T/ INTEREST
3.3
3.3
3.2
3.2
3.1
3.1
3.0
2.7
2.7
2.8
2.0
EfctT/INT 1 Pro IIV
2.4
2.4
2.4
2.4
2.9
2.4
2.9
2.4
2.4
2.4
2.3
-------
Exhibit VI-)
PI«(ELECIRIC UIlLlf ICS) MODEl
APPLICATIONS AND SOURCES OF FUNDS
rOR INVEST OR-OWNED ELECTRIC UIILIIIES
(billions of current dollars)
1YOO
1901
1982
1903
1984
1905
198A
1987
1908
1909
1990
APPLICATIONS OF FUNDS
CAPITAL EXPENDITURES
CAP. EXPEND. FOR PLANT
IN1T. LOAOINfl NUC. FUEL
NET REPLACEMENT
AFDC •
1REFUNDINGS
12.7
.2
-.5
4.7
2.0
22. A
.3
.0
7.5
1.8
2S.4
.4
.5
9.2
2.5
20.5
.4
1.2
11.3
1.8
33.3
.5
.7
14.1
2.1
37.0
1.1
.9
17.1
1.5
40.8
1.3
1.4
18.A
1.4
4A.9
1.4
1 .A
19.8
1.4
55.0
1 .A
1.3
22.3
1.3
A2.8
1 .8
1 .5
2A.A
.9
A9.4
1 .7
1 .9
30.0
1.2
TOTAL APPLICATIONS
21. t
32.2
30.0
43.3
50.7
57. A
A3.5
71 .2
81.5
93.7
104.3
SOURCES OF FUNDS
INTERNAL GENERATION
RETAINED EARNINGS
IDEPRECIArION PLANT
~DEFERRALS
1.9
4.?
2. A
2.3
S.S
2.8
2.a
A.l
3.0
3. A
A.8
3,2
4.5
7.6
3.4
5.8
8. A
4.3
A.5
9.7
4.9
7.0
11 .0
5.5
7.8
12.4
A . 1
9.0
14.0
A.8
10.1
15.9
8.3
TOTAL
9.4
10.S
11.9
13.A
15.A
18.7
21.1
23.5
2A.3
29.8
34.2
EXTERNAL FINANCING
LONG-TERM DEBT
ISTftCK
1 STOCK (CONN >
7.8
.8
3.2
12.9
1.8
7.0
15.5
2.3
8.2
17.5
2.5
9.7
20.0
2.5
11.7
23.1
3.1
12.7
25.1
4.7
12.5
28.0
5.3
14.3
32.1
A.2
1A .9
3A.9
7.2
19.8
40.7
7.9
21.5
TOTAL
11.8
21.7
26.1
29.7
35.1
38.9
42.4
47.7
55.2
A3.8
70.1
TOTAI. SOURCES
21.1
32.2
38.0
43.3
50.7
57.A
A3. 5
71.2
81 .5
93.7
104.3
CIIN. EXTCRHAL FINANCING
11.0
33.4
59.5
89.2
124.3
1A3.2
705.5
253.3
3011.4
372.3
442. 4
-------
Exhibit VI-4
PMaEcinc Ufa.ities) hqdcl
mas consukd rm generation or aEcmicnr
CONVENTION* STEAM AND PEAKING UNITS
TOTAL
COAL
OIL
OAS
GENERATION
-------
Exhibit VI-5
PMticcTRic ur a it ics) Honti
IOIM. GENEHAI ION BY DRIVER
(billion kMh)
TOTAL
GENER.
COAL
OIL
OAS NUCLEAR
HYDRO
PUMPED
PEAKER
1980
1981
1982
1983
1984
2343.3
2413.6
2406.0
2560.6
2637.4
1134.1
1190.5
1249.5
1308.3
1369.3
377.2
368.4
358.5
349.7
339 .0
220.6
219.7
211.2
202.8
194.6
250.3
203.7
310.2
337.9
367. 1
253.7
257.4
260.9
263*8
266.9
63.4
64.4
65.2
65.9
66.7
20.0
29.5
30.5
32.0
33.0
1985
1906
1907
1900
1909
2716.5
2790.0
2001.9
i960.4
3057.4
1432.7
1409.3
1540.3
1606.5
1667.9
324.5
312.4
300*1
200.9
277.0
105.7
104.3
102.0
101.0
180.5
409.5
443.6
478*7
513.0
550.0
264.6
266.8
260.9
271.9
274.3
66.1
66.7
67.2
68.0
60.6
33.3
34 .0
35.0
37.5
39.2
1990
3149.2
1727,0
274.2
178.8
577.9
2Q0.8
70.2
40.2
1991
3243.6
1792.9
267.8
174.7
607.3
288.5
72.1
40.3
1992
3340.9
1060.8
261 .6
170.9
637.5
295 .0
73.9
40.4
1993
3441 .2
1929.2
255.5
167.0
668.7
303.0
75.9
41 . 1
1994
3544.4
2000.5
249.7
163.3
700.2
311 .6
77.9
41.3
1995
3650.7
2097.1
237.8
156.3
723.7
315.4
78.8
41.6
1996
3760.3
2203.1
221 .4
146.2
751.7
319.1
79.8
30.9
1997
3873.1
2310.0
206.2
136.8
780.2
322.9
00.7
36. 1
1990
3909 #3
2415.4
192.3
128.2
010.7
327.1
01 .8
33.8
1999
4108.9
2524.1
179.2
120.2
040.1
331 .1
02.0
31.5
-------
Exhibit VI-*
lf»o
If 81
1702
1903
1904
J9B5
1906
1907
1908
190*
1990
1991
1992
1993
1994
1993
1994
199?
1990
1999
PWaCCIRIC UTILITIES) MODEL
CROSS WOITIONS 10 GENERATING KANT
INCLUDING CONVERSIONS TO COM. fRON OIL
(ailllan kilowatts)
TOTAL
CAPACITY
349.4
582.4
595.4
400.7
421.7
434.2
450.7
445.2
479.7
494.2
713.0
731.7
730.3
749.2
700.0
014.1
040. t
044.2
092.3
910.3
TOTAL
AD0TN8.
15.9
15.9
13.9
13.9
15.9
17.0
17.0
17.0
17.B
17.0
19.0
19. O
19.0
19.0
19.0
30.0
JO.O
30.0
JO.O
30.0
FOSSIL
SUBTOTAL
8.0
0.8
0.8
0.8
8.8
10. 8
10.8
10.8
10.0
10.0
12.2
12.2
12.2
12.2
12.2
22.9
22.9
22.9
22.9
22.9
COAL
8.8
0.0
8.8
8.8
8.8
10.8
10.8
10.0
10.8
10.8
12.2
12.2
12.2
12.2
12.2
22.*
22.9
22.9
22.9
22.9
OIL
OAS HUCLCAR
IIYORO
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
3.1
3.1
3.1
3.1
3.1
3.4
S.4
5.4
3.4
3.4
4.7
4.7
4.7
4.7
4.7
4.3
4.5
4.3
4.3
4.3
.3
.3
.3
.3
.5
pUHPrt
.3
.3
> 3
.3
4
4
4
4
4
3
3
3
3
3
PEAKCR
2.4
2.4
2.4
2.4
2.4
.0
.0
.0
.0
.0
.0
.0
.0
.0
.0
.9
.9
.9
.9
.9
-------
Exhibit VI-7
PMfltCIHIC Uf(LlllES) HOWL
SALES AND CAP ACHY AS9JH>flONS
U.S. ELECTRIC UflLlIY INDUSTRY
1900
1901
1702
1903
1904
19U5
1906
170?
1900
1909
1990
1991
1992
1993
1994
1995
1996
1997
1770
1999
PEAK
PEHANB
(MM)
421.3
433.9
446.9
440.3
4/4.1
400.4
503.0
510.1
533.7
549.7
544.2
503. 1
400. A
410.6
437.2
454.3
476.0
696.3
717.2
730.7
PEAK
CROil Til
RESERVE
MARGIN
CAP AH
AT PEAK
YR EN6
CAP
RAPACITY
PACTOR
(Z>
(HH)
3149.2
9.0
2065.7
3743.6
9.0
2951.7
3340.9
9.0
3040.3
3441.2
7.0
3131.5
3544.4
9.0
322S.4
3650.7
9.0
3322.2
3740.3
9.0
3421.8
3873.1
7.0
3524.5
3709.3
7.0
3630.2
4100.9
7.0
3739.1
SALES
GRUUItl
tz>
3.0
3.0
3.0
3.0
3.0
3.0
3.0
3.0
3.0
3.0
LOAD
TACTOR
< X >
7.0
2132.4
3.0
43.5
7.0
2196.3
3.0
63.5
7.0
2262.2
3.0
43.5
7.0
2330.1
3.0
63.5
7.0
2400.0
3.0
63.5
7.0
2472.0
3.0
63.5
7.0
2546.2
3.0
63.5
7.0
2622.6
3.0
63.5
7.0
2701.2
3.0
63.5
7.0
2702.3
3.0
63.5
63.5
63.5
63.5
63.5
63.5
63.5
63.5
63.5
43.5
63.5
-------
Exhibit Vl-fl
UNIT POLLUTION CONTROL COSTS USED TO
DEVELOP POST-1984 COST ASSUWTIONS
(1982 dollars)
Capital
S/leW
0AM
Cailla/kMh)
Capacity
Panalty
(S capacity)
Enargy
Panalty
(S ganaration)
Eastern 90S Mat Scrubbing:
Hiah-Sulfur Coal
Scrubbar
Maata Diapoaal
TSP Control
127.42
55.96
45.03
1.83
0.37
0.21
2.18
0.03
0.21
3.54
0.03
0.21
Maatam 70S Dry Scrubbing:
Low-Sulfur Coal
Scrubbar
Waata Diapoaal
TSP Control
83.99
4.47
68.51
1.0B
0.51
0.72
o o o
3 8 tt
1.43
0.00
0.95
Waatam 90S Nat Scrubbing i
Low-Sulfur Coal
Scrubbar
Maata Diapoaal
TSP Control
116*35
24.34
74.27
1.67
0.22
0.36
1.53
0.00
0.21
3.43
0.00
0.21
Soureat EPA.
-------
ErfUbit VI-9
riNANCXAL EFFECTS OF POLLUTION CONTROL EH»ENDITURES
BY UNITS IN EXISTENCE AS OF 1579, PLUS COAL
CONVERSIONS AM) RETROFITS«
BASE CASE SCENARIO
(billions of 1982 dollars)
1980
1985
1990
1999
Chsnoss in Plant In-Service*
Total for Year
Total sines 1979
1.20
1.20
0.54
6.83
0.00
8.78
0.00
8.78
External Financina
Total for Yaar
Total sines 1979
2.17
2.17
0.07
4.53
(0.30)
4.04
(0.11)
2.45
Doeratino Revenues
Total for Yaar
Total aincs 1979
8.21
8.21
9.03
51.52
8.59
95.13
7.37
166.31
Oosrations snd Maintenance Exoensss*
Total for Yaar
Total sines 1979
7.23
7.23
7.56
44.62
7.54
82.37
7.20
149.37
Consumer Chaross (mills/WWh)
Average for Yaar
3.86
3.66
3.01
1.98
^Excludes changes in construction work in prograaa.
^Excludes ruclssr fuel.
Sourcs: PT»(Elsctric Utilitiss).
-------
Exhibit VI-10
FINANCIAL EFFECTS OF POLLUTION CONTROL EXPENDITURES
BY UNITS CJHING INTO SERVICE DURING 1980-1984.
BASE CASE SCENARIO
(billions of 1982 dollars)
1980
1985
1990
1999
Chinass in Plant IrvSsrvies1
Total for Ysar
Total sines 1979
1.56
1.56
0.00
8.07
0.00
8.07
0.00
8.07
Extsmal Finaneina
Total for Year
Total sines 1979
3.19
3.19
(0.33)
6.17
(0.17)
5.07
(0.06)
4.20
Oosrstino Revenues
Total for Ysar
Total aines 1979
0.23
0.23
2.18
7.14
1.53
15.80
1.09
26.99
ODsrstions and Haintsnanes Exosnsss?
Total for Ysar
Total sines 1979
0.16
0.16
0.90
3.51
0.91
8.00
0.92
16.22
Consuaer Charaes (mills/kMh)
Averege for Ysar
0.11
0.88
0.53
0.29
^Exclude* cbangss in construction *ork in progress.
Excludes nuclssr fuel.
Sourest PT«(El*etric Utilities).
-------
Exhibit VI-11
FINANCIAL EFFECTS OF POLLUTION CONTROL EXPENDITURES
BY UNITS COMING INTO SERVICE AFTER 1984i
BASE CASE SCENARIO
(billions of 1982 dollar*)
1980
1985
1990
1999
Chanoss in Plant In-Service1
Total for Ysar
Total since 1979
0.00
0.00
2.85
3.55
3,98
18.99
7.36
70.43
External Financing
Total for Year
Total sines 1979
0.00
0.00
2.55
6.16
2.97
19.32
7.03
61.53
Ooersting Revenues
Total for Year
Total sines 1979
0.00
0.00
0.06
(0.36)
3.11
9.48
10.26
69.96
Ooerstions snd Msintenanee Expenses^
Total for Ysar
Total aines 1979
0.00
0.00
0.15
0.15
0.97
3.21
3.90
24.70
Consuner Chsraes (nills/kWi)
Avsrsgs for Year
0.00
0.02
1.08
2.74
^Excludes changes in construction work in progress.
Excludes nuclear fuel#
Source: PTaCElectric Utilities)*
-------
Exhibit VI-12
FINANCIAL EFFECTS OF FUEL PREMIUMS
FOR UNITS IN EXISTENCE AS OF 1579:
BASE CASE SCENARIO
(billion# of 1982 dollars)
1980
1985
1990
1999
Owno** in Plant Ir.-S.rvic*1
Total for Year
0.00
0.00
0.00
0.00
Total sine* 1979
0.00
0.00
0.00
0.00
External f inaneing
Total for Year
0.00
0.00
0.00
0.00
Total sine* 1979
0.00
0.00
0.00
0.00
Ooeretinc R»v*ny**
Total for Year
5.63
5.2ft
4.76
3.79
Total sine* 1979
5.63
32.70
57.35
96.45
Ooarstiona and Maintenance Exsenee*^
Total for Y*ar
5.84
5.47
4.97
3.95
Total tine* 1979
5.8ft
34.09
59.80
100.52
Concwer Charts** (Kills/kMO
Average for Year
2.65
2.12
1.68
1.00
^Excludes changes in construction work in progress.
Excludes nuclssr fusl.
Sourest PT«(Electric Utilitias),
-------
Exhibit VI—13
FINANCIAL EFFECTS OF ALL POLLUTION CONTROL EXPENDITURES,1
EXCLUOING FUEL PREMIUMS, FOR UNITS IN EXISTENCE AS OF 1979:
BASE CASE SCENARIO
(billion, of 1982 dollars)
1980
1985
1990
1999
Chanees in Plant In-Service*
Total for Year
0.00
0.00
0.00
0.00
Total since 1979
0.00
0.00
0.00
0.00
External Financinq
Total for Year
(0.28)
(0.16)
(0.08)
(0.03)
Total since 1979
(0.28)
(1.31)
(1.86)
(2.28)
Ooeratino Revenues
Total for Year
2.45
2.25
2.11
2.48
Total sines 1979
2.45
13.99
24.68
45.00
Ooerations end Maintenance Exoenses^
Total for Year
1.29
1.52
1.77
2.43
Total sines 1979
1.29
6.42
16.76
35.69
Consumer Chaross (Mills/kWh)
Average for Yeer
1.15
0.91
0.74
0.67
1A» defined in this study.
^Excludes changes in construction work in progress.
^Excludes nuclear fuel.
Source: PTm(Electric Utilities).
-------
Exhibit VI-14
FINANCIAL EFFECTS CF FUEL PREMIUMS
FOR UNITS COMING INTO SERVICE AFTER 1979,
PLUS COAL CONVERSIONS!
BASE CASE SCENARIO
(billion* of 1982 dollars)
I960
1985
1990
1999
Chanoiaa in Plant {f»-S«rvip*^
Total for Yaar
Total tinea 1979
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Extamal financing
Total for Yaar
Total ainea 1979
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Oseratira Rfyjpnoaa
Total for Yaar
Total ainoa 1979
0.05
0*05
0.32
1.19
0.44
3.16
0.79
7,76
Ooarationa and Maintananea Exuanaaa2
Total ror Yaar
Total ainea 1979
0.05
0.05
0.33
1.24
0.46
3.30
0.62
8.10
Conauaar Charaaa (•liif/'fWh)
Avaraga for Yaar
0.02
0.13
0.16
0.17
^Excludes changaa in eonsfcruetion work in prograaa.
*Excludaa nuclaar fuel.
Soureat PT«(Elaetric Utilitiaa).
-------
Exhibit VI-15
FINANCIAL EFFECTS OF S02 CONTROLS INSTALLED AFTER 1979
(EXaiJDINC SOLID MASTE DISPOSAL COSTS AND FUEL PREMIUMS) s
BASE CASE SCENARIO
(billion* of 1982 dollars)
1980
1985
1990
1999
Chanoes in Plant In-Service1*
Total for Year
1.32
1.64
1.99
3.73
Total tinea 1979
1.32
8.91
17.40
43.32
Extarnal Financina
Total for Year
2.72
1.19
1.30
3.51
Total sines 1979
2.72
8.78
19.77
35.21
Ooeratino Ravenuss
Total for Yaar
0.17
1.75
3.02
6.31
Total since 1979
0.17
5.31
17.95
59.30
Ooarationa and Haintanancs Exoeneas*
Total for Yaar
O.U
0.72
1.25
2.91
Total sines 1979
0.11
2.49
7.61
26.05
Coneuaer Charoas (aillaAMO
Average for Year
0.08
0.71
1.05
1.70
Excludes changes in construction work in progress.
^Excludes nuclear fuel.
Source: PTa(Elactric Utilitiea).
-------
Exhibit VI-16
FINANCIAL EFFECTS OF TSP CONTROLS INSTALLED AFTER 1979
(EXCLUDING SOLID WASTE DISPOSAL COSTS) t
BASE CASE SCENARIO
(billion* of 1982 dollars)
1980
1985
1990
1999
Chanoaa in Plant In-Sarvie#1
Total for Yaar
Total tinea 1979
0.88
0.88
0.88
S.«
0.92
10.07
1.70
21.94
Extarnal Financina
Total for Yaar
Total ainea 1979
1.81
1.81
0.61
5.41
0.54
8.18
1.58
17.24
Ooaratina Rtvanusa
Total for Yaar
Total ainea 1979
0.04
0.04
0.74
2.01
1.19
2.08
2.23
22.04
Ooaration* and H«lnttosnc»LxMn»tt2
Total for Yaar
Total ainoa 197?
0.00
0.00
0.02
0.02
0.14
0.45
0.56
3.51
Conauaar CharoM (ailla/kMO
Avaraga for Yaar
0.02
0.30
0.41
0.59
kxoludaa ohangaa in construction «ork in prograaa.
*€xclu6m nuelMr fu«l.
Soureai PTa(Elaetric Utilities).
-------
Exhibit Vl-17
FINANCIAL EFFECTS OF SOLID WASTE DISPOSAL COSTS
INCURRED ATTER 1979t
BASE CASE SCENARIO
(billion of 19B2 dollar*)
1980
1985
1990
1999
Chanass in Plsnt In-5«rvic«^
Total for Yssr
0.25
0.43
0.54
0.98
Total since 1979
0.Z5
1.85
4.10
10.98
External Financina
Total for Yssr
0.56
0.33
0.36
0.91
Total since 1979
0.56
1.93
3.59
9.03
Ooeratino Revenues
Total for Year
0.08
0.64
1.03
1.85
Total aince 1979
0.08
2.15
6.53
19.40
Ooeretiona and Haintenence Exosnses^
Total for Yeer
0.07
0.45
0.61
0.97
Total aince 1979
0.07
1.67
4.41
U.48
Coneuner Chsross (eills/kMh)
Averege For Year
0.04
0.26
0.35
0.49
^Cxeludee ehang** in construction work in progress.
^Excludea nuclear fuel.
Source: PTe(Electric Utilities).
-------
Exhibit VI-18
FINANCIAL EffECTS or WAFER POLLUTION CONTROLS
INSTALLED AFTER 1979:
BASE CASE SCENARIO
(billions of 1962 dollan)
1980
1965
1990
1999
CKmm in Plant In-Sarvica1
Total for Yaar
0.2B
0.42
0:54
0.96
Total ainea 1979
0.28
2.01
4.27
11.04
tomiLLiaesiDa
Total foe Yaw
0.57
0.33
0.37
0.88
Total ainea 1979
0.57
2.05
3.73
8.98
9wmi"9 Rrrvf
Total for Yaar
0.02
0.33
0.68
1.47
Total ainea 1979
0.02
0.95
3.64
13.31
Operation* antf Maintananca £*>•*••. 2
T-otal for Yaar
0.01
0.11
0.24
0.59
Total ainea 1979
0.01
0.35
1.26
4.94
Conau—r Charoaa (aillm/kWh)
Avaraga for Yaar
o.m
0.13
0.23
0.39
kxcludM ehangaa in construction work in program.
*Exeludaa nuclaar fuel.
Soureai PTa(Elactric Utilitiaa).
-------
£*)ibit VI-19
FINANCIAL EFFECTS OF ALL POLLUTION CONTROL EXPENDITURESJ1
2 PERCENT GROWTH RATE SCENARIO
(billion* of 1962 dollars)
1980
1985
1990
1999
Chenoea in Plant In-Serviee*
Total for Yaar
Total aines 1979
2.11
2.11
2.03
13.39
2.16
23.49
4.08
53.64
External financing
Total for Yaw
Total ainct 1979
4.04
4.04
1.20
11.43
1.22
17.35
1.80
37.41
Ooeratino Revenues
Total for Yaar
Total tinea 1979
B.22
8.22
10.29
54.13
11.21
108.22
14.26
220.31
Ooarationa and Maintenance Exoeneee3
Total for Yaar
Total since 1979
7.31
7.31
8.17
46.38
8.72
88.98
9.95
173.3
Conatmr Charoes (ailla/kWh)
Average for Yaar
3.90
4.41
4.36
4.64
*Ae defined in this etudy.
Excludes changea in conatructlvi work in progreae.
'Exeludee nuclear fuel.
Sources PTa(Eiectric Utilitiao).
-------
Exhibit VI-20
FINANCIAL EFFECTS OF ALL POLLUTION CONTROL EXPENDITURES:1
NO NUCLEAR ADDITIONS AFTER 1989 SCENARIO
(billion* of 1962 dollars)
1980
1985
1*990
1999
Charms in Plant In-Ssrvics^
Total for Yaar
Total sine* 1979
2.76
2.76
3.40
18.45
5.29
37.49
8.74
101.09
Extsmal Finaneino
Total for Yaar
Total aine* 1979
5.36
5.36
2.29
16.86
3.66
31.26
7.84
79.91
Oosratino Rsvsnuss
Total for Year
Total sines 1979
6. 44
8.44
11.27
58.30
13.30
120.29
21.12
276.40
Oosrstions and Maintsnane* Exoansss^
Total for Yaar
Total ainoa 1979
7.39
7.39
8.61
48.28
9.52
93.69
13.04
195.85
Consular Charoaa (milla/kWh)
Avaraga for Yaar
3.97
4.56
4.65
5.65
1As dafinad in this study.
^xcludaa ehangaa in construction work in progress.
^Exclude* nuclaar fual.
Sourcs: PT«(El«etric Utilities).
-------
;
1
-------
APPENDIX A
TBE ENERGY DATABASE
-------
Appendix A
THE ENERGY DATABASE
The Energy Database is a computerized information system
developed by Temple, Barker & Sloane for the U.S. Environ-
mental Protection Agency. The information contained within
the data files was obtained from the FERC Form 67s supplied to
the Energy Information Administration of the O.S. Department
of Energy (EIA, DOE) by electric utility companies.
Because the information was obtained from the FERC Form
67s, certain limitations exist with the data. First, the
forms used contained information for 1979; therefore, any
anomalies occurring in that year will be reflected in the
data. Second, only steam-electric generating plants with a
capacity of 25 megawatts or greater are required to file the
FERC form. Therefore, smaller sized plants are not repre-
sented in the databases.
To validate the information contained in the FERC Form
67s, comparisons were made between the forms and several other
sources. These sources included:
• Generating Unit Reference File (GORF), DOE
• Steam Electric Plant Factors, 1979, National
Coal Association
• Utility FGD Survey. PEDCo
• Survey of Utility Power Plant Emissions and
Fuel Data. ICF, Inc., for EPA
• Cost and Quality of Fuels for Electric CJtility
Plants. 1980, DOE
Every reasonable attempt has been made to ensure that
numbers in the databases fall within ranges already estab-
lished in other publications.
The Energy Database consists of two sets of computer
files. The first set of data contains three computer files
describing current generating facilities and their operations.
Each of these three files describes a particular set of activ-
ities for power plants in the Energy Database. These three
-------
A-2
files are named after the type of information they contain:
"plant file," "boiler file," and "stack file."
• The plant file describes characteristics of the
power plants in general. These include the
plant1s fuel consumption; fuel characteristics,
including Btu content, sulfur content, and ash
content; characteristics of ash production and
handling; and cooling water characteristics.
Costs associated with these characteristics are
also included. (See Exhibit A-l for a more
detailed description.)
• The boiler file presents characteristics of
individual units within each plant. These
include unit fuel consumption, stack gas clean-
ing equipment for each unit, cooling facilities
on each unit, and costs and in-service dates
for the types of equipment described. (See
Exhibit A-2.)
• The stack file describes the stacks used by the
individual units., including their height and
costs. (See Exhibit A-3.)
The second set of files contains information describing
planned plant expansions and equipment changes for the period
1980 to 1984 and fuel use for 1984 and 1989. This set con-
sists of two computer files, one describing future plant level
operations and the other describing future unit level opera-
tions. These two files are called the "future plant file" and
the "future boiler file."
• The future plant file projects for 1979, 1984,
and 1989 both fuel consumption, including char-
acteristics of the fuel, and plant-level emis-
sions for air, water, and solid wastes. (See
Exhibit A-4.)
• The future boiler file forecasts the units and
pollution control equipment to be associated
with these units. This file includes the same
type of information included in the boiler file
but for future periods. (See Exhibit A-5.)
-------
A-3
Each of the files described above can be examined inde-
pendently, and comparisons can be drawn between the plants,
the boilers, or the stacks within each file. The files cam
also be related, however, producing complete profiles of
plants within a utility of boilers and stacks within the
plants, and of future plans for the plants.
In addition to the five files developed from the FERC
Form 67s, another file concerned with plant emissions data was
also built.
• The emissions data file contains information
describing calculated current emissions and
allowable emissions for sulfur -dioxide and
total suspended particulates on a unit-level
basis. Also included are the ratios of calcul-
ated to allowable emissions for both SO2 and
TSP. (See Exhibit A-6.)
The emissions data file was developed from the ICF report
Review of Calculated and Allowable Emissions for Exisinq Util-
ity Steam Powerplants, prepared for EPA in October 198 0.
An additional capability of the Energy Database is its
coxnpatability with other databases already developed. Its
files of this system can be matched with other databases to
supplement the information in each. For the analysis of this
study, the databases were matched frequently with the comput-
erized DOE Generating Unit Reference File for both validation
requirements and additional information.
The capabilities of the Energy Database cam be seen in
the chapters of this report. Data for the unit level, region-
al, and national analyses were supplied, primarily, by the
Energy Database.
-------
Exhibit A-l
Data File Naae: PLANT.FILE
Item Name
PLANT.CODE
UTILITY.CODE
UTILITY.NAME
PLANT.NAME
COUNTY
STATE
FED.REGION
COAL. CONSCJ MPT
COA1.BTU
COAL.%.SOLFOR
COAL.%.ASH
OIL.CONSUMPT
OIL.BTO
OIL.%.SULFUR
Description
Plant code of plant in question;
provides relational key to other
files in system.
First six numbers of the PLANT.CODE
through which particular utilities
can be selected.
Name of the utility that operates
the plant.
Plant name.
County in which the plant is
located.
State in which the plant is located.
Federal region in which the plant is
located.
Amount (in 1000 tons) of coal con-
sumed by all units in the plant.
Average Btu content (in Btu per
pound) of coal consumed by plant.
Average sulfur content (in percent
by weight) of coal consumed by
plant.
Average ash content (in percent by
weight) of coal consumed by plant.
Amount (in 1000 bbls) of oil con-
sumed by all units in the plant.
Average Btu content (in Btu per
gal.) of oil consumed by the plant.
Average sulfur content (in percent
by weight) of oil consumed by the
plant.
-------
Exhibit A-l (continued)
Item Name
GAS.CONSUMPT
GAS. BTU
TOT.COAL.BTD
TOT.OIL.BTU
TOT.GAS.BTO
FLY.TOTAL
FL* .SOLD
FLX.PD.DISP
BOT.TOTAL
BOT.SOIS
BOT.PD.DISP
FLi.$
BOT. $
TOT.AIR.EXP
Description
Amount (in 1000 mcf) of gas consumed
by all units in the plant.
Average Btu content (in Btu per
c.f.) of gas consumed by the plant.
Total Btu released by coal consump-
tion in millions of Btu (equals
COAL.CON50MPT * COAL.BTD * 2).
Total Btu released by oil consump-
tion in millions of Btu (equals
OIL.CONSUMPT * .042 OIL.BTU).
Total Btu released by gas consunp-
tion in millions of Btu (equals
GAS.CONSOMPT * GAS.BTU).
Total amount of fly ash resulting
from combustion (in 1000 tons).
Amount of fly ash sold (in 1000
tons).
Amount of fly ash disposed of by
contractors off site (in 1000 tons).
Amount of bottom ash resulting from
combustion (in 1000 tons).
Amount of bottom ash sold (in 1000
tons).
Amount of bottom ash disposed of by
contractors off site (in 1000 tons).
Cost of fly ash collection and dis-
posal (in $1000).
Cost of bottom ash collection and
disposal (in $1000).
Total air quality control expenses
(includes fly ash collection and
disposal, bottom ash collection and
disposal, collection of other prod-
ucts from flue gas, and other air
quality expenses (in $1000)).
-------
Exhibit A-l (continued)
Item Name
AVG.DISCHARGE
WINTER.OUTFALL
WINTER.AVG.FLOW
SUMMER.OUTFALL
SUMMER.AVG.FLOW
CHLORINE
PLANT.O.M.
CHEM.COST
BOILER.CHEM
MAX.OUTFALL.TEMP
MAX.TEMP.WINTER
DISCHARGE.VOL
SEWAGE.CODE
Description
Average annual rate of discharge of
cooling water to a water body (in
C • f . S • ) .
Maximum temperature of cooling water
at outfall during winter season (in
°F).
Average winter monthly flow of cool-
ing water to a receiving water body
(in c.f.s.).
Maximum temperature of cooling water
at outfall during summer season (in
°F).
Average summer monthly flow of cool-
ing water to a receiving water body
(in c.f.s.).
Amount of chlorine added to cooling
water during year (in lbs).
Annual operation and maintenance
expenses for the cooling water oper-
ation at the plant (in $1000).
Annual cost of chemical additions to
cooling water at plant (in $1000).
Annual cost of chemical additions to
boiler water makeup and boiler blow-
down treatment (in $1000).
Maximum allowable tenperature of
cooling water at outfall: summer
(in °F).
Maximum allowable temperature of
cooling water at outfall: winter
(in °F).
Total discharge of bottom ash to
settling pounds (in c.f./year).
Code for plant sewage disposal.
-------
Exhibit A-2
Data File Name: BOILER.FILE
Item Name
PLANT.CODE
BOILER.NO
FUEL.COAL
FUEL.OIL
FUEL.GAS
CAPACITY.
STACK.NO
WET.DRY
FIRING
COAL
OIL
GAS
FGC
FGC.EFF
FGC.INSERV
FGC.Cost
ESP.
ESP.EFF
Description
Plant code of the plant in which the
unit is located.
Boiler number of this unit.
Amount of coal consumed by unit (in
1000 tons).
Amount of oil consumed by unit (in
1000 bbls).
Amount of gas consumed by unit (in
1000 mcf).
Capacity factor of unit.
Number of the stack associated with
the unit.
Wet or dry bottom.
Type of firing.
Code identifies whether the unit is
able to burn alternate fuel.
Type of FGC (flue gas cleaning)
equipment associated with unit.
Removal efficiency of the FGC equip-
ment.
In-service year of FGC equipment.
Cost of FGC equipment (in $1000).
Type of ESP (electrostatic precipi-
tator) associated with unit.
Removal efficiency of the ESP equip-
ment.
-------
Exhibit A-2 (continued)
Item Name
ESP.INSERV
ESP.COST
FGD
FGD.EFF
FGD.ItfSERV
FGD.COST
CAPACITY .MW
COOL.TYPE
YR.INST
OTC.COST
CP.COST
CT.COST
SOURCE.OTC
SOURCE.CP
BOILER.YR
KWH
Description
In-service year of ESP equipment.
Cost of ESP equipment (in $1000).
Type of FGD (flue gas desulfuriza-
tion) equipment associated with
unit.
Removal efficiency of FGD equipment.
In-service year of FGD equipment.
Cost of FGD equipment (in $1000).
Rated generating capacity of the
unit in megawatts.
Type of cooling facilities associ-
ated with unit.
Year cooling facilities were
installed.
Cost of cooling facilities
associated with the unit—OTC/ once-
through cooling; CP/ cooling pond;
CT/ cooling tower (in $1000).
Name of water source if unit uses
once-through cooling facilities.
Name of water source if unit uses
cooling ponds.
In-service date of the unit.
Generation for 1979 for the unit.
-------
Exhibit A-3
Data File Name: STACK.FILE
Item Name Description
PLANT.CODE Plant code of the plant in which the
stack is located.
STACK.NO Number of the stack.
COST Cost of the stack (in $1000).
HEIGHT Height of the stack (in feet).
-------
Exhibit A-4
Data File Name: FUTURE.PLANT.FILE
Item Name
PLANT.CODE
PLANT.NAME
COAL.CONS.8 4
COAL.CONS.89
COAL.BTO.84
COAL.BTU.89
COAL.%S.84
COAL.%S.89
R£S.OIL.CONS.84
RES.OIL.CONS.89
RES.OIL.%S.84
RES.OIL.%S.89
DIS.OIL.CONS.84
DIS.OIL.CONS.89
CR.OIL.CONS.84
CR.OIL.CONS.89
CR.OIL.%S.8 4
CR.OIL.%S.89
GAS.CONS.84
GAS.CONS.89
TOT.TSP.79
TOT.TSP.84
TOT.TSP.89
TOT.SOX.79
TOT.SOX.84
TOT.SOX.89
TOT.NOX.79
TOT.NOX.84
TOT.NOX.89
Description
Plant code of plant in question.
Plant name.
Projected coal consumption (in 1000
tons), Btu content (in Btu/lb),
and sulfur content (in percent by
weight) of the coal for 1984 and
1989.
Projected residual oil consumption
(in 1000 bbls) and average sulfur
content (in percent by weight) of
the oil for 1984 nd 1989.
Projected distillate oil consumption
(in 1000 bbls) for 1984 and 1989.
Projected crude oil consumption
(in 1000 bbls) and average sulfur
content (in percent by weight) of
oil for 1984 and 1989.
Projected gas consumption (in 1000
mcf) for 1984 and 1989.
Projected total particulate
emissions (in 1000 tons/year) for
1979, 1984, and 1989.
Projected total sulfur oxide
emissions (in 1000 tons/year) for
1979, 1984, and 1989.
Projected total nitrogen oxide
emissions (in 1000 tons/year) for
1979, 1984, and 1989.
-------
Exhibit A-4 (continued)
Item Name
OTC.%.84
OTC.%.89
WCT.%.8 4
WCT.%.89
DCT.%.8 4
DCT.%.89
CP.%.84
CP.%.89
AVG.WITHDL.8 4
AVG.WITHDL.89
AVG.T.RISE.84
AVG.T.RISE.89
AVG.RETURN.84
AVG.RETURN.89
TOT.ASH.84
TOT.ASH.89
STACK.WASTE.8 4
STACK.WASTE.89
PGD.REGEN
Description
Percent of capacity cooled by the
following types of cooling
facilities for 1984 and 1989: OTC—
once-through cooling; WCT—wet
cooling tower; DCT—dry cooling
tower; CP—cooling pond.
Projected average water withdrawal
from water body (in c.f.s.) for 1984
and 1989.
Projected average temperature across
condensers (in °F) for 1984 and
1989.
Projected average water return to
water body (in c.f.s.) for 1984 and
1989.
Projected total top and bottom ash
(in 1000 tons/year) for 1984 and
1989."
Projected stack scrubbing waste (in
1000 tons/year) for 1984 and 1989.
Is the FGD system regenerable?
-------
Exhibit A-5
Data File Name: FUTURE.BOILER.FILE
Ttgm M»ma
PLAWT.NAME
PLANT.CODE
BOILER.NO
NU.STACK.NO
NU.MW.CAPACITY
NU.INSERV
NU.COAL.PER.HR
NU.OIL.PER.HR
nu.gas.per.hr.
NU.OTHER.FUEL
NU.PRIM.FUEL
NU.BOTTOM
NU .FIRING
FUEL.TYPE
BOILER.CAT
TSP.REG
Description
Plant name.
Plant code of plant in which the
unit is located.
Boiler number of planned unit.
Stack number of planned unit.
Capacity of planned unit (in
megawatts).
In-service date of planned unit.
Coal consumption of planned unit (in
tons/hour).
Oil consumption of planned unit (in
bbIs/hour).
Gas consumption of planned unit (in
1000 c.f./hour).
Consumption of other fuels of the
planned unit.
Primary fuel to be fired in planned
unit.
Wet or dry bottom of planned unit.
Type of firing of planned unit.
Fuel type (of existing or planned
unit).
Code describing the type of boiler
being reported.
Limiting TSP regulation; federal,
state, or local requirement.
-------
Exhibit A-5 (continued)
Item Name
NEWBOIL.TSPCOD
NEW30IL.TSPLIM
TSP.STRATEGY
SOX.REG
NEWBOIL.SOXCOD
NEWBOIL.SOXLIM
SOX.STRATEGY
PREC.BOILER.CAT
PREC.STACK.HO
PREC.RETRO
PREC.TYPE
PREC.INSERV
PREC.FUEL.DSN
PREC.*.S.DSN
PREC.%.ASS.DSN
PREC.EFFIC
Description
Units of TSP requirement (e.g.,
lb in Btu, lb/hour, or grains/stand-
ard cubic foot).
Actual TSP requirement in above
units.
Strategy for meeting TSP require-
ment.
Limiting SOX regulation; federal,
state, or local requirement.
Units of SOX requirement.
Actual SOX requirement in above
units.
Strategy for meeting SOX require-
ment.
Code describing boiler and its
relation to a TSP system.
Stack associated with TSP equipment.
Will particulate equipment be
retrofit?
Type of particulate removal equip-
ment to be installed (for planned or
existing equipment).
In-service date of particulate
equipment.
Type of fuel particulate equipment
is designed to handle.
Percent sulfur fuel specification
for particulate equipment.
Percent ash fuel specification for
particulate equipment.
Particulate equipment design removal
efficiency.
-------
Exhibit A-5 (continued)
Item Name
PREC.MER
PREC.EQ.COST
TOT.PREC.COST
PREC.ENERGY.OM
PREC.WASTE.OM
PREC.TOT.OM
PGD.BOILER.CAT
FGD.STACK.NO
PGD .TYPE
PGD.SCRUB
PGD.INSERV
PGD.CAPACITY
PGD.%S.DSN
PGD.%ASH.DSN
pgd.%chl.dsn
Description
Particulate equipment's designed
mass emission rate.
Equipment and installation cost
($/kWh) for particulate equipment.
PREC.EQ.COST plus other capital
costs ($/kWh).
Operating and maintenance expense
associated with energy for the par-
ticulate control equipment.
Operating and maintenance expense
associated with waste disposal for
the particulate control equipment.
Total operating and maintenance
expense associated with the partic-
ulate control equipment (includes
PREC.ENERGY.OM and PREC.WASTE.OM).
Code describing boiler and its
relation to a FGD system.
Stack associated with PGD equipment.
Type of FGD equipment to be in-
stalled on existing or planned
units.
Wet or dry scrubbing.
Date of commercial operation of the
FGD equipment.
FGD unit capacity (in megawatts).
Percent sulfur in fuel for which the
FGD unit was designed.
Percent ash in fuel for which the
FGD unit was designed.
Percent chlorine in fuel for which
the FGD unit was designed.
-------
Exhibit A-5 (continued)
Item Same
%GAS.TREATED
FGD.BYPASS
FGD.DSN.EFF
FGD . ACT . EFFIC
WITHPREC.EFFIC
FGD.DSN.MER
FGD.LIFE
SLDG.DISP
SUDG.STABLE
POND.REQ
POND.LINED
FGD.INST.COST
FGD.ANCIL
SLDG.DSP.COST
SYS.REV
REG.SYS.COST
Description
Percent of total gas which passes
through the FGD equipment.
Capability to bypass the FGD equip-
ment .
Design removal efficiency (percent
by weight of SO2 removed) of FGD
unit.
Actual removal efficiency (percent
by weight of SO2 removed) .of FGD
unit.
Removal efficiency if particulate
scrubber included on unit.
FGD design mass emission rate.
Estimated useful life of the FGD
unit.
Sludge disposal: on or off site.
Is sludge stabilized?
Pond or landfill requirements (in
acre-feet/year).
Is the sludge pond lined?
Installed capital cost of the FGD
unit (in $/kWh).
Installed capital cost of ancil-
laries (in $/kWh).
Capital costs for sludge disposal
site preparations and waste trans-
port system (in $/kWh).
Revenue from sale of regenerable
product (in $/kWh).
Installed capital cost of regener-
able system (in $/kWh).
-------
Exhibit A-5 (continued)
Item Name
FGD.OTHER.COST
WASTE.OP£R.COST
FGD.TOT.OP.CST
FGD.TOT.MNTC
FGD.ELEC.DEM
FGD.REHEAT.DEM
FGD.SCRCJB.fiRS
FGD. AVG. CAPACITY
FGD.FOR
FGD.FOR.CAPACITY
FGD.RED.LD
FGD . RED . LD . CAP
Description
Other capital costs for FGD system
(in $/kWh).
The waste disposal component of
operating expenses for the FGD unit
(in $/kWh>.
Total operating expenses attribut-
able to the FGD unit (in $/kWh).
Total maintenance expenses attribut-
able to the FGD unit (in $/kWh).
Electrical demand by the FGD unit
(in kWh/h).
Reheat electrical demand equivalent
(in JcWh/h).
Hours of scrubber operation.
Average scrubber capacity during the
year (in MW).
Number of hours during the year that
the boiler was forced out of service
due to an FGD system outage.
Average outage capacity level (in
MW).
Number of hours during the year that
the boiler was forced to operate at
a reduced load due to FGD system
limitations.
Average load reduction capacity
level.
-------
Exhibit A-6
Data File Name: EMISSIONS.DATA.FILE
Item Name
Description
PLANT.CODE
UNIT.NO
FUEL.TYPE
S02.CALC.EM
TSP.CALC.EM
S02.ALLOW.EM
TSP.ALLOW.EM
SO2.RATIO
TSP.RAT10
Plant code of plant in which the
unit is located.
Boiler number of unit.
Emissions for unit associated with
burning this type of fuel (coal,
oil, gas).
Unit's calculated SO2 emission given
fuel consumption (1,000 tons).
Unit's calculated TSP emission given
fuel consumption (1,000 tons).
Allowable SO2 emission for unit
under current regulations (1,000
tons).
Allowable TSP emission for unit
under current regulations (1,000
tons).
Ratio of calculated to allowable
emissions for the unit.
Ratio of calculated to allowable
emissions for the unit.
-------
APPENDIX B
PTm(ELECTRIC UTILITIES)
RESEARCH METHODOLOGY
-------
Appendix B
PTa(ELECTRIC UTILITIES)
RESEARCH METHODOLOGY
This appendix on research methodology consists of a non-
technical overview of the logical structure of the computer
model/ PTm(Electric Utilities)/ used to derive the projections
discussed and analyzed in the text of this report. In broad
terms/ PTm has three main logical components/ which may con-
veniently be labeled the external, physical/ and financial
modules. As shown in Exhibit B-lf it is assumed that general
economic conditions and other factors outside the model deter-
mine the demand for electricity. Expectations regarding fu-
ture generation expansion plans/ and the equipment/ power
drain, and generating efficiency implications of pollution
control requirements/ combine to determine the industry's
physical plant, equipment, fuel/ and labor requirements.
These physical requirements and the relevant factor costs,
which are also influenced by economic considerations external
to PTm, combine to determine the consequences of building and
operating the capacity.
The capital asset and operating cash requirements implied
by the capacity expansion plan are met in part by revenues
collected from the users of electrical energy and in part by
external financing. The amount of cash provided by operations
at any moment is influenced by regulatory policy (in effect
via the allowed revenue per kilowatt-hour), by tax policy (via
the effective rate of taxation after consideration of depreci-
ation tax shields, investment tax credits, etc.), and by the
cost of capital raised in prior periods. Any shortfall be-
tween cash needs and the cash provided by operations is met by
recourse to the capital markets.
Exhibit B-l omits a number of interactions and feedbacks,
two of which are notable. First, if external financing is to
be available, regulatory policy must be such as to allow reve-
nues per kilowatt-hour sufficient to yield returns to capital
that are adequate in light of prevailing capital market condi-
tions, tax policy, and pollution control requirements, all of
which may have am impact on the cost of electrical power and
hence on demand. As a second illustration, because the finan-
cial characteristics of the electric utility industry and of
individual utilities may be considered in the drafting and
administration of pollution control legislation, pollution
-------
3-2
control policy in part determines and in part is determined by
the industry's financial profile.
EXTERNAL MODULE
The model's external module has as its primary function
the inputting of assumptions, such as those concerning future
growth in generating capacity, operating costs, future pollu-
tion control requirements, etc. The implications of these
policy, economic, and technical assumptions are then deter-
mined in the physical and financial modules of PTm. PTm is
programmed so as to be able to test a wide variety of policy
altarnatives through changes in input data.
PHYSICAL PLANT AND EQUIPMENT MODULE
The primary relationships determining the industry's
physical plant and equipment requirements are shown in
Exhibit B-2. The industry's gross generating capacity in
service at any moment is typically determined by the level of
demand, the industry's policy with respect to capacity re-
serves, and the effect of pollution control equipment and in-
plant power requirements. However, for consistency with an-
other recent study for £PAr PTm was modified to accept pro-
jections of future capacity additions and retirements as di-
rect inputs. With the inclusion of the pollution control
equipment required for generating capacity currently in serv-
ice, the additions to in-service plant and related equipment
are fully specified in physical terms.
Given the long time lags involved in constructing new
generating capacity, the industry's plant and equipment con-
struction at any moment typically includes significant amounts
of work in progress. As is shown in Exhibit 3-2, future ca-
pacity additions and future pollution control requirements—
together, with the lags in construction—determine plant con-
struction in progress. It should be noted that because the
time span between ordering and placing generating capacity in
service is radically different for hydro facilities, peaking
units, fossil-fueled baseload plants, and nuclear units, PTm
computes construction work in progress for plants by fuel type
on different time schedules. Thus average construction lags
are_themselves a function of the assumed future mix of these
various types of generating plants.
-------
B-3
FINANCIAL MODULE
For expositional purposes it is convenient to divide
PTin's financial modules into three segments, dealing with:
• Uses of funds,
• Sources of funds, and
• Revenues and related variables.
Pses of Funds
The industry's uses of funds depicted in Exhibit B-3 are
determined primarily by the physical plant and equipment re-
quired to meet current and future demand and by the cost per
unit of this equipment. A second use is the allowance for
funds tied up in plant and equipment in the process of con-
struction. For simplicity, PTm assumes that the industry's
net working capital remains constant, so that changes in work-
ing capital appear neither as a use nor as a source of funds.
Given the minuscule size of such working capital changes in
comparison with the industry's major sources and uses of
funds, such a simplifying assumption is unlikely to introduce
appreciable error in the absence of fundamental structural
changes in the industry's current assets and payables accounts
or in its usage of short-term debt.
Exhibit B-3 shows that once the total physical amounts of
plant and equipment required to meet current and future demand
and the proportions of those amounts accounted for by each
type of new capacity are determined, the crucial input assump-
tions required to convert these physical quantities into fi-
nancial terms are the cost per unit of each type of asset and
the schedule of payments required by contractors while such
plant and equipment are under construction.
Sources of Funds
In the case of the private sector of the electric utility
industry, sources of funds consist of two major elements:
• Funds provided by operations, and
• External financing.
-------
Funds provided by operations are in turn the sum of three
internal sources:
• Depreciation,
• Tax deferrals, and
• Retained earnings.
For the public sector, it is simply assumed that a per-
centage of total funds used is met from internal sources. As
is shown in Exhibit B-4A, any shortfall between total uses and
internal sources is met through external financing.
Exhibit B-4B shows these same relationships in a format
that is slightly different and that shows how the private
sector's total required external financing, capital structure,
and dividend policies combine to determine:
• Cash issues of preferred stock,
• Gross cash offerings of debt, and
• Cash issues of common stock.
Revenues and Related Variables
The third segment of the financial module determines
total industry revenues, expenses, profits, and related sta-
tistics such as price per kilowatt-hour and interest coverage
ratios. The output variables of this revenues segment serve
in many instances as inputs to other segments. For example,
the depreciation expense figure computed in the revenue seg-
ment is an input to the sources of funds segment. Conversely,
certain of the input variables to the revenue segment are
based on the output from the sources and uses segment of the
financial module (e.g., plant and equipment expenditures pro-
vide the base for computing depreciation expense). The struc-
ture of the revenue segment and the interactions between .this
segment and other parts of the total model are depicted in
Exhibit B-5.
As shown at the top of Exhibit B-5, profits available for
common stockholders are assumed to be determined completely by
the amounts of the industry's common equity capital and by a
-------
B-5
rate of return on equity set by regulatory policy.! a
consequence of this assumption, revenues and prices per kilo-
watt-hour of electricity are determined by required profits,
other capital charges, and operating expenses.
Earnings before interest and taxes (BEIT) are simply the
sum of earnings before interest taxes (EBT) and interest
expense and are computed by the same general process used for
preferred dividends. The resultant EBIT figure constitutes
one of the five main determinants of revenues.
The second determinant of revenues, depreciation and
amortization of plant and equipment, is a variable related to
the amount of plant and equipment in service. . Presuming that
taxes other than on income consist primarily of property
taxes, a third determinant of revenue, other taxes, is also
related to the amount of plant and equipment in service.
Generation expansion plans and the power drains and oper-
ating efficiency losses associated with pollution control,
equipment combine to determine the level of operating and
maintenance expenses. This latter expense figure is the
fourth determinant of revenues.
Generation expansion plans and pollution control require-
ments also determine the timing of future in-service plant and
equipment requirements and hence determine, the amount of con-
struction currently in progress. The amount of construction
in progress in turn determines the allowance-f-or-funds used
during construction, which is another non-cash item, but which
*lso affects—in this case diminishes—the level of revenues
required to achieve a given level of profit as determined by
regulatory accounting procedures. This allowance on construc-
tion funds variable is the fifth and last major determinant of
revenues.
Net profit is simply the sum of profits available for
common stock and preferred dividends. The amounts of pre-
ferred dividends are determined by the amounts of preferred
equity capital and the average dividend rate on the industry's
_ « a term intended to com-
mit should be noted that #t rates of return set by
Prise the effect of the administrative lags
individual regulatory bodie vilowatt-hour so as to
involved in adjusting prices per
Achieve such target returns.
-------
B-6
ouc.standi.ng preferred stock. The dividend yield on new pre-
ferred stock issues—and hence the average yield—is in turn
determined over time by the reaction of the capital market to
the industry's offerings.
Earnings before income taxes are then set at a level such
that EBT minus taxes will be equal to the required net profit
figure. The tax expense (or equivalently, the effective tax
rate) is itself a function of. the EBT figure, which is com-
puted in accordance with regulatory accounting procedures, and
several other factors. The calculations are somewhat compli-
cated first because various special features of the tax code
(e.g., provisions allowing investment tax credits and accel-
erated depreciation) and of regulatory accounting (e.g., the
creation d£ allowances for funds used during construction as
non-cash credits to income) must be taken into account. As a
consequence of these differing provisions, taxable EBT and
regulatory EBT may—and typically do—differ. Second, as
mentioned earlier, there exist two substantially different
regulatory methods for determining the tax expense figure to
be associated with EBT. Normalizing accounting gives rise to
deferred taxes, which are non-cash charges against income but
which nonetheless constitute an accounting expense to be
covered by revenues if accounting profits to stockholders are
to reach prescribed levels.
A CONCLUDING COMMENT
As has been outlined above, the operating, financial,
tax, regulatory, and accounting relationships and constraints
relevant to making economic and financial projections for the
industry are individually rather simple. However, the number
of these relationships and constraints is so great as to dic-
tate the use of a computer model such as PTm. Moreover, be-
cause of interactions among the various industry relationships
and constraints, attempts to reduce the number of factors
through shortcut approximations are hazardous. Furthermore,
such shortcuts, even if based on careful econometric analyses
of historical data, tend to preclude an examination of the
implications of structural and policy changes.
PTm was designed not only to compute rapidly the implica-
tions of any given set of assumptions about the future, but
also to facilitate the examination of structural and policy
changes. Thus, the model is able conveniently to accept input
-------
3-7
assumptions for over 100 variables, such as the current level
of and future changes in: the industry's peak demand? the
amount and mix of capacity additions; unit costs of generating
plants, transmission and distribution capacity, thermal and
chemical pollution equipment, etc, PTm then generates projec-
tions for*a variety of physical and financial variables, in-
cluding: generation figures for each of the major fuel seg-
ments of the industry; energy losses resulting from pollution
control equipment; income statements; balance sheets; funds
flows; reconciliations of regulatory and Internal Revenue
Service income tax expense figures; and summary statistics
such as interest coverage figures*
-------
Exhibit B—1
INTERACTIONS BETWEEN THE ENVIRONMENT AND THE PHYSICAL AND
FINANCIAL CHARACTERISTICS OF THE ELECTRIC UTILITY INDUSTRY
Demand
For Eltclilc Power
and Capacity
E upansion Flans
Pollution
Control
Policy
Plant, Equipment,
and Elect ileal
Power Production
Requirement!
Plant, Equipment,
and Operating
Cash Need*
E atarnal financing
") VARIABLES TAKEN AS GIVEN BY r Tin.
VARIABLES DETERMINED WITHIN PTm.
Source: PTm (Electric UIHItlail.
-------
Exhibit B—2
DETERMINANTS OF PLANT AND EQUIPEMENT IN SERVICE AND IN CONSTRUCTION
FOR THE ELECTRIC UTILITY INDUSTRY
Futtire Dwnami
and Capacity
Expantiofl Plant
Currant Rdktmmti
ImcKl of Fulurt Pollution
Equipment on Generating
Plant Efficiency
ComliiKliM lor
Future Requirement*
Impact ol Currant
Pollution Equipment
on Generating Plant
Efficiency
Currant Demand
and Capacity
Current Retirement*
Pollution Control
Equipment Requirements
Additions to Plant
end Equipment In
Service and In
Construction
Conftruction for
Currant Requirements
Currant Required
Gross Capacity
(^2) VARIABLES TAKEN AS GIVfcN BY PTm
] VARIABLES DETERMINED WITHIN PTm
Source: PTm (Electric Utilities).
-------
Exhibit B—3
DETERMINANTS OF USES OF FUNDS FOn THE ELECTRIC UTILITY INDUSTRY
Cost per llnil of
Plant Mid
Equipment
IZEO EXPENDITURES
E«penditiwes lot In-Smlct
Plant and Equipment
Plant and Equipment
Construction lor
Future Requirements
E xpenditure* lor Increasing
Plant and Equipment
in Construction
o
~
VARIABLES TAKEN AS OIVEN 8Y PTm
Cost per Unit ©I
Plant and
Equipment
VARIABLES DETERMINED WITHIN FTm
Plant and Equipment
Construction for Current
, Requirements
Total Usee of Funds
Allowance lor Funds Used
for Construction in
Progress'
Source: PTm (Electric UtMitlesl.
-------
Exhibit B-4
DETERMINANTS AND COMPOSITION OF TOTAL SOURCES OF FUNDS FOR THE
ELECTRIC UTILITY INDUSTRY
' ~ ~ TOTAL SOURCES OF INCOME 1
Total Utat
at Fundi
TOTAL SOURCES OF INCOME
Capital Structure
Policy
o
~
VAUIASLH TAKEN AS OtVBN BY PTm
VARIABLES DETERMINED WITHIN PTm
Profit Ayallabla
for Common
Stock
Dalil Ratiramanlf
Ending Capital
Structure
Initial Capital
Slurctwa
Total Utn
of Fund*
W««»; tlnKhcHkUtMlWI.
-------
Exhibit B-b
DETERMINANTS OF REVENUES. EXPENSES, AND PROFITS FOR THE ELECTRIC
UTILITY INDUSTRY
Capital Markat
Conditions
Prafarrad Slock
Dabt
Capital Mark at
Conditions
/ Currant \
I Damand and 1-
V Capacity J
Ragulstory
Policy
Embaddad Cost
of Prafarrad
Sloch
Prafarrad Dhridands
Embaddad Cost
olOabt
Inter ast
Pollution
Control
Policy
Oparatinf 8>
Maintananca
Enpansas
Bagulatory
Policy
Currant
Damand and
Capacity
flaturn on
Equity
Profit Availabla
For Common
Stock
Nat
P.olll
Eafniiifi bafora
Incoma Tax as
I
Earning* bafora
IntarastA Taxes
Ravanuas
Dapraciation &
Amortiiation of
Plant and Equipmant
Plant & Equipmant
In Sarvica
Common Equity
Plant !¦ Equipmant
In Sarvica
Tanas Payal>la
Incoma Tanas
Policy
Tanas
Fmuia
Damand and
Capacity
Regulatory
Policy
Allowance on
Funds Usad
During
Construction
Plant &
Equipmant
In Construction
Taxas othar
titan Incoma
Tax
Policy
Pollution
Control
Policy
Sourca: PTm (Elaclrk UlHitias).
(^) VARIABLES TAKEN AS GIVEN BV PTm
| | VAHIABLES DETERMINED WITHIN PTm
-------
APPENDIX C
CAPITAL EXPENDITURES AND ELECTRIC
UTILITY ACCOUNTING PROCEDURES
-------
Appendix C
CAPITAL EXPENDITURES AND ELECTRIC UTILITY
ACCOUNTING PROCEDURES
In Chapter VI "changes to plant in-service" or "plant
additions" are used as a measure of the total capital costs
associated with electric utility expansion plans. This ap-
pendix contrasts the definition of plant in-service used in
this study with the definition typically used in the industry
and relates those definitions to other commonly used measures
of capital costs. One of the major issues in accounting for
capital costs is the treatment of the financing costs associ-
ated with the cash outlays for construction work in progress
(CWIP). The second section of this appendix reviews the major
accounting methods used to recover financing costs and pro-
vides a brief summary of the cash flow and balance sheet
effects of these methods.
DEFINITIONS OF PLANT IN-SERVICE
AND CAPITALIZED EXPENDITURES
Changes in plant in-service, as defined for this study,
represent total cash outlays for plant construction during the
year, minus the year-to-year change in the cash a/nounts in the
CWIP account, plus the carrying charges on the past cash out-
lays still in the CWIP account (allowance for funds used dur-
ing construction—AFDC). As discussed further below, the PTm
computer model used for this study transfers AFDC directly to
the plant in-service account in the year in which it is
accrued, rather than in the year the equipment is actually
placed in service. This differs from the typical industry
practice, which retains this AFDC balance in the CWIP account
until the associated cash portion of the construction expendi-
tures is transferred to the plant in-service account.
Additions to plant in-service, using either PTm's defini-
tion or the industry's typical definition, differ from another
common measure of capital costs, namely capitalized expendi-
tures. Total capitalized expenditures typically refer to
total cash outlays and capital-carrying costs incurred during
a given period. Capitalized expenditures differ from changes
in plant in-service to the extent that beginning CWIP balances
do not equal ending CWIP balances. Capitalized expenditures
include costs (both cash outlays and financing costs) for
-------
C-2
equipment not yet placed in service. Plant in-service
excludes costs associated with ongoing construction, except
that PTm does include in the plant in-service account the
financing costs associated with CWIP balances.
TREATMENT OF FINANCING COSTS
Cash outlays for construction of new equipment are
credited to either the plant in-service account/ for outlays
associated with equipment placed into service in the current
period, or to the CWIP account, for outlays associated with
equipment that will not be placed into service until some
future period. Those cash outlays placed in the CWIP account
accrue capital-carrying charges which must be recovered.
There are two principal ratemaking methods used to ac-
count for capital-carrying costs. The first method, the AFDC
approach, treats capital costs as part of the cost of the
project. This is the most common approach used in the indus-
try, and is the approach adopted for this study. During the
period of construction, the allowance is included as a credit
to "other income" on the income statement. The amount of the
credit represents an estimate of capital-carrying charges
associated with financing construction expenditures. This
credit to othear income is an accounting entry only and does
not represent cash earnings in the current period. Instead,
the AFDC credit represents a non-cash credit to earnings; it
in effect replaces revenues collected from customers in terms
of offsetting financing costs. The capital costs accumulated
over the construction period are included in the rate base
once the plant or equipment is placed into service and are re-
covered over the useful life of the asset through financing
and depreciation charges. For the purposes of the PTm analy-
sis used in this study, the rate base is assumed to equal the
dollar value of the plant in-service account.
The second method, allowing CWIP in the rate base, con-
siders construction expenditures as part of the rate base when
they are made. Consumer rates, then, reflect capital-carrying
costs during the construction period. Allowing CWIP in the
rate base may be characterized as a "pay-as-you-go" treatment
for capital-carrying costs. Unlike the AFDC credit to earn-
ings, allowing CWIP in the rate base results in revenues and
cash earnings (as opposed to non-cash earnings associated with
the AFDC credit).
-------
C-3
Figure C-l demonstrates the differences in the two ac-
counting methods in terms of the effect on rate base rev-
enues, and earnings. The left-hand side of the diagram shows
the treatment of cash outlays associated with equipment tha*
is placed into service m the current period. The -iaht-hlnd
side of the diagram shows the treatment of cash outlaws for
equipment that will not be placed into service untilstme
future period. As indicated in Figure c-l, cash outlays for
CWIP when CWIP is included in the rate bas^ have mSch the ILne
impact on revenues as cash outlays for equipment placed inf^
service m the current period. The AFDC method, on the other
hand, does not increase rate base or revenues effects in the
year AFDC is created. The AFDC credit represents a non-cash
earnings offset to be included in plant in-service and
ferviceS€ ^ equipment is eventually placed into
A number of financial changes occur when cwtp
in the rate base. _ Consumer rates rite it
AFDC treatment, since capital-carrying charges daring col-
struction axe reflected m consumer rates immediate"? rather
than over the useful life of the asset. On the other hand
external financing requirements are lower because cwital-
carrying costs need not be financed and the cash fi££ «£.n
able to meet interest and dividends increases ih
CWIP is allowed in the rate base, totalHnancing "It^re "
lower because total assets are lower and because thlclpital
cost rates required by investors can be expected to bS
The analysis presented in this studv assume .
tion of the general industry practice of using the jJoc
approach. However, PTm does not track j ^
individual units and therefore the^U-s^iTI^ "s'a
consequence, AFDC associated with a n*r* ,• as a
be identified and include! in Jhe ml ^T P^ect ^nnot
unit comes on-1ine. The model instead computes total^CWIP®
balances and determines the AFDC associated with
balances. AFDC is allocated directly Jo the nlL? ?.
account, while CWIP, excluding the associated AFDC oor-ifn1C?«
transferred to the plant in-slrvice alcoSnt fn^K
corresponding capacity is operational. Figure C-2 S2SL
strates the differences between the industry method If
accounting for financing charges associated with
expenditures under the AFDC approach and the logil "^ In
-------
Figure C-1
ACCOUNTING TREATMENT OF CASH OUTLAYS
FOR NEW EQUIPMENT
CWIP in
Financing Costs
Plant In-Service
Earnings
Financing Costs
Rate Base
Cash
Outlays
-------
C-5
Figure C-2
DETERMINATION Of ANMJAL CHANGES TO
PLANT IN-SERVICE AND CWP ACCOUNTS:
INDUSTRY VERSUS PTw TREATSNTS1
Industry
PTm
Cash Outlay
Gross Additions to
Plant In-Service
Annual AR5C
Csah Outlay
Additions to
CWIP
Annual AfOC
iTha industry trestment described in this figure aasunrs the AFDC <*thod of accounting for the financing
costs associated with construction work in progress.
-------
C-6
,^ v. a •; between PTm and the usua^.
The result, of ^^ lower APDC amounts
industry practice is that P.m ge:n compounding of the accrued
than the industry method £fr"s®j?°short-run plant in-service
AFDC occurs Therefore, while the snort^^ ^
account will be greater under uh in ;he lon? run to the
in-service account values carbe 1 occurs. The total
extent that cumulative compounding o
CWI? and plant m-service accounts wux u ra-ias
projections by the amount of compound^DC. ^Coverage ra.ios
ment^ince^total^FDC Is tower than under the typical industry
treatment.
The actual industry dat<. used as inputs ^P^were
Hiiiors0 p »? i5i^n,iB
1979 dollars) in ^^""^"I^fLTervi^ "his amoSt is
the°estimated portion'of the CWIP account represented by
AFDC.
Table C-l provides an example of the effect on AFDC
accrual, revenue requirements, and selected balance sheet
itSS of various accounting procedures. While many simplistic
assumptions are made regarding rates of return and the timing
of accounting allocations, it does indicate the direction of
?he change in selected capital accounts under various account-
ing treatments. As indicated, short-run plant in-service ana
rate base accounts are higher using the PTm methodology
because AFDC charges are allocated directly to those accounts.
As a result short-run annual operating revenues are higher.
If CWI? is allowed in the rate base, short-run revenue re-
quirements are higher, but eventually both annual and cumu-
lative operating revenues can be lower than under^AFDC or PTm
accounting conventions. Further, evidence suggests that the
cost of capital for utilities that are allowed to include CWIP
in the rate base is lower, reducing revenue requirements sti-1
more.
-------
C--
Table C-l
EXAMPLES of VARIOUS TREATMENTS or CAP ITAL EXPENDITURES
(dollars)
Caah Outlays
Plant I
Plant 2
Typical Industry Treatment
(A FDC Method)
F io*3
Cash Outlay
A FDC1
Revenue Requirements^
Balance Sheet Jtems^
CWIP Balances
Plant In-Service
Rate Base
CWIP in Rate Base
flows
Casn Outlay
ATOC-1
Revenue Requirements^
Balance Sheet Itema^
CWIP Balances
Plant In-Service
Rate Sase
PTm Treatment
F lo*s
Cash Outlay
AFDC1
Revenue Requirements^
Balance Sheet Items-^
CWIP Balance
Plant In-Service
Rate Base
100.0
100.0
5.0
105.0
100.0
10.0
100.0
100.0
100.0
5.0
0,5
100.0
5.0
5.0
100.0
100.0
200.0
20.0
325 .0
200.0
30.0
300.0
300.0
200.0
20.0
2.5
200.0
25.0
25.0
250 .0
100.0
350.0
47.5
722.5
350 .0
65.0
650.0
650.0
350.0
47.5
7.3
35Q.0
72.5
72.5
Year
250.0
250.0
32.5
50.3
502.5
502.5
502.5
250.0
90.0
450.0
450.0
900.0
250.0
32.5
55.5
250.0
555.0
555.0
1O0.5
1,005.0
1,005.0
90.0
900.0
900.0
100.5
1,003.0
1,005.0
100.5
1,005.0
1,005.0
90.0
900.0
900.0
100.5
1,005.0
1,005.3
rate.
^AFDC is calculated on the average OH? account balance using a 10 Dereent int»
No compounding of ARX is assumed. However of t)*> M «~=)-. interest »
the National Association „ ^ulatoTyTtllity
SET""9 °f AFDC (NARUC' m ^ °n Utili;V "« C»^er
2ftevenue requirements are calculated on the end-of-ye8r rate base balance using a 10 per-
cent interest rate. ^ M
^Balance sheet items are for the end of the
-------
APPENDIX D
COAL PRICES
-------
Appendix D
COAL PRICES
The prices of^coals of different types are determined by
a variety of considerations, including the environmental regu-
lations affecting electric utilities, other factors influenc-
ing coal prices include the overall demand for energy, the
prices of oil and natural gas, the costs of burning coal ver-
sus the alternatives, the availability of reserves of dif-
ferent types of coal in various regions, minincr costs for each
type in each region, and transportation costs." This appendix
provides a brief overview of how these factors interact to
determine coal prices.
UTILITY OPERATING AND CONSTRUCTION DECISIONS
The primary determinant of coal demand is the economics
°f T ^S^^tern&^VeJUels for the generation of steam
m domestic utility and industrial boilers. Of this demand
utiUty use is by far the lar9er. coal is also used
coke for metallurgical purposes and as a source of industrial
process heat in kilns. Furthermore, coal is exported to
Europe, Asia, and elsewhere for metallurgical, utility, and
fofoT'coaH' silS ^blS 0-1 f°r da" °n 'he
for U.S. coal.) Given the central importance of domestic
Table D-l
1981 COAL USES
(millions of tons)
Utility
Industrial
Metallurgical
Export
560
71
56
111
T otal
821
Total may not add because of rounding.
Source: U.S. Department of Energy, Energy Informa-
tion Administration, Coal Distribution,
January-December 1981. April 1982.
-------
D-2
utility usage, and given that nonmetallurgical consumption is
affected by similar considerations, this appendix focuses on
how utility operating and construction decisions affect the
price of coal.
Capacity Utilization Decisions
At any particular point in time, a utility has a fixed
stock of generating equipment and, in meeting its demand for
electricity, can only control the amount of electricity it
generates in each of its units or purchases from others. This
dispatching decision is generally made to minimize the vari-
able costs of meeting any particular level of demand.
A utility's variable costs are determined by two primary
factors. The first is the delivered price per million Btu of
the available fuels that can be burned in each of the utili-
ty' s boilers (or turbines) and that can meet environmental
standards. The second is the thermal efficiency or heat rate
of each unit. (A related consideration for many utilities is
the efficiency of pumped storage for hydrogeneration.) The
product of these factors is the fuel cost per kilowatt-hour
(kWh) of generation from a particular unit. In addition to
fuel costs, the use of a particular unit may involve other
variable costs, such as incremental operation and maintenance
labor and materials expenses, but these tend to be much smal*-
ler than fuel costs and are not discussed at any length in
this appendix.
In dispatching particular units to minimize variable
costs, a utility must meet a variety of physical constraints,
including environmental requirements. They also include keep-
ing boilers operating—if only at low levels and perhaps not
producing power—to provide reliability protection for the
utility system (or power pool) or for a particular geograph-
ical zone. Furthermore, dispatching has to take account of a
variety of physical characteristics of a particular unit and
all other units in a system, such as minimum power output
levels, start-up and shut-down times, maximum rate of change
of power output, and maintenance requirements. In sum, these
constraints mean that dispatching—and hence the consumption
of coal and other fuels — is not determined solely by the
"merit order" of units (or increments of capacity for any
given unit), i.e., their variable costs per kWh when operating
at different "stops," or levels of output.
Environmental regulations affect dispatching primarily
through their effects on the costs of the fuels, on the heat
rates, and on the other variable costs of operating units so
-------
D-3
" "n,!S?hW^ th°fe reS"lati°^- I" some circumstances,
problems with the quality of ambient air or with the avail-
ability °£ cooling water may precise the operation of a init
altogether or may cause it to be operated below full output
«L 6 xS »
Fuels Conversion Decisions
i° d^sP;tc^ing decisions, where equipment
capabilities are fixed, fuels conversion decisions involve
changes in a utility s existing equipment to reduce total
costs over time, rather than the variable costs as of a nar
ticular (shorter) period of time, As discussed in cLv-
ter III, given current regulatory practices fn most ^Sisdic-
tions, fuels conversion decision* *ra ^ ,
another utility obJ^tiv.rtoiSlf'p^IdS^fLnSS^S
' ant? they may be constrained by the practica1
difficulty of raising an^ additional capital to finance ?Se
costs of conversion on reasonable terms.
Whether a utility can convert a unit to coal, which
generally has much lower current or prospective cist per mil-
lion Btu than oil or gas,1 is constrained by a number of con-
siderations These include the capital availability problSs
mentioned above They also include environmental regSlltiMs
which make the burning of coal impossible for all prKtical
purposes. Finally they include physical limitations? sSch as
the lack of space for coal storage or additional pollution
control equipment, which make conversions economically--!? not
physically—impossible. not
Of the feasible conversions, the economic attractiveness
is determined by a panoply o£ considerations. These include
the change in total fuel and other operation and maintenance
expenses oyer time, including any fuel premiums or dislotaj
costs related to environmental requirements, for the utilitv
system as a whole. These cost savings depend in turn on the
reliability and remaining life of the converted unit The
^At a delivered cost of $48 per ton, for example, a 12,000-
Btu-per-pound coal costs $2.00 per million Btu. Residual oil
at $24 per barrel is roughly twice as costly. Some natural
gas is presently priced at or below $2.00 per million cubic
feet, or $2.00 per million Btu, but the planned demise of
price regulation will almost certainly lead to a major in-
crease even in areas where gas currently sells at prices
below those of residual oil.
-------
D-4
economics of a conversion secondly involve the capital expend-
itures required for the conversion and the costs of financing
those expenditures, including any pollution control equipment.
Finally, the economic attractiveness of a conversion depends
on the relative technical, price, and regulatory uncertainties
involved in burning coal instead of the original fuel. It is
these factors that combine to determine whether a utility's
customers would, over time, gain from a conversion to coal.
As suggested above, current rate and environmental regu-
latory practices and requirements tend to inhibit conversions
to coal. In the face of rate regulation that produces inade-
quate returns on investment, utilities tend to find the rais-
ing of additional financing to be difficult and unattractive.
Environmental regulations tend to add to the capital costs of
conversions and thus increase these financing difficulties, as
well as decrease the economic gains from conversions.
Capacity Addition Decisions
Given the general utility objective of meeting demand
with acceptable levels of reliability, growth in a utility's
demand leads ultimately to the need for capacity expansion—
although in a number of cases, various load management tech-
niques are proving cost-effective and are reducing load growth
below previously expected rates. In making capacity expansion
decisions, utilities are typically guided by the customer and
shareholder objectives mentioned in connection with conver-
sions. These are the minimization of total customer costs
over the long run (while still maintaining adequate reliabil-
ity) and the provision of fair returns to investors.
There are several initial determinants of the feasibility
and attractiveness of various capacity expansion alternatives.
As discussed in Chapter III, these include capital availabili-
ty, environmental regulations which may inhibit the siting of
certain types and sizes of generating plants, and.energy regu-
lations which may altogether prohibit the consumption of- oil
or gas.
There are several major determinants of the costs to
consumers associated with various choices of new plant design,
fuel, and site. The first is delivered fuels prices, includ-
ing any premiums associated with environmental regulations, at
the potential new plant and at all other generating units in
the utility's system. The second is nonfuel operation and
maintenance costs, again at the new unit and other units.
(The system costs are relevant because, as discussed in con-
nection with dispatching, the value of any given new unit
-------
D-5
supplements^? displfcJs^f^T^third Il^ent^^ that ^
costs is the capital expenditures associated with^achUnera-
Fourth is'th^cost1^ capital°requiredCto^f inan^^th1^121^63 "
ditures. Fifth is the reliability and longevity^ the new6"'
tive are a variety of technil^ £!ce
uncertainties. =y^aLDry
The financial and shareholder considerations affectino
new capacity decisions are in essence the same a! toole a??
fecting conversions. Thus environmental regulations bv In-
creasing capital expenditure requirements, generally tend in
the current rate regulatory environment to iake the implemen-
tation of least-consumer-cost capacity expansion decffio^T
more difficult and more painful for eharoLi^ - "ecisions
to the extent that new coal units InvSlve M^ " M?re?ve-<
lays than do new oil or gas uniS-iSS^gJ^f
than the preservation of economically obsolete oil or gas
units-applicable environmental regulations in the curlent
rate regulatory environment tend particularly to inhib" the
construction of new coal-fired capacity.
COAL PRICES IN THE ABSENCE OF
ENVIRONMENTAL REGULATIONS"
and pJSduc?ionSvo^ef by't^Tanf ?riC"
three «.Jor factors. n* fE*t^ ofefch^iftis^
a"Vis alternative ruels at each powerplant. The second is
transportation costs. The third is the costs of |?SdScing
each type of coal m each region. 9
Determinants of Delivered Coal Prices
As discussed above, utility plants are constructed and
dispatched so as to produce the lowest possible delivered
electricity costs consistent with reliability objectives,
shareholder interests, and other considerations. The amounts
of plant capacity, the location of that capacity, and the
fuels burned at each plant in turn depend on: the availabil-
ity and delivered costs of each type of fuel (including dif-
ferent coal types); the associated nonfuel operation and main-
tenance expenses; the capital costs associated with burning
each fuel; and the reliability of each type of equipment and
fuel supply.
-------
D-6
After adjusting for the differential capital and other
costs associated with burning coal, the delivered price of
coal must be—if any is to be consumed—at or below the price
(in the long run) of the cheapest alternative fuel. Further-
more, coal prices may be expected to be significantly below
the price of alternative fuels after adjusting for non-fuel-
related expenses. In the many instances where there are mul-
tiple competing types and suppliers of coal to a particular
generating plant, the delivered price of the coal may be as
low as the total of transportation costs and mine-mouth pro-
duction costs for the least-cost transport-mine combination.
Transportation Costs
Because transportation costs frequently are larger than
production costs, coal-burning utility plants—particularly in
the eastern United States—are sited wherever possible close
to coal mines or on navigable waterways. Table D-2 shows
approximate rail rates for selected long rail moves. For
short hauls, conveyor systems or trucking may be an effective
competitor to rail transport, helping to curb costs. With
respect to water transport, costs per ton-mile tend inherently
to be lower and competition among barge and ship operators
precludes large markups on costs.
Table 0-2
SELECTED RAIL
RATES
(1980 dollars)
Oriain
Destination
Miles
Rate oer Ton
Colstrip, MT
Superior, WI
814
$10.56*
Cordero, WY
San Antonio, TX
1,651
22.25
Wattis, UT
Los Angeles, CA
900
20.21
Belle Ayn, WY
Anarillo, TX
940
13.47®
fair View, WV
Bow, NH
870
15.89
"'All rates presune carrier-supplied cars.
atlnit-train rates.
Source: Published tariffs; TBS analysis.
Where either a utility plant or a coal mine can be served
only by one railroad, that railroad has a monopoly, but the
rates it charges are subject to review in certain circum-
stances by the Interstate Commerce Commission, so that abuses
-------
D-7
of monopoly power are constrained. However, within the bounds
set ^by regulation, practices vary substantially amonQ rail-
roads. Railroads differ, for example, in their willingness to
of-er rates that reflect the economies of scale in unit—train
operations and the volumes of coal typically consumed by a
single coal-fared generating unit, e.g., often 2 million or
more tons per year. Railroads also differ in their willing-
ness to set rates that make it possible to transport coal over
two (or more) rail systems. As railroad practices evolve in
response to the recent relaxation of regulation (the Staggers
Act or 1980), long-term contracts that reflect the economics
of volume movements may lead to a situation where rates re-
flect the costs of efficient operations, including a fair
return on capital.
Determinants of Mine-Mouth Coal
prices and Volumes " "
Assuming that transportation costs from alternative
sources of coal to a particular consumer of coal are known
the highest possible mine-mouth price for a particular coal is
the difference between its delivered value (adjusted for capi-
tal and operating cost differentials between competing fuels,
including other coals) and transportation costs Whether "hi*
price is attractive and whether coal is produced from a par-
ticular reserve turn on the costs of mining that coal and on
alternate uses of existing or potential new capacity for
mining that coal. J
_ In the short run, where there exists excess capacity for
proaucing coal, mine-mouth costs may be viewed as the variable
costs of production, i.e., the incremental labor, materials
and other costs incurred by incremental production As sug-
gested by Figure D-l, presuming that production from a single
mine or from a region comes first from the most efficient
sections of a single mine or from the lowest cost mines in a
region, variable costs increase with increasing production
volume. Because such costs do not include a return on caDi-
tal, mine owners obviously try to avoid having to price at
levels approaching variable costs. Unfortunately for pro-
ducers, however, the coal industry has often tended to over-
build relative to the demand that has materialized. Thus for
most recent years and for most producers, prices have not're-"
fleeted a reasonable return on capital. In the worst case for
producers, as shown in Figure D-l, prices would be•equal tc
variable costs until demand exceeds existing capacity.
-------
Figure D—1
MINE-MOUTH COSTS AMD PRICES
Dollars
pur To*
TOTAL COSTS
VARIABLE COSTS
PRICE
Votum*
TfUty
In the long run, capacity and demand may come to be more
in balance and, if so, mine-mouth costs can be viewed as in-
cluding both variable and fixed costs. This equilibration of
supply and demand will involve shifts in three factors:
first, in the amounts of mining capacity for various types of
coal in various regions; second, in the amount, specific de-
sign, and location of coal-fired utility generating plants;
and third {perhaps to a lesser extent), in the costs of trans-
portation between various origin-destination pairs. Ultimate-
ly, to elicit investment by producers in new mine capacity,
prices must rise to -levels expected to cover the full costs of
production from this incremental capacity. As is also .sug-
gested by Figure D-l, presuming that reserves are' developed
and mined in order of their costs, prices for coals of a par-
ticular type from a particular region will rise until demand
for that coal, which is itself related to the price of that
coal, is equated to supply.
The level of both variable and fixed costs and the pro-
duction volumes of various coals are dependent on the amounts,
thickness, depth, and many other characteristics of the re-
serves of various coals. There are enormous reserves of coal
in the continental United States. (See Figure D-2; for con-
sistency with EPA's coal price assumptions, the data are taken
-------
Ffyiwo 0-2
COAL RESERVES BY SULFUR CONTENT
(millions of tons)
NORTHWEST
AND ALASKA
WESTERN
NORTHERN
GREAT PLAINS
EASTERN
NORTHERN
GREAT PLAINS
NORTHERN
APPALACIIIA
ROCKIES
L
M
II
U
118 400
CENTRAL
WEST
4.600
6.400
6.600
7.400
2.400
2.300
61,000
1.1 000
36 400
6,BOO
49 100
0,300
14.400
4 700
1.300
12 300
SOUTHWEST
GULF
1.800
2.000
100
2 800
600
2.700
SOUTHERN
APPALACHIA
L = Low Sulfur - leu tlian 1.20 lb sulfur/106 Btu
M - Medium Sulfur - 1.20 1.07 lb sulfur/106 Btu
II - High Sulfur — mors than 1.67 lb sulfur/10* Btu
t) ™ Unclautfled
L
600
M
600
II
700
U
1,300
CENTRAL
APPALACHIA
L
16.200
M
6.600
H
4,100
U
10,100
O
I
y£>
ANTHRACITE AND
SEMI ANTHRACITE
BITUMINOUS COAL
Slltl BITUMINOUS
COAL
LIGNITE
So«fr.»: ICf. Inc.; mainnramlum ilalwl Notfambar 10. 1081.
-------
D-10
from ICF, Inc., Coal and Electric Utilities Model Documenta-
tion, May 1980. ) However, there are major differences among
regions in the production costs associated with coals of dif-
ferent types. According to ICF estimates, the costs of new
Appalachian production are in the range of $40 to $50 per ton
in 1980 dollars (for coal averaging approximately 12,000 Btu
per pound); the cost of new western subbituminous coal
production is less than $15 per ton (for coal averaging
approximately 8,500 Btu per pound). (Illustrative cost data
are shown in Figures D-3, D-4, and D-5.) It is the interplay
of demand, mine-mouth costs, and transportation costs that
determines over time the amounts and prices of each region's
coal production.
For a variety of reasons, the equilibration process is
slow—and given the many uncertainties affecting each of the
demand and supply variables—may never be complete. The con-
struction lead times for both utility and mine construction
are lengthy—often a decade or more. Even for existing capac-
ity, long-term contracts for the output of a mine (which may
Figure 0—3
MINE-MOUTH COSTS
APPALACHIAN HIGH-SULFUR COAL
(1980 dollars)
$70 —]
sso —
$50 —
0 20 40 60 80 100 120 140 160 180 200
Production (millions of torn par ywl
Sou rot: ICF, Inc.
-------
D-ll
Figure D—4
MINE-MOUTH COSTS
MIDWEST HIGH-SULFUR COAL
(1980 dollars)
S70
$60 —
sso —
S40 —
Con
per Ton
$30 —
i i i r1 i i i i i i i
0 20 40 60 80 100 120 140 160 180 200
Production (million! of tons par yMr)
Sourc*: ICF. Inc.
Figure D-6
MINE-MOUTH COSTS
WESTERN NORTHERN GREAT PLAJNS SUBBITUMINOUS LOW-SULFUR COAL
(1980 dollars)
S70 —|
$60 —
860 —
$40 —
Con
p»r Ton
$30 —
Production (million* of torn per yur)
Sourea: ICF. Inc.
-------
D-12
run for 20 yea^s or more) and utility ownership of coal mines
may inhibit"adjustments. On the other hand, long-term con-
tracts are often key to a coal producer's being willing to
invest in new capacity.
THE EFFECTS OF ENVIRONMENTAL REGULATIONS
ON COAL PRICES AND AMOUNTS
Environmental regulations governing the combustion of
coal affect coal prices both in the short and long run. (Reg-
ulations affecting the mining of coal are ignored in this
appendix, although they are also of major importance.) The
long-run effects arise because certain coals become technical-
ly or economically impossible to burn or because the burning
of such coals entails higher capital and operating costs. The
short-run effects arise to the extent that the character of
the regulations is not correctly anticipated by the coal in-
dustry and that the implementation of the regulation gives
rise to nonequilibrium excess- and deficit-capacity
situations.
Although it is impossible to ascribe the full differen-
tial wholly to environmental regulations or to partition the
causes into short- and long-run causes, in those regions with
coals of varying sulfur content, current prices usually (but
not always) reflect substantial sulfur premiums. Recent
prices for selected coals of different sulfur content are
shown in Table D-3.
Short-Run Implications
To the extent that more stringent environmental regula-
tions on, say, sulfur dioxide (SO2) emissions, are unantici-
pated, a chain of events occurs that tends to create substan-
tial sulfur premiums. Relative to what otherwise would have
been the case, the imposition of new or additional SO2 regula-
tions causes the consumption of high-sulfur coal to decrease.
To the extent that the decrease is unexpected, high-sulfur
coals will be in oversupply and high-sulfur coal prices will
tend to decline toward variable production costs. Conversely,
the desired consumption of low-sulfur coals tends to increase,
production tends to rise toward the limits of available capac-
ity, and low-sulfur coal prices tend to rise until mine-mouth
prices plus transportation costs reflect the delivered costs
of alternative fuels or of coals from more remote regions that
have excess capacity. in both cases, long-term contractual
provisions may preclude some immediate shifts in response to
the unanticipated regulatory changes.
-------
D-13
Table D-3
KID-1982 SPOT COAL PRICES
Sulfur Ash Price per
Region Content Content million Btu
Southern West Virginia, 1.6 13,0 S2.13
eastern Kentucky,
northern T ennessee,
parts of Virginia
Western Kentucky 3.6 14.2 1.82
2.5 10.0 2.32
Illinois 3.5 13.0 1.71
2.5 8.5 1.71
Kansas, Missouri, 4.5 11.0 2.11
parts of Oklahome 0.7 9.0
Source: Coal Week. July 19, 1982; TBS wialysis.
3.00
Long-Run Implications
to creatftrS environmental regulations still tend
of the reserves of Jow i°"ISUlfur iand coals. Most
of the reserves of low-sulfur coals in the East and Midwest
are mineable only at production costs that are significanUy
ure D-6, with the cost curve for" Appalachian high-sSlfurioal,
thf Premium® ^ equilibrium should be
smaller in the long run for several reasons. First, excess
elo^cs andC!nani« diminish' in Part because of mine
closings and in part because utilities will add flue qas de-
Jo bnriZhiahnsulfni wasl?in9' or other equipment enabling them
QAronS rif? nrirfnJL still comply with regulations.
Second, coal producers and transporters will invest in devel-
oping new mines in and transportation facilities fo^ low-
sulfur coal reserves. _ While such investment will be made onlv
if low-sulfur coal prices allow attractive returns on invest-
ment, the amount of low-sulfur coal reserves in the United
States and the competitiveness of the coal industry will pre-
clude monopolistic returns. Nonetheless, long-run ecuil-
ibrium ^ delivered coal prices with environmental reculations
will# in mosu regions, contain a significant sulfur premium.
While there remain some uncertainties and limitations in
the technology, the existence of desulfurization equipment anc
-------
D-14
Figure D—6
MINE-MOUTH COSTS
APPALACHIAN LOW-SULFUR COAL
<1980 dollars)
Cost
par Ton
$150
$140 _
$130
$120
$110
$100
£90
$80 —
S70
$60
$50 —
$40 —
$30 —
$20 —
$10 —
0
U
NEW CAPACITY
20 40 60 80 100 120 140
Production (millions of tons per year)
160 180
200
-------
D-15
techniques places some upper bounds on sulfur premiums.
Scrubbers with 90 percent removal efficiencies add roughly
13 mills per kWh in annual capital and operation and mainten-
ance costs to electricity costs in 1980 dollars. Seventy per-
cent scrubbing adds 10 mills. The differential of 3 mills per
kWh is equivalent to $7.60 per ton of coal.2 Thus, a 3.0 per-
cent sulfur coal scrubbed with 90 percent efficiency and a
.0.67 percent sulfur coal scrubbed with 70 percent efficiency
should, in theory, differ in price by no more than $7.60 per
ton for reasons of sulfur content. If there is a $7.60 per
ton differential, the cost of producing electricity should be
the same for both scrubber technologies.
Implications of Alternative
Tvpes of Environmental
Regulations
The character of environmental regulations affects coal
prices. In particular, regulations expressed in terms of
technology requirements have different effects on prices than
regulations expressed in terms of performance standards—even
if the technology requirements are set so as to attain equiva-
lent environmental results. A first reason is that, to the
extent that technology standards are not identical to the
least-cost methodology for meeting a particular air quality
standard, the price of electricity will be higher than would
otherwise be the case, electricity use would be reduced, and
accordingly, coal use and coal prices would be lower.
The second major result of technology requirements vis-a-
vis performance standards is to change the distribution of
coal consumption by type. Notably, the minimum scrubbing
requirement for NSPS II units tends to decrease the consump-
tion and prices of low-sulfur coal relative to what would be
burned if performance standards were the sole requirement, as
is the case for existing facilities. This does not mean that
2TBS performed the conversion from mills per kWh to 1980 dol-
lars per ton as follows:
dollars per ton = mills per kWh x kWh per ton x 1/1,000
kWh per ton = Btu per pound x pounds per ton
x kWh per Btu
For this calculation, TBS assumed 12,000 Btu per pound and
9,600 Btu per kWh.
-------
D-16
technology standards do not create sulfur premiums, merely
that such premiums are lower than would be the case with per-
formance standards leading to the same emission levels. Both
tend to lead to a preference for low-sulfur coals, to greater
production and higher prices of such coals, and to increased
levels of coal cleaning relative to what would occur in the
absence of environmental regulations. Conversely, environ-
mental regulations tend to harm the economic viability of
high-sulfur mines and the economic well-being of the miners,
companies, and regions associated with high-sulfur coal.
-------
APPENDIX E
TERMS, ACRONYMS, AND CONVERSION FACTORS
-------
Appendix £
TERMS, ACRONYMS, AND CONVERSION FACTORS
This appendix provides definitions of the major terms and
acronyms used throughout this report. In addition, some
useful conversion factors are included.
-------
DEFINITIONS
These definitions are derived primarily from Edison Elec-
tric Institute's Glossary of Electric Utility Terms.
Accelerated Depreciation. See Depreciation, Liberalized.
Accumulated Deferred Income Taxes. A group of balance
sheet accounts, representing the net balances arising from
charges to income that are equivalent to the reductions in
income taxes of the current and prior periods. Such reduc-
tions result from the use, for tax purposes, of deductions
which, for book purposes, will not be fully reflected in the
determination of book net income until subsequent periods.
Most commonly, these taxes arise from normalizing the tax
reductions that result from the use of accelerated amortiza-
tion or liberalized depreciation for tax purposes instead of
straight-line or other nonliberalized depreciation methods
used for book purposes.
Accumulated Deferred Investment Tax Credit. Net unamor-
tized balance of investment tax credits which are being spread
over the average useful life of the related property or some
other shorter period. This balance sheet account is built up
by charges against income in the years in which such credits
are realized (the years in which the qualified property addi-
tions go into service) and is reduced subsequently through
credits to income.
Acquisition Adjustments. See Plant Acquisition
Adjustments.
Additions at Cost. Gross additions to, and betterments,
renewals, and replacements of, utility plant, including those
carried in Construction Work in Progress (CWIP)—at actual
cost—whether for cash or other consideration and including
utility plant acquired. Plant additions described in this
report include the interest portion of CWIP, but not the cash
portion. Please refer to Appendix C for additional explana-
tion of the accounting procedures.
Adverse Hydro (adverse water conditions). Water condi-
tions limiting the production of hydroelectric power either
from low or'restricted water supply or reduced gross head.
Allowance for Funds Used Purina Construction. Listed in
the income account as a subdivison of Other Income, and rep-
resenting amounts concurrently credited for interest that are
-------
E-2
charged to the cost of constructing new plant, ana that are
based generally on the amount expended to date on particular
projects. The rate used may represent the net cost for the
period of funds borrowed for construction purposes with a
reasonable rate upon other funds when so used, or a predeter-
mined rate representing the average cost of capital may be
used.
Amortization. The gradual extinguishment (or accumulated
provision or reserve) of an amount in an account by prorating
such amount over a predetermined period, such as the life of
the assest or liability to which it applies, or the period
during which it is anticipated the benefit will be realized.
Annual Peak Load. See Demand, Annual Maximum.
Annual System Maximum Demand. See Demand, Annual System
Maximum,
Assets (and other debits). Items of value owned by or
owned to a business. Represents either a property right or
value acquired, or an expenditure made which has created a
property right or is properly applicable to the future. Util-
ity assets include: utility plant, other property and invest-
ments , current and accrued assets, and deferred debits.
Availability, Operating. The percent of time the unit
was available for service, whether operated or not. It is
equal to available hours divided by the total hours in the
period under consideration, expressed as a percentage.
Average Annual Customer Charge. Annual revenue (exclud-
ing forfeited discounts and penalties) divided by the average
number of customers served for the 12-month period. A cus-
tomer with two or more meters at the same location because of
special services, such as water heating, etc., is counted as
one customer. Customer charges described in this report
typically refer to revenues per kilowatt-hour. See "Average
Revenue per Kilowatt-Hour Sold."
Average Annual kWh Pse per Customer. Annual kilowatt-
hour sales divided by the average number of customers for the
same 12-month period. A customer with two or more meters at
the .same location because of special services, such as water
heating, etc., is counted as one customer.
Average Demand. See Demand, Average.
Average Number of Customers. The arithmetic averages of
month-end customers in each of 12 consecutive months. For
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E-3
tomers is adjusted to a 12 S roonth,the number of such cus-
billing, the number of rncf!!" for bimonthly
month is multiplied by two anf^h i °r counted' in each
12-month period). the resultant averaged for the
averagrSSSer^eIh2resh"ecoSStSl'n^ * Th® wei^hted
hands of the public du-ina tho •SJ°S outstanding in the
share are to be computed Use oVtSt ^ earnings ?er
necessary so that the effect nf fn^ Wei9ht«d average is
outstanding shares on ea-niL? ni? decreases in
-he oortion of thl ea-nings per share data is related to
applicable. T*
InyUsubseLentrs^iedad^Stf t0 3iVe retroIctivHffec? to
any subsequent stock dividends or stock splits.
o 1 Rgk^!?!!e K^^owatt~Hour Sold (average price of
farf Sj ' f nue, m the sale of electricity (excluding
for^eitea discounts and penalties) divided by the correspond-
^gr^L°fh^i°Watt'hOUrS SOld- Referred to in this report
as customer charges.
Base Load. The minimum load over a given period of time.
.. Base Station, a generating station which is nor-
mally operav.ed to take all or part of the base load of a sys-
tem and which, consequently, operates essentially at a con-
scant output. J
Bond Ratings. Rating systems which provide the investor
wi-h a simple series of graduation by which the relative in-
vestment qualities of bonds are indicated. Moody's Investor
Service and Standard & Poor's Corporation are the princioal
bond rating agencies.
Bonds (mortgage). Certificates of indebtedness repre-
senting long-term borrowing of capital funds, the terms of
which contain an indenture pledging the property as security
ror the loan and providing for the appointment of a trustee to
represent the bondholders. If the lien of the mortgage is
limited to specific property owned at the time the mortgage
was created and to replacements for the property, the mortgage
is described as "closed." If the lien extends to "after ac-
quired" property which may be used as the basis for issuance
of additional bonds under the terms and provisions of the in-
denture, the mortgage is referred to as an "open-end"
mortgage.
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Book Amounts. The amounts recorded on a company's
accounting records at any given time, usually at the most
recent closing date or at year-end. These amounts may reflect
historical cost, original cost, or current value.
Book Cost. The amount at which assets are recorded in
the accounts without deduction of related accumulated provi-
sions for depreciation, amortization, or other purposes.
Book Value per Share of Common Stock. Common Stock
Equity (see definition) divided by the number of common shares
outstanding at the date of the computation.
Btu (British thermal unit). The standard unit for meas-
uring quantity of heat energy, such as the heat content of
fuel. It is the amount of heat energy necessary to raise the
temperature of one pound of water one degree Fahrenheit.
• Content of Fuel, Average. The heat value per
unit quantity of fuel expressed in Btu as
determined from tests of fuel samples. Exam-
ples: Btu per pound of coal, per gallon of
oil, etc.
•• Equivalent of Fuels Burned. The Btu equivalent
of fuels burned is the aggregate heat energy of
all fuels burned. It is derived by calculating
total Btu content of each kind of fuel burned
and totaling to establish the Btu content of
all fuels burned.
Btu per Kilowatt-Hour. See Heat Rate.
Capability. The maximum load which a generating unit,
generating station, or other electrical apparatus can carry
under specified conditions for a given period of time, without
exceeding approved limits of temperature and stress.
• Gross System. The net generating station
capability of a system at a stated period of
time (usually at the time of the system's maxi-
mum load), plus capability available at such
time from other sources through firm power
contracts.
• Net Generating Station. The capability of a
generating station as demonstrated by test or
as determined by actual operating experience
less power generated and used for auxiliaries
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E-5
and other station uses. Capability may vary
with the character of the load, time of year
(due to circulating water temperatures in
thermal stations or availability of water in
hydro stations), and other characteristic
causes. Capability is sometimes referred to as
effective rating.
• Net System. The net generating station capa-
bility of a system at a stated period of time
(usually at the time of the system's maximum
load), plus capability available at such time
from other sources through firm power contracts
less firm power obligations at such time to
other companies or systems.
• Peaking. Generating capability normally de-
signee for use during the maximum load period
of a designated time interval.
Capability Margin (reserve margin). The difference
between net system capability and system maximum load require-
ments (peak load). It is the margin of capability available
to provide for scheduled maintenance, emergency outages, sys-
tem operating requirements, and unforeseen loads. On a
regional or national basis, it is the difference between
aggregate net system capability of the various systems in the
region or nation and the sum of system maximum (peak) loads
without allowance for time diversity between the loads of the
several systems. However, within a region, account is taken
of diversity between peak loads of systems that are operated
as a closely coordinated group.
Capacity. The load for which a generating unit, generat-
ing station, or other electrical apparatus is rated either by
the user or by the manufacturer.
• Dependable. The load-carrying ability for the
time interval and period specified when related
to the characteristics of the load to be sup-
plied. Dependable capacity of a station is
determined by such factors as capability, oper-
ating power factor, and portion of the load
which the station is to supply.
Hydraulic. The rating of a hydroelectric gen-
erating unit or the sum of such ratings for all
units in a station or stations.
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E-6
• Peakinc. Generating units or stations which
are available to assist in meeting that portion
of peak load which is above base load.
• Purchase. The amount of power available for
purchase from a source outside the system to
supply energy or capacity.
• Reserve Margin. See Capability Margin.
Capacity Factor. The ratio of the average load on a
machine or equipment for the period of time considered to the
capacity rating of the machine or equipment.
Capital Expenditures (capital outlay). Cost of construc-
tion of new utility plant (additions, betterments, and re-
placements) and expenditures for the purchase or acquisition
of existing utility plant facilities. See Appendix C for
additional details.
Capital Stock. Represents ownership in a corporation.
If there is no preferred or other special class of stock,
common stock and capital stock are synonymous. See also
Common Capital Stock or Common Stock.
Capitalization. The total of: Long-Term Debt, Preferred
Stock, and Common Stock Equity. For balance sheet presenta-
tion, several modifications are sometimes made: current
maturities of Long-Term Debt are not included in the Capitali-
zation section, but Short-Term Debt (with an original maturity
of less than one year), which will be refinanced by Long-Term
Debt, is sometimes included.
Capitalization Ratios. The percentages of: Long-Term
Debt', Preferred Stock, and Common Stock Equity (or their com-
ponents) to Total Capitalization.
Coincident Demand. See Demand, Coincident.
Commercial and Industrial. A customer, sales, and rev-
enues classification covering energy supplied for commercial
and industrial purposes, except that supplied under special
contracts or agreements or service classifications applicable
only to municipalities or divisions or agencies of federal or
state governments or to railroads and railways. Usually sub-
divided into Commerical and Industrial or into Small Light and
Power and Large Light and Power. Most companies classify such
customers as Commerical or Industrial using the Standard In-
dustrial Classification or predominant kWh use as yardsticks;
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others still classify as Industrial all customers whose de-
mands or annual use exceeds some specified limit. These
limits are generally based on a utility's rate schedules.
Common Capital Stock or Common Stock. Shares of stock
issued and stated at par value, stated value, or the cash
value of the consideration received for such no par stock;
none of which is limited or preferred to distribution of earn-
ings or assets.
Common Stock Dividends. Dividends declared on Common
Stock and charged to unappropriated retained earnings during a
stated period, whether or not they were paid during such
period. Such dividends only include those payable in cash
unless otherwise specified (i.e., payable in stock).
Common Stock Equity. The funds invested in the business
by the residual owners whose claims to income and assets are
subordinate to all other claims. Includes Common Capital
Stock (less reacquired), Other Paid-in Capital, and Retained
Earnings. Installments, Received on Capital Stock, Discount
on Capital Stock, and Capital Stock Expense are usually in-
cluded in either Common or Preferred Capital Stock according
to the nature of the transactions. . Premimum on Preferred
Stock and certain reserves are sometimes included in Common
Stock Equity.
Construction Expenditures (gross). Expenditures (may or
may not include interest or other overheads charged to con-
struction) for construction including additions to and better-
ments, renewals, and replacements of utility plant during a
specific period, but not money spent for maintenance or for
the acquisition of existing utility systems or segments. See
Appendix C for additional details.
Construction Work in Progress. A subaccount in the util-
ity plant section of the balance sheet representing the sum of
the balances of work orders for utility plant in the process
of construction but not yet placed in-service.
Cost (net) of Capital. The return asked, or being asked,
by investors for the use of their money committed to invest-
ment in utility companies, expressed as percentages of the
capital funds (debt, preferred stock, common equity).
• For Common Stock. A mathematical computation,
whose formula varies, of expected future earn-
ings to the net proceeds received from the sale
of common stock after deducting underwriters'
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E-8
commission, and other costs of issuance, in-
cluding pressure and allowance for underpricing
in a rights offering—or ratio of expected
future earnings to current market price. Since
many factors enter into estimating future earn-
ings (e.g., territory served, regulatory cli-
mate, interest costs, growth prospects, manage-
ment, etc.) the calculation cannot be measured
precisely and can only be estimated on the
basis of informed judgment.
• For Long-Term Debt. The contractual interest
rate expressed as a percentage of the net pro-
ceeds, less estimated financing expenses, cur-
rently being received from the sale of new
issues of bonds of companies.
• For Preferred Stock. The contractual dividend
rate expressed as a percentage of the net pro-
ceeds, less estimated financing expenses, cur-
rently being received from the sale of new
issues of preferred stock.
• For Short-Term Debt. The contractual interest
rate being asked by financial institutions for
short-term loans and by sellers of commercial
paper on loans maturing in less than one year.
The effective rate on short-term bank loans may
be greater because of the requirement to main-
tain compensating balances.
Customer (electric). An individual, firm, organization,
or other electric utility which purchases electric service at
one location under one rate classification, contract, or sche-
dule. If service is supplied to a customer at more than one
location, each location is counted as a separate customer
unless the consumptions are combined before the bill is
calculated.
Debentures. Certificates of indebtedness issued under an
indenture agreement (administered by a trustee) representing
long-term borrowings of capital funds, and secured only by the
general credit of the issuing corporation.
Deferred or Future Income Taxes. Amounts representing
income tax reductions resulting from the use of accelerated
amortization or liberalized depreciation in income tax
returns.
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Demand. The rate at which electric energy is delivered
to or by a system, part of a system, or a piece of equipment.
It is expressed in kilowatts, kilovoltamperes, or other suit-
able units at a given instant or averaged over any designated
period of time. The primary source of Demand is the power-
consuming equipment of the customers. See Load.
• Annual Maximum. The greatest of all demands of
the load under consideration which occurred
during a prescribed demand interval in a calen-
dar year.
• Annual System Maximum. The greatest demand on
an electric system during a prescribed demand
interval in a calendar year.
• Average. The demand on, or the power output
of, an electric system or any of its parts over
any interval of time, which is determined by
dividing the total number of kilowatt-hours by
the number of units of time in the interval.
• Billing. The demand upon which billing to a
customer is based, as specified in a rate sche-
dule or contract. It may be based on the con-
tract year, a contract minimum, or a previous
maximum and, therefore, does not necessarily
coincide with the actual measured demand of the
billing period.
• Coincident. The sum of two or more demands
which occur in the same demand interval.
• Instantaneous Peak. The maximum demand at the
instant of greatest load, usually determined
from the readings of indicating or graphic
meters.
• Integrated. The demand usually determined by'
an integrating demand meter or by the integra-
tion of a load curve. It is the summation of
the continuously varying instantaneous demands
during a specified demand interval.
• Maximum. The greatest of all demands of the
load under consideration which has occurred
during a specified period of time.
• Noncoinciaent. The sum of two or more individ-
ual demands which do not occur in the same
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demand interval. Meaningful only when consid-
ering demands within a limited period of timer
such as a day, a week, a month, a heating or a
cooling season; usually for not more than one
year.
Demand Charae. The specified charge to be billed on the
basis of the billing demand, under an applicable rate schedule
or contract.
Demand Factor. The ratio of the maximum demand over a
specitied time period to the total connected load on any
defined system.
Demand Interval. The period of time during which the
electric energy flow is averaged in determining demand, such
as 60-minute, 30-minute, 15-minute, or instantaneous.
Dependable Capacity. See Capacity, Dependable.
Depletion (allowance). A charge against income for the
pro rata cost of extracted depletable natural resources such
as coal, gas, oil, etc.
Depreciation (provision for). Charges made against
income to provide for distributing the cost of depreciable
plant less estimated net salvage over the estimated useful
iife of the asset (using mortality turnover or other appro-
priate methods) in such a way as to allocate it as equitably
as possible to the period during which services are obtained
from the use of facilities. Among the factors to consider
are: wear and tear, decay, inadequacy, obsolescence, changes
m demand, and requirements of public authorities.
• Straight-Line Method. Under this method of
computing provisions for depreciation, the cost
of the asset less estimated salvage is allo-
cated in equal amounts over the asset's esti-
mated useful life.
• Liberalized. This refers to certain approved
methods of computing depreciation allowance for
federal or state income tax purposes, applic-
able to plant additions with a useful life of
three years or more. These methods permit
relatively larger depreciation charges during
the earlier years of the life of the property
and relatively smaller charges during the later
years, in contrast with the straight-line
method, under which the annual charges are the
same for each year.
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E-ll
—Declining Balance Method. One of the liber-
alized methods of computing depreciation
deductions. Under this method, the deprecia-
tion rate is stated as a fixed percentage (up
to twice the applicable straight-line rate)
per year, and the annual charge is derived by
applying the rate to the net plant balance,
which is determined by subtracting the accum-
ulated depreciation deductions of previous
periods from the cost of the property. When
the property of any vintage year is almost
fully depreciated, it is necessary to add to
the reserve the small remaining amount re-
quired to bring the reserve up to 100 percent
of the retirement value (cost less salvage);
otherwise depreciation charges would continue
on in decreasingly smaller amounts to
infinity.
—Sum of the Years' Digits ("SYD") Method.
Another of the liberalized methods of comput-
ing depreciation deductions. Under this
method the annual deduction is derived by
multiplying the cost of the property, less
estimated net salvage, by the estimated
number of years of service life remaining,
and dividing the resultant product by the sum
of all the digits corresponding to the total
years of estimated service life. For a prop-
erty with an assumed 25-year life the sum of
the digits would be 25 + 24 + 23 + 22 + . . .
+5+4+3+2+1, or 325. A simple way to
compute this figure would be to multiply the
number of years by the number of years plus 1
and divide by 2, i.e., (25 x 26) r 2 = 325.
The first year's full depreciation deduction
would be 25/325ths; the second year's would
be 24/325ths, etc., of the cost of the
property.
Direct Current (DC). Electricity that flows continuously
in one direction, as contrasted with alternating current.
Discount on Capital Stock. The excess of par or stated
value over the price paid to the company by the shareholders
for all original issue shares of its capital stock. In bal-
ance sheet presentation, discount on capital stock is usually
treated as a deduction from proprietary capital.
Dispatching. The operating control of an integrated
electric system involving operations such as:
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E-12
(1) The assignment, of load to specific generating sta-
tions and other sources of supply to effect tne most
reliable and economical supply as the total of tne
significant area loads rises or falls.
(2) The control of operation and maintenance of high-
voltage lines, substations, and equipment, including
administration of safety procedures.
(3) The operation of principal tie lines and switching.
(4) The scheduling of energy transactions with connect-
ing electric utilities.
Distribution. The act or process of distributing elec-
tric energy from convenient points on the transmission or bulk
power system to the consumers. Also a functional classifica-
tion relating to that portion of utility plant used for the
purpose of delivering electric energy from convenient points
on the transmission system to the consumers, or to expenses
relating to the operation and maintenance of distribution
plant.
Diversity. That characteristic of variety of electric
loads whereby individual maximum demands usually occur at
different times. Diversity among customer's loads results in
diversity among the loads of distribution transformers, feed-
ers, and substations, as well as between entire systems.
Diversity Factor. The ratio of the sum of the noncoin-
cident maximum demands of two or more loads to their coinci-
dent maximum demand for the same period.
Earnings Per Share. The earnings attributable to common
stock for a stated period divided by the weighted average
number of shares outstanding during the period. The term
should not be used without qualifying language if potentially
dilutive convertible securities, options, warrants, or other
agreements that provide for contingent issuances of common
stock are outstanding.
Earnings Price Ratios. Earnings per share on Common
Stock divided by its market price. The market price used may
be a spot price or an average of the closing or high and low"
prices for a period; the earnings are for the corresponding
period and may be either actual or estimated annual rate.
Earnings Retained in the Business. The remainder of net
income for the period (usually for the reporting year) after
deducting preferred and common dividends payable in cash.
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Electric Utility Industry, or Electric Utilities. All
enterprises engaged in the production or distribution of elec
tricity for use by the public, including investor-owned elec-
tric utility companies; cooperatively-owned electric utili-
ties; and government-owned electric utilities. The term
refers to the annual costs attached to the ownership of
property such as depreciation, taxes, insurance, cost of
money, and in some instances, rents, general and administra-
tive expenses, and necessary regular maintenance.
Flow-Throuah Method. An accounting method under which
decreases or increases in state or federal income taxes re-
sulting from the use of liberalized depreciation and the In-
vestment Tax Credit for income tax purposes are carried down
to net income in the year in which they are realized.
Fuel Clause. A clause in a rate schedule that provides
for adjustment of the amount of the bill as the cost of fuel
varies from a specified base amount per unit.
Fuel Costs (most commonly used
pv electric utility companies)
• Cents Per Million Btu Consumed. Since coal is
purchased on the basis of its heat content, its
cost is measured by computing the "cents per
million Btu" of the fuel consumed. It is the
total cost of fuel consumed divided by its
total Btu content, and multiplied by one
million.
• Coal. Average cost per short ton (dollars per
ton)—includes bituminous and anthracite coal
and relatively small amounts of coke, lignite,
and wood.
• Gas. Average cost per cents per thousand cubic
feet—includes natural, manufactured, mixed,
and waste gas. Frequently expressed as cost
per therm (100,000 Btu).
• Nuclear. Nuclear fuel costs can be given on a
fuel cycle basis. A fuel cycle consists of all
the steps associated with procurement, use, and
disposal of nuclear fuel. Accounting for the
cost of each step in the fuel cycle including
interest charges, nuclear fuel costs can be
given in cents per million 3tu or mills per
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£-14
kilowatt-hour for the cycle lifetime of the
fuel, which is normally five to six years.
Oil. Average cost, per barrel 42 gallons
(dollars per barrel)—includes *uel oil, crude
and diesel oil, and small amounts of tar and
gasoline.
Generating Station (generating plant or powerplant). A
station at which are located prime movers, electric generat-
ors, and auxiliary equipment for converting mechanical,
chemical, or nuclear energy into electric energy.
Generating Pnit. hn electric generator together with its
prime mover.
Generation, Electric. This term refers to the act or
process of transforming other forms of energy into electric
energy, or to the amount of electric energy so produced, ex-
pressed in Kilowatt-hours.
• Gross. The total amount of electric energy
produced by the generating units in a generat-
ing station or stations.
• Net. Gross generation less kilowatt-hours
consumed out of gross generation for station
use.
3eat Rate. A measure of generating station thermal efri~
ciency, generally expressed in Btu per net kilowatt-hour. It
is computed by dividing the total Btu content of fuel burned
for electric generation by the resulting net kilowatt-hour
generation.
Income Taxes. A subdivision of Operating Expenses or of
Other Income and Deductions or Extraordinary Items. Income
Taxes (federal and state) applicable to nonutility operations
are allocated to Other Income and Deductions, and to Extra-
ordinary Items, if appropriate. Used in the broad sense In-
come Taxes include, in addition to federal and state income
taxes: Provisions for Deferred Income Taxes, Income Taxes
deferred in Prior Years—Credit and Investment Tax Credit
Ad justmen ts —'Net,
Interest Charges. A section or group of accounts in the
income statement whicn represents principally the amounts
accrued as expenses for the cost of borrowed funds. Includes:
Interest on Long-Term Debt, Amortization of Debt Discount and
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Expense, Amortization of Premium on Debt-Credit, Interest on
Debt to Associated Companies, and Other Interest Expense.
Interest on Long-Term Debt. Interest on outstanding debt
which is or was due one year or more from the date of
issuance.
Internal Combustion Engine. A prime mover in which
energy released from the rapid burning of a fuel-air mixture
is converted into mechanical energy. Diesel, gasoline, and
gas engines are the principal types in this category.
Invested Capital. The sum of Capitalization, Long-Term
Debt Due Within One Year, and Short-Term Debt.
Investment Tax Credit. The credit against federal income
taxes provided by the Revenue Act for qualified depreciable
assets after December 31, 1961, and before April 18, 1969,
except for a suspension period (October 10, 1966, to March 9,
1967).
Investor-Owned Electric Utilities. Those electric utili-
ties organized as tax-paying businesses usually financed by
the sale of securities in the free market, and whose proper-
ties are managed by representatives regularly elected by their
shareholders. Investor-owned electric utilities, which may be
owned by an individual proprietor or a small group of people,
are usually corporations owned by the general public.
Kilowatt (kW). 1,000 watts (defined herein).
Kilowatt-hour (kWh). The basic unit of electric energy
equal to one kilowatt of power supplied to or taken from an
electric circuit steadily for one hour.
Liabilities and Other Credits. Amounts recorded in books
of account which represent obligations to creditors, items
deferred or in suspense, and the equity of shareowners. In-
cludes Capitalization (Long-Term Debt and Proprietary Capit-
al), Current and Accrued Liabilities, Deferred Credits, Oper-
ating Reserves, Contributions in Aid of Construction, and
Accumulated Deferred Taxes on Income.
Load. The amount of electric power delivered or required
at any specified point or points on a system. Load originates
primarily at the power-consuming equipment of the customers.
See Demand.
• Average. See Demand, Average.
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E-16
• 3ase. See Base Load.
• Connected. Connected load is the sum of the
capacities or ratings of the electric power-
consuming apparatus connected to a supplying
system, or any part of the system under
consideration.
• PeaJc. See Demand, Maximum, and Demand,
Instantaneous PeaJc.
Load Curve. A curve on a chart showing power (kilowatts)
supplied, plotted against time of occurrence, and illustrating
the varying magnitude of the load during the period covered.
Load Diversity. The difference between the sum of the
maxima of two or more individual loads and the coincident or
combined maximum load, usually measured in kilowatts.
Load Factor. The ratio of the average load in kilowatts
supplied during a designated period to the peak or maximum
load in kilowatts occurring in that period. Load factor, in
percent, also may be derived by multiplying the kilowatt-hours
in the period by 100 and dividing by the product of the
maximum demand in kilowatts and the number of hours in the
period.
Long-Term Debt. Includes outstanding mortgage bonds,
debentures, advances from associated companies, and notes
which are due one year or more from date of issuance. The
portion of such securities (inclusive of sinking fund require-
ments) that is due within one year from the date of the
balance sheet is usually included in Current and Accrued
Liabilities, but Long-Term Debt to be refinanced within one
year should continue to be reported under Long-Term Debt.
Long-Term Financing. Refers to the issuance and sale of
debt securities with a maturity of more than one year, and
preferred or common stock for the purpose of raising new
capital or refunding outstanding securities.
Loss (losses). The general term applied to energy (kilo-
watt-hours) and power (kilowatt) lost in the operation of an
electric system. Losses occur principally as energy trans-
formations from kilowatt-hours to waste heat in electrical
conductors and apparatus.
• Average. The total difference in energy input
and output or power input and output (due to
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2-17
losses) averaged over a time interval and ex-
pressed either in physical quantities or as a
percentage of total input.
• Energy. The kilowatt-hours lost in the opera-
tion of an electric system.
• Line. Kilowatt-hours and kilowatts lost in
transmission and distribution lines under
specified conditions.
• Peak Percent. The difference between the power
input and output, as a result of losses due to
the transfer of power between two or more
points on a system at the time of maximum load,
divided by the power input.
• System. The difference between the system net
energy or power input and output, resulting
from characteristic losses and unaccounted for
between the sources of supply and the metering
points of delivery on a system.
Maintenance Expenses. A subdivision of Operating
Expenses—includes labor, materials, and other direct and
indirect expenses incurred for preserving the operating effi-
ciency or physical condition of utility plant used for power
production, transmission and distribution of energy, and
administrative and general operations.
Margin of Reserve Capacity. See Capability Margin.
Maximum Demand. See Demand, Maximum.
Maximum Load. See Demand, Maximum.
Megawatt (MW). 1,000 kilowatts.
Municipally Owned Electric System. An electric utility
system owned or operated by a municipality engaged in serving
residential, commercial, or industrial customers, usually—but
not always—within the boundaries of the municipality.
Name Plate Rating. The full-load continuous rating of a
generator, prime mover, or other electrical equipment under
specified conditions as designated by the manufacturer. It is
usually indicated on a name plate attached mechanically to the
individual machine or device. The name plate rating of a
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steara-electrie turbine—generator set is the guaranteed con-
tinuous output in kilowatts or kVA and power factor at gener-
ator terminals when the turbine is clean and operating under
specified throttle steam pressure and temperature, specified
reheat temperature, specified exhaust pressure, and with full
extraction from all extraction openings.
NAJRUC. The National Association of Regulatory Utility
Commissioners — an advisory council composed of federal and
state regulatory commissioners having jurisdiction over trans-
portation agencies and public utilities.
Net (Available) for Common Stock. Net Income less
dividends on Preferred Stocks applicable to the period.
Net Income. Income before Interest Charges less Interest
Charges plus or minus Extraordinary Items.
Net Other Income and Deductions. Other Income lass Other
Income Deductions plus or minus Taxes Applicable to Other
Income and Deductions.
Normalizing (or deferred) Method.
• For Deferred or Future Income Taxes. An
accounting method under which decreases or
increases in income taxes, usually resulting
from the use of accelerated amortization or
liberalized depreciation deductions in income
tax returns (federal and state), compared with
straight-line depreciation used for book pur-
poses, are offset in the income account by
corresponding credits or charges to balance
sheet accounts maintained for accumulating the
net balances of deferred and future income
taxes. Charges (provisions) equal to the re-
lated tax deferrals are made against income
when the use of accelerated amortization or
liberalized depreciation produces lower income
taxes than would be the case if straight-line
depreciation had been used in the company's tax
return. Conversely, credits (feedbacks) are
made to income when taxes are increased because
for tax purposes the related facilities were
fully amortized or the applicable accelerated
method resulted in a rate lower than straight-
line depreciation. Charges for taxes deferred
until future years reduce current year book
income; feedback credits for taxes deferred in
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E-19
prior years increase current year book income.
• For Investment Tax Credit. The accounting
method used by companies not flowing through to
income the entire investment tax credit in the
year the credit is realized. The credit to the
income account is offset by providing an amount
equivalent to the reduction in income taxes and
allocating to income an appropriate portion of
it over the life of the asset giving rise to
the tax credit or over some shorter period.
Nuclear Energy. Energy produced in the form of heat
during the fission process in a nuclear reactor. When re-
leased in sufficient and controlled quantity, this heat energy
may be used to produce steam to drive a turbine-generator and
thus be converted to electrical energy.
Nuclear (atomic) Fuel. Material containing fissionable
materials of such composition and enrichment that when placed
in a nuclear'reactor will support a self-sustaining fission
chain reaction and produce heat in a controlled manner for
process use.
Nuclear Power. Power released in exothermic (a reaction
which gives off heat) nuclear reactions which can be converted
to electric power by means of heat transformation equipment
and a turbine-generator unit.
Oil Burned for Fuel. Oil burned for fuel includes fuel
oil, crude oil, diesel oil, and small amounts of tar and gaso-
line, with fuel oil predominating. See Fuel for Electric
Generation.
Operating Expenses. A group of expenses applicable to
utility operations composed of: Operation Expense, Main-
tenance Expense, Provisions for Depreciation and Amortization,
Taxes Other Than Income Taxes, Income Taxes, Provision for
Deferred Income Taxes, Income Taxes Deferred in Prior Years—
Credit, and Investment Tax Credit Adjustments—Net.
Operating Income. Operating Revenues less Operating
Expenses.
Operating Ratio. The ratio, generally expressed as a
percentage, of Operating Expenses to Operating Revenues. This
may be for total operations, or for a single departmental
operation, such as electric or gas. (In special variations,
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the numerator may be defined as exclusive of depreciation or
taxes, or both.)
Operating Revenues. The amounts billed by the utility
for utility services rendered and for other incidental
services.
Power Pool. A power pool is two or more interconnected
electric systems planned and operated to supply power in the
most reliable and economical manner for their combined load
requirements and maintenance program.
Preferred Stock or Preferred Capital Stock. Capital
Stock to which preferences or special rights attach particu-
larly as to dividends or proceeds in liquidation.
Preferred Stock Dividends or Preferred Dividend Charges.
The amount of preferred dividends (declared or accrued) that
are deductible from Net Income in arriving at the earnings for
Common Stock for any given period of time.
Price Earnings (P/E) Ratio. Market price divided by the
annual earnings per share of common stock. The market price
used may be a spot price, or an average of closing, or the
high and low prices for a period; the earnings are for the
corresponding period and may be either the actual or an
estimated annual rate.
Provisions for Deferred (future) Income Taxes. Charges
against income (with corresponding credits to a special li-
ability account) representing the tax deferrals resulting from
the use of accelerated amortization or liberalized deprecia-
tion in federal or state income tax returns, when the deduc-
tions for such rapid depreciation and amortization (applied to
any vintage year's property) exceed the allowance that would
have been taken if straight-line depreciation had been used
for tax return as well as for book purposes. Many companies
net in this account the feedback of a prior year's provisions
for deferred taxes. See Normalizing (or deferred) Method.
Public Utility District. A political subdivision (quasi-
public corporation of a state), with territorial boundaries
embracing an area wider than a single municipality (incor-
porated as well as unincorporated) and frequently coverina
more than one county for the purpose of generating, transmit-
ting, and distributing electric energy.
Pumped Storage. An arrangement whereby additional elec-
tric power may be generated during peak load periods by
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hydraulic means using water pumped into a storage reservoir
during off-peak periods.
Rate Base. The value established by a regulatory author-
ity, upon which a utility is permitted to earn a specified
rate of return. Generally this represents the amount of
property used and useful in public service and may be based on
the following values or combinations of values: fair value,
prudent investment, reproduction cost, or original cost; and
it may provide for the inclusion of cash working capital,
materials and supplies, and deductions for: Accumulated Pro-
vision for Depreciation, Contributions in Aid of Construction,
Customer Advances for Construction, and Accumulated Deferred
Income Taxes and Accumulated Deferred Investment Tax Credits.
Rate of Return. The ratio of allowed Operating Income to
a specified rate base, expressed as a percentage.
System Output. The net generation by the system's own
plants plus purchased energy, plus or minus net interchange
energy.
Total Fuel Expense (after residual credit). Total cost
(including freight and handling) of coal, oil, gas, nuclear,
or other fuel used in the production of electric energy, less
fuel portion of steam transfer credit, and residual credits,
such as net credits from the disposal of ashes, cinders, and
nuclear by-products.
Transmission. The act or process of transporting elec-
tric energy in bulk from a source or sources of supply to
other principal parts of the system or to other utility sys-
tems. Also a functional classification relating to that por-
tion of utility plant used for the purpose of transmitting
electric energy in bulk to other principal parts of the system
or to other utility systems, or to expenses relating to the
operation and maintenance of transmission plant.
Turbine-Generator. A rotary-type unit consisting 'of a
turbine and an electric generator.
Turbine (steam or gas). An enclosed rotary type of prime
mover in which heat energy in steam or gas is converted into
mechanical energy by the force of a high velocity flow of
steam or gases directed against successive rows of radial
blades fastened to a central shaft.
Utility Plant. Includes plant: in-service, purchased or
sold, in process of reclassification, leased to others, held
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for future use, completed construction not classified, con-
struction work in progress, plant acquisition adjustments,
other electric plant adjustments, and other utility plant.
The Uniform System of Accounts prescribes for the deduction of
accumulated provision for depreciation and amortization.
Utility Plant In-Service. That portion of a utility's
plant which' is devoted to the operations of the company. Ex-
cludes plant: purchased or sold, in process of reclassifi-
cation, leased to others, held for future use, under construc-
tion, and acquisition adjustments and adjustment accounts, and
without deduction of accumulated provision for depreciation
and amortization. See Appendix C for further details.
Utilization Factor. The ratio of the maximum demand of a
system or part of a system to the rated capacity of the system
or part of the system under consideration.
Watt. The electrical unit of power or rate of doing
work. The rate of energy transfer equivalent to one ampere
flowing under the pressure of one volt at unity power factor.
It is analogous to horsepower or foot-pounds per minute of
mechanical power. One horsepower is equivalent to approxi-
mately 746 watts.
Winter Peak. The greatest load on an electric system
during any prescribed demand interval in the winter or heating
season, usually between December 1 of a calendar year and
March 31 of the next calendar year.
Working Capital. The amount of cash or other liquid
assets that a company must have on hand to meet the current
costs of operations until such a time as it is reimbursed by
its customers. Sometimes it is used in the narrow sense to
mean the difference between Current and Accrued Assets and
Current and Accrued Liabilities.
Yield. Percentage return based on the market price of a
security. For common and preferred stock, the current "annual
dividend rate is divided by market price. In the case of
bonds, yield is computed on the basis of the bonds being held
to maturity. Yield to maturity is the current interest rate
adjusted to amortize the related debt discount or premium over
the remaining life of the bond. Such yields are published in
bond yield tables.
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ACRONYMS
AQCRs air quality control regions
AFDC allowances for funds used during construction
BACT best available control technology
BAT best available technology economically achievable
BCT best conventional technology
BEJ best engineering judgment
BPT best practicable control technology
CEUM Coal and Electric Utility Model
CTG control techniques guidance
CWIP construction work in progress
FERC Federal Energy Regulatory Commission
FGD fuel gas desulfurization
FUA Powerplant and Industrial Fuel Use Act
GEP good engineering practice
GQRF Generating Unit Reference File
LAER lowest achievable emission rate
MBRs market price to book value ratios
NAAQS National Ambient Air Quality Standards
NCAQ National Commission on Air Quality
NERC National Electric Reliability Council
N0X nitrogen oxides
MPDES national pollution discharge elimination system
NRC Nuclear Regulatory Commission
NRDC Natural Resources Defense Council
NSPS new source performance standards
PCBs polychlorinated biphenyls
POTWs publicly owned treatment works
PSD prevention of significant deterioration
PSES pretreatment standards for existing sources
PSNS pretreatment standards for new sources
PUCs public utility commissions
RACT reasonably available control technology
RCRA Resource Conservation and Recovery Act
SIPs state implementation plans
SO2 sulfur dioxide
TSP total suspended particulates
TSS total suspended solids
UIC underground injection control
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CONVERSION FACTORS
The following are some useful conversion factors.
Conversion Factors—General
1
long ton
contains
1.120 short tons
1
short ton
contains
2,000 pounds
X
barrel
contains
42 gallons
1
barrel (crude oil)
weighs
0.136 metric tons
(0.150 short tons)
1
therm (natural gas)
contains
100 cubic feet
(or 100 ,000 Btu)
1
3tu
equals
0.000293 kilowatt-hours
1
Quad
equals
1 Quadrillion (10^5) gtu
1
kWh Produced
requires
10,500 Btu
X
kWh Consumed
equals
3,413 Btu
Aaqreoated Heat Content
Petroleum
Crude Oil
5. 820
million Btu/barrel
(172 :
x 10® barrels/Quad)
Refined products
Imports, average
6.000
million Btu/barrel
Gasoline
5. 248
million Btu/barrel
Distillate fuel oil
5.825
million Btu/barrel
Residual fuel oil
6. 287
million Btu/barrel
Natural Gas
Natural gas liquids
4. 011
million Btu/barrel
Natural gas
Wet
1,097
Btu/cubic foot
(1 trillion (10y) cubic feet/Quad)
Dry
1,032
Btu/cubic foot
Uranium
Uranium in a
Light Water Reactor
17 5,000 Btu/pound of ore
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Coal
Coal, Average
Lignite
Subbitumi nous
Bituminous
Anthracite
22.5 million Btu/short ton
(44.4 x 106 short tons/Quad)
12.0-15.0 million Btu/short ton
18.0-22.0 million Btu/short ton
24.0-30.0 million Btu/short ton
27.0-30.0 million Btu/short ton
Electricity Conversion Aggregate
Heat Rates
Bituminous coal
Subbituminous and
lignite
Gas
Oil
Nuclear steam-
electric
Hydroelectric
10 MW boiler
Purchased electricity
9,850-10,500 Btu/kilowatt-hour
10,100-10,700 Btu/kilowatt-hour
10,010-11,400 Btu/kilowatt-hour
9,650-12,000 Btu/kilowatt-hour
11,000 Btu/kilowatt-hour
10,38 9 Btu/kilowatt-hour
100,200 Btu/hour
3,413 Btu/kilowatt-hour
Abbreviations
MB/D - thousands of barrels per day
MT/Y - thousands of tons per year
BCF - .billions of cubic feet
Quad - quadrillion Btu
kWh - kilowatt-hour
MW - megawatt
GW - gigawatt (MMW)
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1,000 MWe Coal Powerplant;
Annual Emissions (approximate)
A 1,000 MWe powerplant uses 2.5 million tons of eastern
coal/vear (approx).
Eastern Coal Western Coal
302 (no controls) 111,'000 tons/yr 34, 000 tons/yr
SO2 (with wet limestone
scrubbing) 15,000 4,800
NOx (no controls) 20,300 26,400
Released particulates
(no controls) 45,200 31,000
Released particulates
(with ESP) 5,22 6 5,15 5
Sulfur Content and SO-? Emissions
pounds SOo/MMBTU = 2 (percent sulfur of coal)
* / Heat content in 3tu/lb\
( 10,000 J
Pounds sulfur/ton = 38 (percent sulfur of coal by weight)
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