Economic Impact Analysis of the Final
Stationary Combustion Turbines NESHAP:
Final Report
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EPA-452/R-03-014
August 2003
Economic Impact Analysis of the Final Stationary Combustion Turbines NESHAP
By:
RTI International*
Health, Social, and Economics Research
Research Triangle Park, North Carolina 27709
Prepared for:
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Innovative Strategies and Economics Group, C339-01
Research Triangle Park, NC 27711
*RTI International is a trade name of Research Triangle Institute.
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This report has been reviewed by the Emission Standards Division of the Office of Air
Quality Planning and Standards of the United States Environmental Protection Agency
and approved for publication. Mention of trade names or commercial products is not
intended to constitute endorsement or recommendation for use. Copies of this report are
available through the Library Services (MD-35), U.S. Environmental Protection Agency,
Research Triangle Park, NC 27711, or from the National Technical Information Services
5285 Port Royal Road, Springfield, VA 22161.
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TABLE OF CONTENTS
Section Page
1 Introduction 1-1
1.1 Agency Requirements for an EIA 1-1
1.2 Scope and Purpose 1-2
1.3 Organization of the Report 1-2
2 Combustion Turbine Technologies and Costs 2-1
2.1 Simple-Cycle Combustion Turbine Technologies 2-1
2.2 Combined-Cycle Combustion Turbine Technologies 2-2
2.3 Capital and Installation Costs 2-4
2.4 O&M Costs Including Fuel 2-5
3 Background on Health Affects and Regulatory Alternatives 3-1
3.1. Background 3-1
3.1.1 Criteria Used in NESHAP Development 3-1
3.2 Health Effects Associated with HAPs from Stationary Combustion
Turbines 3-2
3.3 Summary of the Rule 3-3
3.3.1 Source Categories and Subcategories Affected by the Rule ... 3-4
3.3.2 Emission Limitations and Operating Limitations 3-6
3.3.3 Initial Compliance Requirements 3-7
3.3.4 Continuous Compliance Provisions 3-8
3.3.5 Notification, Record-keeping, and Reporting Requirements . . . 3-9
3.4 Rationale for Selecting Standards 3-10
3.4.1 Selection of Source Categories and Subcategories 3-10
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3.4.2 Determination of Basis and Level of Emission Limitations for
Existing Sources 3-13
3.4.2.1 MACT Floor for Existing Lean Premix Combustion
Turbines 3-13
3.4.2.2 MACT for Existing Lean Premix Combustion
Turbines 3-15
3.4.2.3 MACT Floor for Existing Diffusion Flame
Combustion Turbines 3-15
3.4.2.4 MACT for Existing Diffusion Flame Combustion
Turbines 3-17
3.4.3 New Sources 3-17
3.4.3.1 New Lean Premix Gas-Fired Combustion Turbines . 3-18
3.4.3.2 New Lean Premix Oil-Fired Combustion Turbines . 3-19
3.4.3.3 New Diffusion Flame Gas-Fired Combustion
Turbines 3-20
3.4.3.4 New Diffusion Flame Oil-Fired Combustion
Turbines 3-21
3.4.4 MACT for Other Subcategories 3-22
3.4.5 Selection of Initial Compliance Requirements 3-24
3.4.5.1 How Did We Select the Continuous Compliance
Requirements? 3-24
3.4.5.2 How Did We Select the Testing Methods to
Measure these Low Concentrations of
Formaldehyde? 3-25
Projection of Units and Facilities in Affected Sectors 4-1
4.1 Profile of Existing Combustion Turbine Units 4-1
4.1.1 Distribution of Units and Facilities by Industry 4-2
4.1.2 Technical Characteristics 4-2
4.2 Projected Growth of Combustion Turbines 4-5
4.2.1 Comparison of Alternative Growth Estimates 4-5
4.3 Number of Affected Stationary Combustion Turbines 4-7
4.4 HAP and Other Emission Reductions 4-8
4.5 Energy and Other Impacts from Direct Application of
Control Measures 4-9
4.5.1 Water Impacts 4-9
4.5.2 Solid Waste Impacts 4-10
IV
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4.6 Trends in the Electric Utility Industry 4-10
5 Profiles of Affected Industries 5-1
5.1 Electric Utility Industry (NAICS 22111) 5-1
5.1.1 Market Structure of the Electric Power Industry 5-1
5.1.1.1 The Evolution of the Electric Power Industry 5-2
5.1.1.2 Structure of the Traditional Regulated Utility 5-3
5.1.1.3 Current Electric Power Supply Chain 5-6
5.1.1.4 Overview of Deregulation and the Potential Future
Structure of the Electricity Market 5-14
5.1.2 Electricity Generation 5-16
5.1.2.1 Growth in Generation Capacity 5-19
5.1.3 Electricity Consumption 5-22
5.2 Oil and Gas Extraction (NAICS 211) 5-23
5.2.1 Introduction 5-24
5.2.2 Supply Side 5-27
5.2.2.1 Production Processes 5-27
5.2.2.2 Types of Output 5-28
5.2.2.3 Major By-products 5-30
5.2.2.4 Costs of Production 5-30
5.2.2.5 Capacity Utilization 5-31
5.2.3 Demand Side 5-32
5.2.4 Organization of the Industry 5-33
5.2.5 Markets and Trends 5-36
5.3 Natural Gas Pipelines 5-37
5.3.1 Introduction 5-37
5.3.2 Supply Side 5-39
5.3.2.1 Service Description 5-39
5.3.2.2 By-products 5-40
5.3.2.3 Costs of Production 5-40
5.3.2.4 Capacity Utilization 5-40
5.3.3 Demand Side 5-42
5.3.4 Organization of the Industry 5-43
5.3.5 Markets and Trends 5-43
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Economic Analysis Methods 6-1
6.1 Agency Requirements for Conducting an EIA 6-1
6.2 Overview of Economic Modeling Approaches 6-2
6.2.1 Modeling Dimension 1: Scope of Economic
Decisionmaking 6-2
6.2.2 Modeling Dimension 2: Interaction Between Economic
Sectors 6-3
6.3 Selected Modeling Approach Used for Combustion Turbine
Analysis 6-4
6.3.1 Electricity Markets 6-7
6.3.2 Other Energy Markets 6-7
6.3.3 Supply and Demand Elasticities for Energy Markets 6-8
6.3.4 Final Product and Service Markets 6-10
6.3.4.1 Modeling the Impact on the Industrial and
Commercial Sectors 6-11
6.3.4.2 Impact on the Residential Sector and
Transportation Sectors 6-13
6.3.4.3 Impact on the Government Sector 6-13
6.4 Summary of the Economic Impact Model 6-13
6.4.1 Estimating Changes in Social Welfare 6-16
Economic Impact Analysis 7-1
7.1 Engineering Control Cost Inputs 7-1
7.1.1 Computing Supply Shifts in the Electricity Market 7-2
7.2 Market-Level Results 7-3
7.3 Social Cost Estimates 7-6
7.4 Executive Order 13211 (Energy Effects) 7-7
8 Small Entity Impacts 8-1
8.1 Identifying Small Businesses 8-2
8.2 Screening-Level Analysis 8-2
8.3 Assessment 8-3
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References R-l
Appendix A Overview of the Market Model A-l
Appendix B Assumptions and Sensitivity Analysis B-l
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LIST OF FIGURES
Number Page
2-1 Simple-Cycle Gas Turbine 2-2
2-2 Combined-Cycle Gas Turbine 2-3
4-1 Number of Units by MW Capacity 4-4
4-2 Number of Units by Annual MWh Output Equivalent 4-6
4-3 Number of Units by Annual Hours of Operation 4-6
5-1 Traditional Electric Power Industry Structure 5-4
5-2 Electric Utility Industry 5-8
5-3 Utility and Nonutility Generation and Shares by Class, 1988 and 1998 5-10
5-4 Annual Electricity Sales by Sector 5-19
6-1 Links Between Energy and Final Product Markets 6-6
6-2 Electricity Market 6-8
6-3 Potential Market Effects of the Proposed MACT on Petroleum, Natural
Gas, or Coal 6-9
6-4 Fuel Market Interactions with Facility-Level Production Decisions 6-11
6-5 Operationalizing the Estimation of Economic Impact 6-15
6-6 Changes in Economic Welfare with Regulation 6-17
7-1 Market for Baseload Electricity 7-4
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LIST OF TABLES
Number Page
2-1 Comparison of Emissions from Coal-Fired and Simple-Cycle Turbines
and Combined-Cycle Turbines 2-4
2-2 Overall Installation Costs 2-5
2-3 Comparison of Percentage of Costs 2-6
4-1 Facilities With Units Having Capacities Above 1 MW by Industry
Grouping and Government Sector 4-3
4-2 Stationary Combustion Turbine Projections 4-4
4-3 Planned Capacity Additions at U.S. Public Utilities, 1998 through 2007, as of
January 1, 1998 4-7
5-1 Total Expenditures in 1996 ($103) 5-7
5-2 Number of Electricity Suppliers in 1999 5-9
5-3 Top Power Marketing Companies, First Quarter 1999 5-13
5-4 Industry Capability by Energy Source, 2000 5-17
5-5 Installed Capacity at U.S. Nonutility Attributed to Major Industry
Groups and Census Division, 1995 through 1999 (MW) 5-17
5-6 Existing Capacity at U.S. Electric Utilities by Prime Mover and Energy
Source, as of January 1, 1998 5-18
5-7 Key Parameters in the Cases 5-20
5-8 Capacity Additions and Retirements at U.S. Electric Utilities by Energy
Source, 1997 5-21
5-9 Fossil-Fueled Existing Capacity and Planned Capacity Additions at
U.S. Electric Utilities by Prime Mover and Primary Energy Source, as
of January 1, 1998 5-22
5-10 U.S. Electric Utility Retail Sales of Electricity by Sector, 1989 Through
July 1999 (Million kWh) 5-23
5-11 Crude Petroleum and Natural Gas Industries Likely to Be Affected by the
Regulation 5-25
5-12 Summary Statistics, Crude Oil and Natural Gas Extraction and
Related Industries 5-26
5-13 U.S. Supply of Crude Oil and Petroleum Products (103 barrels), 1998 5-29
5-14 U.S. Natural Gas Production, 1998 5-30
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5-15 Costs of Production, Crude Oil and Natural Gas Extraction and
Related Industries 5-31
5-16 Estimated U.S. Oil and Gas Reserves, Annual Production, and
Imports, 1998 5-32
5-17 Size of Establishments and Value of Shipments, Crude Oil and Natural Gas
Extraction Industry (NAICS 211111), 1997 and 1992 5-34
5-18 Size of Establishments and Value of Shipments, Natural Gas Liquids
Industry (NAICS 211112), 1997 and 1992 5-35
5-19 Size of Establishments and Value of Shipments, Drilling Oil and Gas Wells
Industry (NAICS 213111), 1997 and 1992 5-36
5-20 Size of Establishments and Value of Shipments, Oil and Gas Field Services
(NAICS 213112), 1997 and 1992 5-37
5-21 Summary Statistics for the Natural Gas Pipeline Industry
(NAICS 4862), 1997 5-38
5-22 Summary Profile of Completed and Proposed Natural Gas Pipeline
Projects, 1996 to 2000 5-41
5-23 Energy Usage and Cost of Fuel, 1994-1998 5-42
5-24 Transmission Pipeline Capacity, Average Daily Flows, and Usage Rates,
1990 and 1997 5-42
5-25 Five Largest Natural Gas Pipeline Companies by System Mileage, 2000 .... 5-44
6-1 Comparison of Modeling Approaches 6-3
6-2 Supply and Demand Elasticities 6-10
6-3 Fuel Price Elasticities 6-12
6-4 Supply and Demand Elasticities for Industrial and Commercial Sectors 6-14
7-1 Engineering Cost Analysis for the Stationary Combustion Turbine
MACT Standard 7-2
7-2 Summary of Turbine Cost Information and Supply Shifts 7-3
7-3 Market-Level Impacts of Stationary Combustion Turbines MACT
Standard: 2005 7-5
7-4 Changes in Market Share for Electricity Suppliers 7-6
7-5 Distribution of Social Costs of Stationary Combustion Turbines
MACT Standard: 2005 7-8
8-1 Number of Units Greater than 1 MW at Small Parents by Industry 8-4
8-2 Summary Statistics for SBREFA Screening Analysis: Recommended
Alternative 8-5
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SELECT LIST OF ACRONYMS AND ABBREVIATIONS
CAA: Clean Air Act
CO: Carbon Monoxide
COPD: Chronic Obstructive Pulmonary Disease
CCCT: Combined-Cycle Combustion Turbine
C/S: Cost to Sales Ratio
DOE: Department of Energy
EO: Executive Order\
EPA: Environmental Protection Agency
EWG: Exempt Wholesale Generators
GW: Gigawatt
HAP: Hazardous Air Pollutant
ICCR: Industrial Combustion Coordinated Rulemaking
IPP: Independent Power Producer
kWh: Kilowatt Hour
Ib: Pound
mills/kWh: Mills per Kilowatt Hour
mmBTU: Millions of British Thermal Units
MACT: Maximum Achievable Control Technology
MW: Megawatts
Mwh: Megawatt Hours
NAAQS: National Ambient Air Quality Standards
NAICS: North American Industrial Classification System
NESHAP: National Emission Standards for Hazardous Air Pollutants
NPR: Notice of Proposed Rulemaking
NSPS: New Source Performance Standards
NSR: New Source Review
OMB: Office of Management and Budget
O&M: Operation and Maintenance
P/E: Partial Equilibrium
PM: Particulate Matter
ppbdv: Parts Per Billion, dry volume
ppm: Parts Per Million
PRA: Paperwork Reduction Act of 1995
RFA: Regulatory Flexibility Act
SAB: Science Advisory Board
SB A: Small Business Administration
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SBREFA: Small Business Regulatory Enforcement Fairness Act of 1996
SCCT: Simple-Cycle Combustion Turbine
SIC: Standard Industrial Classification
SOA: Secondary Organic Aerosols
TAG: Total Annual Cost
tpd: Tons Per Day
tpy: Tons Per Year
UMRA: Unfunded Mandates Reform Act
VOCs: Volatile Organic Compounds
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SECTION 1
INTRODUCTION
The U.S. Environmental Protection Agency (referred to as EPA or the Agency) is
developing regulations under Section 112 of the Clean Air Act (CAA) for new stationary
combustion turbines. The majority of stationary combustion turbines burn natural gas and
are used in the electric power and natural gas industries. The regulations are designed to
reduce emissions of hazardous air pollutants (HAPs) generated by the combustion of fossil
fuels in combustion turbines. The primary HAPs emitted by turbines include formaldehyde,
acetaldehyde, toluene, and benzene. To inform this rulemaking, the Innovative Strategies
and Economics Group (ISEG) of EPA's Office of Air Quality Planning and Standards
(OAQPS) has developed an economic impact analysis (EIA) to estimate the potential social
costs of the regulation. This report presents the results of this analysis in which a market
model was used to analyze the impacts of the air pollution rule on society.
1.1 Agency Requirements for an EIA
Congress and the Executive Office have imposed statutory and administrative
requirements for conducting economic analyses to accompany regulatory actions. Section
317 of the CAA specifically requires estimation of the cost and economic impacts for
specific regulations and standards proposed under the authority of the Act. In addition,
Executive Order (EO) 12866 requires a more comprehensive analysis of benefits and costs
for significant regulatory actions.1 Other statutory and administrative requirements include
examination of the composition and distribution of benefits and costs. For example, the
Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory
Enforcement and Fairness Act of 1996 (SBREFA), requires EPA to consider the economic
impacts of regulatory actions on small entities. Also, Executive Order 13211 requires EPA to
consider for particular rules the impacts on energy markets.
'Office of Management and Budget (OMB) guidance under EO 12866 stipulates that a full benefit-cost analysis
is required only when the regulatory action has an annual effect on the economy of $100 million or more.
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1.2 Scope and Purpose
The CAA's purpose is to protect and enhance the quality of the nation's air resources
(Section 101(b)). Section 112 of the CAA Amendments of 1990 establishes the authority to
set national emissions standards for HAPs. This report evaluates the economic impacts of
pollution control requirements placed on stationary combustion turbines under these
amendments. These control requirements are designed to reduce releases of HAPs into the
atmosphere.
To reduce emissions of HAPs, the Agency establishes maximum achievable control
technology (MACT) standards. The term "MACT floor" refers to the minimum control
technology on which MACT standards can be based. For existing major sources, the MACT
floor is the average emissions limitation achieved by the best performing 12 percent of
sources (if there are 30 or more sources in the category or subcategory). For new sources,
the MACT floor must be no less stringent than the emissions control achieved in practice by
the best controlled similar source. The MACT can also be chosen to be more stringent than
the floor, considering the costs and the health and environmental impacts. Emissions
reductions and the costs associated with the regulation are based primarily on the installation
of an oxidation catalyst emission control device, such as a carbon monoxide (CO) oxidation
catalyst. These control devices are used to reduce CO emissions and are currently installed
on several stationary combustion turbines. In addition, performance testing is required of all
affected stationary combustion turbines.
The regulation affects new stationary combustion turbines over 1 megawatt (MW).
This analysis uses data from EPA's Inventory Database V.4—Turbines (referred to as the
Inventory Database). To estimate the economic impacts associated with the regulation, new
stationary combustion turbines are projected through the year 2005.
1.3 Organization of the Report
The remainder of this report is divided into six sections that describe the
methodology and present results of this analysis:
• Section 2 provides background information on combustion turbine technologies
and compares the equipment, installation, and operating costs of simple-cycle
combustion turbines (SCCTs) and combined-cycle combustion turbines (CCCTs).
• Section 3 provides background information on the regulatory alternatives
examined, information on the emission reductions associated with the rule, and
health effects from exposure to the HAPs emitted by combustion turbines.
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• Section 4 provides projections of new stationary combustion turbines through the
year 2005. This section also profiles the population of existing turbines.
• Section 5 profiles the electric service industry (NAICS 221), oil and gas
extraction industry (NAICS 211), and the natural gas pipeline industry (NAICS
486).
• Section 6 presents the methodology for assessing the economic impacts of the
NESHAP and describes the computerized market model used to estimate the
social cost impacts and to dissagregate impacts into changes in producer and
consumer surplus.
• Section 7 presents the economic impact estimates for the NESHAP and describes
the control alternatives used to estimate the impacts. This section also discusses
the regulation's impact on energy supply, distribution, and use.
• Section 8 provides the Agency's analysis of the regulation's impact on small
entities.
In addition to these sections, Appendix A details the market model approach used to predict
the economic impacts of the NESHAP. Appendix B describes the limitations of the data and
market model and presents sensitivity analyses associated with key assumptions.
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SECTION 2
COMBUSTION TURBINE TECHNOLOGIES AND COSTS
This section provides background information on combustion turbine technologies.
Included is a discussion of simple-cycle combustion turbines (SCCTs) and combined-cycle
combustion turbines (CCCTs), along with a comparison of fuel efficiency and capital costs
between the two classes of turbines.
2.1 Simple-Cycle Combustion Turbine Technologies
Most stationary combustion turbines use natural gas to generate shaft power that is
converted into electricity.1 Combustion turbines have four basic components, as shown in
Figure 2-1.
1. The compressor raises the air pressure up to thirty times atmospheric.
2. A fuel compressor is used to pressurize the fuel.
3. The compressed air is heated in the combustion chamber at which point fuel is
added and ignited.
4. The hot, high pressure gases are then expanded through a power turbine,
producing shaft power, which is used to drive the air and fluid compressors and a
generator or other mechanical drive device. Approximately one-third of the
power developed by the power turbine can be required by the compressors.
Electric utilities primarily use simple-cycle combustion turbines as peaking or backup units.
Their relatively low capital costs and quick start-up capabilities make them ideal for partial
operation to generate power at periods of high demand or to provide ancillary services, such
'Combustion turbine technology used for aircraft engines is virtually the same except the energy is used to
generate thrust.
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Gas Turbines
Fuel
Fuel Compressor
0)
Q.
O
O
Combustion
Chamber
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gas turbine; then the heat that remains is used to create steam, which is run through a steam
turbine. Thus, two single units, gas and steam, are put together to minimize lost potential
energy.
The second cycle is a steam turbine. In a CCCT, the waste heat remaining from the
gas turbine cycle is used in a boiler to produce steam. The steam is then put through a steam
turbine, producing power. The remaining steam is recondensed and either returned to the
boiler where it is sent through the process again or sold to a nearby industrial site to be used
in a production process. Figure 2-2 shows a gas-fired CCCT.
Emissions
Combustion Gases
300-400 °F
Combined Cycle
Steam Generator
Combustion Gases
900-1000 °F
Gas Turbine
Fuel
Air
Figure 2-2. Combined-Cycle Gas Turbine
Source: Siemens Westinghouse. August 31, 1999. Presentation.
There are significant efficiency gains in using a combined-cycle turbine compared to
simple-cycle systems. With SCCTs, adding a second stage allows for heat that otherwise
would have been emitted and completely wasted to be used to create additional power or
steam for industrial purposes. For example, a SCCT with an efficiency of 38.5 percent,
adding a second stage increases the efficiency to 58 percent, a 20 percent increase in
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efficiency (Siemens, 1999). General Electric (1999) has recently developed a 480 MW
system that will operate at 60 percent net combined-cycle efficiency.
In addition to energy efficiency gains, CCCTs also offer environmental efficiency
gains compared to existing coal plants. In addition, efficiency gains associated with the
CCCT lead to lower emissions compared to SCCTs. As Table 2-1 shows, the 58 percent
efficiency turbine decreases NOX emissions by 14 percent over simple-cycle combustion
turbines and 89 percent over existing coal electricity generation plants. In addition, CO2
emissions will be 5 percent lower than emissions from SCCTs and 64 percent lower than
existing coal plants.
Table 2-1. Comparison of Emissions from Coal-Fired and Simple-Cycle Turbines and
Combined-Cycle Turbines
Coal electricity generation
Simple-cycle turbines
Combined-cycle turbines
NOX
(Ib/MW-hr)
5.7
0.7
0.6
CO2
(Ib/MW-hr)
2,190
825
780
Source: Siemens Westinghouse. August 31, 1999. Presentation.
2.3 Capital and Installation Costs
CCCT capital and installation costs are approximately 30 percent less ($/MW) than a
conventional coal or oil steam power plant's capital and installation costs, and CCCT costs
are likely to decrease over the next 10 years. Gas turbine combined-cycle plants range from
approximately $300 per kW installed for very large utility-scale plants to $1,000 per kW
($1998) for small industrial cogeneration installation (GTWHandbook, 1999). However, the
prices of construction can vary as a result of local labor market conditions and the
geographic conditions of the site (GTWHandbook, 1999). SCCTs are approximately half the
cost of CCCT units.
Table 2-2 breaks down the budgeted construction costs of a gas-fired 107 MW
combined-cycle cogenerating station at John F. Kennedy International Airport that was
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Table 2-2. Overall Installation Costs
Construction costs can vary dramatically. This table shows the budgeted cost for a gas-fired
107 MW combined-cycle cogenerating station at John F. Kennedy International Airport in
Brooklyn, New York. The power plant uses two 40 MW Stewart & Stevenson LM6000 gas
turbine generators each exhausting into a triple pressure heat recovery steam generator raising
steam for processes and to power a nominal 27 MW steam turbine generator. Budgeted prices are
in 1995-1996 U.S. dollars.
Budget Equipment Pricing $ Amount
Gas turbine generators $24,000,000
Heat recovery steam generators 10,000,000
Steam turbine generator set 4,000,000
Condenser 300,000
Cooling towers 800,000
Transformer and switchgear 8,000,000
Balance of plant equipment 7,500,000
Subtotal, equipment $54,600,000
Budget Services and Labor
Mechanical and electrical construction $20-75,000,000
Engineering 4,000,000
Subtotal, services $24-79,000,000
Total Capital Cost $78,600,000-133,600,000
Source: 1998-99 GTW Handbook. "Turnkey Combined Cycle Plant Budget Price Levels." Fairfield, CT:
PequotPub. Pgs. 16-26.
installed several years ago. As shown in Table 2-2, the construction price can range
dramatically. This job finished near the top of the budget, close to $133,600,000. According
to Gas Turbine World, the typical budget price for a 168 MW plant is $80,600,000,
($480/kW) for a plant with net efficiency of 50.9 percent (GTWHandbook, 1999).
2.4 O&M Costs Including Fuel
Fuel accounts for one-half to two-thirds of total production costs (annualized capital,
operation and maintenance, fuel costs) associated with generating power using combustion
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turbines. Table 2-3 compares the percentage of costs spent on annualized capital, operation
and maintenance, and fuel for both simple turbines and CCCTs.
Table 2-3. Comparison of Percentage of Costs3
Simple Cycle Combined Cycle
% Capital costs 50 25
% Operation and maintenance 10 10
% Fuel 40 65
a Based on a review of marketing information from turbine manufacturers and the GTW Handbook.
The fuel costs may vary depending on the plant's location. In areas where gas costs
are high, for a base-load CCCT power plant, fuel costs can account for up to 70 percent of
total plant costs—including acquisition, owning and operating costs, and debt service (GTW
Handbook, 1999). General Electric's "H" design goals for future CCCT systems are to
reduce power plant operating costs by at least 10 percent compared to today's technology as
a direct result of using less fuel. The higher efficiency allows more power to be generated
with the same amount of fuel, resulting in a substantial fuel cost savings for the plant owner
(General Electric, 1999).
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SECTION 3
BACKGROUND ON HEALTH AFFECTS AND REGULATORY ALTERNATIVES
3.1 Background
Section 112 of the CAA requires EPA to list categories and subcategories of major
sources and area sources of HAPs and to establish NESHAPs for the listed source categories
and subcategories. The stationary turbine source category was listed on July 16, 1992
(57 FR 31576). Major sources of HAPs are those that have the potential to emit greater than
10 ton/yr of any one HAP or 25 ton/yr of any combination of HAPs.
3.1.1 Criteria Used in NESHAP Development
Section 112 of the CAA requires that we establish NESHAPs for controlling HAPs
from both new and existing major sources. The CAA requires the NESHAP to reflect the
maximum degree of reduction in emissions of HAPs that is achievable. This level of control
is commonly referred to as the MACT.
The MACT floor is the minimum control level allowed for a NESHAP and is defined
under section 112(d)(3) of the CAA. In essence, the MACT floor ensures that the standard is
set at a level that assures that all major sources achieve the level of control at least as
stringent as that already achieved by the better controlled and lower emitting sources in each
source category or subcategory. For new sources, the MACT standards cannot be less
stringent than the emission control that is achieved in practice by the best controlled similar
source. The MACT standards for existing sources can be less stringent than standards for
new sources, but they cannot be less stringent than the average emission limitation achieved
by the best performing 12 percent of existing sources in the category or subcategory (or the
best performing five sources for categories or subcategories with fewer than 30 sources).
In developing MACT, we also consider control options that are more stringent than
the floor. We may establish standards more stringent than the floor based on the
consideration of cost of achieving the emissions reductions, any nonair quality health and
environmental impacts, and energy requirements.
Discussion of the costs and other impacts associated with the MACT floor and other
alternatives can be found in Section 4.
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3.2 Health Effects Associated with HAPs from Stationary Combustion Turbines
Several HAPs are emitted from stationary combustion turbines. These HAP
emissions are formed during combustion or result from HAP compounds contained in the
fuel burned.
Among the HAPs that have been measured in emission tests that were conducted at
natural gas-fired and distillate oil-fired combustion turbines are 1,3 butadiene, acetaldehyde,
acrolein, benzene, ethylbenzene, formaldehyde, naphthalene, poly aromatic hydrocarbons
(PAH), propylene oxide, toluene, and xylenes. Metallic HAPs from distillate oil-fired
stationary combustion turbines that have been measured are arsenic, beryllium, cadmium,
chromium, lead, manganese, mercury, nickel, and selenium. Natural gas-fired stationary
combustion turbines do not emit metallic HAPs.
Although numerous HAPs may be emitted from combustion turbines, only a few
account for essentially all the mass (about 97 percent) of HAP emissions from natural gas-
fired stationary combustion turbines. These HAPs are formaldehyde, toluene, benzene, and
acetaldehyde.
The HAPs emitted in the largest quantity is formaldehyde. Formaldehyde is a
probable human carcinogen and can cause irritation of the eyes and respiratory tract,
coughing, dry throat, tightening of the chest, headache, and heart palpitations. Acute
inhalation has caused bronchitis, pulmonary edema, pneumonitis, pneumonia, and death due
to respiratory failure. Long-term exposure can cause dermatitis and sensitization of the skin
and respiratory tract.
Other HAPs emitted in significant quantities from stationary combustion turbines
include toluene, benzene, and acetaldehyde. The health effect of primary concern for toluene
is dysfunction of the central nervous system (CNS). Toluene vapor also causes narcosis.
Controlled exposure of human subjects produced mild fatigue, weakness, confusion,
lacrimation, and paresthesia; at higher exposure levels there were also euphoria, headache,
dizziness, dilated pupils, and nausea. After effects included nervousness, muscular fatigue,
and insomnia persisting for several days. Acute exposure may cause irritation of the eyes,
respiratory tract, and skin. It may also cause fatigue, weakness, confusion, headache, and
drowsiness. Very high concentrations may cause unconsciousness and death.
Benzene is a known human carcinogen. The health effects of benzene include nerve
inflammation, CNS depression, and cardiac sensitization. Chronic exposure to benzene can
cause fatigue, nervousness, irritability, blurred vision, and labored breathing and has
produced anorexia and irreversible injury to the blood-forming organs; effects include
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aplastic anemia and leukemia. Acute exposure can cause dizziness, euphoria, giddiness,
headache, nausea, staggering gait, weakness, drowsiness, respiratory irritation, pulmonary
edema, pneumonia, gastrointestinal irritation, convulsions, and paralysis. Benzene can also
cause irritation to the skin, eyes, and mucous membranes.
Acetaldehyde is a probable human carcinogen. The health effects for acetaldehyde
are irritation of the eyes, mucous membranes, skin, and upper respiratory tract, and it is a
CNS depressant in humans. Chronic exposure can cause conjunctivitis, coughing, difficult
breathing, and dermatitis. Chronic exposure may cause heart and kidney damage,
embryotoxicity, and teratogenic effects.
3.3 Summary of the Rule
The rule applies to you if you own or operate a stationary combustion turbine that is
located at a major source of HAP emissions, the definition of which is mentioned above.
It should be noted that the rule does not apply to stationary combustion turbines
located at an area source of HAP emissions. An area source of HAP emissions is a
contiguous site under common control that is not a major source.
The rule does not cover duct burners. They are part of the waste heat recovery unit in
a combined cycle system. Waste heat recovery units, whether part of a cogeneration system
or a combined cycle system, are steam-generating units and are not covered by the rule.
Stationary combustion turbines located at research or laboratory facilities are not
subject to the final rule if research is conducted on the turbine itself and the turbine is not
being used to power other applications at the research or laboratory facility.
Finally, the rule does not apply to stationary combustion engine test cells/stands
because these facilities will be covered by another NESHAP, 40 CFR part 63, subpart
PPPPP.
For those sources that are covered, eight subcategories have been defined within the
stationary combustion turbine source category. Although all stationary combustion turbines
are subject to the rule, each subcategory has distinct requirements. For example, existing
combustion turbines and stationary combustion turbines with a rated peak power output of
less than 1.0 megawatt (MW) (at International Organization for Standardization (ISO)
standard day conditions) are not required to comply with emission limitations, record-
keeping, or reporting requirements in the rule. New or reconstructed stationary combustion
turbines with a rated peak power output of 1.0 MW or more that either operate exclusively as
an emergency stationary combustion turbine, on the North Slope of Alaska, or as a stationary
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combustion turbine that burns landfill gas or digester gas equivalent to 10 percent or more of
the gross heat input on an annual basis or where gasified municipal solid waste (MSW) is
used to generate 10 percent or more of the gross heat input to the turbine on an annual basis
do not have to comply with an emission limitation but have initial notification requirements.
New or reconstructed combustion turbines must comply with emission limitations, record-
keeping, and reporting requirements in the rule. You must determine your source's
subcategory to determine which requirements apply to your source.
3.3.1 Source Categories and Subcategories Affected by the Rule
A stationary combustion turbine includes
• all equipment, including, but not limited to, the turbine, the fuel, air, lubrication
and exhaust gas systems, control systems (except emissions control equipment);
• any ancillary components and subcomponents comprising any simple cycle
stationary combustion turbine; and
• any regenerative/recuperative cycle stationary combustion turbine, or the
combustion turbine portion of any stationary combined cycle steam/electric
generating system.
Stationary means that the combustion turbine is not self-propelled or intended to be
propelled while performing its function. A stationary combustion turbine may, however, be
mounted on a vehicle for portability or transportability.
Stationary combustion turbines have been divided into the following eight
subcategories:
1. emergency stationary combustion turbines,
2. stationary combustion turbines that burn landfill or digester gas equivalent to 10
percent or more of the gross heat input on an annual basis or where gasified MSW
is used to generate 10 percent or more of the gross heat input to the stationary
combustion turbine on an annual basis,
3. stationary combustion turbines of less than 1 MW rated peak power output,
4. stationary lean premix combustion turbines when firing gas and when firing oil at
sites where all turbines fire oil no more than 1000 hours annually (also referred to
herein as "lean premix gas-fired turbines"),
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5. stationary lean premix combustion turbines when firing oil at sites where all
turbines fire oil more than 1000 hours annually (also referred to herein as "lean
premix oil-fired turbines"),
6. stationary diffusion flame combustion turbines when firing gas and when firing
oil at sites where all turbines fire oil no more than 1000 hours annually (also
referred to herein as "diffusion flame gas-fired turbines"),
7. stationary diffusion flame combustion turbines when firing oil at sites where all
turbines fire oil more than 1000 hours annually (also referred to herein as
"diffusion flame oil-fired turbines"), and
8. stationary combustion turbines operated on the North Slope of Alaska (defined as
the area north of the Arctic Circle [latitude 66.5° North]).
An emergency stationary combustion turbine means any stationary combustion
turbine that operates in an emergency situation. Examples include stationary combustion
turbines used to produce power for critical networks or equipment (including power supplied
to portions of a facility) when electric power from the local utility is interrupted, or
stationary combustion turbines used to pump water in the case of fire or flood, etc.
Emergency stationary combustion turbines do not include stationary combustion turbines
used as peaking units at electric utilities or stationary combustion turbines at industrial
facilities that typically operate at low capacity factors. Emergency stationary combustion
turbines may be operated for the purpose of maintenance checks and readiness testing,
provided that the tests are required by the manufacturer, the vendor, or the insurance
company associated with the turbine. Required testing of such units should be minimized,
but there is no time limit on the use of emergency stationary sources.
Stationary combustion turbines that burn landfill or digester gas equivalent to 10
percent or more of the gross heat input on an annual basis or stationary combustion turbines
where gasified MSW is used to generate 10 percent or more of the gross heat input to the
stationary combustion turbine on an annual basis qualify as a separate subcategory because
the types of control available for these turbines are limited.
Stationary combustion turbines of less than 1 MW rated peak power output were also
identified as a subcategory. These small stationary combustion turbines are few in number,
and, to our knowledge, none use emission control technology to reduce HAPs. Therefore, it
would be inappropriate to require HAP emission controls to be applied to them without
further information on control technology performance.
Two subcategories of stationary lean premix combustion turbines were established:
stationary lean premix combustion turbines when firing gas and when firing oil at sites where
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all turbines fire oil no more than 1000 hours annually (also referred to as "lean premix gas-
fired turbines"), and stationary lean premix combustion turbines when firing oil at sites
where all turbines fire oil more than 1000 hours annually (also referred to as "lean premix
oil-fired turbines"). Lean premix technology, introduced in the 1990s, was developed to
reduce nitrogen oxide (NOX) emissions without the use of add-on controls. In a lean premix
combustor, the air and fuel are thoroughly mixed to form a lean mixture for combustion.
Mixing may occur before or in the combustion chamber. Lean premix combustors emit
lower levels of NOX, carbon monoxide (CO), formaldehyde and other HAPs than diffusion
flame combustion turbines.
Two subcategories of stationary diffusion flame combustion turbines were
established: stationary diffusion flame combustion turbines when firing gas and when firing
oil at sites where all turbines fire oil no more than 1000 hours annually (also referred to as
"diffusion flame gas-fired turbines"), and stationary diffusion flame combustion turbines
when firing oil at sites where all turbines fire oil more than 1000 hours annually (also
referred to as "diffusion flame oil-fired turbines"). In a diffusion flame combustor, the fuel
and air are injected at the combustor and are mixed only by diffusion prior to ignition.
Hazardous air pollutant emissions from these turbines can be significantly decreased with the
addition of air pollution control equipment.
Stationary combustion turbines located on the North Slope of Alaska have been
identified as a subcategory because of operating limitations and uncertainties regarding the
application of controls to these units. There are very few of these units, and none have
installed emission controls for reducing HAPs.
3.3.2 Emission Limitations and Operating Limitations
As the owner or operator of a new or reconstructed lean premix gas-fired turbine, a
new or reconstructed lean premix oil-fired turbine, a new or reconstructed diffusion flame
gas-fired turbine, or a new or reconstructed diffusion flame oil-fired turbine, you must
comply with the emission limitation to reduce the concentration of formaldehyde in the
exhaust from the new or reconstructed stationary combustion turbine to 91 parts per billion
by volume (ppbv) or less, dry basis (ppbvd), at 15 percent oxygen by the effective date of the
standards (or upon startup if you start up your stationary combustion turbine after the
effective date of the standards).
If you comply with the emission limitation for formaldehyde emissions and you use
an oxidation catalyst emission control device, you must continuously monitor the oxidation
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catalyst inlet temperature and maintain the inlet temperature to the oxidation catalyst within
the range recommended by the catalyst manufacturer.
If you comply with the emission limitation for formaldehyde emissions and you do
not use an oxidation catalyst emission control device, you must petition the Administrator for
approval of operating limitations or approval of no operating limitations.
3.3.3 Initial Compliance Requirements
If you operate a new or reconstructed lean premix gas-fired turbine, a new or
reconstructed lean premix oil-fired turbine, a new or reconstructed diffusion flame gas-fired
turbine, or a new or reconstructed diffusion flame oil-fired turbine, you must conduct an
initial performance test using Test Method 320 of 40 CFR part 63, appendix A, to
demonstrate that the outlet concentration of formaldehyde is 91 ppbvd or less (corrected to
15 percent oxygen). To correct to 15 percent oxygen, dry basis, you must measure oxygen
using Method 3A or 3B of 40 CFR part 60, appendix A, and moisture using either Method 4
of 40 CFR part 60, appendix A, or Test Method 320 of 40 CFR part 63, appendix A. The
initial performance test must be conducted at high load conditions, defined as 100 percent
±10 percent.
If you operate a new or reconstructed stationary combustion turbine in one of the
subcategories required to comply with an emission limitation and use an oxidation catalyst
emission control device, you must also install a continuous parameter monitoring system
(CPMS) to continuously monitor the oxidation catalyst inlet temperature.
If you operate a new or reconstructed stationary combustion turbine in one of the
subcategories required to comply with an emission limitation and you do not use an
oxidation catalyst emission control device, you must petition the Administrator for approval
of operating limitations or approval of no operating limitations.
If you petition the Administrator for approval of operating limitations, your petition
must include the following: (1) identification of the specific parameters you propose to use
as operating limitations; (2) a discussion of the relationship between these parameters and
HAP emissions, identifying how HAP emissions change with changes in these parameters,
and how limitations on these parameters will serve to limit HAP emissions; (3) a discussion
of how you will establish the upper and/or lower values for these parameters that will
establish the limits on these parameters in the operating limitations; (4) a discussion
identifying the methods you will use to measure and the instruments you will use to monitor
these parameters, as well as the relative accuracy and precision of these methods and
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instruments; and (5) a discussion identifying the frequency and methods for recalibrating the
instruments you will use for monitoring these parameters.
If you petition the Administrator for approval of no operating limitations, your
petition must include the following: (1) identification of the parameters associated with
operation of the stationary combustion turbine and any emission control device that could
change intentionally (e.g., operator adjustment, automatic controller adjustment) or
unintentionally (e.g., wear and tear, error) on a routine basis or over time; (2) a discussion of
the relationship, if any, between changes in these parameters and changes in HAP emissions;
(3) for those parameters with a relationship to HAP emissions, a discussion of whether
establishing limitations on these parameters would serve to limit HAP emissions; (4) for
those parameters with a relationship to HAP emissions, a discussion of how you could
establish upper and/or lower values for these parameters which would establish limits on
these parameters in operating limitations; (5) for those parameters with a relationship to HAP
emissions, a discussion identifying the methods you could use to measure these parameters
and the instruments you could use to monitor them, as well as the relative accuracy and
precision of these methods and instruments; (6) for these parameters, a discussion identifying
the frequency and methods for recalibrating the instruments you could use to monitor them;
and (7) a discussion of why, from your point of view, it is infeasible, unreasonable, or
unnecessary to adopt these parameters as operating limitations.
3.3.4 Continuous Compliance Provisions
Several general continuous compliance requirements apply to stationary combustion
turbines required to comply with the emission limitations. You are required to comply with
the emission limitations and the operating limitations (if applicable) at all times, except
during startup, shutdown, and malfunction of your stationary combustion turbine. You must
also operate and maintain your stationary combustion turbine, air pollution control
equipment, and monitoring equipment according to good air pollution control practices at all
times, including startup, shutdown, and malfunction. You must conduct monitoring at all
times that the stationary combustion turbine is operating, except during periods of
malfunction of the monitoring equipment or necessary repairs and quality assurance or
control activities, such as calibration checks.
To demonstrate continuous compliance with the emission limitations, you must
conduct annual performance tests for formaldehyde. You must conduct the annual
performance tests using Test Method 320 of 40 CFR part 63, appendix A, to demonstrate that
the outlet concentration of formaldehyde is at or below 91 ppbvd of formaldehyde (corrected
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to 15 percent oxygen). The annual performance test must be conducted at high load
conditions, defined as 100 percent ±10 percent.
If you operate a new or reconstructed stationary combustion turbine in one of the
subcategories required to comply with an emission limitation and you use an oxidation
catalyst emission control device, you must demonstrate continuous compliance with the
operating limitations by continuously monitoring the oxidation catalyst inlet temperature.
The 4-hour rolling average of the valid data must be within the range recommended by the
catalyst manufacturer.
If you operate a new or reconstructed stationary combustion turbine in one of the
subcategories required to comply with an emission limitation and you do not use an
oxidation catalyst emission control device, you must demonstrate continuous compliance
with the operating limitations by continuously monitoring parameters which have been
approved by the Administrator (if any).
3.3.5 Notification, Record-keeping, and Reporting Requirements
You must submit all of the applicable notifications as listed in the NESHAP General
Provisions (40 CFR part 63, subpart A), including an initial notification, notification of
performance test or evaluation, and a notification of compliance, for each stationary
combustion turbine that must comply with the emission limitation. If your new or
reconstructed source is located at a major source, has greater than 1 MW rated peak power
output, and is an emergency stationary combustion turbine, or a stationary combustion
turbine located on the North Slope of Alaska, you must submit only an initial notification.
For each combustion turbine that burns landfill or digester gas equivalent to 10 percent or
more of the gross heat input on an annual basis or where gasified MSW is used to generate
10 percent or more of the gross heat input to the stationary combustion turbine on an annual
basis, you must submit an initial notification and report the necessary information to
document the fuel usage of the turbine but you do not have to comply with the emission
limitation.
For each combustion turbine in one of the subcategories that is subject to an emission
limitation, you must record all of the data necessary to determine if you are in compliance
with the emission limitation. Your records must be in a form suitable and readily available
for review. You must also keep each record for 5 years following the date of each
occurrence, measurement, maintenance, report, or record. Records must remain on site for at
least 2 years and then can be maintained off site for the remaining 3 years.
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3.4 Rationale for Selecting Standards
3.4.1 Selection of Source Categories and Subcategories
Stationary combustion turbines can be major sources of HAP emissions and, as a
result, we listed them as a major source category for regulatory development under section
112 of the CAA, which allows us to establish subcategories within a source category for the
purpose of regulation. Consequently, we evaluated several criteria associated with stationary
combustion turbines that might serve as potential subcategories.
We identified emergency stationary combustion turbines as a subcategory.
Emergency stationary combustion turbines operate only in emergencies, such as a loss of
power provided by another source. These types of stationary combustion turbines operate
infrequently and, when called on to operate, must respond without failure and without
lengthy periods of startup. These conditions limit the applicability of HAP emission control
technology to emergency stationary combustion turbines.
Similarly, stationary combustion turbines that burn landfill or digester gas equivalent
to 10 percent or more of the gross heat input on an annual basis or where gasified MSW is
used to generate 10 percent or more of the gross heat input to the stationary combustion
turbine on an annual basis were identified as a subcategory. Landfill gas, digester gas, and
gasified MSW contain a family of chemicals referred to as siloxanes, which limit the
application of HAP emission control technology.
Stationary combustion turbines of less than 1 MW rated peak power output were also
identified as a subcategory. We believe these small stationary combustion turbines are few
in number. These small stationary combustion turbines are sufficiently dissimilar from
larger combustion turbines that we cannot evaluate the feasibility of emission control
technology based on information concerning the larger turbines. To our knowledge, none of
the smaller turbines use emission control technology to reduce HAP. Therefore, we believe
it would be inappropriate to require HAP emission controls to be applied to them without
further information on control technology performance.
Stationary combustion turbines can be classified as either diffusion flame or lean
premix. We examined formaldehyde test data for both diffusion flame and lean premix
stationary combustion turbines and observed that uncontrolled formaldehyde emissions for
stationary lean premix combustion turbines are significantly lower than those of stationary
diffusion flame combustion turbines. Because of the difference in the two technologies, we
decided to establish subcategories for diffusion flame and lean premix stationary combustion
turbines.
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We further investigated subcategorizing lean premix turbines based on fuel. At the
time of proposal, EPA was not aware of the availability of distillate oil-fired stationary
combustion turbines that operated in the lean premix mode. We received comments
indicating otherwise during the public comment period from combustion turbine
manufacturers. We believe there is a difference in uncontrolled HAP emissions between
natural gas and distillate oil for stationary lean premix combustion turbines. This is based on
test data for stationary diffusion flame combustion turbines which clearly show there is a
difference in the composition of uncontrolled HAP emissions between natural gas and
distillate oil. We believe this also would apply to stationary lean premix combustion
turbines. For stationary lean premix combustion turbines, NOX emissions also vary
depending on which fuel is burned in the combustion process. Information from combustion
turbine vendors indicate that NOX emission guarantees for distillate oil can be up to five
times higher than the NOX emission guarantees for natural gas for stationary lean premix
combustion turbines. Finally, the mass of total emissions may be similar for natural gas and
distillate oil, but some pollutants such as formaldehyde are lower for distillate oil and other
pollutants such as PAH and metals are higher for oil. For all practical purposes, uncontrolled
natural gas metal emissions are nonexistent, while they are emitted in small quantities when
burning distillate oil.
We expect that the majority of distillate oil burned in stationary combustion turbines
will be fuel oil number 2. We recognize that stationary combustion turbine owners and
operators may burn different varieties of distillate oil; however, we believe that any other
distillate oil combusted will be of similar quality and composition to fuel oil number 2. We
do not anticipate that owners and operators will burn any other liquid-based fuel that is more
contaminated with metals than fuel oil and expect that most available liquid fuels that may be
used in stationary combustion turbines will be similar and fairly consistent.
In recognition of the clear differences we found in the composition of HAP emissions
depending on the fuel that is used, we have determined that it is appropriate to subcategorize
further within stationary lean premix combustion turbines based on fuel use. In devising
appropriate subcategories based on fuel use, we needed to consider that many combustion
turbines are configured both to use natural gas and distillate oil. These dual fuel units
typically burn natural gas as their primary fuel, and only utilize distillate oil as a backup.
Without some allowance for this limited backup use of distillate oil, these turbines might
switch subcategories frequently, causing confusion for sources and complicating compliance
demonstrations. To limit the frequency of switching between subcategories which would
result from limited usage of distillate oil as a backup fuel, we have defined the lean premix
gas-fired subcategory in a manner which permits turbines that fire gas using lean premix
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technology to remain in the subcategory if all turbines at the site in question fire oil no more
than a total of 1000 hours during the calendar year. We believe this 1000 hour allowance
will be sufficient to accommodate those situations where distillate oil is used only as a
backup. The lean premix gas-fired turbines subcategory will be defined to include: (a) each
stationary combustion turbine which is equipped only to fire gas using lean premix
technology, (b) each stationary combustion turbine which is equipped both to fire gas using
lean premix technology and to fire oil, during any period when it is firing gas, and (c) each
stationary combustion turbine which is equipped both to fire gas using lean premix
technology and to fire oil, and is located at a major source where all stationary combustion
turbines fire oil no more than an aggregate total of 1000 hours during the calendar year.
The lean premix oil-fired turbines subcategory will be defined to include: (a) each
stationary combustion turbine which is equipped only to fire oil using lean premix
technology, and (b) each stationary combustion turbine which is equipped both to fire oil
using lean premix technology and to fire gas, and is located at a major source where all
stationary combustion turbines fire oil more than an aggregate total of 1000 hours during the
calendar year, during any period when it is firing oil. We do not know of any actual
combustion turbines which would be in this subcategory, but this is possible because we
have been advised that combustion turbines can be configured to burn oil using lean premix
technology.
We further investigated subcategorizing diffusion flame turbines based on fuel. For
diffusion flame turbines, test data show that HAP emissions vary depending on which fuel is
burned. Formaldehyde emissions are in general lower for diffusion flame units firing
distillate oil versus diffusion flame units firing natural gas. Emissions data also show that
NOX levels are higher for diffusion flame units firing distillate oil than diffusion flame units
firing natural gas. Finally, other fuel differences between natural gas and distillate oil
include higher levels of pollutants such as PAH and metals in the emissions of stationary
diffusion flame combustion turbines burning distillate oil. Quantities of these pollutants are
small for distillate oil; metal emissions from natural gas are at non-detectable levels. As
previously indicated, we expect that most owners and operators of stationary combustion
turbines will burn distillate oil of the form fuel oil number 2. However, we recognize that
other liquid based fuels may be also be fired, but these fuels will be similar to fuel oil
number 2, and do not expect owners and operators to burn any other fuel that is more
contaminated with metals.
As in the case of the lean premix turbines, we concluded based on the clear
differences in the composition of HAP emissions depending on the fuel that is used that it is
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appropriate to subcategorize further within stationary diffusion flame combustion turbines
based on fuel use. As in the case of the lean premix turbines, we have included a 1000 hour
per site allowance for limited backup use of distillate oil in order to limit the frequency that
dual fuel turbines will switch subcategories. We believe this 1000 hour allowance will be
sufficient to accommodate those situations where distillate oil is used only as a backup.
The diffusion flame gas-fired turbines subcategory will be defined to include: (a)
each stationary combustion turbine which is equipped only to fire gas using diffusion flame
technology, (b) each stationary combustion turbine which is equipped both to fire gas using
diffusion flame technology and to fire oil, during any period when it is firing gas, and (c)
each stationary combustion turbine which is equipped both to fire gas using diffusion flame
technology and to fire oil, and is located at a major source where all stationary combustion
turbines fire oil no more than an aggregate total of 1000 hours during the calendar year.
The diffusion flame oil-fired turbines subcategory will be defined to include: (a) each
stationary combustion turbine which is equipped only to fire oil using diffusion flame
technology, and (b) each stationary combustion turbine which is equipped both to fire oil
using diffusion flame technology and to fire gas, and is located at a major source where all
stationary combustion turbines fire oil more than an aggregate total of 1000 hours during the
calendar year, during any period when it is firing oil. We expect that the vast majority of all
stationary combustion turbines which are primarily oil-fired will be included in this
subcategory.
Stationary combustion turbines located on the North Slope of Alaska have been
identified as a subcategory because of operation limitations and uncertainties regarding the
application of controls to these units. There are very few of these units, and none have
installed emission controls for reducing HAPs.
3.4.2 Determination of Basis and Level of Emission Limitations for Existing Sources
As established in section 112 of the CAA, the MACT standards must be no less
stringent than the MACT floor. The MACT floor for existing sources is the average
emission limitation achieved by the best performing 12 percent of existing sources.
3.4.2.1 MACT Floor for Existing Lean Premix Combustion Turbines
We have established two subcategories of stationary lean premix combustion
turbines, lean premix gas-fired turbines and lean premix oil-fired turbines. Emissions of
each HAP are relatively homogeneous within each of these two subcategories, and any
variation in HAP emissions cannot be readily controlled except by add-on control. To
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determine the MACT floor for both subcategories of existing stationary lean premix
combustion turbines, the EPA's combustion turbine inventory database was consulted.
The inventory database provides population information on stationary combustion
turbines in the United States (U.S.) and was constructed in order to support the development
of the rule. Data in the inventory database are based on information from available
databases, such as the Aerometric Information Retrieval System (AIRS), the Ozone
Transport and Assessment Group (OTAG), and State and local agencies' databases. The first
version of the database was released in 1997. Subsequent versions have been released
reflecting additional or updated data. The most recent release of the database is version 4,
released in November 1998.
The inventory database contains information on approximately 4,800 stationary
combustion turbines. The current stationary combustion turbine population is estimated to
be about 8,000 turbines. Therefore, the inventory database represents about 60 percent of the
stationary combustion turbines in the U.S. At least 20 percent of those turbines are estimated
to be lean premix combustion turbines, based on conversations with turbine manufacturers.
The information contained in the inventory database is believed to be representative
of stationary combustion turbines primarily because of its comprehensiveness. The database
includes both small and large stationary combustion turbines in different user segments.
Forty-eight percent are "industrial," 39 percent are "utility," and 13 percent are "pipeline."
Note that independent power producers (IPP) are included in the utility and industrial
segments.
We examined all of the information available to us including the inventory database
to identify any operational modifications such as equipment adjustments or work practice
revisions which might be associated with lower HAP emissions. We were unsuccessful in
identifying any such operational modifications. Therefore, we were unable to utilize any
factors other than add-on controls in deriving the MACT floor.
Another approach we investigated to identify a MACT floor was to review the
requirements in existing State regulations and permits. No State regulations exist for HAP
emission limits for stationary combustion turbines. Only one State permit limitation for a
single HAP (benzene) was identified. Therefore, we were unable to use State regulations or
permits in deriving a MACT floor.
The only add-on control technology currently proven to reduce HAP emissions from
stationary lean premix combustion turbines is an oxidation catalyst emission control device.
At proposal, the inventory database indicated that no existing stationary lean premix
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combustion turbines were controlled with oxidation catalyst systems. During the public
comment period, we received a test report where a lean premix combustion turbine burning
natural gas was tested twice about 2 years apart with an oxidation catalyst in operation.
We estimate that about 1 percent of existing lean premix gas-fired turbines may have
oxidation catalyst systems installed. Accordingly, the average of the best performing 12
percent is no emission reduction. Therefore, the MACT floor for existing lean premix gas-
fired turbines for each individual HAP is no emission reduction.
For lean premix oil-fired turbines, we do not have any data indicating that turbines in
this subcategory are in actual use, nor do we have data indicating that oxidation catalysts
have been installed. Accordingly, the average emission limitation achieved by the best
performing existing units in this subcategory for each individual HAP would also be no
emission reduction.
3.4.2.2 MACT for Existing Lean Premix Combustion Turbines
To determine MACT for both subcategories of existing stationary lean premix
combustion turbines, we evaluated regulatory alternatives more stringent than the MACT
floor. We considered requiring the use of an oxidation catalyst emission control device.
According to catalyst vendors, oxidation catalysts are currently being used on some existing
lean premix stationary combustion turbines. In addition, we recently received a test report
where testing was conducted on a lean premix unit with an oxidation catalyst. However, an
analysis of the application of oxidation catalyst control to existing lean premix stationary
combustion turbines showed that the incremental cost per ton of HAP removed was
excessive. We have not identified any operational modifications which are not currently in
use for these turbines but might result in HAP reductions. Nor have we identified any
technologies to control those metallic HAPs which may be emitted during burning of
distillate oil which are technologically feasible and cost-effective. For these reasons, we
concluded that MACT for each individual HAP for existing sources in both subcategories of
existing stationary lean premix combustion turbines is the same as the MACT floor, i.e., no
emission reduction.
3.4.2.3 MACT Floor for Existing Diffusion Flame Combustion Turbines
We have established two subcategories of stationary diffusion flame combustion
turbines, diffusion flame gas-fired turbines and diffusion flame oil-fired turbines. We
believe emissions of each HAP are relatively homogeneous within each of these two
subcategories and any variation in HAP emissions cannot be readily controlled except by
add-on control. To determine the MACT floor for both subcategories of existing stationary
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diffusion flame combustion turbines, we consulted the inventory database previously
discussed in this section. At least 80 percent of those turbines are assumed to be diffusion
flame combustion turbines, based on conversations with turbine manufacturers.
We investigated the use of operational modifications such as equipment adjustments
and work practice revisions for stationary diffusion flame combustion turbines to determine
if HAP reductions associated with such operational modifications might be relevant in
deriving the MACT floor. We found no relevant references in the inventory database. Most
stationary diffusion flame combustion turbines will not operate unless preset conditions
established by the manufacturer are met. Stationary diffusion flame combustion turbines, by
manufacturer design, permit little operator involvement and there are no operating
parameters, such as air/fuel ratio, for the operator to adjust. We concluded, therefore, that
there are no specific operational modifications which could reduce HAP emissions or which
could serve to identify a MACT floor.
Another approach we investigated to identify a MACT floor was to review the
requirements in existing State regulations and permits. No State regulations exist for HAP
emission limits for stationary combustion turbines. Only one State permit limitation for a
single HAP (benzene) was identified. Therefore, we were unable to use State regulations or
permits in deriving a MACT floor.
We examined the inventory database for information on HAP emission control
technology. There were no turbines controlled with oxidation catalyst systems in the
inventory database so we used information supplied by catalyst vendors. There are about
200 oxidation catalyst systems installed in the U.S. The only control technology currently
proven to reduce HAP emissions from stationary diffusion flame combustion turbines is an
oxidation catalyst emission control device, such as a CO oxidation catalyst. These control
devices are used to reduce CO emissions and are currently installed on several stationary
combustion turbines.
Less than 3 percent of existing stationary diffusion flame gas-fired turbines in the
U.S., based on information in our inventory database and information from catalyst vendors,
are equipped with oxidation catalyst emission control devices. Therefore, the average
emission limitation for the best performing 12 percent of existing diffusion flame gas-fired
turbines is no emission reduction and the MACT floor for each individual HAP for existing
turbines in this subcategory is also no emission reduction.
We estimate that less than 1 percent of existing stationary diffusion flame oil-fired
turbines have oxidation catalyst systems installed. Thus, the average of the best performing
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12 percent of existing diffusion flame oil-fired turbines is no emission reduction for organic
HAP. No technologies to control metallic HAP have been installed on the existing turbines
in this subcategory. Therefore, the MACT floor for each individual HAP for existing
turbines in the diffusion flame oil-fired subcategory is no emission reduction.
3.4.2.4 MACT for Existing Diffusion Flame Combustion Turbines
To determine MACT for both subcategories of existing diffusion flame combustion
turbines, regulatory alternatives more stringent than the MACT floor were evaluated. One
beyond-the-floor regulatory option is requiring an oxidation catalyst. However, cost per ton
estimates of oxidation catalyst emission control devices for control of total HAP from
stationary diffusion flame combustion turbines were deemed excessive. In addition, we did
not identify any operational modifications which are not currently in use for these turbines
but might result in HAP reductions. Moreover, we did not identify any technologies to
control those metallic HAP which may be emitted during burning of distillate oil which are
technologically feasible and cost-effective. For these reasons, MACT for each individual
HAP for turbines in both subcategories of existing stationary diffusion flame combustion
turbines is the same as the MACT floor, i.e., no emission reduction.
3.4.3 New Sources
For new sources, the MACT floor is defined as the emission control that is achieved
in practice by the best controlled similar source. To be a similar source, a source should not
have any characteristics that differ sufficiently to have a material effect on the feasibility of
emission controls, but the source need not be in the same source category or subcategory.
We considered using a surrogate in order to reduce the costs associated with
monitoring while at the same time being relatively sure that the pollutants the surrogate is
supposed to represent are also controlled. We investigated the use of formaldehyde
concentration as a surrogate for all organic HAP emissions. Formaldehyde is the HAP
emitted in the highest concentrations from stationary combustion turbines. Formaldehyde,
toluene, benzene, and acetaldehyde account for essentially all the mass of HAP emissions
from the stationary combustion turbine exhaust, and emissions data show that these
pollutants are equally controlled by an oxidation catalyst.
Information from testing conducted on a diffusion flame combustion turbine
equipped with an oxidation catalyst control system indicated that the formaldehyde and
acetaldehyde emission reduction efficiency achieved was 97 and 94 percent, respectively.
Later, after review of an expert task group, the conclusion reached was that both
formaldehyde and acetaldehyde were controlled at least 90 percent. In addition, emissions
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tests conducted on reciprocating internal combustion engines (RICE) at Colorado State
University (CSU) in 1998 showed that the benzene emission reduction efficiency across an
oxidation catalyst averaged 73 percent, and the toluene emission reduction averaged 77
percent for 16 runs at various engine conditions on a two-stroke lean burn engine. The
toluene emission reduction efficiency across the oxidation catalyst averaged 85 percent for
ten runs at various engine conditions on a compression ignition RICE. We would expect the
emissions reductions efficiencies for benzene and toluene from combustion turbines to be as
high or higher than those reported for the CSU RICE tests since combustion turbines catalyst
temperatures are generally higher. Finally, catalyst performance information obtained from a
catalyst vendor indicated that the percent conversion for an oxidation catalyst system
installed on combustion turbines did not vary significantly between formaldehyde, benzene,
and toluene. The percent conversion was measured at 77, 72, and 71 for formaldehyde,
benzene, and toluene, respectively. Although emissions reductions for large molecules may
in theory be less than for formaldehyde, the above information shows that formaldehyde is a
good surrogate for the most significant HAP pollutants emitted from combustion turbines as
demonstrated by evaluating the reduction efficiency of larger, heavier molecules, hence
taking differences in molecular density into account. In addition, emission data show that
HAP emission levels and formaldehyde emission levels are related, in the sense that when
emissions of one are low, emissions of the other are low and vice versa. This leads us to
conclude that emission control technologies which lead to reductions in formaldehyde
emissions will lead to reductions in organic HAP emissions. For the reasons provided above,
it is appropriate to use formaldehyde as a surrogate for all organic HAP emissions.
3.4.3.1 New Lean Premix Gas-Fired Combustion Turbines
To determine the MACT floor for new stationary lean premix gas-fired turbines, we
reviewed the emissions data we had available at proposal and additional test reports received
during the comment period. In order to set the MACT floor for new sources in this
subcategory, we chose the best performing turbine. Emissions of each HAP are relatively
homogeneous within the subcategory of stationary lean premix gas-fired turbines and any
variation in HAP emissions cannot be readily controlled except by add-on control. The best
performing turbine is equipped with an oxidation catalyst.
The formaldehyde concentration from the best performing turbine was measured at
the outlet of the control device using CARB 430. Concerns were raised during the public
comment period that CARB 430 formaldehyde results can be biased low as compared to
formaldehyde results obtained by FTIR. For a comprehensive discussion of test methods and
the development of the correlation between CARB 430 and FTIR formaldehyde levels,
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please refer to the memorandum entitled "Review of Test Methods and Data used to
Quantify Formaldehyde Concentrations from Combustion Turbines" in the docket. A bias
factor of 1.7 was, therefore, applied to the formaldehyde concentration of the best
performing turbine. The best performing turbine was tested twice under the same conditions
about 2 years apart where one test measured 19 ppbvd and the other test measured 91 ppbvd
formaldehyde (numbers have been bias corrected). We determined that since both of these
tests were performed under similar conditions but at different times, this represented the
variability of the best performing unit and used the higher value as the MACT floor. The
MACT floor for organic HAP for new stationary lean premix gas-fired turbines is, therefore,
an emission limit of 91 ppbvd formaldehyde at 15 percent oxygen.
We recognize that our selection of an emission limit of 91 ppbvd formaldehyde is
based on quite limited data. We think that each new combustion turbine in this subcategory
should be able to achieve compliance with this limit if an oxidation catalyst is properly
installed and operated. If actual emission data demonstrate that we are incorrect, and that
sources which properly install and operate an oxidation catalyst cannot consistently achieve
compliance, we will revise the standard accordingly.
No beyond-the-floor regulatory alternatives were identified for new lean premix gas-
fired turbines. We are not aware of any add-on control devices which can reduce organic
HAP emissions to levels lower than those resulting from the application of oxidation catalyst
systems. We, therefore, determined that MACT for organic HAP emissions from new
stationary lean premix gas-fired turbines is the same as the MACT floor, i.e., an emission
limit of 91 ppbvd formaldehyde at 15 percent oxygen.
3.4.3.2 New Lean Premix Oil-Fired Combustion Turbines
We do not have any tests for lean premix combustion turbines firing any other fuels
besides natural gas. However, we expect that emissions of organic HAP will be controlled
by installation of an oxidation catalyst on any units in this subcategory to a degree similar to
lean premix gas-fired turbines and diffusion flame oil-fired turbines. We also expect that
organic HAP emissions from lean premix oil-fired turbines would be equal to or less than
organic HAP emissions from lean premix gas-fired turbines. We have these expectations
based on the fact that dual-fuel units using oxidation catalyst systems operate on distillate oil
and the fact that catalyst vendors indicate that oxidation catalyst systems operate equally well
on either fuel. Therefore, we used the best performing turbine from the lean premix gas-fired
turbine subcategory to set the MACT floor for lean premix oil-fired turbines. As a result, the
MACT floor for organic HAP for new stationary lean premix oil-fired turbines is an
emission limit of 91 ppbvd formaldehyde at 15 percent oxygen.
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We are not aware of any similar sources which are equipped with emission control
devices that could also reduce emissions of metallic HAP. We also examined the inventory
database in an attempt to identify any operating modifications which might reduce metal
emissions, but could not identify any such practices. We also referred to the inventory
database to determine if any similar sources are equipped with emission controls for the
reduction of particulate matter (PM) which would also reduce metal emissions. No such
units were found in the inventory database and none were identified by commenters during
the public comment period. For this reason, the MACT floor for new stationary lean premix
oil-fired turbines is no emission control for metallic HAP emissions.
We were unable to identify any beyond-the-floor regulatory alternatives for new
stationary lean premix oil-fired turbines. We know of no emission control technology
currently available which can reduce HAP emissions to levels lower than those achieved
through use of an oxidation catalyst. We also have not identified any add-on controls for
metallic HAP. We conclude, therefore, that MACT for new lean premix oil-fired turbines
would be equivalent to the MACT floor, i.e., an emission limit of 91 ppbvd formaldehyde at
15 percent oxygen for organic HAP, and no emission reduction for metallic HAP.
3.4.3.3 New Diffusion Flame Gas-Fired Combustion Turbines
In the proposed rule, we requested sources to submit any HAP emissions test data
available from stationary combustion turbines. After the proposal, we also contacted several
State agencies to request emissions test data from diffusion flame combustion turbines. Due
to the CARB advisory issued on April 28, 2000, which stated that formaldehyde emissions
data where the NOX levels were greater than 50 ppmvd were suspect and should be flagged as
non-quantitative, we conducted an analysis of existing diffusion flame emissions test data.
Tests where the NOX emissions were greater than 50 ppm or tests where the NOX levels were
unknown were excluded from our analysis. Most of the diffusion flame tests in the
emissions database were unable to pass the screening. Therefore, we specifically requested
States to provide test reports for diffusion flame combustion turbines where Method 320 was
used, or CARB 430 was used and the NOX emissions were below 50 ppmvd. During the
comment period we received three additional test reports for testing conducted on a total of
five stationary diffusion flame combustion turbines.
To identify the MACT floor for new stationary diffusion flame gas-fired turbines, we
based our analysis on the performance of the best turbine. Individual HAP emissions are
relatively homogeneous within the subcategory of stationary diffusion flame gas-fired
turbines and any variation in HAP emissions cannot be readily controlled except by add-on
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control. The best performing turbine in this subcategory is equipped with an oxidation
catalyst.
As previously indicated, formaldehyde is the HAP emitted in the highest
concentrations from stationary combustion turbines and data show control of organic HAP
emissions and formaldehyde emissions are related. We have, therefore, concluded that
formaldehyde is an appropriate surrogate for all organic HAP emissions.
Formaldehyde was measured by CARB 430 at the outlet of the oxidation catalyst.
We applied a bias factor of 1.7 to the formaldehyde concentration obtained by CARB 430 for
the best performing turbine. The corrected outlet concentration of formaldehyde from the
best performing turbine was 15 ppbvd. We only have one controlled test for this turbine, but
we expect that similar variability would be associated with this turbine as was associated
with the best performing lean premix turbine. Therefore, applying a factor of 5 to the
formaldehyde concentration measured at the outlet of the best performing diffusion flame
turbine is appropriate to account for variability. Therefore, we would establish a
formaldehyde emission limitation of 75 ppbvd based on the outlet of the control device.
However, with a similar control system, we would expect that the emission limit should be
no lower than the emission limit for lean premix turbines since diffusion flame turbines on
average emit more HAP. The MACT floor for new stationary diffusion flame combustion
gas-fired turbines is, therefore, an emission limit of 91 ppbvd formaldehyde at 15 percent
oxygen.
We were unable to identify any beyond-the-floor regulatory alternatives for new
stationary diffusion flame gas-fired turbines. We know of no emission control technology
currently available which can reduce organic HAP emissions to levels lower than that
achieved through the use of an oxidation catalyst. We concluded, therefore, that MACT for
organic HAP emissions from new diffusion flame stationary gas-fired turbines is equivalent
to the MACT floor, i.e., an emission limit of 91 ppbvd formaldehyde at 15 percent oxygen.
3.4.3.4 New Diffusion Flame Oil-Fired Combustion Turbines
To determine the MACT floor for new diffusion flame oil-fired turbines, we again
based our analysis on the best performing turbine. Emissions of each individual HAP are
relatively homogeneous within stationary diffusion flame oil-fired turbines and any variation
in HAP emissions cannot be readily controlled except by add-on control. The best
performing turbine in this subcategory is equipped with an oxidation catalyst.
As previously described in more detail, we are using formaldehyde as a surrogate for
all organic HAP emissions. The formaldehyde was measured with EPA Method 0011 at the
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outlet of the control device. The EPA Method 0011 is similar to CARB 430 and the
problems associated with CARB 430 are expected to be associated with EPA Method 0011.
So again we applied a bias factor of 1.7 to the formaldehyde outlet concentration of the best
performing diffusion flame oil-fired turbine. The corrected formaldehyde concentration
from this turbine is 44 ppbvd. We only had one controlled test for this turbine, but would
expect some variability as has been shown with other turbines. However, since
formaldehyde emissions from distillate oil fired turbines are lower on average by a factor of
1.4, we do not believe that the MACT emission limit should be set higher than the emission
limit for new stationary diffusion flame gas-fired turbines. Therefore, the MACT floor for
organic HAP for new stationary diffusion flame oil-fired turbines is an emission limit of 91
ppbvd formaldehyde at 15 percent oxygen.
We examined the inventory database to identify any operating practices which could
affect metal emissions. We were unable to identify any such practices. We also determined
that no similar sources are equipped with emission control devices for the reduction of PM
which could also reduce metal emissions. Therefore, the MACT floor for metallic HAP for
new diffusion flame oil-fired turbines is no emission reduction.
To determine MACT for new stationary diffusion oil-fired turbines, we tried to
identify beyond-the-floor options. There are currently no beyond-the-floor regulatory
alternatives for this subcategory as we know of no emission control technology current
available that can reduce organic HAP emissions to levels lower than that obtained with the
use of an oxidation catalyst. We also have not identified any add-on controls for metallic
HAP. We conclude, therefore, that MACT for new diffusion flame oil-fired turbines would
be equivalent to the MACT floor, i.e., an emission limit of 91 ppbvd formaldehyde at 15
percent oxygen organic HAP, and no emission reduction for metallic HAP.
3.4.4 MACT for Other Subcategories
Although the final rule will apply to all stationary combustion turbines located at
major sources of HAP emissions, emergency stationary combustion turbines, stationary
combustion turbines that burn landfill or digester gas equivalent to 10 percent or more of the
gross heat input on an annual basis or where gasified MSW is used to generate 10 percent or
more of the gross heat input to the stationary combustion turbine on an annual basis,
stationary combustion turbines of less than 1 MW rated peak power output, and stationary
combustion turbines located on the North Slope of Alaska are not required to meet the
emission limitations or operating limitations.
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For each of the other subcategories of stationary combustion turbines, we have
concerns about the applicability of emission control technology. For example, emergency
stationary combustion turbines operate infrequently. In addition, when called upon to
operate they must respond immediately without failure and without lengthy startup periods.
This infrequent operation limits the applicability of HAP emission control technology.
Landfill and digester gases contain a family of silicon-based gases called siloxanes.
Siloxanes are also a component of municipal waste. Combustion of siloxanes forms
compounds that can foul post-combustion catalysts, rendering catalysts inoperable within a
very short period of time. It is our judgment based on public comments and information
obtained from catalyst vendors and sanitation districts that firing even 10 percent landfill or
digester gas will cause fouling that will render the oxidation catalyst inoperable within a
short period of time. Pretreatment of exhaust gases to remove siloxanes was investigated.
However, no pretreatment systems are in use and their long-term effectiveness is unknown.
We also considered fuel switching for this subcategory of turbines. Switching to a different
fuel such as natural gas or diesel would potentially allow the turbine to apply an oxidation
catalyst emission control device. However, fuel switching would defeat the purpose of using
this type of fuel which would then either be allowed to escape uncontrolled or would be
burned in a flare with no energy recovery. We believe that switching landfill or digester gas
or gasified MSW to another fuel is inappropriate and is an environmentally inferior option.
For stationary combustion turbines of less than 1 MW rated peak power output, we
have concerns about the effectiveness of scaling down the oxidation catalyst emission
control technology. Just as there are often unforeseen problems associated with scaling up a
technology, there can be problems associated with scaling down a technology.
Stationary combustion turbines located on the North Slope of Alaska have been
identified as a subcategory due to operation limitations and uncertainties regarding the
application of controls to these units. There are very few of these units; in addition, none
have installed emission controls for the reduction of HAP.
As a result, we identified subcategories for each of these types of stationary
combustion turbines and investigated MACT floors and MACT for each subcategory. As
expected, since we identified these types of stationary combustion turbines as separate
subcategories based on concerns about the applicability of emission control technology, we
found no stationary combustion turbines in these subcategories using any emission control
technology to reduce HAP emissions. As discussed above, we are not aware of any work
practices that might constitute a MACT floor, nor did we find that the use of a particular fuel
3-23
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results in HAP emission reductions. The MACT floor, therefore, for each of these
subcategories is no emission reduction.
Despite our concerns with the applicability of emission control technology, we
examined the cost per ton of HAP removed for these subcategories. This analysis can be
found in the docket (Docket ID No. OAR-2002-0060 (A-95-51)) for the final rule. Whether
our concerns are warranted or not, we consider the incremental cost per ton of HAP removed
excessive—primarily because of the very small reduction in HAP emissions that would
result.
We also considered the non-air health, environmental, and energy impacts of an
oxidation catalyst system, as discussed previously, and concluded that there would be only a
small energy impact and no non-air health or environmental impacts. However, as stated
above, we did not adopt this regulatory option due to cost considerations and concerns about
the applicability of this technology to these subcategories. We were not able to identify any
other means of achieving HAP emission reduction for these subcategories.
As a result, for all of these reasons, we conclude that MACT for these subcategories
is the MACT floor (i.e., no emission reduction).
3.4.5 Selection of Initial Compliance Requirements
New and reconstructed sources complying with the emission limitation for
formaldehyde emissions are required to conduct an initial performance test. The purpose of
the initial test is to demonstrate initial compliance with the formaldehyde emission
limitation.
3.4.5.1 How Did We Select the Continuous Compliance Requirements?
If you must comply with the emission limitations, continuous compliance with these
requirements is required at all times except during startup, shutdown, and malfunction of
your stationary combustion turbine. You are required to develop a startup, shutdown, and
malfunction plan.
We considered requiring FTIR CEMS; however, we concluded that the costs of FTIR
CEMS were excessive and were not yet demonstrated at the low formaldehyde levels of the
standards. We considered requiring those sources to continuously monitor operating load to
demonstrate continuous compliance because the data establishing the formaldehyde outlet
concentration level are based on tests that were done at high loads. However, we believe that
the performance of a stationary combustion turbine at high load is also indicative of its
3-24
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operation at lower loads. In fact, the operator can make no parameter adjustments that would
lead to lower emissions.
For these reasons, EPA determined that it would be appropriate to require sources
that comply with the emission limitation for formaldehyde emissions and that use an
oxidation catalyst emission control device to continuously monitor the oxidation catalyst
inlet temperature. Continuously monitoring the oxidation catalyst inlet temperature and
maintaining this temperature within the range recommended by the catalyst manufacturer
will ensure proper operation of the oxidation catalyst emission control device and continuous
compliance with the emission limitation for formaldehyde.
Sources that do not use an oxidation catalyst emission control device are required to
petition the Administrator for approval of operating limitations or approval of no operating
limitations.
3.4.5.2 How Did We Select the Testing Methods to Measure these Low Concentrations of
Formaldehyde ?
The final rule requires the use of Method 320 to determine compliance with the
emission limitation for formaldehyde. With regard to formaldehyde, we believe systems
meeting the requirements of Method 320, a self-validating FTIR method, can be used to
attain detection limits for formaldehyde concentrations well below the current emission
limitations with a path length of 10 meters or less. Some of the older technology may
require 100 or even 200 meter path lengths. We expect state-of-the-art digital signal
processing (to reduce signal to noise ratio) would be needed. Method 320 also includes
formaldehyde spike recovery criteria, which require spike recoveries of 70 to 130 percent.
While we believe FTIR systems can meet the requirements of Method 320 and
measure formaldehyde concentrations at these low levels, we have limited experience with
their use. As a result, we solicited comments on the ability and use of FTIR systems to meet
the validation and quality assurance requirements of Method 320 for the purpose of
determining compliance with the emission limitation for formaldehyde. Commenters were
generally in agreement that Method 320 is the most accurate and reliable test method
currently available to test for formaldehyde emissions from the stationary combustion turbine
exhaust.
As an alternative to Method 320, we proposed Method 323 for natural gas-fired
sources. Method 323 uses the acetyl acetone colorimetric method to measure formaldehyde
emissions in the exhaust of natural gas-fired, stationary combustion sources. Commenters
did not support Method 323 and were concerned whether this method could provide reliable
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results. In addition, Method 323 has not been validated or demonstrated for use on stationary
combustion turbines emitting low formaldehyde emissions. Therefore, Method 323 has not
been included as a compliance method for formaldehyde in the final rule.
At proposal we believed CARD Method 430 and EPA SW-846 Method 0011 were
capable of measuring formaldehyde concentrations at these low levels. Commenters were
not supportive of these methods. In addition, CARB 430 is susceptible to interferences and
sample loss contributes to large measurement variability. Method 0011 uses a similar
analytical approach to CARB 430 and has many shortcomings and limited application
opportunities. Accordingly, we are not including CARB 430 and Method 0011 in the final
rule.
For these reasons, EPA has specified that Method 320 should be used to determine
compliance with the formaldehyde emission limitation in the final rule.
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SECTION 4
PROJECTION OF UNITS AND FACILITIES IN AFFECTED SECTORS
The regulation will affect turbine units with capacity over 1 MW. As a result, the
economic impact estimates presented in Section 6 and the small business screening analysis
presented in Section 7 are based on the population of existing units and the projection of new
combustion turbine units through the year 2007. This section begins with a review of the
technical characteristics and industry distribution of existing combustion turbines contained
in the Agency's Inventory Database. It presents projected growth estimates for combustion
turbines greater than 1 MW and describes trends in the electric utility industry. It also
presents (in Section 4.3) the estimated number of existing and new combustion turbines that
will be affected by this rule.
4.1 Profile of Existing Combustion Turbine Units
This section profiles existing combustion turbine units (greater than 1 MW) with
respect to business applications, industry of parent company, and fuel use. For nonutility
combustion turbines, the population of existing sources will be used to provide the
characteristics of new combustion turbines constructed through the year 2007.
The population of existing combustion turbine units used in the analysis was
developed from the EPA Inventory Database V.4— Turbines (referred to as the Inventory
Database). The combustion turbines contained in the Inventory Database are based on
information from the Aerometric Information Retrieval System (AIRS) and Ozone Transport
Assessment Group (OTAG) databases, state and local permit records, and the combustion
source Information Collection Request (ICR) conducted by the Agency in 1997. The list of
combustion turbine units contained in the Inventory Database was reviewed and updated by
industry and environmental stakeholders as part of the Industrial Combustion Coordinated
Rulemaking (ICCR), chartered under the Federal Advisory Committee Act (FACA).
From the Inventory Database, EPA identified 2,072 combustion turbines with greater
than 1 MW capacity. More than 2,800 additional turbines were listed in the database, but
their records lacked capacity information and/or industry information, so these units are
excluded from this analysis. The total estimated population of existing combustion turbines
is about 8,000, so the coverage in the Inventory Database of the estimated existing
combustion turbine population is approximately 60 percent. The profiles presented below
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are based in the 2,072 combustion turbines in the Inventory Database above 1 MW of
capacity with valid information for inclusion in the analyses conducted for this rule.
4.1.1 Distribution of Units and Facilities by Industry
Table 4-1 presents the number of combustion turbines and facilities owning turbines
by NAICS code. Forty-seven percent of existing combustion turbines are in Utilities
(NAICS 221), 22 percent are in Pipeline Transportation, and 18 percent are in Oil and Gas
Extraction (NAICS 211). Section 4 presents industry profiles for the electric power, natural
gas pipelines, and oil and gas industries. The remaining units are primarily distributed across
the manufacturing sector and are concentrated in the chemical and petroleum industries.
4.1.2 Technical Characteristics
This section characterizes the population of 2,072 units by MW capacity, fuel type,
hours of operation, annual MWh produced (or equivalent), and simple or combined cycle.
• MW Capacity: Unit capacities in the population range between 1 and 368 MW.
Although some units have large capacities in excess of 100 MW, about half
(1,000 units) have capacities between 1 and 10 MW (see Figure 4-1). Only
approximately 13 percent (278 units) have capacities greater than 100 MW. The
total estimated capacity of all the units in the population is 79,909 MW.
• Fuel type: Natural gas is the most common fuel consumed by units in the
population. About 28 percent (579 units) use distillate oil, which is more
commonly known as diesel fuel. A relatively small number (53 units) consume
other fuels, such as landfill gas, crude oil, and residual fuel oil.
Although only 28 percent of units use distillate oil, in terms of the total MW
capacity of the population, distillate oil fuels a disproportionate percentage,
nearly 43 percent. This implies either that many of the mid- to large-sized
turbines are fueled by distillate oil, that natural gas is more common in smaller
units, or that a combination of the two explains this fact.
• Hours of Operation: Nearly half of all turbines (925 units) operate more than
7,500 hours per year (see Table 4-2). A year consists of approximately 8,760
hours. Although 488 units operate less than 500 hours per year, only 414 units
operate between 500 and 7,500 hours per year. Information on annual hours of
operation was unavailable for 245 (or 12 percent) of the 2,072 units. Because the
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Table 4-1. Facilities With Units Having Capacities Above 1 MW by Industry Grouping
and Government Sector
NAICS
112
211
212
221
233
235
311
321
322
324
325
326
327
331
332
333
334
335
336
337
339
422
486
488
513
522
541
561
611
622
721
923
926
928
Unknown
Total
Description
Animal Production
Oil and Gas Extraction
Mining (Except Oil and Gas)
Utilities
Building, Developing, and General Contracting
Special Trade Contractors
Food Manufacturing
Wood Products Manufacturing
Paper Manufacturing
Petroleum and Coal Products Manufacturing
Chemical Manufacturing
Plastics and Rubber Products Manufacturing
Nonmetallic Mineral Product Manufacturing
Primary Metal Manufacturing
Fabricated Metal Product Manufacturing
Machinery Manufacturing
Computer and Electronic Product Manufacturing
Electrical Equipment, Appliance, and Component
Manufacturing
Transportation Equipment Manufacturing
Furniture and Related Product Manufacturing
Miscellaneous Manufacturing
Wholesale Trade, Nondurable Goods
Pipeline Transportation
Support Activities for Transportation
Broadcasting and Telecommunications
Credit Intermediation and Related Activities
Professional, Scientific, and Technical Services
Administrative and Support Services
Educational Services
Hospitals
Accommodation
Administration of Human Resource Programs
Administration of Economic Programs
National Security and International Affairs
Industry Classification Unknown
# Units
1
365
3
983
1
2
18
3
17
34
63
4
1
13
2
2
6
1
3
1
3
6
448
1
1
3
2
1
10
23
1
1
1
42
6
2,072
# Facilities
1
105
3
393
1
1
11
2
11
11
39
3
1
4
2
2
5
1
3
1
3
4
244
1
1
1
2
1
8
14
1
1
1
12
5
899
Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the
Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking
Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research
Triangle Park, North Carolina. September 16-17.
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900 -,
800 -
700 -
w
~ 600 -
o 50° '
j> 400 -
I 300 -
z
200 -
100 -
n
785
215
325
227
242 221
57
| |
1 to 5 5 to 10 10 to 25 25 to 50 50 to 100 100 to 200 >200
MW Capacity Range
Figure 4-1. Number of Units by MW Capacity
Table 4-2. Stationary Combustion Turbine Projections
Total Number of New Units
Utility Turbines
Base load energy (combined cycle)
Peak power (simple cycle)
Total utility turbines
Nonutility Turbines
Small
Medium
Large
Total nonutility turbines
Total in 5th year
Average per year
136
66
202
3
9
4
16
218
44
4-4
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vast majority of those units were located on pipelines, which operate 24 hours a
day, or at electric utility plants, many of the 245 units probably operate more than
7,500 hours a year.
• Annual MWh Equivalent: Figure 4-2 presents the distribution of units by the
estimated annual MWh equivalent produced by each unit. For units that are used
for compression or other functions, their likely MWh output was estimated using
their MW capacity and annual hours of operation. Annual MWh for 245 units
lacking annual hours of operation information was not calculated. Figure 4-3
includes data for the other 1,827 units, more than one-third of which have output
of between 10,000 and 50,000 MWh a year. 360 units have output of less than
5,000 MWh, and 217 units have output greater than 500,000 MWh.
• Simple vs. combined cycle: Information was not available from the Inventory
Database on the type of turbine. However, based on industry sales data, a
breakdown of 1998 industry orders shows that 32 percent of the orders were for
peak SCCTs and the remaining 68 percent were for CCCTs. Sixty percent of the
buyers were merchant plants, 10 percent were independent power producers
(IPPs), and the remaining 30 percent were rate-base utility generators (Siemens
Westinghouse, 1999).
4.2 Projected Growth of Combustion Turbines
The Agency estimates there will be a total of 218 new stationary combustion turbines
over the next 5 years (see Table 4-2). This projection is based on information supplied from
the turbine manufacturing industry, state permit data compiled by EPA, and Gas Turbine
World's 1999-2000 Handbook on Gas Turbine Orders and Installations.
4.2.1 Comparison of Alternative Growth Estimates
Specific growth projections for combustion turbines vary with respect to the timing
of the construction of new units. Table 4-3 shows that according to 1998 projections made
by the Department of Energy (DOE), U.S. electric utilities were planning to install 316 new
units between 1998 and 2007. The units are expected to average 165 MW. The majority of
these units are projected to be CCCTs (DOE, 1999d). According to a second study, the
Department of Energy projects 300 GW of new generation capacity will be needed by the
year 2020 (Reuters News Service, 1999).
Because the electric utility industry accounts for over 90 percent of the projected new
units and 97 percent of the projected new capacity in MW and nearly half of the existing
units and 72 percent of the existing capacity in MW, the remainder of this section focuses on
the trends in the electric utility industry.
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700 -,
600
w 500 -
'E
2 400
o
Jl 300 -I
E
i 200 -I
100
0
132
228
183
624
149
294
217
<500
500 to 5,000
5,000 to
10,000
10,000 to
50,000
50,000 to
100,000
100,000to
500,000
>500,000
Annual MWh Equivalent
Figure 4-2. Number of Units by Annual MWh Output Equivalent
Note: Excludes 245 units for which information on annual hours of operation was unavailable.
1,000 -,
900 -
800-
w 700-
"c
3 600-
•^
° 500 -
S
| 400-
3
Z 300 -
200 -
H nn
100 -
n
488
106
111
90
| |
107
925
<500 500 to 1,500 1,500 to 3,500 3,500 to 5,500 5,500 to 7,500
Annual Hours of Unit Operation
>7,500
Figure 4-3. Number of Units by Annual Hours of Operation
Note: Excludes 245 units for which information on annual hours of operation was unavailable.
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Table 4-3. Planned Capacity Additions at U.S. Public Utilities, 1998 through 2007, as of
January 1,1998
Year
U.S. Total
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Number of Units
316
60
25
31
31
35
34
26
31
22
21
Generator Nameplate Capacity
(MW)
52,044
2,020
2,298
3,875
5,843
5,978
8,201
5,707
7,576
5,879
4,667
Notes: Total may not equal the sum of components because of independent rounding.
Source: U.S. Department of Energy, Energy Information Administration. 1999c. Electric Power Annual 1998.
Volumes I and II. Washington, DC: U.S. Department of Energy.
4.3 Number of Affected Stationary Combustion Turbines
We estimate that 20 percent of the stationary combustion turbines affected by this
rule will be located at major sources. This estimate is based on an examination by EPA of
permit data, which indicated that utility turbines will primarily be installed at greenfield
power plants where no other sources of HAP emissions will be present. Greenfield power
plants that had a total capacity of more than the calculated MW were assumed to be major
sources, while those that were less were assumed to be area sources. Industrial turbines were
all assumed to go into brownfield sites that were already major HAP sites. Based on this
analysis of permit data, it is expected that twenty percent of new turbines will be major
sources. As a result, the environmental and energy impacts presented here reflect these
estimates. Existing sources are not required to comply with emission limitations,
recordkeeping, or reporting requirements in the rule.
For new stationary combustion turbines, 218 new turbines are projected to come
online by the fifth year after promulgation as shown in Table 4-2; 20 percent or 44 are
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expected to be at major sources. All of these 44 turbines are expected to require installation
of an oxidation catalyst to meet the emission limitations in the rule for new sources. A
breakdown of these 44 turbines shows that 27 new base load energy turbines and 13 peak
power turbines will be affected in the next 5 years. For new nonutility turbines, 3 new units
will be affected in the next 5 years.
Based on the description in the previous two paragraphs, 44 stationary combustion
turbines will have to apply an oxidation catalyst to meet the emission limitations associated
with this rule. In the fifth year after promulgation, those 44 turbines are expected to require
performance testing. This total includes the approximately 9 new turbines (which is 20
percent of 44) that come online that year and are required to conduct an annual performance
test to demonstrate compliance.
4.4 HAP and Other Emission Reductions
The rule will reduce total national HAP emissions by an estimated 98 tons/year in the
fifth year after the standards are promulgated. The emissions reductions achieved by the rule
would be come from the sources that install an oxidation catalyst control system. We
estimate that new stationary combustion turbines located at a major source will install
oxidation catalyst control to comply with the standards.
To estimate the baseline HAP emissions and reductions associated with this rule,
national HAP emissions in the absence of the rule were calculated using an emission factor
from the emissions database. We assumed new simple cycle stationary combustion turbines
typically operate at a 20 percent capacity factor (or 1,752 hours per year) and combined
cycle turbines typically operate at a 60 percent capacity factor (or 5,256 hours per year).
These figures are based on information submitted during the public comment period for the
proposed rule. It was also assumed that half of the turbines installed in the next five years
would be simple cycle and the other half combined cycle. We then assumed a HAP
reduction of 95 percent, achieved by using oxidation catalyst emission control devices, and
applied this reduction to the baseline HAP emissions to estimate total national HAP emission
reduction.
In addition to HAP emission reductions, the rule will reduce criteria air pollutant
emissions, primarily CO emissions, though there will be a very small amount of PM and
VOC emission reductions as well. Oxidation catalyst control systems have been
demonstrated to reduce CO emissions by 95 percent. PM emissions are very low from
stationary combustion turbines since virtually all of the affected turbines burn natural gas or
4-8
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similar gaseous fuels. Very few existing turbines burn oils, and we do not believe any new
affected turbines in the next five years will exclusively use an oil fuel. Any turbines that are
built to use oils are likely to be dual fuel-fired, which means they can operate off of two
different types of fuel that are likely to be natural gas and diesel oil. In any event, oxidation
catalyst control systems will reduce PM emissions by 25 to 50 percent. Oxidation catalyst
control systems will reduce VOC emissions as well. The control efficiency depends on the
specific compounds. However, we believe that VOC (and hydrocarbon [HC]) emissions
from combustion turbines that are not HAP are very low and we have been unable to
quantify emission reductions for these pollutants.
4.5 Energy and Other Impacts from Direct Application of Control Measures
The only energy impact from the direct application of oxidation catalyst control
systems is the pressure drop across the oxidation catalyst bed of typically 1 to 1-1/2 inches of
water pressure drop. According to information contained in the Gas Turbine World 1999-
2000 Handbook (GTWH), a rough rule of thumb for heavy frame turbines, which are the
types of turbines which we believe will mostly be installed in the next five years, is that
every four inches of water pressure outlet loss is equivalent to a 0.6 percent heat rate loss
resulting in a 0.6 percent power output loss. (Heat rate is a measure of the amount of inlet
heat input to a turbine required to produce a certain amount of power. When the turbine heat
rate increases, more inlet heat is required to produce the same amount of power resulting in a
decrease in the thermal efficiency.)
Vendors state that an oxidation catalyst system can be designed so that the maximum
pressure drop across the control device does not exceed 1.5 inches of water pressure drop
including the catalyst system and housing. Therefore, the heat rate increase is expected to be
about 0.15 percent (1/4 x 0.6 percent) increase per inch of water pressure drop increase in the
turbine outlet. (Other studies by Gas Technology Institute have indicated that this value is
0.105 percent per inch of turbine outlet pressure drop. However we chose to use the GTWH
value for this calculation.) Therefore for a 1.5 inch pressure drop across an oxidation
catalyst system, the power output loss is estimated to be 0.225 percent (1.5 x 0.15). This
represents the energy impact which is very low.
4.5.1 Water Impacts
Oxidation catalyst systems do not use water or produce water so the water impacts
are expected to be very low.
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4.5.2 Solid Waste Impacts
Oxidation catalyst are made with precious metals. When the catalyst charge is
replaced (about every six years), the old catalyst is usually sent to a catalyst metal processor
who reclaims the precious metals and the owner/operator gets a reimbursement from the
processor. Therefore, because the spent catalyst is recycled, the solid waste impact is very
small.
4.6 Trends in the Electric Utility Industry
Most industry and government forecasts project sizable growth of new electric power
generation capacity in the near future to meet the increase in consumer demand for electricity
and the retirement of aging coal and nuclear units. Experts agree that this new capacity will
mainly come from SCCTs and CCCT units fueled by natural gas. Two factors have
contributed to recent and projected dominance of gas combustion turbines to meet the
demand for new generation capacity:
• Technology advances in combustion turbines have increased efficiency.
• Deregulation of the electric utility industry has opened the market to smaller
independent operators with applications ideally suited for combustion turbines.
Over the next 5 years deregulation of the electric power industry will be the main
factor influencing the growth of combustion turbines to generate electric power.
Deregulation is influencing the demand for utility combustion turbines in the following
ways:
1. Competitive markets for wholesale power are leading to the replacement of
less-efficient coal and nuclear power plants. Because of advances in gas turbine
technology, new SCCTs and CCCTs are more economical compared to new oil
and coal power plants and less-efficient existing plants.
2. Competitive markets for wholesale power have led to an increased demand for
bulk transmission resources. However, economic and political factors continue to
limit the growth in new transmission corridors. Combustion turbine units that are
smaller in size and more environmentally friendly (compared to coal or nuclear
power plants) can be placed throughout the grid (referred to as distributed
generation) to alleviate transmission constraints.
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3. Deregulation has opened the market to merchant power producers and IPPs. The
smaller-scale combustion turbine power plants are ideal for these market players
who generally serve niche markets where there are capacity shortages or where
industrial steam loads are high.1
industry experts agree that (at least in the short run) deregulation will lead to four major regional power
markets in the U.S. Bulk transmission interfaces between these four regional markets will continue to be
capacity strained, implying that electricity prices may continue to vary from region to region. In addition,
there will be local metropolitan areas or geographically isolated areas, such as San Francisco, where
transmission constraints will restrict "perfect" competition. In these areas, small-scale distributed
generation, such as CCCTs, will be able to command price premiums for electric power.
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SECTION 5
PROFILES OF AFFECTED INDUSTRIES
This section contains profiles of the major industries affected by the regulation of
stationary combustion turbines. The Agency anticipates that most of the direct costs of the
regulation will be borne by the electric services (NAICS 22111) sector. However, the crude
oil and natural gas extraction (NAICS 211) and natural gas pipelines (NAICS 486) sectors
will be indirectly affected through changes in industry production and fuel switching.
Together, these energy sectors account for about 90 percent of the existing combustion
turbines (greater than 1 MW) identified by the Agency in the Inventory Database. The
remaining combustion turbines are spread across a wide variety of industries, most notably
chemicals and allied products, petroleum products, health services, and national security
agencies, and are primarily used for self-generated electricity or co-generated electricity and
process steam. Direct costs on these industries are expected to be minimal.
The Agency projects that growth in new combustion turbines that will be affected by
the regulation will also be concentrated in the electric services, crude oil and natural gas
extraction, and natural gas industries. This section contains background information on these
three industries to help inform the regulatory process.
5.1 Electric Utility Industry (NAICS 22111)
This profile of the U.S. electric power industry provides background information on
the evolution of the electricity industry, the composition of a traditional regulated electric
utility, the current market structure of the electric industry, and deregulation trends and the
potential future market structure of the electricity market. This profile also discusses current
industry characteristics and trends that will influence the future generation and consumption
of electricity.
5.7.1 Market Structure of the Electric Power Industry
The ongoing process of deregulation of wholesale and retail electric markets is
changing the structure of the electric power industry. Deregulation is leading to the
functional unbundling of generation, transmission, and distribution and to competition in the
generation segment of the industry. This section provides background on the current
structure of the industry and future deregulation trends. It begins with a brief overview of
the evolution of the electric power industry because the future market structure will, in large
5-1
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part, be determined by the existing infrastructure and capital assets that have evolved over
the past decades.
5.1.1.1 The Evolution of the Electric Power Industry
The electric utility industry began as isolated local service systems with the first
electric companies evolving in densely populated metropolitan areas like New York and
Chicago. Prior to World War I, rural electrification was a piecemeal process. Only small,
isolated systems existed, typically serving a single town. The first high-voltage transmission
network was built in the Chicago area in 1911 (the Lake County experiment). This new
network connected the smaller systems surrounding Chicago and resulted in substantial
production economies, lower customer prices, and increased company profits.
In light of the success of the Lake County experiment, the 1910s and 1920s saw
increased consolidation and rapid growth in electricity usage. During this period, efficiency
gains and demand growth provided the financing for system expansions. Even though the
capacity costs (fixed costs per peak kW demanded) were typically twice as large with the
consolidated/interconnected supply systems, the fixed costs per unit of energy production
(kWh) were comparable to those of the old single-city system. This was the case because of
load factor improvements, which resulted from aggregating customer demand.
Whereas the average fixed cost per customer was relatively unchanged as a result of
the move from single-city to consolidated supply systems, large savings were realized from
decreases in operating costs. In particular, fuel costs per kWh decreased 70 percent because
of the improved combustion efficiency of larger plants and lower fuel prices for purchases of
large quantities. In addition, operation and maintenance costs decreased 85 percent,
primarily as a result of decreased labor intensity.
During the 1920s, only a small part of the efficiency gains were passed on to
customers in the form of lower prices. Producers retained the bulk of the productivity
increases as profits. These profits provided the internal capital to finance system expansions
and to buy out smaller suppliers. Industry expansion and consolidation led to the
development of large utility holding companies whose assets were shares of common stock
in many different operating utilities.
The speculative fever of the 1920s led to holding companies purchasing one another,
creating financial pyramids based on inflated estimates of company assets. With the stock
market crash in 1929, shareholders who had realized both real economic profits and
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speculative gains lost large amounts of money. The financial collapse of the utility holding
companies led to new levels of utility regulation.
From the 1930s through the 1960s, the regulated mandate of electric utilities was
basically unchanged: to provide safe, adequate, and reliable service to all electricity users.
The majority of the state and federal laws regulating utilities in place during this era had
been written shortly after the Depression. The laws were primarily designed to prevent
"ruinous competition" through costly duplication of utility functions and to protect customers
against exploitation from a monopoly supplier.
During this period, most utilities were vertically integrated, controlling everything
from generation to distribution. Economies of scale in generation and the inefficiency of
duplicating transmission and distribution systems made the electric utility industry a
textbook example of a natural monopoly. Electricity was viewed as a homogeneous good
from which there were no product unbundling opportunities or unique product offerings on
which competition could get a foothold. In addition, the industry was extremely capital-
intensive, providing a sizable barrier to entry even if the monopoly status of the utilities had
not been protected.
From the 1930s to the 1960s, the electric industry experienced almost continuous
growth in demand. In addition, there was a steady stream of technological innovations in
generation, transmission, and distribution operations. The increased economies of scale,
technological advances, and fast demand growth led to steadily declining unit costs.
However, in an environment of decreasing unit costs, there were few rate cases and almost
no pressure from customers to change the system. This period is often referred to as the
golden era for the electric utility industry.
5.1.1.2 Structure of the Traditional Regulated Utility
The utilities vary substantially in size, type, and function. Figure 5-1 illustrates the
typical structure of the electric utility market. Even with the technological and regulatory
changes in the 1970s and 1980s, at the beginning of the 1990s the structure of the electric
utility industry could still be characterized in terms of generation, transmission, and
distribution. Commercial and retail customers were in essence "captive," and rates and
service quality were primarily determined by public utility commissions.
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Electricity
Generation
Power Plants
Trans-
mission
High Voltage Lines
Transformer
Distribution
Residential
Customers
Small C/l
Customers
Large C/l
Customers
Figure 5-1. Traditional Electric Power Industry Structure
The majority of utilities are interconnected and belong to a regional power pool.
Pooling arrangements enable facilities to coordinate the economic dispatch of generation
facilities and manage transmission congestion. In addition, pooling diverse loads can
increase load factors and decrease costs by sharing reserve capacity.
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Generation. Coal-fired plants have historically accounted for the bulk of electricity
generation in the United States. With abundant national coal reserves and advances in
pollution abatement technology, such as advanced scrubbers for pulverized coal and flue gas-
desulfurization systems, coal will likely remain the fuel of choice for most existing
generating facilities over the near term.
Natural gas accounts for approximately 10 percent of current generation capacity but
is expected to grow; advances in natural gas exploration and extraction technologies and new
coal gasification have contributed to the use of natural gas for power generation.
Nuclear plants and renewable energy sources (e.g., hydroelectric, solar, wind)
provide approximately 20 percent and 10 percent of current generating capacity,
respectively. However, there are no plans for new nuclear facilities to be constructed, and
there is little additional growth forecasted in renewable energy.
Transmission. Transmission refers to high voltage lines used to link generators to
substations where power is stepped down for local distribution. Transmission systems have
been traditionally characterized as a collection of independently operated networks or grids
interconnected by bulk transmission interfaces.
Within a well-defined service territory, the regulated utility has historically had
responsibility for all aspects of developing, maintaining, and operating transmissions. These
responsibilities included
• system planning and expanding,
• maintaining power quality and stability, and
• responding to failures.
Isolated systems were connected primarily to increase (and lower the cost of) power
reliability. Most utilities maintained sufficient generating capacity to meet customer needs,
and bulk transactions were initially used only to support extreme demands or equipment
outages.
Distribution. Low-voltage distribution systems that deliver electricity to customers
comprise integrated networks of smaller wires and substations that take the higher voltage
and step it down to lower levels to match customers' needs.
The distribution system is the classic example of a natural monopoly because it is not
practical to have more than one set of lines running through neighborhoods or from the curb
to the house.
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5.1.1.3 Current Electric Power Supply Chain
This section provides background on existing activities and emerging participants in
the electric power supply chain.1 Because the restructuring plans and time tables are made at
the state level, the issues of asset ownership and control throughout the current supply chain
in the electric power industry vary from state to state. However, the activities conducted
throughout the supply chain are generally the same.
Table 5-1 shows costs by utility ownership and by segment of the supply chain.
Generation accounts for approximately 75 percent of the cost of delivered electric power.
Figure 5-2 provides an overview of the electric power supply chain, highlighting a
combination of activities and service providers. The activities/members of the electric power
supply chain are typically grouped into generation, transmission, and distribution. These
three segments are described in the following sections.
Generation. As part of deregulation, the transmission and distribution of electricity
are being separated from the business of generating electricity, and a new competitive market
in electricity generation is evolving. As power generators prepare for the competitive
market, the share of electricity generation attributed to nonutilities and utilities is shifting.
More than 7,000 electricity suppliers currently operate in the U.S. market. As shown
in Table 5-2, approximately 42 percent of suppliers are utilities and 58 percent are
nonutilities. Utilities include investor-owned, cooperatives, and municipal systems. Of the
approximately 3,100 utilities operating in the United States, only about 700 generate electric
power. The majority of utilities distribute electricity that they have purchased from power
generators via their own distribution systems.
Utility and nonutility generators produced a total of 3,369 billion kWh in 1995.
Although utilities generate the vast majority of electricity produced in the United States,
nonutility generators are quickly eroding utilities' shares of the market. Nonutility
generators include private entities that generate power for their own use or to sell to utilities
or other end users. Between 1985 and 1995, nonutility generation increased from 98 billion
kWh (3.8 percent of total generation) to 374 billion kWh (11.1 percent). Figure 5-3
illustrates this shift in the share of utility and nonutility generation.
The electric power supply chain includes all generation, transmission, distribution, administrative, and market
activities needed to deliver electric power to consumers.
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Table 5-1. Total Expenditures in 1996 ($103)
Utility
Ownership
Investor-
owned
Publicly
owned
Federal
Cooperatives
Generation
80,891,644
12,495,324
3,685,719
15,105,404
112,178,091
75.6%
148,370,552
Transmission
2,216,113
840,931
327,443
338,625
3,723,112
2.5%
Distribution
6,124,443
1,017,646
1,435
1,133,984
8,277,508
5.6%
Customer
Accounts
and Sales
6,204,229
486,195
55,536
564,887
7,310,847
4.9%
Administration
and General
Expenses
13,820,059
1,360,111
443,809
1,257,015
16,880,994
11.4%
Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1998a. Financial Statistics of
Major Publicly Owned Electric Utilities, 1997. Washington, DC: U.S. Department of Energy.
U.S. Department of Energy, Energy Information Administration (EIA). 1997. Financial Statistics of
Major U.S. Investor-Owned Electric Utilities, 1996. Washington, DC: U.S. Department of Energy.
Utilities. There are four categories of utilities: investor-owned utilities (lOUs),
publicly owned utilities, cooperative utilities, and federal utilities. Of the four, only lOUs
always generate electricity.
lOUs are increasingly selling off generation assets to nonutilities or converting those
assets into nonutilities (Haltmaier, 1998). To prepare for the competitive market, lOUs have
been lowering their operating costs, merging, and diversifying into nonutility businesses.
In 1995, utilities generated 89 percent of electricity, a decrease from 96 percent in
1985. lOUs generate the majority of the electricity produced in the United States. lOUs are
either individual corporations or a holding company, in which a parent company operates one
or more utilities integrated with one another. lOUs account for approximately three-quarters
of utility generation, a percentage that held constant between 1985 and 1995.
Utilities owned by the federal government accounted for about one-tenth of
generation in both 1985 and 1995. The federal government operated a small number of large
utilities in 1995 that supplied power to large industrial consumers or federal installations.
The Tennessee Valley Authority is an example of a federal utility.
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Fuel Source: Coal, Natural Gas, Water, etc.
IPP Generation
Private
Lines
Self-Generation
Electricity
Waste Heat
A Surplus
Electricity
V Purchased
Local Utility
Generation
Competing Utility
Generation
(outside service
territory)
Bulk Transmission
Intersystem
Exchange
System Reliability
and Control
Local Distribution
^Surplus
Electricity
^Purchased
Large C/l
Customers
Small C/l
Customers
Residential
Customers
Figure 5-2. Electric Utility Industry
Many states, municipalities, and other government organizations also own and
operate utilities, although the majority do not generate electricity. Those that do generate
electricity operate capacity to supply some or all of their customers' needs. They tend to be
small, localized outfits and can be found in 47 states. These publicly owned utilities
accounted for about one-tenth of utility generation in 1985 and 1995. In a deregulated
market, these generators may be in direct competition with other utilities to service their
market.
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Table 5-2. Number of Electricity Suppliers in 1999
Electricity Suppliers
Utilities
Investor-owned utilities
Cooperatives
Municipal systems
Public power districts
State projects
Federal agencies
Nonutilities
Nonutilities (excluding EWGs)
Exempt wholesale generators
Total
Number
3,124
222
875
1,885
73
55
14
4,247
4,103
144
7,371
Percent
42%
58%
100%
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999g. The Changing
Structure of the Electric Power Industry 1999: Mergers and Other Corporate Combinations.
Washington, DC: U.S. Department of Energy.
Rural electric cooperatives are the fourth category of utilities. They are formed and
owned by groups of residents in rural areas to supply power to those areas. Cooperatives
generally purchase from other utilities the energy that they sell to customers, but some
generate their own power. Cooperatives only produced 5 percent of utility generation in
1985 and only 6 percent in 1995.
Nonutilities. Nonutilities are private entities that generate power for their own use or
to sell to utilities or other establishments. Nonutilities are usually operated at mines and
manufacturing facilities, such as chemical plants and paper mills, or are operated by electric
and gas service companies (DOE, EIA, 1998b). More than 4,200 nonutilities operate in the
United States.
Between 1985 and 1995, nonutility generators increased their share of electricity
generation from 4 percent to 11 percent (see Figure 5-3). In 1978, the Public Utilities
Regulatory Policies Act (PURPA) stipulated that electric utilities must interconnect with and
purchase capacity and energy offered by any qualifying nonutility. In 1996, FERC issued
Orders 888 and 889 that opened transmission access to nonutilities and required utilities to
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Utilities
Shares of Total
Utility Generation
Investor-Owned
Cooperative
Investor-Owned
1988 Generation
Utility 93%
Nonutility 7%
Nonutilities
Shares Qf Total
Monutility ©@ii@ratton
4%
10%
9%
Shares of Total
Utility Generation
1998 Generation
Utility 89%
Nonutility 11%
Shares of Total
Nonutility Generation:
a Includes facilities classified in more than one of the following FERC designated categories: cogenerator QF, small power
producer QF, or exempt wholesale generator.
Cogen = Cogenerator.
EWG = Exempt wholesale generator.
Other Non-QF = Nocogenerator Non-QF.
QF = Qualifying facility.
SPP = Small power producer.
Note: Sum of components may not equal total due to independent rounding. Classes for nonutility generation are
determined by the class of each generating unit.
Sources: Utility data: U.S. Department of Energy, Energy Information Administration (EIA). 1996b. Electric Power
Annual 1995. Volumes I and II. DOE/EIA-0348(95)/1. Washington, DC: U.S. Department of Energy; Table 8
(and previous issues); 1985 nonutility data: Shares of generation estimated by EIA; total generation from Edison
Electric Institute (EEI). 1998. Statistical Yearbook of the Electric Utility Industry 1998. November.
Washington, DC; 1995 nonutility data: U.S. Department of Energy, Energy Information Administration (EIA).
1996b. Electric Power Annual 1995. Volumes I and II. DOE/EIA-0348(95)/1. Washington, DC: U.S.
Department of Energy.
Figure 5-3. Utility and Nonutility Generation and Shares by Class, 1988 and 1998
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share information about available transmission capacity. These moves established wholesale
competition, spurring nonutilities to increase generation and firms to invest in nonutility
generation.
Nonutilities are frequently categorized by their FERC classification and the type of
technology they employ. There are three categories of nonutilities: cogenerators, small
power producers (SPPs), and exempt wholesale generators (EWGs).
Cogenerators are nonutilities that sequentially or simultaneously produce electricity
and another form of energy (such as heat or steam) using the same fuel source. At
cogeneration facilities, steam is used to drive a turbine to generate electricity. The waste
heat and steam from driving the turbine is then used as an input in an industrial or
commercial process. For a cogenerator to qualify or interconnect with utilities, it must meet
certain ownership, operating, and efficiency criteria specified by FERC. In 1985, about
55 percent of nonutility generation was produced by cogenerators that qualified or met
FERC's specifications and sold power to utilities. By 1995 the percentage increased to
67 percent as the push for deregulation gathered momentum. At the same time, the
percentage that was produced by nonqualifying cogenerators decreased from 25 percent to
9 percent.
SPPs typically generate power using renewable resources, such as biomass, solar
energy, wind, or water. However, increasingly SPPs include companies that self-generate
power using combustion turbines and sell excess power back to the grid. As with
cogenerators, SPPs must fulfill a series of FERC requirements to interconnect with utilities.
PURPA revisions enabled nonutility renewable electricity to grow significantly, and SPPs
have responded by improving technologies, decreasing costs, and increasing efficiency and
reliability (DOE, EIA, 1998b). Between 1985 and 1995, the percentage of SPP nonutility
generation nearly doubled to 13 percent.
EWGs produce electricity for the wholesale market. Also known as IPPs, EWGs
typically contract directly with large bulk customers, such as large industrial and commercial
facilities and utilities. They do not operate any transmission or distribution facilities but pay
tariffs to use facilities owned and operated by utilities. Unlike with qualifying cogenerators
and SPPs, utilities are not required to purchase energy produced by EWGs, but they may do
so at market-based prices. EWGs did not exist until the Energy Policy Act created them in
1992, and by 1995 they generated about 2 percent of nonutility electricity.
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In 1995, about 4 percent of nonutility generation was produced by facilities that were
classified as any combination of cogenerator, SPP, and EWG. An additional 6 percent was
produced by facilities that generate electricity for their own consumption.
Transmission. Whereas the market for electricity generation is moving toward a
competitive structure, the transmission of electricity is currently (and will likely remain) a
regulated, monopoly operation. In areas where power markets are developing, generators
pay tariffs to distribute their electricity over established lines owned and maintained by
independent organizations. Independent service operators (ISOs) will most likely coordinate
transmission operations and generation dispatch over the bulk power system.
The bulk power transmission system consists of three large regional networks, which
also encompass smaller groups. The three networks are geographically defined: the Eastern
Interconnect in the eastern two-thirds of the nation; the Western Interconnect in the western
portion; and the Texas Interconnect, which encompasses the majority of Texas. The western
and eastern networks are each fully integrated with Canada. The western is also integrated
with Mexico. Within each network, the electricity producers are connected by extra high-
voltage connections that allow them to transfer electrical energy from one part of the
network to the other.
The bulk power system makes it possible for electric power producers to engage in
wholesale trade. In 1995, utilities sold 1,283 billion kWh to other utilities. The amount of
energy sold by nonutilities has increased dramatically from 40 billion kWh in 1986 to 222
billion kWh in 1995, an average annual increase of 21 percent (DOE, EIA, 1996a).
Distribution utilities and large industrial and commercial customers also have the option of
purchasing electricity in bulk at market prices from their local utility, a nonutility, or another
utility. The process of transmitting electricity between suppliers via a third party is known as
wholesale wheeling.
The wholesale trade for electricity is increasingly handled by power marketers
(brokers). Power marketers act as independent middlemen that buy and sell wholesale
electricity at market prices (EEI, 1999). Customers include large commercial and industrial
facilities in addition to utilities. Power marketers emerged in response to increased
competition. Brokers do not own generation facilities, transmissions systems, or distribution
assets, but they may be affiliated with a holding company that operates generation facilities.
Currently, 570 power marketers operate in the United States. The amount of power sold by
marketers increased from 3 million MWh to 2.3 billion MWh between 1995 and 1998. This
is the equivalent of going from powering 1 million homes to powering 240 million homes
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(EEI, 1999). Table 5-3 lists the top ten power marketers by sales for the first quarter of
1999.
Table 5-3. Top Power Marketing Companies, First Quarter 1999
Company Total MWh Sold
Enron Power Marketing, Inc. 78,002,931
Southern Company Energy Marketing, L.P. 38,367,107
Aquila Power Corp. 29,083,612
PG&E Energy Trading-Power, L.P. 28,463,487
Duke Energy Trading & Marketing, L.L.C. 22,276,608
LG&E Energy Marketing, Inc. 15,468,749
Entergy Power Marketing Corp. 12,670,520
PacifiCorp Power Marketing, Inc. 11,800,263
Tractebel Energy Marketing, Inc. 10,041,039
NorAm Energy Services, Inc. 9,817,306
Source: Resource Data International. 1999. "PMA Online Top 25 Power Marketer Rankings." Power
Marketers Online Magazine, As obtained on August
11, 1999.
Distribution. The local distribution system for electricity is expected to remain a
regulated monopoly operation. But power producers will soon be able to compete for retail
customers by paying tariffs to entities that distribute the power. Utilities may designate an
ISO to operate the distribution system or continue to operate it themselves. If the utility
operates its own system, it is required by law to charge the same tariff to other power
producers that it charges producers within its own corporate umbrella. The sale of electricity
by a utility or other supplier to a customer in another utility's retail service territory is known
as retail wheeling.
Supporters of retail wheeling claim that it will help lower the average price paid for
electricity. The states with the highest average prices for electricity are expected to be the
first to permit retail wheeling; wholesale wheeling is already permitted nationwide. In 1996,
California, New England, and the Mid-Atlantic States had the highest average prices for
electricity, paying 3 cents or more per kilowatt-hour than the national average of 6.9 cents
(DOE, EIA, 1998b). Open access to the electricity supply, coupled with a proliferation of
electricity suppliers, should combine to create falling electricity prices and increasing usage.
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By 2002, the nationwide average price for electricity is projected to be 11 percent lower than
in 1995, an average annual decline of roughly 2 percent (Haltmaier, 1998).
The explosion in computer and other information technology usage in the commercial
sector is expected to offset energy efficiency gains in the residential and industrial sectors
and lead to a net increase in the demand for electricity. Retail wheeling has the potential to
allow customers to lower their costs per kilowatt-hour by purchasing electricity from
suppliers that best fit their usage profiles. Large commercial and industrial customers
engaged in self-generation or cogeneration will also be able to sell surplus electricity in the
wholesale market.
5.1.1.4 Overview of Deregulation and the Potential Future Structure of the Electricity
Market
Beginning in the latter part of the 19th century and continuing for about 100 years,
the prevailing view of policymakers and the public was that the government should use its
power to require or prescribe the economic behavior of "natural monopolies" such as electric
utilities. The traditional argument is that it does not make economic sense for there to be
more than one supplier—running two sets of wires from generating facilities to end users is
more costly than one set. However, since monopoly supply is not generally regarded as
likely to provide a socially optimal allocation of resources, regulation of rates and other
economic variables was seen as a necessary feature of the system.
Beginning in the 1970s, the public policy view shifted against traditional regulatory
approaches and in favor of deregulation for many important industries including
transportation, communications, finance, and energy. The major drivers for deregulation of
electric power included the following:
• existence of rate differentials across regions offering the promise of benefits from
more efficient use of existing generation resources if the power can be transmitted
across larger geographic areas than was typical in the era of industry regulation;
• the erosion of economies of scale in generation with advances in combustion
turbine technology;
• complexity of providing a regulated industry with the incentives to make socially
efficient investment choices;
• difficulty of providing a responsive regulatory process that can quickly adjust
rates and conditions of service in response to changing technological and market
conditions; and
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• complexity of monitoring utilities' cost of service and establishing cost-based
rates for various customer classes that promote economic efficiency while at the
same time addressing equity concerns of regulatory commissions.
Viewed from one perspective, not much changes in the electric industry with
restructuring. The same functions are being performed, essentially the same resources are
being used, and in a broad sense the same reliability criteria are being met. In other ways,
the very nature of restructuring, the harnessing of competitive forces to perform a previously
regulated function, changes almost everything. Each provider and each function become
separate competitive entities that must be judged on their own.
This move to market-based provision of generation services is not matched on the
transmission and distribution side. Network interactions on AC transmission systems have
made it impossible to have separate transmission paths compete. Hence, transmission and
distribution remain regulated. Transmission and generation heavily interact, however, and
transmission congestion can prevent specific generation from getting to market.
Transmission expansion planning becomes an open process with many interested parties.
This open process, coupled with frequent public opposition to transmission expansion, slows
transmission enhancement. The net result is greatly increased pressure on the transmission
system.
Restructuring of the electric power industry could result in any one of several
possible market structures. In fact, different parts of the country will probably use different
structures, as the current trend indicates. The eventual structure may be dominated by a
power exchange, bilateral contracts, or a combination. A strong Regional Transmission
Organization (RTO) may operate in the area, or a vertically integrated utility may continue to
operate a control area. In any case, several important characteristics will change:
• Commercial provision of generation-based services (e.g., energy, regulation, load
following, voltage control, contingency reserves, backup supply) will replace
regulated service provision. This drastically changes how the service provider is
assessed.
• Individual transactions will replace aggregated supply meeting aggregated
demand. It will be necessary to continuously assess each individual's
performance.
• Transaction sizes will shrink. Instead of dealing only in hundreds and thousands
of MW, it will be necessary to accommodate transactions of a few MW and less.
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• Supply flexibility will greatly increase. Instead of services coming from a fixed
fleet of generators, service provision will change dynamically among many
potential suppliers as market conditions change.
5.7.2 Electricity Generation
Because of the uncertainties associated with the future course of deregulation,
forecasting deregulation's impact on generation trends, and hence growth in combustion
turbines, is difficult. However, most industry experts believe that deregulation will lead to
increased competition in the wholesale (and eventually retail) power markets, driving out
high cost producers of electricity, and that there will be an increased reliance on distributed
generation to compensate for growing demands on the transmission system.
In 2000, the United States relied on fossil fuels to produce almost 74 percent of its
electricity. Table 5-4 shows a breakdown of generation by energy source.2 Whereas natural
gas seems to play a relatively minor role among utility producers, it represents 30 percent of
capacity among nonutility producers. This is because nonutilities use coal and petroleum to
the same extent as the larger, traditionally regulated utility power producers.
Among nonutility producers, manufacturing facilities contain the largest electricity-
generating capacity. Table 5-5 illustrates that, from 1995 through 1999, manufacturing
facilities consistently had the capacity to produce over two-thirds of nonutility electricity
generation.
In 1997 cogenerators produced energy totaling 146 billion kWh for their own use.
Cogenerators are expected to continue to increase their generation capabilities at a slightly
slower rate than utilities.
Table 5-6 further disaggregates capacity by prime mover and energy source at
electric utilities. As the table shows, hydroelectric and steam are the two prime movers with
the most units, while steam and nuclear generators have the greatest total capacity.
Combustion turbines' (including the second stage of CCCTs) generation represents
approximately 10 percent of total U.S. capacity.
Figure 5-4 shows the annual electricity sales by sector from 1970 with projections
through 2020.
2Nonutility power producers have approximately 10 percent of the capacity of utility power producers.
5-16
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Table 5-4. Industry Capability by Energy Source, 2000
Energy Source
Fossil fuels
Coal
Natural gas
Petroleum
Duel-fired
Nuclear
Hydroelectric
Renewable/other
Total
Utility Generators
(MW)
424,218
259,059
38,964
26,250
99,945
85,519
91,590
1,050
602,377
Nonutility
Generators (MW)
173,320
56,190
58,668
13,003
45,549
12,038
7,478
16,322
209,248
Total (MW)
597,538
315,249
97,632
39,253
145,494
97,557
99,068
17,372
811,625
Sources: U.S. Department of Energy, Energy Information Administration. 2000. Electric Power Annual,
1999, Vol.2. DOE/EIA-0348(99)/2. Washington, DC: U.S. Department of Energy.
Table 5-5. Installed Capacity at U.S. Nonutility Attributed to Major Industry Groups
and Census Division, 1995 through 1999 (MW)
Year Manufacturing
1995
1996
1997
1998
1999
47,606
49,529
49,791
51,255
52,430
Transportation
and Public
Utilities
15,124a
16,050
16,559
24,527
78,419
Services
2,165
2,181
2 223
2,506
2,342
Other
Public Industry
Mining Administration Groups
3,428
3,313
3,306
3,275
5,123
544
542
616
534
536
l,388a
1,575
1,510
15,989
28,506
Total
70,254
73,189
74,004
98,085
167,357
a Revised data.
Notes: All data are for 1 MW and greater. Data for 1997 are preliminary; data for prior years are final. Totals
may not equal sum of components because of independent rounding.
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2000. Electric Power Annual
1999, Volume II. Washington, DC: U.S. Department of Energy.
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Table 5-6. Existing Capacity at U.S. Electric Utilities by Prime Mover and Energy
Source, as of January 1,1998
Prime Mover Energy Source
U.S. Total
Steam
Coal only
Other solids3
Petroleum only
Gas only
Other solids/coal"
Solids/petroleum13
Solids/gasb
Solids/petroleum/gasb
Petroleum/gas
Internal Combustion
Petroleum only
Gas only
Petroleum/gas
Other solids only3
Combustion Turbine
Petroleum only
Gas only
Petroleum/gas
Second Stage of CCCTs
Petroleum only
Gas only
Coal/petroleum
Coal/gas
Petroleum/gas
Waste heat
Nuclear
Hydroelectric (conventional)
Hydroelectric (pumped storage)
Geothermal
Solar
Wind
Number of Units
10,421
2,117
911
15
137
117
1
72
232
1
624
2,892
1,799
48
1,044
1
1,549
625
179
745
202
11
29
1
1
100
60
107
3,352
141
27
11
19
Generator Nameplate Capacity (MW)
754,925
469,210
276,895
334
22,476
10,840
2
10,796
36,763
558
110,324
5,075
2,671
66
2,335
3
63,131
22,802
5,776
34,554
16,224
470
2,331
326
113
8,852
4,130
107,632
73,202
18,669
1,746
5
14
a Includes wood, wood waste, and nonwood waste.
b Includes coal, wood, wood waste, and nonwood waste.
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999c. Electric Power Annual
1998. Volumes I and II. Washington, DC: U.S. Department of Energy.
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fttsidsntial
Ctim-nwrcLoi
Industrial
Figure 5-4. Annual Electricity Sales by Sector
The literature suggests that electricity consumption is relatively price inelastic.
Consumers are generally unable or unwilling to forego a large amount of consumption as the
price increases. Numerous studies have investigated the short-run elasticity of demand for
electricity. Overall, the studies suggest that, for a 1 percent increase in the price of
electricity, demand will decrease by 0.15 percent. However, as Table 5-7 shows, elasticities
vary greatly, depending on the demand characteristics of end users and the price structure.
Demand elasticities are estimated to range from a -0.05 percent elasticity of demand for a
"flat rates" case (i.e., no time-of-use assumption) up to a -0.50 percent demand elasticity for
a "high consumer response" case (DOE, EIA, 1999b).
5.1.2.1 Growth in Generation Capacity
The electric industry is continuing to grow and change. Throughout the country,
electric utility capacity additions are slightly outpacing capacity retirements. The trend goes
beyond an increasing capacity but also shows that coal units are slowly being replaced by
newer, more efficient methods of producing energy. In 1997, 71 electric utility units were
closed, decreasing capacity by 2,127 MW. Of those, six were coal facilities and 43 were
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Table 5-7. Key Parameters in the Cases
Key Assumptions
Case Name
AEO97 Reference Case
No Competition
Flat Rates
(no time-of-use rates)
Moderate Consumer
Response
High Consumer Response
High Efficiency
No Capacity Additions
High Gas Price
Low Gas Price
High Value of Reliability
HalfO&M
Intense Competition
Cost Reduction
and Efficiency
Improvements
AEO97 Reference
Case
No change from
1995
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
Increased cost
savings and
efficiencies
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
Short-Run
Elasticity
of Demand
(Percent)
—
—
-0.05
-0.15
-0.50
-0.15
-0.15
-0.15
-0.15
-0.15
-0.15
-0.15
Natural Gas
Prices
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Low Oil
and Gas Supply
Technology Case
AEO97 High Oil
and Gas Supply
Technology Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
AEO97 Reference
Case
Capacity
Additions
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
Not allowed
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
As needed
to meet demand
As needed to meet
demand
— = not applicable.
Source: U.S. Department of Energy, Energy Information Administration, Office of Integrated Analysis and
Forecasting. "Competitive Electricity Price Projections."
. As obtained on November 15, 1999b.
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petroleum facilities. However, of the 62 facility additions (2,918 MW), none were coal
powered, while 24 use petroleum. Gas installations slightly outpaced petroleum ones,
totaling 25 new units at electric utilities in 1997. Table 5-8 outlines capacity additions and
retirements at U.S. electric utilities by energy source.
Table 5-8. Capacity Additions and Retirements at U.S. Electric Utilities by Energy
Source, 1997
Additions
Primary Energy
Source
U.S. total
Coal
Petroleum
Gas
Number of
Units
62
—
24
25
Generator
Nameplate
Capacity (MW)
2,918
—
199
2,475
Retirements
Number of
Units
71
6
43
18
Generator
Nameplate
Capacity (MW)
2127
281
445
405
Water (pumped storage
hydroelectric)
Nuclear
Waste heat
Renewable3
995
3
10
171
73
a Includes conventional hydroelectric; geothermal; biomass (wood, wood waste, nonwood waste); solar; and
wind.
Note: Total may not equal the sum of components because of independent rounding.
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999c. Electric Power Annual
1998. Volumes I and II. Washington, DC: U.S. Department of Energy.
Planned additions indicate a strong trend towards gas-powered turbine/stationary
combustion units. Three-quarters of the gas turbine/stationary combustion units are expected
to be gas-powered with the remaining quarter petroleum-powered. Based on 1998 planned
additions, it is likely that all additional petroleum-fueled units in the near future will be gas
turbine/stationary combustion units, not steam. Table 5-9 shows planned capacity additions
by prime mover and energy source.
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Table 5-9. Fossil-Fueled Existing Capacity and Planned Capacity Additions at U.S.
Electric Utilities by Prime Mover and Primary Energy Source, as of January 1,1998
Prime Mover Energy Source
U.S. Total
Steam
Coal
Petroleum
Gas
Gas Turbine/Internal
Combustion
Petroleum
Gas
Planned
Number of Units
272
45
8
—
37
226
52
174
Additions3
Generator Nameplate
Capacity (MW)
50,184
18,518
2,559
—
15,959
31,663
1,444
30,219
a Planned additions are for 1998 through 2007. Totals include one 2.9 MW fuel cell unit.
Notes: Total may not equal the sum of components because of independent rounding. The Form EIA-860
was revised during 1995 to collect data as of January 1 of the reporting year, where "reporting year" is
the calendar year in which the report is required to be filed with the Energy Information
Administration. These data reflect the status of electric plants/generators as of January 1; however,
dynamic data are based on occurrences in the previous calendar year (e.g., capabilities and energy
sources based on test and consumption in the previous year).
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999c. Electric Power
Annual 1998. Volumes I and II. Washington, DC: U.S. Department of Energy.
5.7.3 Electricity Consumption
This section analyzes the growth projections for electricity consumption as well as
the price elasticity of demand for electricity. Growth in electricity consumption has
traditionally paralleled GDP growth. However, improved energy efficiency of electrical
equipment, such as high-efficiency motors, has slowed demand growth over the past few
decades. The magnitude of the relationship has been decreasing over time, from growth of 7
percent per year in the 1960s down to 1 percent in the 1980s. As a result, determining what
the future growth will be is difficult, although it is expected to be positive (DOE, EIA,
1999a). Table 5-10 shows consumption by sector of the economy over the past 10 years.
The table shows that since 1989 electricity sales have increased at least 10 percent in all four
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Table 5-10. U.S. Electric Utility Retail Sales of Electricity by Sector, 1989 Through
July 1999 (Million kWh)
Period
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
Percentage
change
1989-1998
Residential
905,525
924,019
955,417
935,939
994,781
1,008,482
1,042,501
1,082,491
1,075,767
1,124,004
19%
Commercial
725,861
751,027
765,664
761,271
794,573
820,269
862,685
887,425
928,440
948,904
24%
Industrial
925,659
945,522
946,583
972,714
977,164
1,007,981
1,012,693
1,030,356
1,032,653
1,047,346
12%
Other3
89,765
91,988
94,339
93,442
94,944
97,830
95,407
97,539
102,901
99,868
10%
All Sectors
2,646,809
2,712,555
2,762,003
2,763,365
2,861,462
2,934,563
3,013,287
3,097,810
3,139,761
3,220,121
18%
a Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways,
and interdepartmental sales.
Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1999c. Electric Power Annual
1998. Volumes I and II. Washington, DC: U.S. Department of Energy.
U.S. Department of Energy, Energy Information Administration (EIA). 1996b. Electric Power Annual
1995. Volumes I and II. Washington, DC: U.S. Department of Energy.
sectors. The commercial sector has experienced the largest increase, followed by residential
consumption.
In the future, residential demand is expected to be at the forefront of increased
electricity consumption. Between 1997 and 2020, residential demand is expected to increase
at 1.6 percent annually. Commercial growth in demand is expected to be approximately 1.4
percent, while industry is expected to increase demand by 1.1 percent (DOE, EIA, 1999a).
5.2 Oil and Gas Extraction (NAICS 211)
The crude petroleum and natural gas industry encompasses the oil and gas extraction
process from the exploration for oil and natural gas deposits through the transportation of the
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product from the production site. The primary products of this industry are natural gas,
natural gas liquids, and crude petroleum.
5.2.1 Introduction
The United States is home to half of the major oil and gas companies operating
around the globe. Although small firms account for nearly 45 percent of U.S. crude oil and
natural gas output, the domestic oil and gas industry is dominated by 20 integrated petroleum
and natural gas refiners and producers, such as Exxon Mobil, BP Amoco, and Chevron
(Lillis, 1998). Despite the presence of many large global players, the industry experiences a
more turbulent business cycle than most other major U.S. industries. Because the industry
imports 60 percent of the crude oil used as an input into refineries, it is susceptible to
fluctuations in crude oil output and prices, which are strongly influenced by the Organization
of Petroleum Exporting Countries (OPEC). OPEC is a cartel consisting of most of the
world's largest petroleum-producing countries that acts to increase the profits of member
countries. In contrast, natural gas markets in the United States are competitive and relatively
stable. Most natural gas used in the United States comes from domestic and Canadian
sources.
NAICS 211 includes five major industry groups (see Table 5-11):
• NAICS 211111 (SIC 1311): Crude petroleum and natural gas. Firms in this
industry are primarily involved in operating oil and gas fields. These firms may
also explore for crude oil and natural gas, drill and complete wells, and separate
crude oil and natural gas components from natural gas liquids and produced
fluids.
• NAICS 211112 (SIC 1321): Natural gas liquids (NGL). NGL firms separate
NGLs from crude oil and natural gas at the site of production. Propane and
butane are NGLs.
• NAICS 213111 (SIC 1381): Drilling oil and gas wells. Firms in this industry
drill oil and natural gas wells on a contract or fee basis.
• NAICS 213112/54136 (SIC 1382): Oil and gas field exploration services. Firms
in this industry perform geological, geophysical, and other exploration services.
• NAICS 213112 (SIC 1389): Oil and gas field services, not elsewhere classified.
Companies in this industry perform services on a contract or fee basis that are not
classified in the above industries. Services include drill-site preparations, such as
building foundations and excavating pits, and maintenance.
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Table 5-11. Crude Petroleum and Natural Gas Industries Likely to Be Affected by the
Regulation
SIC
1311
1321
1381
1382
1389
NAICS
211111
211112
213111
213112
54136
213112
Description
Crude Petroleum and Natural Gas
Natural Gas Liquids
Drilling Oil and Gas Wells
Oil and Gas Exploration Services
Geophysical Surveying and Mapping
Oil and Gas Field Services, N.E.C.
Services
In 1997, more than 6,800 crude oil and natural gas extraction companies (NAICS
211111) generated $75 billion in revenues. Revenues for 1997 were approximately 5 percent
higher than revenues in 1992, although the number of companies and employees declined
11.5 and 42.5 percent, respectively.
Table 5-12 shows the NGL extraction industry (NAICS 211112) experienced a
decline in the number of companies, establishments, and employees. The industry's
revenues declined nearly 8.0 percent between 1992 and 1997, from $27 billion per year to
$24.8 billion per year.
Revenues for NAICS 213111, drilling oil and gas wells, more than doubled between
1992 and 1997. In 1992, the industry employed 47,700 employees at 1,698 companies and
generated $3.6 billion in annual revenues. By the end of 1997, the industry's annual
revenues were $7.3 billion, a 106 percent improvement. Although the total number of
companies and establishments decreased from 1992 levels, industry employment increased
13 percent to 53,865.
The recent transition from the SIC system to the North American Industrial
Classification System (NAICS) changed how some industries are organized for information
collection purposes and thus how certain economic census data are aggregated. Some SIC
codes were combined, others were separated, and some activities were classified under one
NAICS code and the remaining activities classified under another. The oil and gas field
services industry is an example of an industry code that was reclassified. Under NAICS, SIC
1382, Oil and Gas Exploration Services, and SIC 1389, Oil and Gas Services Not Elsewhere
Classified, were combined. The geophysical surveying and mapping services portion of SIC
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Table 5-12. Summary Statistics, Crude Oil and Natural Gas Extraction and Related
Industries
NAICS
211111
211112
213111
213112
Industry
Crude Oil and Natural
Gas Extraction
1992
1997
Natural Gas Liquid
Extraction
1992
1997
Drilling Oil and Gas
Wells
1992
1997
Oil and Gas Field
Services
1997
Number of
Companies
7,688
6,802
108
89
1,698
1,371
6,385
Number of
Establishments
9,391
7,781
591
529
2,125
1,638
7,068
Revenues
($1997 103)
71,622,600
75,162,580
26,979,200
24,828,503
3,552,707
7,317,963
11,547,563
Employees
174,300
100,308
12,000
10,549
47,700
53,865
106,339
Sources: U.S. Department of Commerce, Bureau of the Census. 1999a. 7997 Economic Census, Mining
Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N-2111A. Washington, DC:
U.S. Department of Commerce.
U.S. Department of Commerce, Bureau of the Census. 1995a. 7992 Census of Mineral Industries,
Industry Series: Crude Petroleum and Natural Gas. MIC92-I-13A. Washington, DC: U.S.
Department of Commerce.
1382 was reclassified and grouped into NAICS 54136. The adjustments to SIC 1382/89
have made comparison between the 1992 and 1997 economic censes difficult at this time.
The U.S. Census Bureau has yet to publish a comparison report. Thus, for this industry only
1997 census data are presented. For that year, nearly 6,400 companies operated under SIC
1382/89 (NAICS 213112), employing more than 100,000 people and generating $11.5 billion
in revenues.
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5.2.2 Supply Side
Characterizing the supply side of the industry involves describing the production
processes, the types of output, major by-products, costs of production, and capacity
utilization.
5.2.2.1 Production Processes
There are four major processes in the oil and gas extraction industry: exploration,
well development, production, and site abandonment (EPA, 1999b). Exploration is the
search for rock formations associated with oil and/or natural gas deposits. Nearly all oil and
natural gas deposits are located in sedimentary rock. Certain geological clues, such as
porous rock with an overlying layer of low-permeability rock, help guide exploration
companies to a possible source of hydrocarbons. While exploring a potential site, the firm
conducts geophysical prospecting and exploratory drilling.
After an economically viable field is located, the well development process begins.
Well holes, or well bores, are drilled to a depth of between 1,000 and 30,000 feet, with an
average depth of about 5,500 feet (EPA, 1999b). The drilling procedure is the same for both
onshore and offshore sites. A steel or diamond drill bit, which may be anywhere between
4 inches and 3 feet in diameter, is used to chip off rock to increase the depth of the hole. The
drill bit is connected to the rock by several pieces of hardened pipe known collectively as the
drill string. As the hole is drilled, casing is placed in the well to stabilize the hole and
prevent caving. Drilling fluid is pumped down through the center of the drill string to
lubricate the equipment. The fluid returns to the surface through the space between the drill
string and the rock formation or casing. Once the well has been drilled, rigging, derricks,
and other production equipment are installed. Onshore fields are equipped with a pad and
roads; ships, floating structures, or a fixed platform are procured for offshore fields.
Production is the process of extracting hydrocarbons through the well and separating
saleable components from water and silt. Oil and natural gas are naturally occurring co-
products, and most production sites handle crude oil and gas from more than one well. Once
the hydrocarbons are brought to the surface, they are separated into a spectrum of substances,
including liquid hydrocarbons, gas, and water and other nonsaleable constituents. After
being extracted, crude oil is always delivered to a refinery for processing; natural gas may be
processed at the field or at a natural gas processing plant to remove impurities. Natural gas
is separated from crude oil by passing the hydrocarbons through one or two decreasing
pressure chambers. Excess water is removed from the crude oil, at which point the oil is
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about 98 percent pure, a purity sufficient for storage or transport to a refinery (EPA, 1999b).
Excess water is returned to the well to facilitate the production process, but silt is discarded.
If enough natural pressure does not exist in the reservoir to force the hydrocarbons through
the well, then the reservoir is pressurized using pumps or excess water to lift the
hydrocarbons.
Natural gas is conditioned using a dehydration and a sweetening process, which
removes hydrogen sulfide and carbon dioxide, so that it is of high enough quality to pass
through transmission systems. The gas may be conditioned at the field or at one of the 623
operating gas-processing facilities located in gas-producing states, such as Texas, Louisiana,
Oklahoma, and Wyoming. These plants also produce the nation's NGLs, propane and butane
(NCSA et al., 2000c).
Site abandonment occurs when a site lacks the potential to produce economic
quantities of natural gas or when a production well is no longer economically viable. The
well(s) are plugged using long cement plugs and steel plated caps, and supporting production
equipment is disassembled and moved offsite.
5.2.2.2 Types of Output
The oil and gas industry's principal products are crude oil, natural gas, and NGLs
(see Tables 5-13 and 5-14). Refineries process crude oil into several petroleum products.
These products include motor gasoline (40 percent of crude oil); diesel and home heating oil
(20 percent); jet fuels (10 percent); waxes, asphalts, and other nonfuel products (5 percent);
feedstocks for the petrochemical industry (3 percent); and other lesser products (DOE, EIA,
1999d).
Natural gas is produced from either oil wells (known as "associated gas") or wells
that are drilled for the primary purpose of obtaining natural gas (known as "nonassociated
gas") (see Table 5-14). Methane is the predominant component of natural gas (about
85 percent), but ethane (about 10 percent), propane, and butane are also significant
components (see Table 5-13). Propane and butane, the heavier components of natural gas,
exist as liquids when cooled and compressed. These latter two components are usually
separated and processed as NGLs (EPA, 1999b).
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Table 5-13. U.S. Supply of Crude Oil and Petroleum Products (103 barrels), 1998
Commodity
Crude Oil
Natural Gas Liquids
Ethane/ethylene
Propane/propylene
Normal butane/butylene
Isobutane/isobutylene
Other
Other Liquids
Finished Petroleum Products
Finished motor gasoline
Finished aviation gasoline
Jet fuel
Kerosene
Distillate fuel oil
Residual fuel oil
Naptha
Other oils
Special napthas
Lubricants
Waxes
Petroleum coke
Asphalt and road oil
Still gas
Miscellaneous products
Total
Field
Production
2,281,919
642,202
221,675
187,369
54,093
66,179
112,886
69,477
69,427
69,427
3,063,025
Refinery
Production
245,918
11,444
200,815
29,333
4,326
5,970,090
2,880,521
7,118
556,834
27,848
1,249,881
277,957
89,176
78,858
24,263
67,263
8,355
260,061
181,910
239,539
20,506
6,216,008
Imports
3,177,584
82,081
6,230
50,146
8,612
5,675
11,418
211,266
437,515
113,606
43
45,143
466
76,618
100,537
22,388
61,554
2,671
3,327
613
263
10,183
103
3,908,446
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999 f. Petroleum Supply
Annual 1998, Volume I. Washington, DC: U.S. Department of Energy.
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Table 5-14. U.S. Natural Gas Production, 1998
Gross Withdrawls Production (10 cubic feet)
From gas wells 17,558,621
From oil wells 6,365,612
Less losses and repressuring 5,216,477
Total 18,707,756
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999e. Natural Gas Annual
1998. Washington, DC: U.S. Department of Energy.
5.2.2.5 Major By-products
The engines that provide pumping action at wells and push crude oil and natural gas
through pipes to processing plants, refineries, and storage locations produce HAPs. HAPs
produced in engines include formaldehyde, acetaldehyde, acrolein, and methanol.
5.2.2.4 Costs of Production
The 42 percent decrease in the number of people employed by the crude oil and
natural gas extraction industry between 1992 and 1997 was matched by a corresponding
40 percent decrease in the industry's annual payroll (see Table 5-15). During the same
period, industry outlays for supplies, such as equipment and other supplies, increased over
32 percent, and capital expenditures nearly doubled. Automation, mergers, and corporate
downsizing have made this industry less labor-intensive (Lillis, 1998).
Unlike the crude oil and gas extraction industry, the NGL extraction industry's
payroll increased over 6 percent even though total industry employment declined 12 percent.
The industry's expenditures on capital projects, such as investments in fields, production
facilities, and other investments, increased 11.4 percent between 1992 and 1997. The cost of
supplies did, however, decrease 13 percent from $23.3 billion in 1992 to $20.3 billion in
1997.
Employment increased in Drilling Oil and Gas Wells. In 1992, the industry
employed 47,700 people, increasing 13 percent to 53,865 in 1997. During a period where
industry revenues increased over 100 percent, the industry's payroll increased 41 percent and
the cost of supplies increased 182 percent.
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Table 5-15. Costs of Production, Crude Oil and Natural Gas Extraction and Related
Industries
NAICS
211111
211112
213111
213112
Industry
Crude Oil and
Natural Gas
Extraction
1992
1997
Natural Gas
Liquid Extraction
1992
1997
Drilling Oil and
Gas Wells
1992
1997
Oil and Gas Field
Services
1997
Employees
174,300
100,308
12,000
10,549
47,700
53,865
106,339
Cost of Supplies
Used, Purchased Capital
Payroll Machinery Installed, Expenditures
($1997 103) Etc. ($1997 103) ($1997 103)
$8,331,849
$4,968,722
$509,272
$541,593
$1,358,784
$1,918,086
$3,628,416
$16,547,510
$21,908,191
$23,382,770
$20,359,528
$1,344,509
$7,317,963
$3,076,039
$10,860,260
$21,117,850
$609,302
$678,479
$286,509
$2,209,300
$1,165,018
Sources: U.S. Department of Commerce, Bureau of the Census. 1999a. 7997 Economic Census, Mining,
Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N-2111A. Washington, DC:
U.S. Department of Commerce.
U.S. Department of Commerce, Bureau of the Census. 1995a. 7992 Census of Mineral Industries,
Industry Series: Crude Petroleum and Natural Gas. MIC92-I-13A. Washington, DC: U.S.
Department of Commerce.
5.2.2.5 Capacity Utilization
U.S. annual oil and gas production is a small percentage of total U.S. reserves. In
1998, oil producers extracted approximately 1.5 percent of the nation's proven crude oil
reserves (see Table 5-16). A slightly lesser percentage of natural gas was extracted
(1.4 percent), and an even smaller percentage of NGLs was extracted (0.9 percent). The
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Table 5-16. Estimated U.S. Oil and Gas Reserves, Annual Production, and Imports,
1998
Category
Crude oil (106 barrels)
Natural gas (109 cubic feet)
Natural gas liquids (106 barrels)
Reserves
152,453
1,330,930
26,792
Annual
Production
2,281
18,708
246
Imports
3,178
3,152
NA
Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1999h. U.S. Crude Oil,
Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report. Washington, DC: U.S.
Department of Energy.
U.S. Department of Energy, Energy Information Administration (EIA). 1999f. Petroleum Supply
Annual 1998, Volume I. Washington DC: U.S. Department of Energy.
United States produces approximately 40 percent (2,281 million barrels) of its annual crude
oil consumption, importing the remainder of its crude oil from Canada, Latin America,
Africa, and the Middle East (3,178 million barrels). Approximately 17 percent (3,152 billion
cubic feet) of U.S. natural gas supply is imported. Most imported natural gas originates in
Canadian fields in the Rocky Mountains and off the Coast of Nova Scotia and New
Brunswick.
5.2.3 Demand Side
Characterizing the demand side of the industry involves describing product
characteristics. Crude oil, or unrefined petroleum, is a complex mixture of hydrocarbons that
is the most important of the primary fossil fuels. Refined petroleum products are used for
petrochemicals, lubrication, heating, and fuel. Petrochemicals derived from crude oil are the
source of chemical products such as solvents, paints, plastics, synthetic rubber and fibers,
soaps and cleansing agents, waxes, jellies, and fertilizers. Petroleum products also fuel the
engines of automobiles, airplanes, ships, tractors, trucks, and rockets. Other applications
include fuel for electric power generation, lubricants for machines, heating, and asphalt
(Berger and Anderson, 1978). Because the market for crude oil is global and its price set by
OPEC, slight increases in the cost of producing crude oil in the United States will have little
effect on the price of products that use crude oil as an intermediate good. Production cost
increases will be absorbed by the producer, not passed along to consumers.
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Natural gas is a colorless, flammable gaseous hydrocarbon consisting for the most
part of methane and ethane. The largest single application for natural gas is as a domestic or
industrial fuel. However, other specialized applications have emerged over the years, such
as a nonpolluting fuel for buses and other motor vehicles. Carbon black, a pigment made by
burning natural gas with little air and collecting the resulting soot, is an important ingredient
in dyes, inks, and rubber compounding operations. Also, much of the world's ammonia is
manufactured from natural gas; ammonia is used either directly or indirectly in urea,
hydrogen cyanide, nitric acid, and fertilizers (Tussing and Tippee, 1995).
5.2.4 Organization of the Industry
Many oil and gas firms are merging to remain competitive in both the global and
domestic marketplaces. By merging with their peers, these companies may reduce operating
expenses and reap greater economies of scale than they would otherwise. Recent mergers,
such as BP Amoco and Exxon Mobil, have reduced the number of companies and facilities
operating in the United States. Currently, there are 20 domestic major oil and gas
companies, and only 40 major global companies in the world (Conces, 2000). Most U.S. oil
and gas firms are concentrated in states with significant oil and gas reserves, such as Texas,
Louisiana, California, Oklahoma, and Alaska.
Tables 5-17 through 5-20 present the number of facilities and value of shipments by
facility employee count for each of the four MACS 211 industries. In 1997, 6,802 oil and
gas extraction companies operated 7,781 facilities, an average of 1.14 facilities per company
(see Table 5-17). Facilities with more than 100 employees produced more than 55 percent of
the industry's value of shipments. Although the number of companies and the number of
facilities operating in 1992 were both greater then than in 1997, the distribution of shipment
values by employee size was similar to that of 1992.
Facilities employing fewer than 50 people in the NGLs extraction industry accounted
for 64 percent, or $15.8 billion, of the industry's total value of shipments in 1997 (see
Table 5-18). Four hundred eighty-seven of the industry's 529 facilities are in that
employment category. This also means that a relatively small number of larger facilities
produced 36 percent of the industry's annual output, in terms of dollar value. The number of
facilities with zero to four employees and the number with 50 or more employees decreased
during the 5-year period, accounting for most of the 10.5 percent decline in the number of
facilities from 1992 to 1997. The average number of facilities per company was 5.5 and 5.9
in 1992 and 1997, respectively.
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Table 5-17. Size of Establishments and Value of Shipments, Crude Oil and Natural Gas
Extraction Industry (NAICS 211111), 1997 and 1992
Average Number of
Employees in Facility
0 to 4 employees
5 to 9 employees
10 to 19 employees
20 to 49 employees
50 to 99 employees
100 to 249 employees
250 to 499 employees
500 to 999 employees
1,000 to 2,499 employees
2,500 or more employees
Total
Number of
Facilities
5,249
1,161
661
412
132
105
40
14
5
2
7,781
1997
Value of
Shipments
($1997 103)
$5,810,925
$3,924,929
$4,843,634
$10,538,529
$8,646,336
$41,318,227
$75,162,580
1992
Number of
Facilities
6,184
1,402
790
523
203
154
68
46
18
3
9,391
Value of
Shipments ($1997
103)
$5,378,330
$3,592,560
$4,504,830
$8,820,100
$5,942,130
$11,289,730
$8,135,850
$14,693,630
$9,265,530
D
$71,622,600
D = undisclosed
Sums do not add to totals due to independent rounding.
Sources: U.S. Department of Commerce, Bureau of the Census. 1999a. 7997 Economic Census, Mining,
Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N-2111A. Washington, DC:
U.S. Department of Commerce.
U.S. Department of Commerce, Bureau of the Census. 1995a. 7992 Census of Mineral Industries,
Industry Series: Crude Petroleum and Natural Gas. MIC92-I-13A. Washington, DC: U.S.
Department of Commerce.
As mentioned earlier, the oil and gas well drilling industry's 1997 value of shipments
were 106 percent larger than 1992's value of shipments (see Table 5-19). However, the
number of companies primarily involved in this industry declined by 327 over 5 years, and
487 facilities closed during the same period. The distribution of the number of facilities by
employment size shifted towards those that employed 20 or more people. In 1997, those
facilities earned two-thirds of the industry's revenues.
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Table 5-18. Size of Establishments and Value of Shipments, Natural Gas Liquids
Industry (NAICS 211112), 1997 and 1992
Average Number of
Employees in Facility
0 to 4 employees
5 to 9 employees
10 to 19 employees
20 to 49 employees
50 to 99 employees
100 to 249 employees
250 to 499 employees
500 to 999 employees
1,000 to 2,499 employees
2,500 or more employees
Total
Number of
Facilities
143
101
122
121
35
3
3
1
0
0
529
1997
Value of
Shipments
($1997 103)
$1,407,192
$1,611,156
$4,982,941
$7,828,439
$5,430,448
D
D
D
—
—
$24,828,503
1992
Number of
Facilities
190
92
112
145
36
14
2
0
0
0
591
Value of
Shipments ($1997
103)
$2,668,000
$1,786,862
$5,240,927
$10,287,200
$4,789,849
$2,205,819
D
—
—
—
$26,979,200
D = undisclosed
Sums do not add to totals due to independent rounding.
Sources: U.S. Department of Commerce, Bureau of the Census. 1999b. 7997 Economic Census, Mining,
Industry Series: Natural Gas Liquid Extraction. EC97N-2111b. Washington, DC: U.S. Department
of Commerce.
U.S. Department of Commerce, Bureau of the Census. 1995b. 7992 Census of Mineral Industries,
Industry Series: Natural Gas Liquids. MIC92-I-13B. Washington, DC: U.S. Department of
Commerce.
In 1997, 6,385 companies operated 7,068 oil and gas field services facilities, an
average of 1.1 facilities per company. Most facilities employed four or fewer employees;
however, those facilities with 20 or more employees accounted for the majority of the
industry's revenues (see Table 5-20).
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Table 5-19. Size of Establishments and Value of Shipments, Drilling Oil and Gas Wells
Industry (NAICS 213111), 1997 and 1992
Average Number of
Employees in Facility
0 to 4 employees
5 to 9 employees
10 to 19 employees
20 to 49 employees
50 to 99 employees
100 to 249 employees
250 to 499 employees
500 to 999 employees
1,000 to 2,499 employees
2,500 or more employees
Total
Number of
Facilities
825
215
197
200
95
75
10
14
6
1
1,638
1997
Value of
Shipments ($1997
103)
$107,828
$231,522
$254,782
$1,008,375
$785,804
$1,069,895
$435,178
$1,574,139
D
D
$7,317,963
1992
Number of
Facilities
1,110
321
244
233
120
70
19
5
3
—
2,125
Value of Shipments
($1997 103)
$254,586
$182,711
$256,767
$572,819
$605,931
$816,004
$528,108
$97,254
$238,427
—
$3,552,707
D = undisclosed
Sums do not add to totals due to independent rounding.
Sources: U.S. Department of Commerce, Bureau of the Census. 1999c. 7997 Economic Census, Mining,
Industry Series: Drilling Oil and Gas Wells. EC97N-2131A. Washington, DC: U.S. Department of
Commerce.
U.S. Department of Commerce, Bureau of the Census. 1995c. 7992 Census of Mineral Industries,
Industry Series: Oil and Gas Field Services. MIC92-I-13C. Washington, DC: U.S. Department of
Commerce.
5.2.5 Markets and Trends
Between 1990 and 1998, crude oil consumption increased 1.4 percent per year, and
natural gas consumption increased 2.0 percent per year. The increase in natural gas
consumption came mostly at the expense of coal consumption (EPA, 1999b). The Energy
Information Administration (EIA), a unit of the Department of Energy, anticipates that
natural gas consumption will continue to grow at a similar rate through the year 2020 to 32
trillion cubic feet/year (DOE, EIA, 1999d). They also expect crude oil consumption to grow
at an annual rate of less than 1 percent over the same period.
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Table 5-20. Size of Establishments and Value of Shipments, Oil and Gas Field Services
(NAICS 213112), 1997 and 1992
Average Number of Employees at
Facility
0 to 4 employees
5 to 9 employees
10 to 19 employees
20 to 49 employees
50 to 99 employees
100 to 249 employees
250 to 499 employees
500 to 999 employees
1,000 to 2,499 employees
2,500 or more employees
Total
1997
Number of Facilities
4,122
1,143
835
629
211
84
21
13
9
1
7,068
Value of Shipments
($1997 103)
$706,396
$571,745
$904,356
$1,460,920
$1,480,904
$1,175,766
$754,377
$1,755,689
D
D
$11,547,563
D = undisclosed
Sums do not add to totals due to independent rounding.
Source: U.S. Department of Commerce, Bureau of the Census. 1999d. 1997 Economic Census, Mining,
Industry Series: Support Activities for Oil and Gas Operations. EC97N-2131B. Washington, DC:
U.S. Department of Commerce.
5.3 Natural Gas Pipelines
The natural gas pipeline industry (NAICS 4862) comprises establishments primarily
engaged in the pipeline transportation of natural gas from processing plants to local
distribution systems. Also included in this industry are natural gas storage facilities, such as
depleted gas fields and aquifers.
5.3.1 Introduction
The natural gas industry can be divided into three segments, or links: production,
transmission, and distribution. Natural gas pipeline companies are the second link,
performing the vital function of linking gas producers with the local distribution companies
and their customers. Pipelines transmit natural gas from gas fields or processing plants
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through high compression steel pipe to their customers. By the end of 1998, there were more
than 300,000 miles of transmission lines (OPS, 2000).
The interstate pipeline companies that linked the producing and consuming markets
functioned mainly as resellers or merchants of gas until about the 1980s. Rather than acting
as common carriers (i.e., providers only of transportation), pipelines typically bought and
resold the gas to a distribution company or to some other downstream pipelines that would
later resell the gas to distributers. Today, virtually all pipelines are common carriers,
transporting gas owned by other firms instead of wholesaling or reselling natural gas
(Tussing and Tippee, 1995).
According to the U.S. Bureau of the Census, the natural gas pipeline industry's
revenues totaled $19.6 billion in 1997. Pipeline companies operated 1,450 facilities and
employed 35,789 people (see Table 5-21). The industry's annual payroll is nearly
$1.9 billion.
Table 5-21. Summary Statistics for the Natural Gas Pipeline Industry (NAICS 4862),
1997
Establishments 1,450
Revenue ($103) $19,626,833
Annual payroll ($103) $1,870,950
Paid employees 35,789
Source: U.S. Department of Commerce, Bureau of the Census. 2000. 1997 Economic Census, Transportation
and Warehousing: Geographic Area Series. EC97T48A-US. Washington, DC: Government Printing
Office.
As noted previously, the recent transition from the SIC system to the NAICS changed
how some industries are organized for information collection purposes and thus how certain
economic census data are aggregated. Some SIC codes were combined, others were
separated, and some activities were classified under one NAICS code and the remaining
activities classified under another. The natural gas transmission (pipelines) industry is an
example of an industry code that was reclassified. Under NAICS, SIC 4922, natural gas
transmission (pipelines), and a portion of SIC 4923, natural gas distribution, were combined.
The adjustments have made comparison between the 1992 and 1997 economic censes
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difficult at this time. The U.S. Census Bureau has yet to publish a comparison report. Thus,
for this industry only 1997 census data are presented.
5.3.2 Supply Side
Characterizing the supply side involves describing services provided by the industry,
by-products, the costs of production, and capacity utilization.
5.3.2.1 Service Description
Natural gas is delivered from gas processing plants and fields to distributers via a
nationwide network of over 300,000 miles of transmission pipelines (NCSA et al., 2000a).
The majority of pipelines are composed of steel pipes that measure from 20 to 42 inches in
diameter and operate 24 hours a day. Natural gas enters pipelines at gas fields, storage
facilities, or gas processing plants and is "pushed" through the pipe to the city gate or
interconnections, the point at which distribution companies receive the gas. Pipeline
operators use sophisticated computer and mechanical equipment to monitor the safety and
efficiency of the network.
Reciprocating stationary combustion engines compress and provide the pushing force
needed to maintain the flow of gas through the pipeline. When natural gas is transmitted, it
is compressed to reduce the volume of gas and to maintain pushing pressure. The gas
pressure in pipelines is usually between 300 and 1,300 psi, but lesser and higher pressures
may be used. To maintain compression and keep the gas moving, compressor stations are
located every 50 to 100 miles along the pipeline. Most compressors are large reciprocating
engines powered by a small portion of the natural gas being transmitted through the pipeline.
There are over 8,000 gas compressing stations along U.S. gas pipelines, each
equipped with one or more engines. The combined output capability of U.S. compressor
engines is over 20 million hp (NCSA et al., 2000a). Nearly 5,000 engines have individual
output capabilities from 500 to over 8,000 hp. The replacement cost of this subset of larger
engines is estimated by the Gas Research Institute to be $18 billion (Whelan, 1998).
Before or after natural gas is delivered to a distribution company, it may be stored in
an underground facility. Underground storage facilities are most often depleted oil and/or
gas fields, aquifers, or salt caverns. Natural gas storage allows distribution and pipeline
companies to serve their customers more reliably by withdrawing more gas from storage
during peak-use periods and reduces the time needed to respond to increased gas demand
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(NCSA et al., 2000b). In this way, storage guarantees continuous service, even when
production or pipeline transportation services are interrupted.
5.3.2.2 By-products
According to the Natural Gas Supply Association (NCSA), about 3 percent of the
natural gas moved through pipelines escapes. The engines that provide pumping action at
plants and push crude oil and natural gas through pipelines to customers and storage facilities
produce HAPs. As noted previously, HAPs produced in engines include formaldehyde,
acetaldehyde, acrolein, and methanol.
5.3.2.3 Costs of Production
Between 1996 and 2000, pipeline firms committed over $14 billion to 177 expansion
and new construction projects. These projects added over 15,000 miles and 36,178 million
cubic feet per day (MMcf/d) capacity to the transmission pipeline system. Table 5-22
summarizes the investments made in pipeline projects during the past 5 years. Building new
pipelines is more expensive than expanding existing pipelines. For the period covered in the
table, the average cost per project mile was $862,000. However, the costs for pipeline
expansions averaged $542,000, or 29 cents per cubic foot of capacity added. New pipelines
averaged $1,157,000 per mile at 48 cents per cubic foot of capacity.
Pipelines must pay for the natural gas that is consumed to power the compressor
engines. The amount consumed and the price paid have fluctuated in recent years. In 1998,
pipelines consumed 635,477 MMcf of gas, paying, on average, $2.01 per 1,000 cubic feet.
Pipelines used less natural gas in 1998 than in previous years; the price paid for that gas
fluctuated between $1.49 and $2.29 between 1994 and 1997 (see Table 5-23). For
companies that transmit natural gas through their own pipelines the cost of the natural gas
consumed is considered a business expense.
5.3.2.4 Capacity Utilization
During the past 15 years, interstate pipeline capacity has increased significantly. In
1990, the transmission pipeline system's capacity was 74,158 MMcf/day (see Table 5-24).
By the end of 1997, capacity reached 85,847 MMcf/day, an increase of approximately
16 percent. The system's usage has increased at a faster rate than capacity. The average
daily flow was 60,286 MMcf/day in 1997, a 22 percent increase over 1990's rates.
Currently, the system operates at approximately 72 percent of capacity.
5-40
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Table 5-22. Summary Profile of Completed and Proposed Natural Gas Pipeline Projects, 1996 to 2000
Year
1996
1997
1998
1999
2000
Total
Number
of
Projects
26
42
54
36
19
177
System
Mileage
1,029
3,124
3,388
3,753
4,364
15,660
All
New
Capacity
(MMcf/d)
2,574
6,542
11,060
8,205
7,795
36,178
Type Projects
Project
Costs
($106)
$552
$1,397
$2,861
$3,135
$6,339
$14,285
Average
Cost per
Mile ($103)
$448
$415
$1,257
$727
$1,450
$862
Costs per
Cubic Foot
Capacity
(cents)
21
21
30
37
81
39
New
Average
Cost per
Mile
($103)
$983
$554
$1,301
$805
$1,455
$1,157
Pipelines
Costs per
Cubic Foot
Capacity
(cents)
17
22
31
46
91
48
Expansions
Average
Cost per
Mile
($103)
$288
$360
$622
$527
$940
$542
Costs per
Cubic Foot
Capacity
(cents)
27
21
22
31
57
29
Note: Sums may not add to totals because of independent rounding.
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999d. Natural Gas 1998: Is sue sand Trends. Washington, DC:
U.S. Department of Energy.
-------
Table 5-23. Energy Usage and Cost of Fuel, 1994-1998
Year
1994
1995
1996
1997
1998
Pipeline Fuel (MMcf)
685,362
700,335
711,446
751,470
635,477
Average Price ($ per 1,000 cubic
feet)
1.70
1.49
2.27
2.29
2.01
Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999e. Natural Gas Annual
1998. Washington, DC: US Department of Energy.
Table 5-24. Transmission Pipeline Capacity, Average Daily Flows, and Usage Rates,
1990 and 1997
Capacity (MMcf per day)
Average Flow (MMcf per day)
Usage Rate (percent)
1990
74,158
49,584
68
1997
85,847
60,286
72
Percent Change
16
22
4
Source: U.S. Department of Energy, Energy Information Administration. 1999d. Natural Gas 1998: Issues
and Trends. Washington, DC: US Department of Energy.
5.3.3 Demand Side
Most pipeline customers are local distribution companies that deliver natural gas
from pipelines to local customers. Many large gas users will buy from marketers and enter
into special delivery contracts with pipelines. However, local distribution companies (LDCs)
serve most residential, commercial, and light industrial customers. LDCs also use
compressor engines to pump natural gas to and from storage facilities and through the gas
lines in their service area.
5-42
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While economic considerations strongly favor pipeline transportation of natural gas,
liquified natural gas (LNG) emerged during the 1970s as a transportation option for markets
inaccessible to pipelines or where pipelines are not economically feasible. Thus, LNG is a
substitute for natural gas transmission via pipelines. LNG is natural gas that has been
liquified by lowering its temperature. LNG takes up about 1/600 of the space gaseous
natural gas takes up, making transportation by ship possible. However, virtually all of the
natural gas consumed in the United States reaches its consumer market via pipelines because
of the relatively high expense of transporting LNG and its volatility. Most markets that
receive LNG are located far from pipelines or production facilities, such as Japan—the
world's largest LNG importer, Spain, France, and Korea (Tussing and Tippee, 1995).
5.3.4 Organization of the Industry
Much like other energy-related industries, the natural gas pipeline industry is
dominated by large investor-owned corporations. Smaller companies are few because of the
real estate, capital, and operating costs associated with constructing and maintaining
pipelines (Tussing and Tippee, 1995). Many of the large corporations are merging to remain
competitive as the industry adjusts to restructuring and increased levels of competition.
Increasingly, new pipelines are built by partnerships: groups of energy-related companies
share capital costs through joint ventures and strategic alliances (DOE, EIA, 1999d). Ranked
by system mileage, the largest pipeline companies in the United States are El Paso Energy
(which recently merged with Southern Natural Gas Co.), Enron, Williams Cos., Coastal
Corp., and Duke Energy (see Table 5-25). El Paso Energy and Coastal intend to merge in
mid-2000.
5.3.5 Markets and Trends
During the past decade, interstate pipeline capacity has increased 16 percent. Many
existing pipelines underwent expansion projects, and 15 new interstate pipelines were
constructed. In 1999 and 2000, proposals for pipeline expansions and additions called for a
$9.5 billion investment, an increase of 16.0 billion cubic feet per day of capacity (DOE, EIA,
1999d).
The EIA (1999d) expects natural gas consumption to grow steadily, with demand
forecasted to reach 32 trillion cubic feet by 2020. The expected increase in natural gas
demand has significant implications for the natural gas pipeline system.
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Table 5-25. Five Largest Natural Gas Pipeline Companies by System Mileage, 2000
El Paso Energ)
Company
i Corporation
Headquarters
Houston, TX
Sales
($1999 106)
$5,782
Employment
(1999)
4,700
Miles of
Pipeline
40,200
Incl. El Paso Natural Gas Co.
Southern Natural Gas Co.
Tennessee Gas Pipe Line Co.
Enron Corporation Houston, TX $40,112
Incl. Northern Border Pipe Line Co.
Northern Natural Gas Co.
Trans western Pipeline Co.
Williams Companies, Inc. Tulsa, OK $8,593
Incl. Transcontinental Gas Pipe Line
Northwest Pipe Line Co.
Texas Gas Pipe Line Co.
The Coastal Corporation Houston, TX $8,197
Incl. ANR Pipeline Co.
Colorado Interstate Gas Co.
Duke Energy Corporation Charlotte, NC $21,742
Incl. Panhandle Eastern Pipeline Co.
Algonquin Gas Transmission Co.
Texas Eastern Transmission Co.
17,800 32,000
21,011 27,000
13,000 18,000
21,000 11,500
Sources: Heil, Scott F., Ed. Ward's Business Directory of U.S. Private and Public Companies 1998, Volume 5.
Detroit, MI: Gale Research Inc.
Sales, employment, and system mileage: Hoover's Incorporated. 1998. Hoover's Company Profiles.
Austin, TX: Hoover's Incorporated, .
The EIA (1999d) expects the interregional pipeline system, a network that connects
the lower 48 states and the Canadian provinces, to grow at an annual rate of 0.7 percent
between 2001 and 2020. However, natural gas consumption is expected to grow at more
than twice that annual rate, 1.8 percent, over that same period. The majority of the growth in
consumption is expected to be fueled by the electric generation sector. According to the
EIA, a key issue is what kinds of infrastructure changes will be required to meet this demand
and what the financial and environmental costs will be of expanding the pipeline network.
The EIA addresses the discrepancy between annual consumption growth and
interregional pipeline capacity growth with the following explanation: "Overall,
interregional pipeline capacity (including imports) is projected to grow at an annual rate of
only about 0.7 percent between 2001 and 2020 (compared with 3.7 percent between 1997
5-44
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and 2000 and 3.8 percent between 1990 and 2000). However, EIA also forecasts that
consumption will grow at a rate of 27 Bcf per day (1.8 percent annually) during the same
period. The difference between these two growth estimates is predicted upon the assumption
that capacity additions to support increased demand will be local expansions of facilities
within regions (through added compression and pipeline looping) rather than through new
long-haul (interregional) systems or large-scale expansions" (1999d, p. 125).
5-45
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SECTION 6
ECONOMIC ANALYSIS METHODS
This section presents the methodology for analyzing the economic impacts of the
NESHAP. Implementation of this methodology will provide the economic data and
supporting information needed by EPA to support its regulatory determination. This analysis
is based on microeconomic theory and the methods developed for earlier EPA studies to
operationalize this theory. These methods are tailored to and extended for this analysis, as
appropriate, to meet EPA's requirements for an economic impact analysis (EIA) of controls
placed on stationary combustion turbines.
This methodology section includes a description of the Agency requirements for
conducting an EIA, background information on typical economic modeling approaches, the
conceptual approach selected for this EIA, and an overview of the computerized market
model used in the analysis. The focus of this section is on the approach for modeling the
electricity market and its interactions with other energy markets and final product markets.
Appendix A contains additional detail on estimating changes is producer and consumer
surplus in the nonelectric utility markets included in the economic model.
6.1 Agency Requirements for Conducting an EIA
The CAA provides the statutory authority under which all air quality regulations and
standards are implemented by OAQPS. The 1990 CAA Amendments require that EPA
establish emission standards for sources releasing any of the listed HAPs.
Congress and the Executive Office have imposed requirements for conducting
economic analyses to accompany regulatory actions. The Agency has published its
guidelines for developing an EIA (EPA, 1999a). Section 312 of the CAA specifically
requires a comprehensive analysis that considers benefits, costs, and other effects associated
with compliance. On the benefits side, it requires consideration of all the economic, public
health, and environmental benefits of compliance. On the cost side, it requires consideration
of the effects on employment, productivity, cost of living, economic growth, and the overall
economy. These effects are evaluated by measures of facility- and company-level
production impacts and societal-level producer and consumer welfare impacts. The RFA and
SBREFA require regulatory agencies to consider the economic impacts of regulatory actions
on small entities. Executive Order 12866 requires regulatory agencies to conduct an analysis
of the economic benefits and costs of all proposed regulatory actions with projected costs
greater than $100 million. Also, Executive Order 13211 requires EPA to consider for
6-1
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particular rales the impacts on energy markets. The Agency's draft Economic Analysis
Guidelines provide detailed instructions and expectations for economic analyses that support
rulemaking (EPA, 1999a). The EIA provides the data and information needed to comply
with the federal regulation, the executive order, and the guidance manual.
6.2 Overview of Economic Modeling Approaches
In general, the EIA methodology needs to allow EPA to consider the effect of the
different regulatory alternatives. Several types of economic impact modeling approaches
have been developed to support regulatory development. These approaches can be viewed as
varying along two modeling dimensions:
• the scope of economic decisionmaking accounted for in the model and
• the scope of interaction between different segments of the economy.
Each of these dimensions was considered in recommending our approach. The advantages
and disadvantages of each are discussed below.
6.2.1 Modeling Dimension 1: Scope of Economic Decisionmaking
Models incorporating different levels of economic decisionmaking can generally be
categorized as with behavior responses and without behavior responses (accounting
approach). Table 6-1 provides a brief comparison of the two approaches. The behavioral
approach is grounded in economic theory related to producer and consumer behavior in
response to changes in market conditions. In essence, this approach models the expected
reallocation of society's resources in response to a regulation. The behavioral approach
explicitly models the changes in market prices and production. Resulting changes in price
and quantity are key inputs into the determination of a number of important phenomena in an
EIA, such as changes in producer surplus, changes in consumer surplus, and net social
welfare effects. For example, a large price increase may imply that consumers bear a large
share of the regulatory burden, thereby mitigating the impact on producers' profits and plant
closures.
In contrast, the nonbehavioral/accounting approach essentially holds fixed all
interaction between facility production and market forces. In this approach, a simplifying
assumption is made that the firm absorbs all control costs, and discounted cash flow analysis
is used to evaluate the burden of the control costs. Typically, engineering control costs are
weighted by the number of affected units to develop "engineering" estimates of the total
annualized costs. These costs are then compared to company or industry sales to evaluate
the regulation's impact.
6-2
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Table 6-1. Comparison of Modeling Approaches
EIA With Behavioral Responses
Incorporates control costs into production function
Includes change in quantity produced
Includes change in market price
Estimates impacts for
• affected producers
• unaffected producers
• consumers
• foreign trade
EIA Without Behavioral Responses
• Assumes firm absorbs all control costs
• Typically uses discounted cash flow analysis to evaluate burden of control costs
• Includes depreciation schedules and corporate tax implications
• Does not adjust for changes in market price
• Does not adjust for changes in plant production
6.2.2 Modeling Dimension 2: Interaction Between Economic Sectors
Because of the large number of markets potentially affected by the combustion
turbines regulation, an issue arises concerning the level of sectoral interaction to model. In
the broadest sense, all markets are directly or indirectly linked in the economy; thus, all
commodities and markets are to some extent affected by the regulation. For example, the
control costs on turbines may directly affect the market for aluminum if aluminum plants are
operating turbines for self-generation of electricity or generation of process steam. However,
control costs will also indirectly affect the market for aluminum because the cost of
electricity will increase. As a result, the increased price of aluminum production (due to
direct and indirect costs on the aluminum industry) may be passed onto consumers of
aluminum products.
The appropriate level of market interactions to be included in the EIA is determined
by the scope of the regulation across industries and the ability of affected firms to pass along
the regulatory costs in the form of higher prices. Alternative approaches for modeling
interactions between economic sectors can generally be divided in three groups:
6-3
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• Partial equilibrium model: Individual markets are modeled in isolation. The only
factor affecting the market is the cost of the regulation on facilities in the industry
being modeled.
• General equilibrium model: All sectors of the economy are modeled together.
General equilibrium models operationalize neoclassical microeconomic theory by
modeling not only the direct effects of control costs, but also potential input
substitution effects, changes in production levels associated with changes in
market prices across all sectors, and the associated changes in welfare
economywide. A disadvantage of general equilibrium modeling is that
substantial time and resources are required to develop a new model or tailor an
existing model for analyzing regulatory alternatives.
• Multiple-market partial equilibrium model: A subset of related markets are
modeled together, with intersectoral linkages explicitly specified. To account for
the relationships and links between different markets without employing a full
general equilibrium model, analysts can use an integrated partial equilibrium
model. In instances where separate markets are closely related and there are
strong interconnections, there are significant advantages to estimating market
adjustments in different markets simultaneously using an integrated market
modeling approach.
6.3 Selected Modeling Approach Used for Combustion Turbine Analysis
To conduct the analysis for the combustion turbine MACT, the Agency used a market
modeling approach that incorporates behavioral responses in a multiple-market partial
equilibrium model as described above. The majority of the regulation's control costs are
projected to be associated with combustion turbines in the electricity market. These control
costs will increase the price of energy, affecting almost all sectors of the economy. Because
the elasticity of demand for energy varies across fuel types, it is important to use a market
modeling approach to estimate the share of the burden borne by producers and consumers.
Multiple-market partial equilibrium analysis provides a manageable approach to
incorporate interactions between energy markets and final product markets into the EIA to
accurately estimate the impact of the regulation. The multiple-market partial equilibrium
approach represents an intermediate step between a simple, single-market partial equilibrium
approach and a full general equilibrium approach. This approach involves identifying and
modeling the most significant subset of market interactions using an integrated partial
equilibrium framework. In effect, the modeling technique is to link a series of standard
partial equilibrium models by specifying the interactions between supply functions and then
solving for all prices and quantities across all markets simultaneously.
6-4
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Figure 6-1 presents an overview of the key market linkages included in the economic
impact modeling approach used to analyze the combustion turbines MACT. The focus of the
analysis is on the energy supply chain, including the extraction and distribution of natural gas
and oil, the generation of electricity, and the consumption of energy by producers of final
products and services. As shown in Figure 6-1, wholesale electricity generators consume
natural gas and petroleum products to generate electricity that is then used in the production
of final products and services. In addition, the final product and service markets also use
natural gas and petroleum products as an input into their production process. This analysis
explicitly models the linkages between these market segments.
The control costs associated with the regulation will directly affect the cost of the
generation of wholesale electricity using combustion turbines. In addition to the direct
impact of control costs on entities installing new combustion turbines, indirect impacts are
passed along the energy supply chain through changes in prices. For example, the price of
natural gas will increase because of two effects: the higher price of electricity used in the
natural gas industry and increased demand for natural gas generated by fuel switching from
electricity to natural gas. Similarly, production costs for manufacturers of final products will
change as a result of price of electricity and natural gas.
Also included in the impact model is feedback on changes in outputs in final product
markets to the demand for Btus in the fuel markets. The change in facility output is
determined by the size of the Btu cost increase (typically variable cost per output), the
facility's production function (slope of facility-level supply curve), and the characteristics of
the facility's downstream market (other market suppliers and market demanders). For
example, if consumers' demand for a product is not sensitive to price, then producers can
pass the cost of the regulation through to consumers and the facility output will not change.
However, if only a small number of facilities in a market are affected, then competition will
prevent a facility from raising its prices.
One possible feedback pathway not explicitly modeled is technical changes in
manufacturing processes. For example, if the cost of Btus increases, a facility may use
measures to increase manufacturing efficiency or capture waste heat. These facility-level
responses are a form of pollution prevention. However, directly incorporating these
responses into the model is beyond the scope of our analysis.1
'Technical changes are indirectly captured through the own-price and cross-price elasticities of demand used to
model fuel switching. These are discussed in Section 6.4.1.
6-5
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a
CTQ
ON
r
I
Cd
CD
1
CTQ
ON 55
3
a
n
P^-
CB
Fuel Markets
Supply Demand
Exogenous Endogenous
Oil
Gas
Coal
i demand
2-i demand
lemand
Energy Consumption
Industry A
Btu ^ Manufacturing
Production ^ Process
Electricity Market
Electricity
2-i demand
T
Regulatory
Costs
Industry B
Industry C
Intermediate or
Final Product Markets
Supply Demand
Endogenous Exogenous
supply
Product A
-------
The major market segments included in the model and the intermarket linkages
connecting the fuel markets and final product and service markets are described below.
Because, as mentioned in Section 3, the overwhelming majority of combustion turbine units
are used to generate wholesale electric power, the discussion focuses on the electricity
market.
6.3.1 Electricity Markets
In this analysis, the market for base load energy and peak power are modeled
separately. As the industry deregulates, it is becoming increasingly common for separate
market prices to be determined for these two commodity attributes of electricity. In addition,
the growth of CCCTs is being driven primarily by growth in base load energy demand, and
the growth in SCCTs will be driven primarily by growth in peak demand. And because the
relative impact on the control costs is greater for SCCTs compared to CCCTs, economic
impacts will be different for base load energy and peak power.2
The base load energy and peak power market analyses compare the baseline
equilibrium (without the regulation) to the regulated market equilibrium. Figure 6-2a
presents a generalized market for the base load electricity that includes the installation of
new turbines to meet demand growth for base load power.3 Existing source supply is
characterized by an up ward-sloping marginal cost (supply) curve. The supply of new base
load generation capacity is characterized by constant marginal costs and is modeled as a
horizontal supply curve through the current market price. Figure 6-2b shows that the control
costs associated with the rule will affect both existing and new sources of supply, shifting the
market supply curve and leading to an increase in price and decrease in quantity of base load
power consumed.
6.3.2 Other Energy Markets
The petroleum, natural gas, and coal markets are also included in the market model.
Because the overwhelming majority of the affected combustion turbines is projected to be
used in the electricity market, the other energy markets are assumed not to be directly
affected by the rule. However, these markets will be indirectly affected through changes in
input fuel prices (i.e., a supply shift) and changes in demand from final product and service
2The same controls are required for SCCTs and for CCCTs. But the relative costs are higher for SCCTs because
their equipment and installation costs are approximately 40 percent less compared to CCCTs. Control costs
are discussed in Section 6.1.
3A similar figure and analysis apply for peak load power with the exception that peak load supply is generally
less responsive to price changes at the margin (i.e., base load elasticity of supply > peak load elasticity of
supply).
6-7
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Price
$/kWh
Price
$/kWh
AP
Qo
Existing
Sources
New
Sources
Quantity
(kWh)
a) Without Regulation
AQ
b) With Control Costs
Quantity
(kWh)
Figure 6-2. Electricity Market
markets using these energy sources (i.e., a demand shift). The ultimate impact on market
price and quantities depends on the relative magnitudes of these shifts. Note the demand for
other fuels may increase (Figure 6-3a) as firms switch away from electricity to petroleum,
natural gas, or coal, or demand may decrease (Figure 6-3b) as the higher price for electricity
suppresses economic activity decreasing demand for all fuels.
6.3.3 Supply and Demand Elasticities for Energy Markets
The market model incorporates behavioral changes based on the price elasticities of
supply and demand. The price elasticities used to estimate the economic impacts presented
in Section 6.3 are given in Table 6-2. Appendix B contains the sensitivity analysis for the
key supply and demand elasticity assumptions.
Because most of the direct cost impacts fall on the combustion turbines in electricity
markets, the price elasticities of supply in the electricity markets are important factors
influencing the size and distribution of the economic impacts associated with the combustion
turbine regulation. The elasticities of supply are intended to represent the behavioral
6-8
-------
AP
AQ
a) Demand Increase
APJ
Btu
AQ
b) Demand Decrease
Btu
Figure 6-3. Potential Market Effects of the MACT on Petroleum, Natural Gas, or Coal
responses from existing sources.4 However, in general, there is no consensus on estimates of
the price elasticity of supply for electricity. Estimates of the elasticity of supply for electric
power were unavailable. This is in part because, under traditional regulation, the electric
utility industry had a mandate to serve all its customers. In addition, utilities
werecompensated on a rate-based rate of return. As a result, the market concept of supply
elasticity was not the driving force in utilities' capital investment decisions. To
operationalize the model, a supply elasticity of 0.75 was assumed for the base load energy
market. We assumed that the peak power market was one-half of base load energy elasticity.
Given the uncertainty surrounding these parameters, the Agency conducted a sensitivity
analysis for this value. The results of this sensitivity analysis are reported in Appendix B.
In contrast, many studies have been conducted on the elasticity of demand for
electricity, and it is generally agreed that, in the short run, the demand for electricity is
relatively inelastic. Most residential, commercial, and industrial electricity consumers do not
significantly adjust short-run behavior in response to changes in the price of electricity. The
elasticity of demand for electricity is primarily driven by long-run decisions regarding
4The supply curve for new sources is assumed to be horizontal, reflecting a constant marginal cost of production
for new sources.
6-9
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Table 6-2. Supply and Demand Elasticities
Energy
Sectors
Electricity:
baseload
energy
Electricity:
peak power
Natural gas
Petroleum
Coal
Elasticity of
Supply
0.75
0.375b
0.4T
0.58d
1.0e
Manufacturing
Derived demand
Derived demand
Derived demand
Derived demand
Derived demand
Elasticity
Commercial3
Derived
demand
Derived
demand
Derived
demand
Derived
demand
Derived
demand
of Demand
Transportation3
-0.24
-0.24
-0.47
-0.28
-0.28
Residential3
-0.23
-0.23
-0.26
-0.28
-0.28
a Energy Information Administration. 2000. "Issues in Midterm Analysis and Forecasting 1999—Table 1."
. As obtained on May 8, 2000.
b Assumed to be one-half of baseload energy elasticity.
c Dahl, Carol A., and Thomas E. Duggan. 1996. "U.S. Energy Product Supply Elasticities: A Survey and
Application to the U.S. Oil Market." Resource and Energy Economicsl8:243-263.
d Hogman, William W. 1989. "World Oil Price Projections: A Sensitivity Analysis." Prepared pursuant to the
Harvard-Japan World Oil Market Study. Cambridge, MA: Energy Environmental Policy Center, John F.
Kennedy School of Government, Harvard University.
e Zimmerman, M.B. 1977. "Modeling Depletion in the Mineral Industry: The Case of Coal." The Bell
Journal of Economics 8(2):41-65.
equipment efficiency and fuel substitution. Table 6-6 shows the elasticities of demand used
for the commercial, residential, and transportation sectors.
Additional elasticity of demand parameters for the commercial, residential, and
transportation sectors, by fuel type (natural gas, petroleum and coal), were obtained from the
Energy Information Administration. The elasticity of demand in the energy market for the
manufacturing sector is not specified because the model calculates the derived demand for
each of the five energy markets modeled. In effect, adjustments in the final product markets
due to changes in production levels and fuel switching are used to estimate changes in
demand, eliminating the need for demand elasticity parameters in the energy markets.
6.3.4 Final Product and Service Markets
Producers of final products and services are segmented into industrial, commercial,
transportation, and residential sectors. The industrial sector is further partitioned into the 23
manufacturing, agricultural, and mining sectors. A partial equilibrium analysis was
6-10
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conducted for each of these model the supply and demand of final products. Changes in
production levels and fuel switching due to the regulation's impact on the price of electricity
are then linked back into the energy markets.
6.3.4.1 Modeling the Impact on the Industrial and Commercial Sectors
The impact of the regulation on these sectors was modeled using changes in the cost
of Btus used in production processes. In this context, Btus refer to the generic energy
requirements that are used to generate process heat, process steam, or shaft power. As shown
in Figure 6-4, the regulation will increase the cost of Btu production indirectly through
increases in the price of Btus due to control costs on wholesale electricity generators. The
effect is similar to placing a tax on certain types of energy sources (i.e., on Btus generated by
combustion turbines). The firms' reactions to the change in the cost of Btu production feeds
back into the energy markets in two ways (see Figure 6-4). The first feedback pathway is
through changing the fuel used in the production process. This can include fuel switching,
such as switching from gas turbines to power processes to diesel engines, and/or process
changes that increase energy efficiency and reduce the amount of Btus required per unit of
output. Fuel switching impacts are modeled using cross-price elasticities of demand between
energy sources and own-price elasticities.
Compliance Costs
A $/Btu
Fuel
Markets
A
$/Btu
Btu Production
Decision
A $/Btu
Production
Decision
Output
Market
A Fuel Use
A Output
Figure 6-4. Fuel Market Interactions with Facility-Level Production Decisions
6-11
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EPA modeled fuel switching using secondary data developed by the U.S. Department
of Energy for the National Energy Modeling System (NEMS). Table 6-3 contains fuel price
elasticities of demand for electricity, natural gas, petroleum products, and coal. The diagonal
elements in the table represent own-price elasticities. For example, the table indicates that
for steam coal, a 1 percent change in the price of coal will lead to a 0.499 percent decrease in
the use of coal. The off diagonal elements are cross-price elasticities and indicate fuel
switching propensities. For example, for steam coal, the second column indicates that a
1 percent increase in the price of coal will lead to a 0.061 percent increase in the use of
natural gas.
Table 6-3. Fuel Price Elasticities
Own and Cross Elasticities in 2015
Inputs
Electricity
Natural Gas
Steam Coal
Residual
Distillate
Electricity
-0.074
0.496
0.021
0.236
0.247
Natural Gas
0.092
-0.229
0.061
0.036
0.002
Coal
0.605
1.087
-0.499
0.650
0.578
Residual
0.080
0.346
0.151
-0.587
0.044
Distillate
0.017
0.014
0.023
0.012
-0.055
Source: U.S. Department of Energy, Energy Information Administration (EIA). January 1998c. Model
Documentation Report: Industrial Sector Demand Module of the National Energy Modeling System.
DOE/EIA-M064(98). Washington, DC: U.S. Department of Energy.
The second feedback pathway to the energy markets is through the facility's change
in output. Because Btus are an input into the production process, price increases (t$/Btu)
lead to an upward shift in the industry supply curve. In a perfectly competitive market, the
point where supply equals demand determines the market price and quantity. A shift in the
industry supply curve leads to a change in the equilibrium market price and quantity. EPA
assumed constant returns to scale in production so that the percentage change in the
equilibrium market quantity in each final product and service market equals the percentage
change in Btus consumed by industries.
The change in equilibrium supply and demand in each final industrial and
commercial sector was modeled using a partial equilibrium approach. The size of the
regulation-induced shifts in the final product supply curves is a function of the indirect fuel
costs (determined by the change in fuel prices and the fuel intensity) relative to variable
production costs in each manufacturing industry.
6-12
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It was assumed that the demand for final industrial and commercial products and
services is unchanged by the regulation. However, because the demand function quantifies
the change in quantity demanded in response to a change in price, the baseline demand
conditions are important in determining the regulation's impact. Because prices changes are
anticipated to be small, the key demand parameters are the elasticity of demand with respect
to changes in the price of final products. Demand elasticities for each of the sectors included
in the analysis are reported in Table 6-4.
6.3.4.2 Impact on the Residential Sector and Transportation Sectors
The residential and transportation sector does not bear any direct costs associated
with the regulation because they do not own combustion turbines. However, they bear
indirect costs due to price increases. These sectors' change in energy demand in response to
changes in energy prices is modeled as a series of demand curves parameterized by elasticity
of demand parameters (see Table 6-2).
6.3.4.3 Impact on the Government Sector
All combustion turbines projected to be installed by government entities will be for
local generation of electricity. These municipal generators are grouped into the electricity
energy market; thus the government sector is not explicitly included in the model.
6.4 Summary of the Economic Impact Model
We summarize the linkages used to operationalize the estimation of economic
impacts associated with the compliance costs in Figure 6-5.
Control costs on new turbines used for generators will shift the supply curve for
wholesale electricity. The new equilibrium price and quantity in the electricity market will
determine the distribution of impacts between producers (electricity generators) and
consumers. Changes in wholesale electricity generators' demand for input fuels (due to
changes in the market quantity of electricity) feed back into the natural gas, coal, and
petroleum markets.
Finally, manufacturers experience supply curve shifts due to changes in prices for
natural gas, petroleum, electricity, and coal. The share of these costs borne by producers
(manufactures) and consumers is determined by the new equilibrium price and quantity in
the final product and service markets. Changes in manufacturers' Btu demands due to fuel
switching and changes in production levels feed back into the energy markets.
6-13
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Table 6-4. Supply and Demand Elasticities for Industrial and Commercial Sectors
NAICS Description
Industrial Sectors
311 Food
312 Beverage and Tobacco Products
313 Textile Mills
314 Textile Product Mills
315 Apparel
316 Leather and Allied Products
321 Wood Products
322 Paper
323 Printing and Related Support
325 Chemicals
326 Plastics and Rubber Products
327 Nonmetallic Mineral Products
331 Primary Metals
332 Fabricated Metal Products
333 Machinery
334 Computer and Electronic Products
335 Electrical Equip., Appliances, and
Components
336 Transportation Equipment
337 Furniture and Related Products
339 Miscellaneous
1 1 Agricultural Sector
23 Construction Sector
21 Other Mining Sector
Commercial Sector (NAICS 42-45;51-56;61-72)
Supply
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
Demand
-1.00
-1.30
-1.50
-1.50
-1.10
-1.20
-1.00
-1.50
-1.80
-1.80
-1.80
-1.00
-1.00
-0.20
-0.50
-0.30
-0.50
-0.50
-1.80
-0.60
-1.80
-1.00
-0.30
-1.00
6-14
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a
CTQ
n
ON
O
«
CD
a
o
N
N^*
9
CTQ
&
CD
a
ON Q-
^ 2
Ur 63
O
n
HH
Fuel Markets
Assume
Supply
Oil
Gas
Coal
Model
Demand
/ demand
demand
/ demand
Electricity Market
Electricity
i demand
Energy Consumption
Final Product Markets
Fuel Prices
Industry A
Btu ^ Manufacturing
Production Process
Product Supply
Product Price
Fuel Prices
Industry B
Fuel Prices
Industry Z
Fuel Prices
Commercial Businesses
Fuel Prices
Residential Households
A Production Process
(Fuel Switching)
AQ
Q
P = market price of final
output
Q = quantity sold of final
output
A Production Levels
Regulatory Costs
-------
Adjustments in price and quantity in all energy and final product markets occur
simultaneously. A computer model was used to numerically simulate market adjustments by
iterating over commodity prices until equilibrium is reached (i.e., until supply equals demand
in all markets being modeled) and to estimate the economic impact of the regulation (change
in producer and consumer surplus) in the sectors of the economy being modeled.
This model comprises a series of computer spreadsheet modules. The modules
integrate the engineering inputs and the market-level adjustment parameters to estimate the
regulation's impact on the price and quantity in each market being analyzed. At the heart of
the model is a market-clearing algorithm that compares the total quantity supplied to the total
quantity demanded for each market commodity. Appendix A describes the computer model
in more detail.
6.4.1 Estimating Changes in Social Welfare
The combustion turbine regulation will impact almost every sector of the economy
either directly through control costs or indirectly through changes in the price of energy and
final products. For example, a share of control costs that originate in the energy markets are
passed through the final product markets and are borne by both the producers and consumers
of final products. To estimate the total change in social welfare without double-counting
impacts across the linked partial equilibrium markets being modeled, EPA quantified social
welfare changes for the following categories:
• change in producer surplus in the energy markets,
• change in producer surplus in the final product and service markets,
• change in consumer surplus in the final product and service markets, residential
and transportation energy markets.
Figure 6-6 illustrates the change in producer and consumer surplus in the intermediate energy
market and the final product markets. For example, assume a simple world with only one
energy market, wholesale electricity, and one final product market, pulp and paper. If the
regulation increased the cost of generating wholesale electricity, then part of the cost of the
regulation will be borne by the electricity producers as decreased producer surplus and part
of the costs will be passed on to the pulp and paper manufacturers. In Figure 6-6a, the pulp
and paper manufacturers are the consumers of electricity, so the change in consumer surplus
is displayed. This change in consumer surplus in the energy market is captured by the final
product market (because the consumer is the pulp and paper industry in this case), where it is
split between consumer surplus and producer surplus in those markets. Figure 6-6b shows
the change in producer surplus in the energy market.
6-16
-------
(a) Change in Consumer
Surplus in the Energy
Market
(b) Change in Producer Surplus
in the Energy Market
(c) Change in Consumer
Surplus in Final Product
Markets
(d) Change in Producer Surplus
in Final Product Markets
Figure 6-6. Changes in Economic Welfare with Regulation
As shown in Figures 6-6c and 6-6d, the cost affects the pulp and paper industry by
shifting up the supply curve in the pulp and paper market. These higher electricity prices
therefore lead to costs in the pulp and paper industry that are distributed between producers
and consumers of paper products in the form of lower producer surplus and lower consumer
surplus. Note that the change in consumer surplus in the intermediate energy market must
equal the total change in consumer and producer surplus in the final product market. Thus,
to avoid double-counting, the change in consumer surplus in the intermediate energy market
was not quantified; instead the total change in social welfare was calculated as
6-17
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Change in Social Welfare = £APSE + £APSF + £ACSF + £ACSRT (6.1)
where
APSE = change in producer surplus in the energy markets,
APSF = change in producer surplus in the final product markets,
ACSF = change in consumer surplus in the final product markets, and
ACSRT = change in consumer surplus residential and transportation energy
markets.
Appendix A contains the detailed equations used to calculate the change in producer and
consumer surplus in the appropriate intermediate and final product markets.
6-18
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SECTION 7
ECONOMIC IMPACT ANALYSIS
Control measures implemented to comply with the regulation will impose regulatory
costs on affected facilities in the energy, manufacturing, commercial, and government
sectors. These costs will be distributed between producers and consumers through changes
in energy prices and changes in prices of final products and services. This section describes
the engineering control costs of the regulatory alternatives and presents the economic impact
estimates, including energy impacts, of the regulation.
7.1 Engineering Control Cost Inputs
The cost impacts associated with the regulation in the fifth year after promulgation
comprise capital and annual operating, performance testing, monitoring, recordkeeping, and
reporting costs. The Department of Energy (DOE) projects the 218 new combustion turbines
will begin operation during the 5-year period between 2002 and 2007. Of these new
turbines, it is estimated that approximately 44 units (20 percent) will be located at major
HAP sources and be required to comply with the combustion turbine NESHAP.
EPA estimates the annualized capital costs of these add-on controls for 44 new
stationary combustion turbines (170 MW) are $42.6 million (see Table 7-1).1 Additional
annual costs include performance testing, monitoring, recordkeeping, reporting, and the
annual costs of the oxidation catalyst control system and CEMS yielding a total annual cost
of $43.3 million for affected units. All new sources will be required to conduct an initial
performance test to demonstrate compliance. In addition, EPA estimates that every year
most of the "nonaffected" new sources (70 percent) may have to perform an initial
notification to comply with the regulation. The total cost for initial notification for 123 new
turbines is estimated to be approximately $12,000. For more details on the derivation of
these costs, refer to the "Cost Analysis for Impacts Associated with Stationary Combustion
Turbine MACT," a memo that is in the public docket.
'All costs are reported in 1998 dollars.
7-1
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Table 7-1. Engineering Cost Analysis for the Stationary Combustion Turbine
MACT Standard ($1998)
Combine per Number of
Turbine Affected Turbines Total Cost
Capital Costs
CEMS
Oxidation catalyst
Total Capital Cost
Annual Costs
CEMS
Oxidation catalyst
Performance tests
Monitoring, recordkeeping, reporting
Initial notification only
Total Annual Cost (1998$)
$3,000
$3,255,377
$427
$969,499
$12,350
$2,709
98
44
44
44
44
44
44
123
$132,000
$143,236,588
$143,368,588
$18,788
$42,657,956
$543,400
$119,201
$11,993
$43,351,338
"Revenues and costs are in 1998$.
7.1.1 Computing Supply Shifts in the Electricity Market
For the purpose of the market model, the electric services industry is broken into two
market sectors: base load energy and peak power. As shown in Section 4 (Table 4-3), EPA
estimates approximately two-thirds of new combustion turbine units are projected to
contribute to the base load energy market, and the remaining one-third are projected to
contribute to the peak power market. As a result, the control costs for the electricity are
distributed 67 percent to the electric base load energy market and 33 percent to the peak
power market. The relative shift in the supply curve for each segment is presented as the
percentage shift in the price of the marginal unit produced. The percentage shift is calculated
as the ratio of control costs to the revenue of the affected portion of the industry2 (see
Table 7-2). As shown, new affected sources with add-on controls and testing requirements
have the largest supply shift (1.8 percent for base load energy and 3.5 percent for peak
power). The supply shifters for the remaining segments are all less than 0.1 percent.
Revenue in the electric utility industry was segmented into the base load and peak power markets
assuming an 80/20 split, respectively. This ratio was estimated based on discussions with industry
experts.
7-2
-------
Table 7-2. Summary of Turbine Cost Information and Supply Shifts
Base Load Energy
Existing — unaffected
New unaffected
New affected — notification only
New affected — notification and capital
Total
Peak Power
Existing — unaffected
New unaffected
New affected — notification only
New affected — notification and capital
Total
Total
Share
Units of
Market (%)
95.08
1.07
2.59
0.92
100.00
95.08
1.07
2.59
0.92
100.00
Revenue3
($109)
169.0
1.9
4.6
1.6
177.6
42.2
0.5
1.1
0.4
44.4
222.1
Control
Costs3
($106)
0.00
0.00
0.01
29.04
29.05
0.00
0.00
0.00
14.30
14.31
43.35
Supply
Shift (%)
0.00
0.00
0.00
1.77
0.02
0.00
0.00
0.00
3.48
0.03
"Revenues and costs are in 1998$.
Figure 7-1 illustrates the supply shifts and shows the with-regulation supply curve Sj.
In this example, the regulation leads to an increased supply by unaffected existing units,
crowding out the new units with add-on capital costs.
7.2 Market-Level Results
The model projects the MACT standard will increase base load electricity price by
0.529 percent and peak power prices by 0.717 percent (see Table 7-3). Domestic production
declines by 0.534 and 0.665 percent, respectively.
The analysis also shows the impact on distribution of electricity supply (see
Table 7-4). First, it delays entry of affected new units with add-on controls and testing
requirements because price does not sufficiently increase to cover the costs of production for
these units. Second, the increase in the price of electricity will make it profitable for existing
unaffected sources to increase supply, displacing approximately 0.92 percent of affected new
supply. This increase in supply implies that fewer older units may be retired as a result of
the regulation. The remaining change in quantity results from decreased consumer demand
as the prices of base load energy and peak power increase.
7-3
-------
Price
($/kWh)
-B-
- Projected new source growth -
B = New unaffected unit supply
B+C = Increase in supply from existing units
D = New notification only
F = Decreased quantity demanded due to price increase
G = Affected supply that delays entry into the market until demand
sufficiently grows
a = Supply shift for new monitoring only units
b = Supply shift for new testing and capital equipment units
D
(Projected
Demand)
kWh
Figure 7-1. Market for Baseload Electricity
7-4
-------
Table 7-3. Market-Level Impacts of Stationary Combustion Turbines MACT
Standard: 2005
Energy Markets
Petroleum
Natural Gas
Base Electricity
Peak Electricity
Coal
Industrial Sectors
NAICS Description Description
311 Food
312 Beverage and Tobacco Products
313 Textile Mills
314 Textile Product Mills
315 Apparel
316 Leather and Allied Products
321 Wood Products
322 Paper
323 Printing and Related Support
325 Chemicals
326 Plastics and Rubber Products
327 Nonmetallic Mineral Products
331 Primary Metals
332 Fabricated Metal Products
333 Machinery
334 Computer and Electronic Products
335 Electrical Equipment, Appliances, and
Components
336 Transportation Equipment
337 Furniture and Related Products
339 Miscellaneous
1 1 Agricultural Sector
23 Construction Sector
21 Other Mining Sector
Commercial Sector
Percent
Price
0.019
0.052
0.529
0.717
-0.244
Percent
Price
0.001
0.000
0.002
0.001
0.000
0.001
0.002
0.002
0.001
0.002
0.002
0.004
0.005
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.012
0.002
0.002
Change
Quantity"
0.010
0.018
-0.534
-0.665
-0.244
Change
Quantity
-0.001
-0.001
-0.003
-0.001
0.000
-0.001
-0.002
-0.003
-0.001
-0.004
-0.003
-0.004
-0.005
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.005
-0.012
-0.001
-0.002
aActual value for all 0.000 entries for the various sectors is > -0.001 and < 0.
7-5
-------
Table 7-4. Changes in Market Shares for Electricity Suppliers
Baseline Shares (%) With Regulation Shares (%)
Existing—unaffected
New unaffected
New affected—testing only
New affected—testing and capital
95.42
1.07
2.59
0.92
96.32
1.07
2.60
0.00
In the natural gas and petroleum markets, both the price and quantity increase,
indicating that an increase in demand for the fuel (due to fuel switching) dominates the
upward shift in the supply curve (increased electricity costs as a fuel input). Price increases
in these markets are below 0.1 percent. Price and quantity decrease in the coal market,
reflecting the decreased demand for coal as electric utilities reduce output. Market-level
impacts on downstream product and service markets are less than 0.3 percent.
7.3 Social Cost Estimates
The social impact of a regulatory action is traditionally measured by the change in
economic welfare that it generates. The social costs of the rule will be distributed across
producers of energy and their customers. Producers experience welfare impacts resulting
from changes in profits corresponding with the changes in production levels and market
prices. Consumers experience welfare impacts due to changes in market prices and
consumption levels. However, it is important to emphasize that this measure does not
include benefits that occur outside the market, that is, the value of reduced levels of air
pollution with the regulation.
The national compliance cost estimates are often used to approximate the social cost
of the rule. The engineering analysis estimated annual costs of $43.4 million. In cases
where the engineering costs of compliance are used to estimate social cost, the burden of the
regulation is measured as falling solely on the affected producers, who experience a profit
loss exactly equal to these cost estimates. Thus, the entire loss is a change in producer
surplus with no change (by assumption) in consumer surplus, because no change in market
price is estimated. This is typically referred to as a "full-cost absorption" scenario in which
all factors of production are assumed to all factors of production are assumed to be fixed and
firms are unable to adjust their output levels when faced with additional costs.
In contrast, the economic analysis conducted by the Agency accounts for behavioral
responses by producers and consumers to the regulation, as affected producers shift costs to
7-6
-------
other economic agents. This approach results in a social cost estimate that may differ from
the engineering compliance cost estimate and also provides insights on how the regulatory
burden is distributed across stakeholders. As shown in Table 7-5, the economic model
estimates the total social cost of the rule to be $7.8 million. The social cost estimate is 18
percent of the estimated engineering costs as a result of behavioral changes of producers and
consumers. The major behavioral change is that units with testing and add-on capital
controls are crowded out of the new source market; hence these costs are not incurred by
society. Therefore the social costs primarily reflect higher costs by existing units to increase
supply, and the deadweight loss to consumers as price increases and quantity decreases.
The analysis also shows important distributional impacts across stakeholders. For
example, the model projects consumers will bear a burden of $860 million, as a result of
higher energy prices. In contrast, producer surplus increases by $853 million as energy
producers, particularly the electricity industry, become more profitable with higher prices.
7.4 Executive Order 13211 (Energy Effects)
Executive Order 13211, "Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use" (66 Fed. Reg. 28355 [May 22, 2001]), requires EPA to
prepare and submit a Statement of Energy Effects to the Administrator of the Office of
Information and Regulatory Affairs, Office of Management and Budget, for certain actions
identified as "significant energy actions." Section 4(b) of Executive Order 13211 defines
"significant energy actions" as "any action by an agency (normally published in the Federal
Register) that promulgates or is expected to lead to the promulgation of a final rule or
regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices
of proposed rulemaking:
• that is a significant regulatory action under Executive Order 12866 or any
successor order, and is likely to have a significant adverse effect on the supply,
distribution, or use of energy; or
• that is designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action."
7-7
-------
Table 7-5. Distribution of Social Costs of Stationary Combustion Turbines MACT
Standard: 2005 ($1998 106)
Sectors/Markets
Energy Sector
Petroleum (NAICS 32411, 4861)
Natural Gas (NAICS 21111, 4862, 2212)
Electricity (NAICS 22 1 1 1 , 22 1 1 22, 22 1 1 2 1 )
Coal (NAICS 2121)
Subtotal:
Industrial Sector
NAICS Description
311 Food
312 Beverage and Tobacco Products
313 Textiles Mills
314 Textile Product Mills
315 Apparel
316 Leather and Allied Products
321 Wood Products
322 Paper
323 Printing and Related Support
325 Chemicals
326 Plastics and Rubber Products
327 Nonmetallic Mineral Products
331 Primary Metals
332 Fabricated Metal Products
333 Machinery
334 Computer and Electronic Products
335 Electrical Equipment, Appliances, and
Components
336 Transportation Equipment
337 Furniture and Related Products
339 Miscellaneous
1 1 Agricultural Sector
23 Construction Sector
21 Other Mining Sector
Industrial Sector Subtotal:
Commercial Sector
Residential Sector
Transportation Sector
Subtotal
Grand Total
Producer
Surplus
$55.56
$45.41
$1,297.01
-$76.94
$1,321.05
Producer
Surplus
-$6.5
-$0.8
-$3.3
-$0.6
-$0.5
-$0.1
-$2.0
-$8.5
-$1.7
-$22.9
-$6.2
-$4.1
-$15.2
-$1.9
-$1.9
-$1.8
-$1.1
-$3.8
-$1.0
-$0.9
-$12.7
-$131.7
-$0.7
-$229.9
-$238.7
NA
NA
-$468.6
$852.5
Change in:
Consumer
Surplus
NA
NA
NA
NA
NA
Change in:
Consumer
Surplus
-$4.9
-$0.4
-$1.7
-$0.3
-$0.4
-$0.1
-$1.5
-$4.3
-$0.7
-$9.5
-$2.6
-$3.1
-$11.4
-$6.9
-$2.8
-$4.6
-$1.6
-$5.7
-$0.4
-$1.1
-$5.3
-$98.7
-$1.6
-$169.7
-$179.0
-$454.9
-$56.7
-$860.3
-$860.3
Social
Welfare
NA
NA
NA
NA
NA
Social
Welfare
-$11.4
-$1.2
-$5.0
-$0.9
-$0.9
-$0.1
-$3.5
-$12.8
-$2.5
-$32.5
-$8.7
-$7.1
-$26.7
-$8.8
-$4.7
-$6.4
-$2.7
-$9.6
-$1.5
-$2.0
-$18.0
-$230.4
-$2.3
-$399.6
-$417.7
-$454.9
-$56.7
-$1,328.9
-7.8
Given the magnitude of the annual costs, no Statement of Energy Effects will be
completed. However, to provide some information on the impacts of the rule on affected
7-8
-------
energy markets, the following estimates have been prepared Energy Price Effects. As
described in the market-level results section, electricity prices are projected to increase by
less than 1 percent. Petroleum and natural gas prices are all projected to increase by less
than 0.1 percent. The price of coal is projected to decrease slightly.
Impacts on Electricity Supply, Distribution, and Use. We project the increased
compliance costs for the electricity market will result in an annual production decline of
approximately 20.4 billion kWh and a delay of new installed capacity of 7,480 MW. Note
these effects have been mitigated to some degree in two ways:
• The delay in installed capacity is offset by increased supply from existing
unaffected sources, implying that fewer older units may be retired as a result of
the regulation.
• Sectors previously using electricity in the baseline will switch to other energy
sources (see below).
Impacts on Petroleum, Natural Gas, and Coal Supply, Distribution, and Use. The rule will
lead to higher electricity prices relative to other fuel types, resulting in fuel switching. The
model projects increases in petroleum production/consumption of approximately 2,000
barrels per day. Similarly, natural gas production/consumption is projected to increase by
11.7 million cubic feet per day. The model also projects decreases in coal
production/consumption of approximately 8,000 short tons per year.
7-9
-------
SECTION 8
SMALL ENTITY IMPACTS
The regulatory costs imposed on domestic producers and government entities to
reduce air emissions from combustion turbines will have a direct impact on owners of
the affected facilities. Firms or individuals that own the facilities with combustion turbines
are legal business entities that have the capacity to conduct business transactions and make
business decisions that affect the facility. The legal and financial responsibility for
compliance with a regulatory action ultimately rests with these owners, who must bear the
financial consequences of their decisions. Environmental regulations potentially affect all
sizes of businesses, but small businesses may have special problems relative to large
businesses in complying with such regulations.
The RFA of 1980 requires that special consideration be given to small entities
affected by federal regulations. The RFA was amended in 1996 by SBREFA to strengthen
the RFA's analytical and procedural requirements. Prior to enactment of SBREFA, EPA
exceeded the requirements of the RFA by requiring the preparation of a regulatory flexibility
analysis for every rule that would have any impact, no matter how minor, on any number, no
matter how small, of small entities. Under SBREFA, however, the Agency decided to
implement the RFA as written and to require a regulatory flexibility analysis only for rules
that will have a significant impact on a substantial number of small entities. In practical
terms, the amount of analysis of impacts to small entities has not changed, for SBREFA
required EPA to increase involvement of small entities in the rulemaking process.
This section investigates characteristics of businesses and government entities that
are likely to install new combustion turbines affected by this rule and provides a preliminary
screening-level analysis to assist in determining whether this rule is likely to impose a
significant impact on a substantial number of the small businesses within this industry.
The screening-level analysis employed here is a "sales test," which computes the
annualized compliance costs as a share of sales/revenue for existing companies/government
entities. Existing companies/government entities with combustion turbines are used to
provide insights into future companies/government entities that are likely to install new
turbines that are affected by the regulation.
8-1
-------
8.1 Identifying Small Businesses
As described in Section 3 of this report, the Agency has projected that approximately
218 new combustion turbines will begin operation during the 5-year period between 2002
and 2007. Of this population approximately 20 percent of the new turbines are projected to
be located at major sources. Thus approximately 44 sources would be required to comply
with the combustion turbines NESHAP. No existing combustion turbines will be effected by
the regulation. However, because it is not possible to project specific companies or
government organizations that will purchase combustion turbines in the future, the small
business screening analysis for the combustion turbine rule is based on the evaluation of
existing owners of combustion turbines. It is assumed that the existing size and ownership
distribution of combustion turbines contained in the Inventory Database is representative of
the future growth in new combustion turbines. The remainder of this section presents cost
and sales information on small companies and government organizations that own existing
combustion turbines of 1 MW or greater.
8.2 Screening-Level Analysis
Based on the Inventory Database and Small Business Administration (SB A)
definitions, 29 small entities own 51 units, which are located at 35 facilities.1 The 51 units
owned by small entities represent approximately 2.5 percent of the 2,072 units in the
Inventory Database with valid capacity information. As with the total population, not all
units owned by small entities will incur costs as a result of the regulation. However, because
we do not have the information to determine which units will be affected, we have included
all potentially affected small entities in the screening analysis, recognizing that this yields an
overestimate of the impacts on small entities.
'Public and private electric service providers are defined as small if their annual generation is less than 4 million
kWh. Local government entities that own combustion turbines are defined as small if the city population is
fewer than 50,000. In the manufacturing sector, companies are defined as small if the total employment of
the parent company is fewer than 500.
8-2
-------
Table 8-1 presents the distribution of small entities by business type.2 As is the case
with the majority of turbine operators, ownership of turbines in the Inventory Database by
small companies is concentrated in the electric services industry. In fact, 22 of small entities
are municipalities that own and operate local utility systems. The remaining entities are
either small energy (e.g., oil and gas) firms or small manufacturing companies.
To assess the potential impact of this rule on the 29 small companies and government
entities that own combustion turbines, the Agency considered the regulatory control costs
presented in Section 7. For this screening-level analysis, annual compliance costs were
defined as the annualized costs of performance tests, monitoring, recordkeeping, and
reporting imposed on each company or government entity assuming that it owned or were to
install one turbine. The total annualized cost associated with these activities is $25,119
(1998 dollars). Control costs of oxidation catalysts and CEMs were not included in the
screening analysis because the Agency estimates that only a small number units per year will
require these add-on capital costs. It is highly unlikely that small entities will be installing
170 MW turbines and would be required to install this equipment.
The results of this initial screening analysis are shown in Table 8-2. If each entity
owned or were to install one turbine, the annual compliance costs, as a percentage of annual
revenues, for small companies and government organizations would range from 0.01 to 0.46
percent. The average (median) compliance cost-to-sales ratio (CSR) is 0.11 percent. As
shown, none of the small entities are affected above the 1 percent level.
8.3 Assessment
The RFA generally requires an agency to prepare a regulatory flexibility analysis of
any rule subject to notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities. Small entities include
small businesses, small organizations, and small governmental jurisdictions.
2The Inventory Database also contains small turbines that are not included in Table 8-1. These units, frequently
referred to as "micro turbines," did not meet the 1 MW size requirements and are excluded from this rule.
Six hundred thirty-five units at 204 facilities in the Inventory Database had unit capacities under 1 MW. As
a result, a large number of small entities potentially purchasing combustion turbines in the future will not be
affected by the regulation due to the rule's size cutoff.
8-3
-------
Table 8-1. Number of Units Greater than 1 MW at Small Parents by Industry
NAICS
112
211
212
221
233
235
311
321
322
324
325
326
327
331
332
333
334
335
336
337
339
422
486
488
513
522
541
561
611
622
721
923
926
928
Unknown
Description
Animal Production
Oil and Gas Extraction
Mining (Except Oil and Gas)
Utilities
Building, Developing, and General Contracting
Special Trade Contractors
Food Manufacturing
Wood Products Manufacturing
Paper Manufacturing
Petroleum and Coal Products Manufacturing
Chemical Manufacturing
Plastics and Rubber Products Manufacturing
Nonmetallic Mineral Product Manufacturing
Primary Metal Manufacturing
Fabricated metal Product Manufacturing
Machinery Manufacturing
Computer and Electronic Product
Manufacturing
Electrical Equipment, Appliance, and
Component Manufacturing
Transportation Equipment Manufacturing
Furniture and Related Product Manufacturing
Miscellaneous Manufacturing
Wholesale Trade, Nondurable Goods
Pipeline Transportation
Support Activities for Transportation
Broadcasting and Telecommunications
Credit Intermediation and Related Activities
Professional, Scientific, and Technical Services
Administrative and Support Services
Educational Services
Hospitals
Accommodation
Administration of Human Resource Programs
Administration of Economic Programs
National Security and International Affairs
Industry Classification Unknown
TOTAL
Number of
Units Greater
than 1 MW
Number of Owned by
Units Small Parents
1
365 5
3
983 35
1
2
18
3 2
17
34
63 1
4
1
13
2
2
6
1
3 1
1
3
6
448 7
1
1
3
2
1
10
23
1
1
1
42
6
2,072 51
Number of
Small
Parents
2
22
1
1
1
2
29
8-4
-------
Table 8-2. Summary Statistics for SBREFA Screening Analysis: Recommended
Alternative
Total Number of Small Entities
Average Annual Compliance Cost per Small Entity3
29
$15,059
Number Share (%)
Entities with Sales/Revenue Data
Compliance costs are <1% of sales
Compliance costs are > 1 to 3% of sales
Compliance costs are >3% of sales
Compliance Cost-to-Sales/Revenue Ratios
Average
Median
Maximum
Minimum
29 100
0 0
0 0
0 0
0.07
0.04
0.28
0.01
"Assumes no market responses (i.e., price and output adjustments) by regulated entities.
For purposes of assessing the impacts of today's rule on small entities, small entity is
defined as:
• a small business whose parent company has fewer than 100 or 1,000 employees,
depending on size definition for the affected NAICS code, or fewer than 4 billion
kW-hr per year of electricity usage;
• a small governmental jurisdiction that is a government of a city, county, town,
school district, or special district with a population of fewer than 50,000; and
• a small organization that is any not-for-profit enterprise, which is independently
owned and operated and is not dominant in its field.
It should be noted that small entities in six three-digit NAICS codes are affected by this rule,
and the small business definition applied to each industry by NAICS code is that listed in the
SB A size standards (13 CFR 121).
8-5
-------
After considering the economic impacts of today's rule on small entities, this analysis
determines this action will not have a significant economic impact on a substantial number of
small entities. This certification is based on two analytical approaches:
• examining the hypothetical impacts on small entities based on the existing
combustion turbines inventory, and presuming that the existing mix of
combustion turbines among industries is a good approximation of the mix of new
turbines that will be installed over the next 5 years, and
• considering influences on the decision by small entities to install new turbines.
First, based on the existing combustion turbines inventory, this analysis determines that only
29 small entities out of 300 small entities would have been impacted by this rule if it had
affected existing sources. These 29 small entities own 51 affected turbines in the existing
combustion turbines inventory, which represents only 2.5 percent of the existing turbines
overall. Of these entities, 22 of these entities are small communities and seven are small
firms. None of the 29 affected small entities are estimated to have compliance costs that
exceed 1 percent of their revenues. Based on industry profit margin (i.e., profits per sales)
data for the electric services industry (92 percent of all affected turbines) shown in the
industry profile, the average return on sales for the industries is 4.6 percent. It should be
noted that a comparison of profits with costs for small communities in this analysis is valid,
for the small communities manage the electric services they own in a similar fashion to the
small firms affected by this rule. No small entity is estimated to have compliance cost to
sales of greater than the average return on sales. In addition, the rule is likely to also
increase profits at the many small firms and increase revenues for the many small
communities using turbines that are not affected by the rule as a result of the very slight
increase in market prices.
Second, another approach to examining small entity impacts is to look at the
influences on purchases of new turbines by small entities in the next 5 years. It is very likely
that the ongoing deregulation of the electric power industry across the nation will minimize
the rule's impacts on small entities. Increased competition in the electric power industry is
forecasted to decrease the market price for wholesale electric power. Open access to the grid
and lower market prices for electricity will make it less attractive for local communities to
purchase and operate new combustion turbines.3 Regardless of either analytical approach,
3The increasing trend is for local governments to engage in municipal aggregation and purchase long- and short-
term power contracts through the emerging wholesale markets (see Cliburn, 2001).
8-6
-------
the Agency concludes that this rule will not have a significant impact on a substantial
number of small entities.
Although this rule will not have a significant economic impact on a substantial
number of small entities, EPA nonetheless has tried to reduce the impact of this rule on small
entities. In this rule, the Agency is applying the minimum level of control and the minimum
level of monitoring, recordkeeping, and reporting to affected sources allowed by the CAA.
In addition, as mentioned earlier in the preamble, turbines with capacities under 1.0 MW are
not covered by this rule. This provision should reduce the level of small entity impacts.
EPA continues to be interested in the potential impacts of the rule on small entities and
welcomes comments on issues related to such impacts.
8-7
-------
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of the Matter." .
R-5
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APPENDIX A
OVERVIEW OF THE MARKET MODEL
To develop estimates of the economic impacts on society resulting from the
regulation, the Agency developed a computational model using a framework that is
consistent with economic analyses performed for other rules. This approach employs
standard microeconomic concepts to model behavioral responses expected to occur with the
regulation. This appendix describes the spreadsheet model in detail and discusses how the
Agency
• characterized the supply and demand in the energy markets,
• characterized supply and demand responses in industrial and commercial markets,
• introduced a policy "shock" into the electricity market by using control cost-
induced shifts in the supply functions of affected supply segments (new and
existing sources),
• introduced indirect shifts in market supply functions resulting from changes in
energy prices
• used a solution algorithm to determine a new with-regulation equilibrium in each
market.
A.I Energy Markets
The operational model includes five energy markets: coal, electricity (base load
energy), electricity (peak power), natural gas, and petroleum. The following sections
describe supply and demand equations the Agency developed to characterize these markets.
The data source for the price and quantity data used to calibrate the model is the Department
of Energy's Supplemental Tables to the Annual Energy Outlook 2000 (DOE, EIA, 2001).
A.I.I Supply Side Modeling
The Agency modeled the existing market supply of energy markets (Qsi) using a
single representative supplier with an upward-sloping supply curve. The Cobb-Douglas
(CD) function specification is
QSi= Aj-fo, - c, - I a;APi /' (A.1)
A-l
-------
where
Qs. = the supply of energy product i,
Aj = a parameter that calibrates the supply equation to replicate the
estimated 2005 level of production (Btu),
pi = the 2005 ($/Btu) market price for product i, and
q = direct compliance costs (electricity markets only). Supply
shifts were computed and reported in Section 6, Table 6-2.
n
Y, a Ap. = indirect effects of changes in input prices, where a is the fuel
1=1''
share, i indexes the energy market. The fuel share is allowed
to vary using a fuel switching rule using cross-price elasticities
of demand between energy sources, as described in Section 5
of the report.
esi = the domestic supply elasticity for product i.
For the electricity markets, new supply sources are characterized with a constant
marginal cost (supply) curve. In baseline, these units are willing to supply their generation
capacity at the baseline market price (P0i). With regulation, affected sources are willing to
supply their generation capacity if the new price (PH) exceeds costs (baseline + direct +
indirect):
n
PH * [Poi+ Cj + £ ajApJ (A.2)
A.I.2 Demand Side Modeling
Market demand in the energy markets (QDi) is expressed as the sum of the energy,
residential, transportation, industrial, and commercial sectors:
QDi = E qDiJ, (A.3)
A-2
-------
where i indexes the energy market and j indexes the consuming sector. The Agency modeled
the residential, and transportation sectors as single representative demanders using a simple
Cobb Douglas specification:
where p is the market price, r| is an assumed demand elasticity (actual values are presented in
Section 5, Table 5-2), and A is a demand parameter. In contrast, the energy, industrial and
commercial sectors demand is modeled as a derived demand resulting from the
production/consumption choices in agricultural, energy, mining, manufacturing, and service
industries. Changes in energy demand for these industries respond to changes in output and
fuel switching that occurs in response to changes in relative energy prices projected in the
energy markets. For each sector, energy demand is expressed as follows:
qDijl = (1 + %AQDj) • (qDijo) • FSW (A.5)
where qD is demand for energy, QD is output in the final product or service market, FSW is a
factor generated by the fuel switching algorithm, i indexes the energy market, j indexes the
market. The subscripts 0 and 1 represent baseline and with regulation conditions,
respectively.
A.2 Industrial and Commercial Markets
Given data limitations associated with the scope of potentially affected industrial and
commercial markets, EPA used an alternative approach to estimate the relative changes in
price and quantities. These measures are used to compute change in economic welfare as
described in Section A.4.
A.2.1 Compute Percentage Change in Market Price
First, we computed the change in production costs resulting from changes in the
market price of fuels (determined in the energy markets):
n
%ACj = £ a;APi , (A.6)
i= 1
A-3
-------
where a is the fuel share1, i indexes the energy market, and j indexes the industrial or
commercial market. We use the results from equation A. 6 and the market supply and
demand elasticities to compute the change in market price2:
(A.7)
A.2.2 Compute Percentage Change in Market Quantity
Using the percentage change in the price calculated in Equation A.7 and assumptions
regarding the market demand elasticity, the relative change in quantity was computed. For
example, in a market where the demand elasticity is assumed to be -1 (i.e., unitary), a
1 percent increase in price results in a 1 percent decrease in quantity. This change was then
input into equation A.5 to determine energy demand.
A.3 With-Regulation Market Equilibrium Determination
Market adjustments can be conceptualized as an interactive feedback process.
Supply segments face increased production costs as a result of the rule and are willing to
supply smaller quantities at the baseline price. This reduction in market supply leads to an
increase in the market price that all producers and consumers face, which leads to further
responses by producers and consumers and thus new market prices, and so on. The new
with-regulation equilibrium is the result of a series of iterations in which price is adjusted
and producers and consumers respond, until a set of stable market prices arises where total
market supply equals market demand (i.e., Qs = QD) in each market. Market price
adjustment takes place based on a price revision rule that adjusts price upward (downward)
by a given percentage in response to excess demand (excess supply).
The algorithm for determining with-regulation equilibria can be summarized by
seven recursive steps:
lrThe fuel share is allowed to vary using a fuel switching rule using cross-price elasticities of demand between
energy sources, as described in Section 5.
2The approach is based on a mathematical model of tax incidence analysis decribed in Nicholson (1998) pages
444-445.
A-4
-------
1. Impose the control costs on electricity supply segments, thereby affecting their
supply decisions.
2. Recalculate the market supply in the energy markets. Excess demand exists.
3. Determine the new energy prices via a price revision rule.
4. Recalculate energy market supply.
5. Account for fuel switching given new energy prices. Solve for new equilibrium
in final product and service market.
6. Compute energy demand.
7. Compare supply and demand in energy markets. If equilibrium conditions are not
satisfied, go to Step 3, resulting in a new set of energy prices. Repeat until
equilibrium conditions are satisfied (i.e., the ratio of supply to demand is
arbitrarily close to one).
A.4 Computing Social Costs
In the energy markets, consumers(residential and transportation) and producer
surplus were calculated using standard methods based on the price and quantity before and
after regulation. In the industrial and commercial markets, however, there is no easily
defined price or quantity due to the wide variety of products that fall under each sector (i.e.
NAICs code). Therefore, methods of calculating consumer and producer surplus are defined
based on relative changes in price and quantity and total industry sales rather than on the
price and quantity directly. The following sections describe how we derive welfare estimates
for these markets.
A.4.1 Change in Consumer Surplus
If price and quantities were available, a linear approximation of the change in
consumer surplus can be calculated using the following formula:
ACS = -[(AP) Q0 -0.5(AQ) (AP)], (A.8)
where Q0 denotes the baseline quantity. Given the model only estimates relative changes in
price and quantity for each industrial/commercial market, changes in consumer surplus were
calculated using these data and total revenue by NAICS code as shown below:
A-5
-------
ACS = -[(AP) Qt - 0.5 (AQ) (AP)] (Pt QJ/^ Qt)
ACS = -[%AP - 0.5 (%AP) (%AQ)] (Pt Qt). (A.9)
A.4.2 Change in Producer Surplus
If price and quantities were available, a linear approximation could also be used to
compute the change in producer surplus:
APS ^[((CC/Qi) - APXQi - AQ)]+ 0.5 [(CC/Qi - AP) (AQ)], (A.10)
where CC/Qj equals the per-unit "cost-shifter" of the regulation. Again, we transform this
equation into one that relies only on percentage changes in price and quantity, total revenue,3
and compliance costs:
APS = - [((CC/QJ - AP)(Qt - AQ)]+ 0.5 [((CC/QJ - AP)(AQ)](P1 Q^/fP, Qt)
APS = - [(% cost shift - %AP)(1 - %AQ)+ 0.5 (% cost shift - %AP )(%AQ)][PX QJ
APS = - [% cost shift- %AP ][1 - 0.5(%AQ)][TR], (A.11)
Multiplying price and quantity in an industry yields total industry revenue. The U.S. Census Bureau provides
shipment data for the NAICs codes included in the economic model.
A-6
-------
APPENDIX B
ASSUMPTIONS AND SENSITIVITY ANALYSIS
In developing the economic model to estimate the impacts of the stationary
combustion turbine NESHAP, several assumptions were necessary to make the model
operational. This appendix lists and explains the major model assumptions and describes
their potential impact on the analysis results. Sensitivity analyses are presented for numeric
assumptions.
Assumption: The domestic markets for energy are perfectly competitive.
Explanation: Assuming that the markets for energy are perfectly competitive implies that
individual producers are not capable of unilaterally affecting the prices they receive for their
products. Under perfect competition, firms that raise their price above the competitive price
are unable to sell at that higher price because they are a small share of the market and
consumers can easily buy from one of a multitude of other firms that are selling at the
competitive price level. Given the relatively homogeneous nature of individual energy
products (petroleum, coal, natural gas, electricity), the assumption of perfect competition at
the national level seems to be appropriate.
Possible Impact: If energy markets were in fact imperfectly competitive, implying that
individual producers can exercise market power and thus affect the prices they receive for
their products, then the economic model would understate possible increases in the price of
energy due to the regulation as well as the social costs of the regulation. Under imperfect
competition, energy producers would be able to pass along more of the costs of the
regulation to consumers; thus, consumer surplus losses would be greater, and producer
surplus losses would be smaller in the energy markets.
Assumption: Base load energy and peak power represent 80 percent and 20 percent,
respectively, of the total cost of electricity production.
Explanation: With deregulation, it is increasingly common for base load energy and peak
power to be traded as different commodities. This economic model segments the electricity
market into these separate markets. However, no production cost or sales data are currently
available to partition the electricity market into base load and peak power markets. The
80/20 percent was obtained from discussions with industry experts.
B-l
-------
Sensitivity Analysis: Table B-l shows how estimated economic impacts change as the share
of base load versus peak power costs varies.
Table B-l. Sensitivity Analysis: Base Load and Peak Power Markets' Share of
Electricity Production Costs ($106)
Base Load = 70%
Peak = 30%
Base Load = 80 % Base Load = 90 %
Peak = 20% Peak =10%
Change in producer
surplus
Change in consumer
surplus
Change in social welfare
870.4
-878.6
-8.1
852.5
-860.3
-7.8
835.2
-842.7
-7.5
Assumption: The elasticity of supply in the base load and peak power electricity
markets for existing sources is approximately 0.75 and 0.38, respectively.
Explanation: The price elasticity of supply in the electricity markets represents the
behavioral responses from existing sources to changes in the price of electricity. However,
there is no consensus on estimates of the price elasticity of supply for electricity. This is in
part because, under traditional regulation, the electric utility industry had a mandate to serve
all its customers and utilities were compensated on a rate-based rate of return. As a result,
the market concept of supply elasticity was not the driving force in utilities' capital
investment decisions. This has changed under deregulation. The market price for electricity
has become the determining factor in decisions to retire older units or to make higher cost
units available to the market.
Sensitivity Analysis: Table B-2 shows how the economic impact estimates vary as the
elasticity of supply in the electricity markets varies.
Table B-2. Sensitivity Analysis: Elasticity of Supply in the Electricity Markets
Change in producer surplus
Change in consumer surplus
Change in social welfare
ES = -25%
942.4
-951.2
-8.8
Base Case
852.5
-860.3
-7.8
ES = + 25%
778.8
-785.8
-7.0
B-2
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Assumption: The domestic markets for final products and services are all perfectly
competitive.
Explanation: Assuming that these markets are perfectly competitive implies that the
producers of these products are unable to unilaterally affect the prices they receive for their
products. Because the industries used in this analysis are aggregated across a large number
of individual producers, it is a reasonable assumption that the individual producers have a
very small share of industry sales and cannot individually influence the price of output from
that industry.
Possible Impact: If these product markets were in fact imperfectly competitive, implying
that individual producers can exercise market power and thus affect the prices they receive
for their products, then the economic model would understate possible increases in the price
of final products due to the regulation as well as the social costs of the regulation. Under
imperfect competition, producers would be able to pass along more of the costs of the
regulation to consumers; thus, consumer surplus losses would be greater, and producer
surplus losses would be smaller in the final product markets.
Assumption: The elasticity of supply in final product markets.
Explanation: The final product markets are modeled at the two-, and three-digit NAICS
codes level to operationalize the economic model. Because of the high level of aggregation,
elasticities of supply and demand estimates are not often available in the literature. The
elasticities of supply and demand in the final product markets primarily determine the
distribution of economic impacts between producers and consumers.
Sensitivity Analysis: Table B-3 shows how the economic impact estimates vary as the
supply and demand elasticities in the final product markets vary.
Table B-3. Sensitivity Analysis: Supply and Demand Elasticities in the Final Product
Markets
Change in producer surplus
Change in consumer surplus
Change in social welfare
ES = -25%
ED = -25%
853.0
-860.9
-7.8
ES = Base Case
ED = Base Case
852.5
-860.3
-7.8
ES = +25%
ED = +25%
851.9
-859.8
-7.8
B-3
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Assumption: The amount of energy (in terms of Btus) required to produce a unit of
output in the final product markets remains constant as output changes and prices.
Explanation: The importance of this assumption is that when output in the final product
markets changes as a result of a change in energy prices, it is assumed that the amount of fuel
used changes in the same proportion as output, although the distribution of fuel usage among
fuel types may change due to fuel switching. This change in the demand for fuels feeds into
the energy markets and affects the equilibrium price and quantity in the energy markets.
Possible Impact: For example, fuel usage per unit output may change if the price of energy
increases because of increased energy efficiency. National energy-efficiency trends are
included in the model through projected Btu consumption (i.e., Btu consumption is projected
to grow more slowly than output). However, if the regulation leads to increased energy
efficiency because of higher fuel prices, this will result in a smaller economic impact than
the model results presented in Section 6 indicate.
Assumption: Sensitivity to Fuel Switching.
Sensitivity Analysis: Table B-4 shows how the economic impact estimates vary as fuel-
switching is turned on or off in the model.
Table B-4. Sensitivity Analysis: Own- and Cross-Price Elasticities Used to Model Fuel
Switching
Base Case Without Fuel Switching
Change in producer surplus 852.5 194.2
Change in consumer surplus -860.3 -208.6
Change in social welfare -7.8 -14.3
B-4
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
1. REPORT NO.
EPA-452/R-03-014
4. TITLE AND SUBTITLE
Economic Impact Analysis of the
NESHAP: Final Report
2
Final Stationary Combustion Turbines
7. AUTHOR(S)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
RTI International
Center for Regulatory Economics and Policy Research, Hobbs Bldg.
Research Triangle Park, NC 27709
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 2771 1
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
August 2003
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
RTI Project Number 7647-004-385
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-D-99-024
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report evaluates the economic impacts of the Final Stationary Combustion Turbines NESHAP. The social
costs of the rule are estimated by incorporating the expected costs of compliance in a partial equilibrium
model and projecting the market impacts. The report also provides the screening analysis for small business
impacts.
17.
a. DESCRIPTORS
economic impacts
small business impacts
social costs
18. DISTRIBUTION STATEMENT
Release Unlimited
KEY WORDS AND DOCUMENT ANALYSIS
b. IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Economic Impact Analysis
Regulatory Flexibility Analysis
19. SECURITY CLASS (Report)
Unclassified
20. SECURITY CLASS (Page)
Unclassified
c. COSATI Field/Group
21. NO. OF PAGES
156
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE
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United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-03-014
Environmental Protection Air Quality Strategies and Standards Division August 2003
Agency Research Triangle Park, NC
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