DOE/EIA-0348(2001)

Electric Power Annual 2001

March 2003

Energy Information Administration

Office of Coal, Nuclear, Electric and Alternate Fuels

U.S. Department of Energy 

Washington, DC 20585

This report is available on the Web at:

http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html

This report was prepared by the Energy Information Administration, the independent statistical and analytical agency 

within the U.S. Department of Energy. The information contained herein should be attributed to the Energy Information 

Administration and should not be construed as advocating or reflecting any policy of the Department of Energy or any 

other organization.
ii Energy Information Administration/Electric Power Annual 2001

Contacts

Questions regarding this report may be directed to: 

Energy Information Administration, EI-53 

Electric Power Division

U.S. Department of Energy

1000 Independence Avenue, S.W.

Washington, D.C. 20585-0650

Questions of a general nature should be directed to:

Robert Schnapp (202/287-1787)

Director, Electric Power Division;

Internet e-mail: robert.schnapp@eia.doe.gov

Dr. Suraj P. Kanhouwa (202/287-1919) 

Chief, Electric Market Assessment

Internet e-mail: suraj.kanhouwa@eia.doe.gov

Contributions to this report were provided by the following 

employees of the Electric Power Division (fax 

number 202/287-1946):

Publication Coordinator:

Roger L. Sacquety (202/287-1745),

Internet e-mail: roger.sacquety@eia.doe.gov;

Lead Coordinators:

Elsie Bess (202/287-1730)

Internet e-mail: elsie.bess@eia.doe.gov;

Linda Bromley (202/287-1748)

Internet e-mail: linda.bromley@eia.doe.gov;

Dean Fennell (202/287-1744)

Internet e-mail: dean.fennell@eia.doe.gov;

Generation

Melvin E. Johnson (202/287-1754)

Internet e-mail: melvin e.johnson@eia.doe.gov;

Channele Carner (202/287-1928)

Internet e-mail: channele.carner@eia.doe.gov;

Capacity

Kenneth McClevey (202/287-1732)

Internet e-mail: kenneth.mcclevey@eia.doe.gov;

Betty Williams (202/287-1927)

Internet e-mail: betty.williams@eia.doe.gov;

Demand, Capacity Resources, and Capacity Margins

John Makens (202/287-1749)

Internet e-mail: john.makens@eia.doe.gov;

Fuel

Melvin E. Johnson (202/287-1754)

Internet e-mail: melvin e.johnson@eia.doe.gov;

Channele Carner (202/287-1928)

Internet e-mail: channele.carner@eia.doe.gov;

Emissions

Natalie Ko (202/287-1957)

Internet e-mail: natalie.ko@eia.doe.gov;

Trade

Rodney Dunn (202/287-1676)

Internet e-mail: rodney.dunn@eia.doe.gov;

Retail Customers, Sales, and Revenue

Rodney Dunn (202/287-1676)

Internet e-mail: rodney.dunn@eia.doe.gov;

Revenue and Expense Statistics

Karen McDaniel (202/287-1754)

Internet e-mail: karen.mcdaniel@eia.doe.gov;

Demand-Side Management

Rodney Dunn (202/287-1676)

Internet e-mail: rodney.dunn@eia.doe.gov;

Quality

The Energy Information Administration is committed to quality products and quality service. To ensure that this report meets 

the highest standards for quality, please forward your comments or suggestions about this publication to Roger L. Sacquety at 

(202/287-1745), or Internet e-mail: roger.sacquety@eia.doe.gov.

For general inquiries about energy data, please contact the National Energy Information Center 

at (202/586-8800). Internet users may contact the center at: infoctr@eia.doe.gov.
Energy Information Administration/Electric Power Annual 2001 iii

Preface

The Electric Power Annual 2001 presents a summary 

of electric power industry statistics at the national

level. The objective of the publication is to provide 

industry decisionmakers, government policymakers,

analysts, and the general public with historical data 

that may be used in understanding U.S. electricity 

markets. The Electric Power Annual, is prepared by 

the Electric Power Division; Office of Coal, Nuclear, 

Electric and Alternate Fuels; Energy Information

Administration (EIA); U.S. Department of Energy.

In the private sector, the majority of the users of the 

Electric Power Annual, are researchers, analysts, and 

individuals with policymaking and decision-making 

responsibilities in electric utility companies or other 

energy concerns. Other users include financial and 

investment institutions, economic development

organizations, special interest groups, lobbyists,

electric power associations, and the news media.

In the public sector, users include the U.S. Congress, 

Federal government agencies, State governments and 

public service commissions, and local governments.

Data in this report can be used in analytic studies to 

evaluate new legislation and are used by analysts,

researchers, statisticians, and other professionals with 

regulatory, policy, and program responsibilities for

Federal, State, and local governments.

The Electric Power Annual, presents an overview of 

the electric power industry in the United States and a 

summary of the key statistics for the reporting year. 

The chapters present information and data in each 

specific area: generation; capacity; demand, capacity 

resources, and capacity margins; emissions; trade;

retail customers, sales, and revenues; revenue and

expense statistics; and demand-side management. 

Monetary values in this publication are expressed in 

nominal terms.

Data published in the Electric Power Annual, are 

compiled from six forms filed annually by electric 

utilities and deregulated electric power producers with 

the EIA and five forms filed with other government 

organizations. The EIA forms are described in detail 

in the "Technical Notes."
iv Energy Information Administration/Electric Power Annual 2001

Contents

Electric Power Industry 2001: Year in Review......................................................................................................................................................1

Chapter 1. Generation..............................................................................................................................................................................................11

Chapter 2. Capacity .................................................................................................................................................................................................15

Chapter 3. Demand, Capacity Resources, and Capacity Margins...................................................................................................................21

Chapter 4. Fuel .........................................................................................................................................................................................................27

Chapter 5. Emissions...............................................................................................................................................................................................33

Chapter 6. Trade.......................................................................................................................................................................................................35

Chapter 7. Retail Customers, Sales, and Revenues............................................................................................................................................37

Chapter 8. Revenue and Expense Statistics.........................................................................................................................................................45

Chapter 9. Demand-Side Management ................................................................................................................................................................53

Appendices

A. Technical Notes.........................................................................................................................................................................................59

B. Estimating and Presenting Power Sector Fuel Use.............................................................................................................................75

Glossary ......................................................................................................................................................................................................................81
Energy Information Administration/Electric Power Annual 2001 v

Tables

Pages

Table ES. Electric Power Industry - Summary Statistics for the United States, 1990 through 2001....................................................8

Chapter 1. Generation......................................................................................................................................................................................... 11

Table 1.1. Net Generation by Energy Source by Type of Producer, 1990 through 2001 ........................................................................12

Table 1.2. Useful Thermal Output by Energy Source, by Combined Heat and Power Producers, 1990 through 2001.....................14

Chapter 2. Capacity ............................................................................................................................................................................................. 15

Table 2.1. Existing Net Summer Capacity by Energy Source and Producer Type, 1990 through 2001...............................................16

Table 2.2. Existing Capacity by Energy Source, 2001 ..................................................................................................................................18

Table 2.3. Existing Capacity by Producer Type, 2001 ..................................................................................................................................18

Table 2.4. Planned Nameplate Capacity Additions by Energy Source, 2002 through 2006...................................................................18

Table 2.5. Planned Capacity Additions by Energy Source, 2002-2006......................................................................................................19

Table 2.6. Capacity Additions and Retirements by Energy Source, 2001 .................................................................................................20

Chapter 3. Demand, Capacity Resources, and Capacity Margins.......................................................................................................... 21

Table 3.1. Noncoincident Peak Load, Actual and Projected by North American Electric Reliability Council Region, 1997 

through 2006......................................................................................................................................................................................22

Table 3.2. Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Council 

Region, Summer, 1990 through 2001............................................................................................................................................23

Table 3.3. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by North American Electric 

Reliability Council Region, Summer, 2001 through 2006.........................................................................................................24

Table 3.4. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by North American Electric 

Reliability Council Region, Winter, 2001 through 2006 ...........................................................................................................25

Chapter 4. Fuel ....................................................................................................................................................................................................... 27

Table 4.1. Consumption of Fossil Fuels for Electricity Generation by Type of Power Producer, 1990 through 2001......................28

Table 4.2. Consumption of Fossil Fuels for Useful Thermal Output by Type of Combined Heat and Power Producer, 1990 

through 2001......................................................................................................................................................................................29

Table 4.3. Consumption of Fossil Fuels for Electricity Generation and for Useful Thermal Output, 1990 through 2001 ...............30

Table 4.4. End-of-Year Stocks of Coal and Petroleum, by Type of Producer, 1990 through 2001 ......................................................30

Table 4.5. Receipts, Average Cost, and Quality of Fossil Fuels at Electric Utilities, 1990 through 2001...........................................31

Table 4.6. Receipts and Quality of Coal Delivered to Electric Utilities, 1990 through 2001.................................................................31

Table 4.7. Average Quality of Fossil Fuels Burned at Electricity Generators, 1990 through 2001 ......................................................32

Chapter 5. Emissions............................................................................................................................................................................................. 33

Table 5.1. Emissions, 1990 through 2001.......................................................................................................................................................34

Table 5.2. Number and Capacity of Fossil-Fueled Steam-Electric Generators with Environmental Equipment, 1990 through 

2001.....................................................................................................................................................................................................34

Table 5.3. Average Flue Gas Desulfurization Costs, 1990 through 2001..................................................................................................34

Chapter 6. Trade .................................................................................................................................................................................................... 35

Table 6.1. Electric Power Industry - Purchases, 1990 through 2001 ..........................................................................................................36

Table 6.2. Electric Power Industry - Sales for Resale, 1990 through 2001 ...............................................................................................36

Table 6.3. Electric Power Industry - U.S. Electricity Imports from and Electricity Exports to Canada and Mexico, 1990 through 

2001.....................................................................................................................................................................................................36

Chapter 7. Retail Customers, Sales, and Revenues ...................................................................................................................................... 37

Table 7.1. Number of Ultimate Customers Served by Sector, by Provider, 1990 through 2001...........................................................38

Table 7.2. Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 1990 through 2001 ..........................................40

Table 7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 1990 through 2001 ...............42

Table 7.4. Average Revenue per Kilowatthour from Retail Sales to Ultimate Customers by Sector, by Provider, 1990 through 

2001.....................................................................................................................................................................................................44
vi Energy Information Administration/Electric Power Annual 2001

Chapter 8. Revenue and Expense Statistics.................................................................................................................................................... 45

Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1990 through 2001..........................50

Table 8.2. Average Operating Expenses for Major U.S. Investor-Owned Electric Utilities, 1990 through 2001 ..............................50

Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With Generation Facilities), 1990 

through 2001......................................................................................................................................................................................51

Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without Generation Facilities), 

1990 through 2001............................................................................................................................................................................51

Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1990 through 2001....................................52

Table 8.6. Revenue and Expense Statistics for Major U.S. Cooperative Borrower Owned Electric Utilities, 1990 through 2001 .52

Chapter 9. Demand-Side Management............................................................................................................................................................ 53

Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1990 through 2001............................54

Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1990 through 2001 .....................................54

Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1990 through 2001 .............................54

Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1990 through 2001...........................................................55

Table 9.5. Demand-Side Management Program Incremental Effects by Sector, 1990 through 2001...................................................55

Table 9.6. Demand-Side Management Program Energy Savings, 1990 through 2001............................................................................56

Table 9.7. Demand-Side Management Program Direct and Indirect Costs, 1990 through 2001...........................................................56

Appendices ............................................................................................................................................................................................................. 57

Table A1. Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide Emission Factors...............................................................................70

Table A2. Carbon Dioxide Emission Factors for Coal by Rank and State of Origin ...............................................................................72

Table A3. Sulfur Dioxide and Nitrogen Oxide Factors for Specific Fuels ................................................................................................73

Table A4. Nitrogen Oxide Reduction Factors.................................................................................................................................................74

Table A5. Unit-of-Measure Equivalents..........................................................................................................................................................74

Illustrations

Figure 1.1. U.S. Electric Power Industry Net Generation by State, 2001............................................................................................13

Figure 2.1. U.S. Electric Power Industry Existing Capacity by State, 2001 .......................................................................................17

Figure 7.1. U.S. Electric Power Industry Total Ultimate Customers by State, 2001.........................................................................39

Figure 7.2. U.S. Electric Power Industry Total Retail Sales by State, 2001 .......................................................................................41

Figure 7.3. U.S. Electric Power Industry Total Revenues by State, 2001 ...........................................................................................43

Figure 7.4. U.S. Electric Power Industry Average Revenue per Kilowatthour by State, 2001........................................................45

Figure 7.5. U.S. Electric Power Industry Residential Average Revenue per Kilowatthour by State, 2001...................................46

Figure 7.6. U.S. Electric Power Industry Commercial Average Revenue per Kilowatthour by State, 2001.................................47

Figure 7.7. U.S. Electric Power Industry Industrial Average Revenue per Kilowatthour, 2001.....................................................48
Energy Information Administration/Electric Power Annual 2001 1

Electric Power Industry 2001: Year in Review

Introduction

The pace of restructuring the electric power industry 

slowed significantly in 2001. Market volatility and 

associated price increases in California during the

2000-2001 period caused serious financial problems 

for the investor-owned electric utilities in the State. 

The financial turmoil was capped by the bankruptcy 

filing of Pacific Gas and Electric Company and the 

near bankruptcy of Southern California Edison

Company.

As the creditworthiness of the investor owned electric 

utilities deteriorated, the State of California stepped in 

to buy power at high prices. This intervention created 

financial problems for the State and imposed burdens 

that are likely to last for a number of years in the

future. In addition, electricity customers in the State 

will be required to pay rates that are significantly 

higher than those prevailing in the prior periods. As a 

result of the California situation, other States in the 

Northwest also experienced varying degrees of

economic impacts as power prices increased regionally.

The bankruptcy of Enron Corporation in the midst of 

allegations of financial improprieties contributed to

charges that the power markets could be manipulated 

and that the regulatory authorities lacked the tools to 

monitor such abuses in a timely fashion. Overall, the 

above events have, at least temporarily, led to an 

erosion of confidence in the efficacy of competitive 

power markets. As a result, nearly half the States have 

adopted a go-slow approach. Others like New Mexico 

and Oklahoma have delayed implementation. 

California, which spearheaded the movement toward 

deregulation, has stepped back. By the end of 2001, 

restructuring had either been delayed or suspended in 8 

States that previously enacted legislation or issued

regulatory orders for its implementation (Figure 1). 

Eighteen other States that had ongoing investigations 

either at the legislative or regulatory levels in the year 

2000 reported no such activity in 2001.

Figure 1: Status of State Electric Utility 

Deregulation Activity, as of January 2002

1These States have either enacted enabling legislation or issued a regulatory order to implement retail access. Retail access is either currently available to all or some 

customers or will soon be available. Some States are currently running pilot programs, and they will begin to implement retail access in the near future: Arizona, 

Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, 

Rhode Island, Texas, and Virginia. 

2These States have either passed l egislation or issued regulatory orders to delay implementing retail access: Arkansas, Montana, Nevada, New Mexico, Oklahoma, and 

Oregon. Although West Virginia passed legislation that approved the PSC's plan to restructure and implement retail access, the process is delayed until a bill for tax 

reform is enacted. 

3The CPUC ordered suspension of direct retail access. 

4These States have not enacted enabling legislation to restructure the electric power industry or implement retail access: Alabama, Alaska, Colorado, Florida, Georgia, 

Hawaii, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Carolina, North Dakota, South Carolina, South 

Dakota, Tennessee, Utah, Vermont, Washington, Wisconsin, and Wyoming.

Source: Energy Information Administration.
2 Energy Information Administration/Electric Power Annual 2001

As a result of the financial turmoil in the power sector, 

commitments and planning for new plants began to 

slow in 2001. Infrastructure investments including 

additions to transmission capability have not kept pace 

with increases in demand for power and trading

requirements. These developments retard the growth 

of a fully competitive market for power.

The electric power industry is and will continue to be 

in a state of flux in the foreseeable future. FERC’s 

efforts to create a competitive market for power

nationally will hinge on the critical support it receives 

from the States. Changes will continue to emerge 

albeit at a slower pace.

The following is a summary of statistics gathered on 

the U.S. electric power industry for 2001.

Industry Profile

The electric power industry in the United States is 

composed of traditional electric utilities, and

nontraditional participants, including energy service

providers, power marketers, and independent power

producers (IPP). Electric utilities include investorowned electric utilities, municipal and State utilities, 

Federal electric utilities, and rural electric cooperatives. 

A utility is defined as a corporation, person, agency, 

authority, or other legal entity or instrumentality 

aligned with distribution facilities for delivery of

electric energy for use primarily by the public. In total, 

there are more than 3,100 electric utilities in the United 

States (Figure 2).

Figure 2: Composition of the Electric 

Utility Industry in the United States, 2001

2009

894

240

9

2012

888

232

9

0

500

1,000

1,500

2,000

2,500

Publicly Owned Cooperative Investor-Owned Federal

2000 2001

Source: Energy Information Administration, Form 

EIA-861, “Annual Electric Power Industry Report."

Historically, the most influential of these entities have 

been the vertically integrated investor-owned utility 

companies that provided generation, transmission,

distribution, and retail energy services for all customers 

in a designated service territory. However, the industry 

has continued to change from this vertically integrated 

structure to a functionally unbundled industry with a 

competitive market for power generation. As a result, 

there were 128 active power marketers operating by the 

end of 2001. 

Electric power that is sold to end users may be

generated by electricity generators that are traditional 

electric utilities, by independent power producers, or 

by combined heat and power producers. An

independent power producer is an entity defined as a 

corporation, person, agency, authority, or other legal 

entity or instrumentality that owns or operates facilities 

for the generation of electricity for use primarily by the 

public, and is not an electric utility. Combined heat 

and power producers (typically industrial cogenerators) 

are plants designed to produce both heat and electricity 

from a single heat source. There are approximately 

2,800 unregulated independent power producers or

combined heat and power plants in the United States.

Generation

In 2001, the total U.S. net generation of electricity was 

3,734 billion kilowatthours, 2-percent lower than 2000. 

This decrease is unusual in that net U.S. generation has 

historically increased from year to year. This is only 

the second time in over 50 years that there has been a 

decrease in net generation (Figure 3). Demand

reductions caused by an economic slowdown explain 

somewhat corresponding declines in generation. 

Because nuclear and coal units are typically operated 

as base load generators (the generating equipment

normally operated to serve loads on an around-theclock basis), they contribute a major share of electric 

generation. In 2001, coal plants accounted for 51 

percent of generation and nuclear plants for 21 percent 

of generation for a total of 72 percent of power supply, 

although coal and nuclear plants provide just under 50 

percent of total capacity.

In contrast, natural gas and petroleum units typically 

run in cycling (load-following) service or as peaking 

capacity for short periods of time to meet the highest 

daily loads. Consequently, natural gas and petroleum 

plants account for only 20 percent of generation,

although they make up 38 percent of total capacity.

While net generation dropped for the industry overall, 

the independent power producers’ share of net

generation was up sharply in 2001. This is a result of 

both new plant construction by independent producers 

and plant divestitures by investor owned utilities. In 

contrast to IPP electric–only production, net generation 
Energy Information Administration/Electric Power Annual 2001 3

by combined heat and power producers has remained 

fairly constant from 1996 through 2001 at 8 to 9 

percent of the total net generation.

Figure 3: Total Net Generation Compared to 

Total Retail Sales, 1990 through 2001

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Million Megawatthours

Electric Utilities IPP Facilities CH&P Facilities Sales

Sources: Energy Information Administration, Form 

EIA-861, “Annual Electric Power Industry Report," 

and Form EIA -906, "Power Plant Report." 

Capacity

In 2001, total net summer generating capacity was 848 

gigawatts, up 4.5 percent from the year 2000. Large 

increases in natural gas capacity, which increased by 

31 percent to 126 gigawatts, drove most of this

increase in capacity. 

The total amount of U.S. net summer capacity for 2001 

of coal-fired capacity is more than two times higher 

than the capacity for any other single energy source 

(Figure 4). However, most “dual fuel” generating

plants consume natural gas most of the time and use oil 

as a back-up source. When the aggregate capacity of 

these dual fuel plants is added to the natural gas-only 

capacity, the total for natural gas has a 33-percent share 

of the total U.S. net summer capacity for 2001. The 

2001 net summer capacity for “other renewables” fuel 

sources is dominated by biomass and municipal solid 

waste generating plants. Contributions by these

sources increased 4 percent over the year 2000,

resulting in an additional 608 MW of net summer 

capacity from this fuel source. 

Figure 4: Share of U.S. Net Summer 

Capacity by Energy Source, Year-End 2001

0

50

100

150

200

250

300

350

Coal

Gas

Dual Fuel

Nuclear

Hydro

Oil

Other Renewables

Gigawatts

37%

14.8%

18.1%

11.6% 11.6%

4.7%

1.9%

Source: Energy Information Administration, Form

EIA-860, "Annual Electric Generator Report."

The aggregate annual capacity factor is an index that 

shows the average production by a group of generating 

facilities as a percent of the maximum possible

production over the year 2001. At year-end 2001, 

nuclear plant capacity factors were at 89.4 percent 

(Figure 5) and coal plant capacity factors were at 73.4 

percent, consistent with base load operation. In

contrast, gas and oil units had, respectively, capacity 

factors of only 34.4 percent and 27.1 percent, reflecting 

load-following and peaking operations. Hydroelectric 

generators had an average capacity factor of only 17.2 

percent. 

Figure 5: Average Capacity Factor by 

Energy Source, 2001

89.4%

73.4%

34.4%

27.1%

17.2%

6.2%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Nuclear Coal Gas Petroleum Hydro Other

Source: Energy Information Administration, Form

EIA-906, "Power Plant Report." 

Demand, Capacity Resources, and 

Capacity Margins

Available Capacity Margin is defined as the difference 

between Available Resources and Net Internal

Demand, expressed as a percent of Available

Note: Net Summer capacity of 0.2 percent from blast furnace gas, propane gas, and other manufactured

and waste gases derived from fossil fuels is not included. 
4 Energy Information Administration/Electric Power Annual 2001

Resources. This is the capacity available to cover 

random factors such as forecast outages of generating

equipment, demand forecast errors, weather extremes, 

and capacity service schedule slippage. Variations 

from capacity margins in regional tables may exist due 

to differences in reporting methods for purchases and 

sales. Summer capacity margins in the contiguous

United States declined over the past 12 years by over 7 

percent. Despite a brief increase in 1999 and 2000, the 

downward trend has reemerged with nationwide

capacity margins at 14.5 percent in 2001 (Figure 6). 

Although net internal demand has increased an average 

of 2 percent per year over the period from 1999 to 

2001, capacity resources have only increased

approximately 1 percent a year in the corresponding 

time period. 

21.6

20.9 20.5 19.9

18.7 18.9

17.5

16.2

14.3 14.6

15.7

14.5

0

5

10

15

20

25

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Figure 6: Summer Capacity Margins, 

Contiguous U.S., 1990-2001 

Percent

Source: Energy Information Administration, Form

EIA-411, "Coordinated Bulk Power Supply Program 

Report."

According to the North American Reliability Council 

(NERC), a reduction in capacity margins in 2001 is 

primarily due to variances in qualitative assumptions 

incorporated in the estimation process for that year. As 

an example, drought-induced restrictions on

hydroelectric generating capacity in the Northwest and 

South played a critical role. Other influencing factors 

for the 2001 estimates include the then prevailing 

concerns with respect to the availability and adequacy

of natural gas supplies and the higher-than-usual 

outages in the West and South. Attempts to secure 

suitable interconnection and transmission access

agreements were frustrated in varying degrees by siting 

and permitting hurdles, difficulties in financing due to 

market uncertainties, and fuel supply adequacy issues.

Fuel

Consumption of coal for electricity generation was

down 2.2 percent from 2000, going from 995 to 973 

million short tons in 2001. Use of petroleum for 

electricity generation increased 13.9 percent, going 

from 195 million barrels in 2000 to 222 million barrels 

in 2001. Consumption of natural and other gases used 

for electricity generation increased only 0.7 percent to 

6 trillion cubic feet in 2001. 

In 2001, the average cost of natural gas to electric 

utilities increased 4.3 percent and the average cost of 

coal increased 2.6 percent. However, these average 

prices do not reflect the extraordinary volatility in the 

spot markets for natural gas and coal in 2001. For 

example, the spot price for natural gas at the Henry 

Hub trading point exceeded 9.00 per million Btu in 

January 2001, but was under 3.00 per million Btu by 

Fall. Coal spot prices were also very high at the

beginning of 2001 and moderated as the year

progressed. The high price of spot market natural gas 

for much of the year may be one factor explaining why 

natural gas generation increased only slightly even as 

many new natural gas-fired plants entered commercial 

operation.

The total consumption of these fuels and others

resulted in the production of 3,734 billion

kilowatthours (Figure 7). Approximately 1,900 billion 

kilowatthours, over half of the total net generation, was 

produced by coal-fired generators. Nuclear and gasfired generation accounted for most of the balance with 

21 and 17 percent, respectively, of the total net

generation.

Figure 7: U.S. Net Generation by Energy 

Source, 2001

1,903

769

630

208 127 79

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Coal Nuclear Gas 1 Hydroelectric Petroleum Other Renewables

Million Megawatthours

1 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels resulting 

in net generation of 13,767 thousand megawatthours are not included.

An additional 4,254 thousand megawatthours, not shown here, were generated from “Other” energy sources.

Source: Energy Information Administration, Form

EIA-906, "Power Plant Report." 
Energy Information Administration/Electric Power Annual 2001 5

Emissions

Electricity generators must adhere to rigorous

environmental regulations in the United States. Many 

have invested billions of dollars in emissions reduction 

technologies to meet these requirements. Nonetheless, 

fossil fuel combustion continues to be the largest single 

source of industrial air emissions according to the 

United States Environmental Protection Agency1.

Carbon dioxide emissions have continued to rise

steadily since 1990 resulting in a 23-percent increase in 

2001 over 1990 levels (Figure 8). On the other hand, 

nitrogen oxides have steadily decreased in the 1990-

2000-time period, with 2001 levels 11-percent less than 

they were in 1990. Despite rising during 1996-1998 

and 2001, sulfur dioxide emissions are 12-percent 

lower than they were in 1990.

Figure 8: Carbon Dioxide Emissions, 

1990 – 2001

0

500

1,000

1,500

2,000

2,500

3,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Million metric tons

Source: Energy Information Administration, Form 

EIA-906, "Power Plant Report."

Trade

Restructuring of the industry has dramatically

increased trade in some parts of the country. In 2001, 

purchases by electric utilities increased to 2,976 billion 

kilowatthours, a 32-percent increase over 2000

purchases of 2,250 billion kilowatthours. 

Retail Customers, Sales, and 

Revenues

1

 See the EPA website at http://www.epa.gov/ cleanenergy/impacts/ 

impacts.htm#chart.

Total retail sales in 2001 were 3,370 million

megawatthours, down slightly from the 2000 level of 

3,421 million megawatthours. This represents an

approximate decrease of 0.6 percent. Further

examination shows the biggest decreases in retail sales 

occurred on the West Coast, as a result of California’s 

electricity crisis. 

Sales between the three major sectors are relatively 

well balanced in the United States. The residential 

sector, at 1,203 million megawatthours, is larger than 

the commercial sector or industrial sector by

approximately 10 percent and 25 percent, respectively 

(Figure 9). 

Figure 9: U.S. Total Electric Industry, Retail 

Sales to Ultimate Consumers by Sector, 

2000 and 2001 

1192

1055 1064

109

1203

1089

964

114

0

200

400

600

800

1,000

1,200

1,400

Residential Commercial Industrial Other

Millions of Megawatthours

2000 2001

Source: Energy Information Administration, Form 

EIA-861, “Annual Electric Power Industry Report."

In 2001, annual revenues increased by 6 percent to 247 

billion. As a consequence, average revenues, which 

reflect the average cost to consumers, were up by 7.5 

percent to 7.32 cents per kWh (Figure 10).

Figure 10: U.S. Average Revenue, 

by Sector, 2000 and 2001 

8.24

7.43

4.64

6.56 6.81

8.62

7.93

5.04

7.03 7.32

0

2

4

6

8

10

Residential

Commercial

Industrial

Other

All Sectors

Average Revenue per kilowatthour (cents)

2000 2001

Source: Energy Information Administration, Form

EIA-861, “Annual Electric Power Industry Report."
6 Energy Information Administration/Electric Power Annual 2001

Revenue and Expense Statistics 

In 2001, electric utility revenues once again surpassed 

300 billion (Figure 11). Electric utility revenues and 

expenses for 2001 differed among the various utility 

ownership classes. Investor-owned utilities (IOUs), by 

far the largest ownership category, had increases in 

both total revenues and total operating expenses. IOU 

operating revenues were up by 14 percent to 268 

billion, while operating expenses increased by 12

percent to 235 billion. Most of the increase in

expenses could be attributed to increases in production 

costs and purchased power costs. Increased natural gas 

costs were a major cause of these increases.

Figure 11: Revenue and Expense Statistics 

for Major Electric Utilities, 1990 through 2001

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Million Dollars

Electric Operating Expenses Net Electric Operating Income

Sources: Energy Information Administration, Form 

EIA-412, “Annual Electric Industry Financial Report;” 

Federal Energy Regulatory Commission (FERC) Form 

1, “Annual Report of Major Electric Utilities,

Licensees and Others;” Rural Utilities Services (RUS) 

Form 7, “Financial and Statistical Report;” and RUS 

Form 12, “Operating Report-Financial.”

Financial results for the other utility ownership types 

differed sharply from those for IOUs. Revenues for 

publicly owned utilities were up by 16 percent to 48 

billion, but expenses increased by approximately 20 

percent to 43 billion. Most of this could be accounted 

for by the increased purchase power costs from 2000 to 

2001. 

Federal utility revenues increased by 14 percent to 12 

billion, while operating expenses increased by 20

percent to 10 billion. Most stable were the financial 

results for cooperatively owned electric utilities

(cooperatives). Cooperatives reported annual revenue 

increases of 3 percent to 26 billion, with expenses 

increasing by only 3 percent to 24 billion. The

cooperatives’ costs and revenues were largely insulated 

from market changes as a result of long-term contracts.

Demand-Side Management

In 2001, the total peak-load reductions from demandside management (DSM) in 2001 were 24,955

megawatts, up 9 percent from 2000, and down 6

percent from 1999 (Figure 12). There has been a clear 

and steady decline in peak-load reduction from DSM 

measures since 1996. This may reflect a reduced

emphasis on integrated resource planning at State

regulatory commissions as the resource planning

process has become fragmented.

13,704

15,619

17,204

23,069

25,001

29,561 29,893

25,284

27,231

26,455

22,901

24,955

0

5,000

10,000

15,000

20,000

25,000

30,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Megawatts

Figure 12: Demand-Side Management Peak 

Load Reductions, 1990-2001

Source: Energy Information Administration, Form

EIA-861, “Annual Electric Power Industry Report.”
Energy Information Administration/Electric Power Annual 2001 7

Electric Power Generation

Sales for

Resale/Transmission

Distribution

Steam Production

EIA Electric Industry Data Collection

Residential

Industrial

Commercial

Other

EIA-423

Monthly data on cost and 

quality of fuels delivered 

to non cost-of-service plants

EIA-767

Annual data on plant design, 

operation, and emissions for 

organic-fueled or combustible 

renewable steam-electric plants

EIA-860

Annual data on existing and 

proposed power plants, generators, 

and ownership

EIA-412

Annual data on:

public and Federal finances 

public, Federal, and unregulated 

plant statistics 

public, Federal, and cooperative 

transmission lines statistics

EIA-411

Annual data on NERC peak EIA-826 demand and energy

Monthly data on retail sales 

by State

EIA-861

Annual data on energy sources 

and disposition, electric 

operating revenue, retail sales 

by State, demand-side 

management, and distribution 

system information

Exports

Canada

Mexico

Imports

Canada

Mexico

EIA-417

Incident data on electric 

emergencies and disturbances

Coal

Petroleum

Natural Gas

Other Gas

Nuclear

Hydroelectric

Other

Renewables excluding hydroelectric

Energy

Sources

Wood, Waste

Geothermal, Solar, Wind

FERC 1 (Majors) or 

FERC 1F (Nonmajors)

Annual data on investor-owned

finances and operations

RUS 7 (Distributors) or

RUS 12 (Generation &

 Transmission)

Annual data on cooperative 

borrowers finances and operations

EIA-906

Monthly/annual data on generation, 

consumption, useful thermal 

output, and ending stocks

FE-781R

Annual data on international 

electric export/import transactions (or)

(or)

FERC Form 423

Monthly data on cost and 

quality of fuels delivered to 

cost-of-service plants

(or)

Indicates Non-EIA Forms

Steam for Industrial Use
8 Energy Information Administration/Electric Power Annual 2001

Table ES. Electric Power Industry - Summary Statistics for the United States, 1990 through 2001

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Net Generation (thousand megawatthours)

Coal1......................................................................... 1,903,380 1,966,265 1,881,087 1,873,516 1,845,016 1,795,196 1,709,426 1,690,694 1,690,070 1,621,206 1,590,623 1,594,011

Petroleum2............................................................... 127,629 111,221 118,061 128,800 92,555 81,411 74,554 105,901 112,788 100,154 119,752 126,621

Natural Gas............................................................. 629,201 601,038 556,396 531,257 479,399 455,056 496,058 460,219 414,927 404,074 381,553 372,765

Other Gases3........................................................... 13,767 13,955 14,126 13,492 13,351 14,356 13,870 13,319 12,956 13,270 11,336 10,383

Nuclear.................................................................... 768,826 753,893 728,254 673,702 628,644 674,729 673,402 640,440 610,291 618,776 612,565 576,862

Hydroelectric4........................................................ 207,548 270,034 313,439 318,868 352,413 344,074 308,108 256,748 276,458 248,911 284,453 289,358

Other Renewables5............................................... 78,916 80,906 79,423 77,088 77,183 75,796 73,965 76,535 76,213 73,770 68,779 64,372

Other6....................................................................... 4,254 4,794 4,024 3,571 3,612 3,571 4,104 3,667 3,487 3,720 4,739 3,616

All Energy Sources............................................. 3,733,521 3,802,105 3,694,810 3,620,295 3,492,172 3,444,188 3,353,487 3,247,522 3,197,191 3,083,882 3,073,799 3,037,988

Net Summer Generating Capacity (megawatts)

Coal1......................................................................... 314,230 315,114 315,496 315,786 313,624 313,382 311,386 311,415 310,148 309,372 307,438 307,361

Petroleum2 Only.................................................... 39,714 35,890 35,587 40,399 43,202 43,585 43,708 42,695 44,019 45,642 47,296 48,994

Natural Gas Only.................................................. 125,798 95,705 73,562 75,772 76,348 74,498 75,438 70,685 65,523 60,736 60,836 56,194

Dual Fired............................................................... 153,482 149,833 146,039 130,399 129,384 128,570 121,958 123,110 120,157 118,913 113,725 113,582

Other Gases3........................................................... 1,670 2,342 1,909 1,520 1,525 1,664 1,661 2,093 1,931 2,069 2,103 1,641

Nuclear.................................................................... 98,159 97,860 97,411 97,070 99,716 100,784 99,515 99,148 99,041 98,985 99,589 99,624

Hydroelectric4........................................................ 98,580 98,881 98,958 98,669 98,725 97,548 99,948 99,249 98,557 95,962 94,450 93,385

Other Renewables5............................................... 16,180 15,572 15,942 15,444 15,351 15,309 15,300 15,021 14,656 14,281 13,895 12,840

Other6....................................................................... 440 523 1,023 810 774 550 550 550 550 545 539 501

All Energy Sources............................................. 848,254 811,719 785,927 775,868 778,649 775,890 769,463 763,967 754,582 746,507 739,870 734,122

Demand, Capacity Resources, and Capacity Margins – Summer

Net Internal Demand (megawatts).................... 674,833 680,941 653,857 638,086 618,389 602,438 589,860 578,640 565,041 554,462 547,946 538,824

Capacity Resources (megawatts)...................... 788,990 808,054 765,744 744,670 737,855 730,376 727,481 711,583 705,360 697,432 692,337 687,341

Capacity Margins (percent)................................ 14.5 15.7 14.6 14.3 16.2 17.5 18.9 18.7 19.9 20.5 20.9 21.6

Fuel

Consumption of Fossil Fuels for Electricity Generation

Coal (thousand tons) 1.................................. 973,076 994,933 949,802 946,295 931,949 907,209 860,594 848,796 842,153 805,140 793,666 792,457

Petroleum (thousand barrels) 2.................. 222,294 195,228 207,871 222,640 159,715 144,626 132,578 183,618 192,462 172,241 203,669 218,997

Natural Gas (millions of cubic feet)........ 5,768,117 5,691,481 5,321,984 5,081,384 4,564,770 4,312,458 4,737,871 4,367,148 3,928,653 3,899,718 3,764,778 3,691,563

Other Gases (millions of cubic feet) 3..... 515,707 551,355 600,070 503,292 519,581 998,556 844,741 727,389 758,648 716,587 616,179 632,328

Consumption of Fossil Fuels for Thermal Output in Combined Heat and Power Facilities

Coal (thousand tons) 1.................................. 19,949 20,466 20,373 20,320 21,005 20,806 20,418 20,609 19,750 19,372 18,458 19,081

Petroleum (thousand barrels) 2.................. 20,379 22,266 26,822 28,845 28,802 27,873 25,562 27,929 26,394 24,077 23,039 26,002

Natural Gas (millions of cubic feet)........ 977,823 985,263 982,958 949,106 868,569 865,774 834,382 784,015 733,584 717,860 663,963 654,749

Other Gases (millions of cubic feet) 3..... 663,977 902,345 873,137 841,769 839,718 809,558 654,799 793,898 831,806 849,446 750,704 809,773

Consumption of Fossil Fuels for Electricity Generation and Useful Thermal Output

Coal (thousand tons) 1.................................. 993,025 1,015,398 970,175 966,615 952,955 928,015 881,012 869,405 861,904 824,512 812,124 811,538

Petroleum (thousand barrels) 2.................. 242,673 217,494 234,694 251,486 188,517 172,499 158,140 211,547 218,855 196,318 226,708 244,998

Natural Gas (millions of cubic feet)........ 6,745,940 6,676,744 6,304,942 6,030,490 5,433,338 5,178,232 5,572,253 5,151,163 4,662,236 4,617,578 4,428,742 4,346,311

Other Gases (millions of cubic feet) 3..... 1,179,685 1,453,701 1,473,207 1,345,061 1,359,299 1,808,114 1,499,540 1,521,287 1,590,454 1,566,033 1,366,884 1,442,101

Stocks at Electricity Generators (year end)7

Coal (thousand tons) 1.................................. 140,583 103,440 142,846 120,501 98,826 114,623 126,304 126,897 111,341 154,130 157,876 156,166

Petroleum (millions of cubic feet) 2......... 59,214 41,956 55,254 56,591 51,138 48,146 50,821 63,333 62,890 72,183 75,343 83,970

Receipts of Fuel at Electricity Generators

Coal (thousand tons) 1.................................. 762,815 790,274 908,232 929,448 880,588 862,701 826,860 831,929 769,152 775,963 769,923 786,627

Petroleum (thousand barrels) 2.................. 124,618 108,272 145,939 181,276 128,749 113,678 89,908 149,258 154,144 147,825 172,051 212,118

Natural Gas (millions of cubic feet)........ 2,152,366 2,629,986 2,809,455 2,922,957 2,764,734 2,604,663 3,023,327 2,863,904 2,574,523 2,637,678 2,630,818 2,490,979

Cost of Fuel at Electricity Generators (cents per million Btu)

Coal (thousand tons) 1.................................. 123.1 120.0 121.6 125.2 127.3 128.9 131.8 135.5 138.5 141.2 144.7 145.5

Petroleum (thousand barrels) 2.................. 389.5 442.0 250.8 212.3 286.3 314.2 266.7 248.1 242.7 254.7 254.6 338.1

Natural Gas (millions of cubic feet)........ 448.6 430.2 257.4 238.1 276.0 264.1 198.4 223.0 256.0 232.8 215.3 232.1

Emissions (thousand metric tons)

Carbon Dioxide (CO2)......................................... 2,290,045 2,327,868 2,222,525 2,209,983 2,123,263 2,058,980 1,985,162 1,970,581 1,945,346 1,865,680 1,851,086 1,853,975

Sulfur Dioxide (SO2)............................................ 13,038 10,678 11,791 12,534 12,484 12,125 11,469 13,721 14,246 14,337 14,604 14,779

Nitrogen Oxides (NOX)....................................... 6,118 5,191 5,549 5,999 6,085 6,137 5,908 6,732 6,927 6,717 6,816 6,887

Trade (megawatthours)8

Purchases9............................................................... 2,976,254 2,345,540 2,039,969 2,020,622 1,966,447 1,797,720 1,617,715 1,528,222 1,492,370 1,395,789 1,340,593 1,191,222

Sales for Resale9.................................................... 2,081,384 2,325,652 1,977,753 1,914,916 1,838,539 1,656,090 1,495,015 1,387,966 1,387,137 1,284,273 1,250,314 1,115,946

International Imports and Exports (thousand megawatthours)

Imports..................................................................... 38,478 48,879 42,923 39,525 43,031 43,497 42,854 46,833 31,358 28,247 21,931 18,445

Exports..................................................................... 18,173 14,829 14,000 13,229 8,974 3,302 3,623 2,010 3,541 2,827 2,305 16,134

Retail Sales and Revenue Data – Bundled and Unbundled

Number of Ultimate Customers (thousands)

Residential.............................................................. 114,318 111,718 110,383 109,048 107,066 105,343 103,917 102,321 100,860 99,513 98,296 97,095

Commercial............................................................ 14,940 14,349 14,074 13,887 13,542 13,181 12,949 12,733 12,526 12,367 12,179 12,082

Industrial................................................................. 574 527 553 540 563 586 581 584 553 548 518 525

Other10...................................................................... 1,008 974 935 933 952 894 882 851 795 858 887 859

All Sectors.............................................................. 130,840 127,568 125,945 124,408 122,123 120,004 118,330 116,489 114,735 113,286 111,880 110,561

See end of table for Notes and Sources.
Energy Information Administration/Electric Power Annual 2001 9

Table ES. Electric Power Industry - Summary Statistics for the United States, 1990 through 2001

(Continued)

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Retail Sales and Revenue Data – Bundled and Unbundled (Continued)

Sales to Ultimate Customers (thousand megawatthours)

Residential.............................................................. 1,202,647 1,192,446 1,144,923 1,130,109 1,075,880 1,082,512 1,042,501 1,008,482 994,781 935,939 955,417 924,019

Commercial............................................................ 1,089,154 1,055,232 1,001,996 979,401 928,633 887,445 862,685 820,269 794,573 761,271 765,664 751,027

Industrial................................................................. 964,224 1,064,239 1,058,217 1,051,203 1,038,197 1,033,631 1,012,693 1,007,981 977,164 972,714 946,583 945,522

Other......................................................................... 113,756 109,496 106,952 103,518 102,901 97,539 95,407 97,830 94,944 93,442 94,339 91,988

All Sectors.............................................................. 3,369,782 3,421,414 3,312,087 3,264,231 3,145,610 3,101,127 3,013,287 2,934,563 2,861,462 2,763,365 2,762,003 2,712,555

Revenue From Ultimate Customers (million dollars) 

Residential.............................................................. 103,671 98,209 93,483 93,360 90,704 90,503 87,610 84,552 82,814 76,848 76,828 72,378

Commercial............................................................ 86,354 78,405 72,771 72,575 70,497 67,829 66,365 63,396 61,521 58,343 57,655 55,117

Industrial................................................................. 48,573 49,369 46,846 47,050 47,023 47,536 47,175 48,069 47,357 46,993 45,737 44,857

Other......................................................................... 7,999 7,179 6,796 6,863 7,110 6,741 6,567 6,689 6,528 6,296 6,138 5,891

All Sectors.............................................................. 246,597 233,163 219,896 219,848 215,334 212,609 207,717 202,706 198,220 188,480 186,359 178,243

Average Re venue per Kilowatthour (cents)

Residential.............................................................. 8.62 8.24 8.16 8.26 8.43 8.36 8.40 8.38 8.32 8.21 8.04 7.83

Commercial............................................................ 7.93 7.43 7.26 7.41 7.59 7.64 7.69 7.73 7.74 7.66 7.53 7.34

Industrial................................................................. 5.04 4.64 4.43 4.48 4.53 4.60 4.66 4.77 4.85 4.83 4.83 4.74

Other......................................................................... 7.03 6.56 6.35 6.63 6.91 6.91 6.88 6.84 6.88 6.74 6.51 6.40

All Sectors.............................................................. 7.32 6.81 6.64 6.74 6.85 6.86 6.89 6.91 6.93 6.82 6.75 6.57

Revenue and Expense Statistics (Million dollars)11

Major Investor Owned

Utility Operating Revenues................................. 267,525 235,336 214,160 218,175 215,083 207,459 199,967 196,282 193,638 185,493 182,451 173,000

Utility Operating Expenses................................. 235,198 210,324 182,258 186,498 182,796 173,920 165,321 164,207 161,908 153,682 150,362 142,471

Net Utility Operating Income ............................. 32,327 25,012 31,902 31,677 32,286 33,539 34,646 32,074 31,730 31,811 32,089 30,529

Major Publicly Owned (with Generation Facilities)12

Operating Revenues.............................................. 38,028 31,843 26,767 26,155 25,397 24,207 23,473 23,267 22,522 21,686 21,083 20,470

Operating Expenses............................................... 32,811 26,244 21,274 20,880 20,425 19,084 18,959 18,649 18,162 17,191 16,887 16,461

Net Electric Operating Income ........................... 5,217 5,598 5,493 5,275 4,972 5,123 4,514 4,618 4,360 4,496 4,196 4,010

Major Publicly Owned (without Generation Facilities)12

Operating Revenues.............................................. 10,417 9,904 9,354 8,790 8,586 8,582 8,435 7,996 7,523 7,247 7,120 6,979

Operating Expenses............................................... 9,820 9,355 8,737 8,245 8,033 8,123 7,979 7,567 7,063 6,844 6,860 6,741

Net Electric Operating Income ........................... 597 549 617 545 552 459 457 429 460 404 260 238

Major Federally Owned

Operating Revenues.............................................. 12,136 10,685 10,186 9,780 8,833 9,082 8,743 8,552 8,141 7,872 8,194 8,197

Operating Expenses............................................... 9,785 8,139 7,775 7,099 5,999 6,390 6,162 6,303 6,056 5,883 5,288 5,428

Net Electric Operating Income ........................... 2,352 2,546 2,411 2,681 2,834 2,692 2,581 2,249 2,085 1,989 2,906 2,769

Major Cooperative Borrower Owned

Operating Revenues.............................................. 26,402 25,629 23,824 23,988 23,321 24,424 24,609 23,777 24,873 23,325 22,784 22,226

Operating Expenses............................................... 23,714 22,982 21,283 21,223 20,715 23,149 21,741 20,993 21,675 20,353 19,887 19,169

Net Electric Operating Income ........................... 2,688 2,647 2,541 2,764 2,606 2,872 2,868 2,784 3,197 2,973 2,897 3,057

Demand-Side Management (DSM) Data

Actual Peak Load Reductions (megawatts)

Total Actual Peak Load Reduction13................ 24,955 22,901 26,455 27,231 25,284 29,893 29,561 25,001 23,069 17,204 15,619 13,704

DSM Energy Savings (thousand megawatthours)

Energy Efficiency .................................................. 52,946 52,827 49,691 48,775 55,453 59,853 55,328 49,720 41,119 31,779 NA NA

Load Management................................................. 1,816 875 872 392 953 1,989 2,093 2,763 4,175 4,114 NA NA

DSM Cost (thousand dollars)

Total Cost14.......................................................... 1,639,424 1,564,901 1,423,644 1,420,920 1,636,020 1,902,197 2,421,284 2,715,657 2,743,533 2,348,094 1,803,773 1,177,457

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

7

 Anthracite, bituminous coal, subbituminous coal, and lignite, excludes waste coal.

8

 Alaska and Hawaii are not included.

9

 The 2001 data for unregulated entities are not available.

10 Includes miscellaneous sales, such as sales for public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.

11 Unless otherwise noted, all "dollars" are nominal dollars.

12 The 1998-2001 data represent those utilities meeting a threshold of 150 million kilowatthours sales to ultimate customers and/or 150 million kilowatthours of sales for resale for the two 

previous years. The 1990-1997 data represent those utilities meeting a threshold of 120 million kilowatthours sales to ultimate customers and/or 120 million kilowatthours of sales for 

resale for the 2 previous years.

13 Actual reduction in annual peak load achieved by all program participants during the reporting year, at the time of annual peak load, as opposed to the installed peak load reduction 

capability.

14 Sum of the total incurred direct and indirect utility costs for the year. Utility costs reflect the total cash expenditures for the year, in nominal d ollars, that flows out to support demandside management programs.

 NA = Not available.

 Notes: ·See Glossary for definitions.·See Technical Notes for the methodology used to convert short tons to metric tons.·Totals may not equal sum of components because of independent 

rounding.

 Sources: Form EIA-411, "Coordinated Bulk Power Supply Program;" Form EIA-412, "Annual Electric Industry Financial Report;" EIA-767, "Steam-Electric Plant Operation and Design 

Report;" Form EIA-860, " Annual Electric Generator Report;" Form EIA-861, "Annual Electric Power Industry Report;" Form EIA-906, "Power Plant Report;" and predecessor forms. 

Federal Regulatory Commission, FERC Form 1, "Annual Report of Major Utilities, Licensees and Others;" FERC Form 1 -F, "Annual Report for Nonmajor Public Utilities and Licensees;" 

FERC Form 423, "Monthly Cost and Quality of Fuels for Electric Plants Report," and predecessor forms; Rural Utility Services (RUS) Form 7, "Operating Report;" RUS Form 12, 

"Operating Report;" Imports and Exports: Mexico data - DOE, Fossil Fuels, Office of Fuels Programs, Form FE-781R, "Annual Report of International Electrical Export/Import Data" : 

Canada data - Natural Energy Board of Canada (metered energy firm and interruptible).
Energy Information Administration/Electric Power Annual 2001 11

Chapter 1. Generation
12 Energy Information Administration/Electric Power Annual 2001

Table 1.1. Net Generation by Energy Source by Type of Producer, 1990 through 2001

(Thousand Megawatthours)

Period Coal1 Petroleum2 Natural 

Gas

Other 

Gases3 Nuclear Hydroelectric4

Other 

Renewables5 Other6 Total

Total Electric Power Industry

1990........................ 1,594,011 126,621 372,765 10,383 576,862 289,358 64,372 3,616 3,037,988

1991........................ 1,590,623 119,752 381,553 11,336 612,565 284,453 68,779 4,739 3,073,799

1992........................ 1,621,206 100,154 404,074 13,270 618,776 248,911 73,770 3,720 3,083,882

1993........................ 1,690,070 112,788 414,927 12,956 610,291 276,458 76,213 3,487 3,197,191

1994........................ 1,690,694 105,901 460,219 13,319 640,440 256,748 76,535 3,667 3,247,522

1995........................ 1,709,426 74,554 496,058 13,870 673,402 308,108 73,965 4,104 3,353,487

1996........................ 1,795,196 81,411 455,056 14,356 674,729 344,074 75,796 3,571 3,444,188

1997........................ 1,845,016 92,555 479,399 13,351 628,644 352,413 77,183 3,612 3,492,172

1998........................ 1,873,516 128,800 531,257 13,492 673,702 318,868 77,088 3,571 3,620,295

1999........................ 1,881,087 118,061 556,396 14,126 728,254 313,439 79,423 4,024 3,694,810

2000........................ 1,966,265 111,221 601,038 13,955 753,893 270,034 80,906 4,794 3,802,105

2001........................ 1,903,380 127,629 629,201 13,767 768,826 207,548 78,916 4,254 3,733,521

Electricity Generators, Electric Utilities

1990....................... 1,559,606 117,017 264,089 0 576,862 279,926 10,651 0 2,808,151

1991....................... 1,551,167 111,463 264,172 0 612,565 275,519 10,137 0 2,825,023

1992....................... 1,575,895 88,916 263,872 0 618,776 239,559 10,200 0 2,797,219

1993....................... 1,639,151 99,539 258,915 0 610,291 265,063 9,565 0 2,882,525

1994....................... 1,635,493 91,039 291,115 0 640,440 243,693 8,933 0 2,910,712

1995....................... 1,652,914 60,844 307,306 0 673,402 293,653 6,409 0 2,994,529

1996....................... 1,737,453 67,346 262,730 0 674,729 327,970 7,214 0 3,077,442

1997....................... 1,787,806 77,753 283,625 0 628,644 337,234 7,462 0 3,122,523

1998....................... 1,807,480 110,158 309,222 0 673,702 304,403 7,206 0 3,212,171

1999....................... 1,767,679 86,929 296,381 0 725,036 293,932 3,716 0 3,173,674

2000....................... 1,696,619 72,180 290,715 0 705,433 248,195 2,241 0 3,015,383

2001....................... 1,560,146 78,919 264,434 0 534,207 190,105 2,152 0 2,629,962

Electricity Generators, Independent Power Producers

1990....................... 556 553 589 * -- 6,319 23,878 -- 31,895

1991....................... 757 745 3,604 3 -- 5,959 27,527 -- 38,596

1992....................... 1,165 1,160 6,999 3 -- 6,280 30,228 -- 45,836

1993....................... 2,904 1,060 8,293 7 -- 8,425 32,706 -- 53,396

1994....................... 4,370 1,047 8,603 7 -- 6,934 33,554 -- 54,514

1995....................... 5,044 1,162 10,136 6 -- 9,033 32,841 -- 58,222

1996....................... 5,312 1,170 10,104 4 -- 10,101 33,440 -- 60,132

1997....................... 5,344 2,557 7,506 31 -- 9,375 33,929 -- 58,741

1998....................... 15,539 5,503 26,657 55 -- 8,997 34,703 -- 91,455

1999....................... 64,387 17,906 60,264 36 3,218 14,635 40,460 -- 200,905

2000....................... 213,956 25,795 108,712 181 48,460 17,604 42,831 -- 457,540

2001....................... 290,429 35,534 156,093 47 234,619 14,434 41,361 0 772,517

Combined Heat and Power, Electric Power 7

1990....................... 11,947 1,294 44,808 621 -- -- 2,593 12 61,275

1991....................... 16,921 590 49,997 716 -- -- 3,315 403 71,942

1992....................... 20,653 2,162 63,403 1,209 -- -- 3,411 480 91,319

1993....................... 23,409 4,827 75,013 959 -- -- 3,360 408 107,976

1994....................... 26,414 6,592 85,971 1,085 -- -- 3,199 239 123,500

1995....................... 28,098 6,139 101,737 1,921 -- -- 3,372 213 141,480

1996....................... 29,207 6,267 105,923 1,337 -- -- 3,632 201 146,567

1997....................... 27,611 6,170 108,465 1,503 -- -- 4,299 63 148,111

1998....................... 27,174 6,550 113,413 2,260 -- -- 4,234 159 153,790

1999....................... 26,551 6,704 116,351 1,571 -- -- 4,088 139 155,404

2000....................... 32,536 7,217 118,551 1,847 -- -- 4,330 125 164,606

2001....................... 31,087 6,785 125,380 2,410 -- -- 4,376 113 170,151

Combined Heat and Power, Commercial 8

1990....................... 796 589 3,272 121 -- 138 922 -- 5,837

1991....................... 775 413 3,213 116 -- 131 1,010 1 5,659

1992....................... 749 302 3,867 105 -- 122 1,082 1 6,228

1993....................... 864 334 4,471 100 -- 100 1,132 * 7,000

1994....................... 850 417 4,929 115 -- 93 1,216 -- 7,619

1995....................... 998 379 5,162 -- -- 118 1,575 * 8,232

1996....................... 1,051 369 5,249 * -- 126 2,235 * 9,030

1997....................... 1,040 427 4,725 3 -- 120 2,385 * 8,701

1998....................... 985 383 4,879 7 -- 120 2,373 -- 8,748

1999....................... 995 434 4,607 * -- 115 2,412 * 8,563

2000....................... 1,097 432 4,262 * -- 100 2,012 * 7,903

2001....................... 978 427 4,492 * -- 66 1,480 * 7,443

Combined Heat and Power, Industrial9

1990....................... 21,107 7,169 60,007 9,641 -- 2,975 26,328 3,604 130,830

1991....................... 21,002 6,540 60,567 10,501 -- 2,844 26,791 4,336 132,579

1992....................... 22,743 7,615 65,933 11,953 -- 2,950 28,847 3,239 143,280

1993....................... 23,742 7,028 68,234 11,890 -- 2,871 29,450 3,079 146,294

1994....................... 23,568 6,808 69,600 12,112 -- 6,028 29,633 3,428 151,178

1995....................... 22,372 6,030 71,717 11,943 -- 5,304 29,768 3,890 151,025

1996....................... 22,172 6,260 71,049 13,015 -- 5,878 29,274 3,370 151,017

1997....................... 23,214 5,649 75,078 11,814 -- 5,685 29,107 3,549 154,097

1998....................... 22,337 6,206 77,085 11,170 -- 5,349 28,572 3,412 154,132

1999....................... 21,474 6,088 78,793 12,519 -- 4,758 28,747 3,885 156,264

2000....................... 22,056 5,597 78,798 11,927 -- 4,135 29,491 4,669 156,673

2001....................... 20,740 5,964 78,802 11,310 -- 2,943 29,548 4,141 153,448

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

7

 Electric utility CHP plants are included in Electricity Generators, Electric Utilities.

8

 Small number of commercial electricity-only plants included.

9

 Small number of Industrial electricity-only plants included.

 * = For detailed data, the absolute value is less than 0.5, for percentage calculations, the absolute value is less than 0.05 percent.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 13

DC

MD

DE

CT

RI

MA

ME

NH

PA

WV

VA

OH

SC

NC

NJ

KS

TN

KY

TX

VT

IN

LA

NV

IL

NY

49

0.1

6.8

39

7.5

19.6

15.1

196.6

81.9

74

142.3

95.4

117.7

89.9

30.6

59.7

143.8

44.7

96.3

122.6

179.1

365.8

5.5

88.7

34

AL

AR

AZ

CA

CO

FL

GA

IA

ID MI

MN

MO

MS

MT

ND

NE

NM

OK

OR SD

UT

WA

WI

WY

125.4

47.2

89.9

199.5

46.8

191.2

118.4

40.7

9.4 112.3

48.5

79.5

52.7

24.2

30.3

30.5

33.6

55.3

45.2 7.4

35.9

83.1

58.8

44.7

AK

6.8

HI

10.6

Total: 3,734 Million MWh

Net Generation

(Million MWh)

0 - 20

21 - 35

36 - 80

81 - 100

101 - 366

Figure 1.1. U.S. Electric Power Industry

Net Generation by State, 2001

(Million Megawatthours)

Source: Energy Information Administration, Form EIA-906, "Power Plant Report."
14 Energy Information Administration/Electric Power Annual 2001

Table 1.2. Useful Thermal Output by Energy Source, by Combined Heat and Power Producers, 1990 

through 2001

(Billion Btus)

Period Coal1 Petroleum2 Natural Gas Other Gases3 Other 

Renewables4 Other5 Total

Total Combined Heat and Power

1990............................ 362,524 127,363 538,063 140,695 687,005 40,149 1,895,799

1991............................ 351,834 112,144 546,755 148,216 660,091 44,331 1,863,371

1992............................ 367,158 117,172 591,875 159,887 698,350 41,598 1,976,040

1993............................ 372,603 128,884 604,256 142,044 713,009 40,731 2,001,527

1994............................ 387,604 132,528 645,561 143,682 767,417 42,129 2,118,921

1995............................ 386,403 120,790 686,182 144,715 768,338 44,389 2,150,817

1996............................ 391,540 132,815 710,733 149,831 755,847 42,980 2,183,746

1997............................ 388,944 136,742 712,683 150,144 785,306 53,361 2,227,180

1998............................ 381,546 135,519 781,637 167,064 757,131 46,437 2,269,334

1999............................ 385,926 125,486 810,918 178,971 744,470 47,871 2,293,642

2000............................ 383,687 108,045 812,036 184,062 763,674 50,459 2,301,963

2001............................ 373,084 98,484 805,528 179,478 666,381 41,742 2,164,697

Combined Heat and Power, Electric Power 6

1990............................ 20,793 9,029 79,905 3,822 24,509 28 138,086

1991............................ 21,239 5,502 82,279 3,940 26,293 590 139,843

1992............................ 27,545 6,123 101,923 4,825 24,861 1,543 166,820

1993............................ 29,742 7,820 106,650 3,091 24,088 1,322 172,713

1994............................ 36,663 8,631 119,199 5,190 24,497 880 195,060

1995............................ 40,427 13,044 117,994 4,344 26,910 249 202,968

1996............................ 42,982 11,603 121,431 3,928 32,761 314 213,019

1997............................ 39,437 11,823 132,125 7,746 30,147 29 221,307

1998............................ 43,256 6,261 141,834 5,064 25,969 68 222,452

1999............................ 52,061 6,718 145,525 3,548 30,172 28 238,052

2000............................ 53,329 6,610 157,886 5,312 25,661 39 248,837

2001............................ 55,131 5,029 161,236 7,833 20,997 36 250,262

Combined Heat and Power, Commercial7

1990............................ 14,670 5,406 15,515 118 10,580 -- 46,289

1991............................ 15,967 3,684 20,809 118 9,149 1 49,728

1992............................ 15,311 3,964 24,298 93 13,511 1 57,178

1993............................ 18,285 4,130 22,601 118 14,324 1 59,459

1994............................ 17,759 4,483 25,578 172 14,172 -- 62,164

1995............................ 16,718 2,877 28,574 -- 15,223 1 63,393

1996............................ 19,742 2,905 32,770 0 18,057 0 73,474

1997............................ 21,958 3,832 39,893 20 20,232 0 85,935

1998............................ 20,185 4,853 38,510 34 18,426 -- 82,008

1999............................ 20,479 3,298 36,857 0 17,145 0 77,779

2000............................ 21,001 3,827 39,293 0 17,613 0 81,734

2001............................ 21,193 4,713 38,089 0 14,084 0 78,079

Combined Heat and Power, Industrial8

1990............................ 327,061 112,928 442,643 136,755 651,916 40,121 1,711,424

1991............................ 314,628 102,958 443,667 144,158 624,649 43,740 1,673,800

1992............................ 324,302 107,085 465,654 154,969 659,978 40,054 1,752,042

1993............................ 324,576 116,934 475,005 138,835 674,597 39,408 1,769,355

1994............................ 333,182 119,414 500,784 138,320 728,748 41,249 1,861,697

1995............................ 329,258 104,869 539,614 140,371 726,205 44,139 1,884,456

1996............................ 328,816 118,307 556,532 145,903 705,029 42,666 1,897,253

1997............................ 327,549 121,087 540,665 142,378 734,927 53,332 1,919,938

1998............................ 318,105 124,405 601,293 161,966 712,736 46,369 1,964,874

1999............................ 313,386 115,470 628,536 175,423 697,153 47,843 1,977,811

2000............................ 309,357 97,608 614,857 178,750 720,400 50,420 1,971,392

2001............................ 296,760 88,742 606,203 171,645 631,300 41,706 1,836,356

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomas, geothermal, solar thermal, photovoltaic energy, and 

wind.

5

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

6

 Electric utility CHP plants are not included.

7

 Small number of commercial electricity-only plants included.

8

 Small number of industrial electricity -only plants included.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 15

Chapter 2. Capacity
16 Energy Information Administration/Electric Power Annual 2001

Table 2.1. Existing Net Summer Capacity by Energy Source and Producer Type, 1990 through 2001

(Megawatts)

Period Coal1 Petroleum2 Natural 

Gas Dual Fired Other Gases3 Nuclear Hydroelectric4

Other 

Renewables5 Other6 Total

Total Power Producers

1990................................ 307,361 48,994 56,194 113,582 1,641 99,624 93,385 12,840 501 734,122

1991................................ 307,438 47,296 60,836 113,725 2,103 99,589 94,450 13,895 539 739,870

1992................................ 309,372 45,642 60,736 118,913 2,069 98,985 95,962 14,281 545 746,507

1993................................ 310,148 44,019 65,523 120,157 1,931 99,041 98,557 14,656 550 754,582

1994................................ 311,415 42,695 70,685 123,110 2,093 99,148 99,249 15,021 550 763,967

1995................................ 311,386 43,708 75,438 121,958 1,661 99,515 99,948 15,300 550 769,463

1996................................ 313,382 43,585 74,498 128,570 1,664 100,784 97,548 15,309 550 775,890

1997................................ 313,624 43,202 76,348 129,384 1,525 99,716 98,725 15,351 774 778,649

1998................................ 315,786 40,399 75,772 130,399 1,520 97,070 98,669 15,444 810 775,868

1999................................ 315,496 35,587 73,562 146,039 1,909 97,411 98,958 15,942 1,023 785,927

2000................................ 315,114 35,890 95,705 149,833 2,342 97,860 98,881 15,572 523 811,719

2001................................ 314,230 39,714 125,798 153,482 1,670 98,159 98,580 16,180 440 848,254

Electricity Generators, Electric Utilities

1990................................ 299,781 47,722 43,958 106,011 375 99,624 90,885 2,111 * 690,465

1991................................ 299,444 45,931 48,280 105,019 692 99,589 92,031 2,031 -- 693,016

1992................................ 300,385 44,330 47,599 107,485 692 98,985 93,375 2,207 -- 695,059

1993................................ 300,634 42,699 49,709 109,066 698 99,041 95,910 2,215 -- 699,971

1994................................ 300,941 41,296 51,239 110,633 698 99,148 95,995 2,278 -- 702,229

1995................................ 300,569 42,232 55,220 109,294 291 99,515 96,661 2,330 -- 706,111

1996................................ 302,420 42,090 52,527 115,740 63 100,784 94,239 2,079 -- 709,942

1997................................ 302,866 41,545 53,552 116,174 206 99,716 95,487 2,123 222 711,889

1998................................ 299,739 38,144 40,764 114,201 55 97,070 94,424 2,067 229 686,692

1999................................ 277,780 31,742 31,755 108,716 220 95,030 93,067 790 224 639,324

2000................................ 260,990 25,823 32,069 106,806 57 85,968 91,758 837 13 604,319

2001................................ 244,451 24,150 35,117 92,030 57 63,060 90,065 979 13 549,920

Electricity Generators, Independent Power Producers

1990................................ 95 123 136 414 1 -- 1,918 5,485 -- 8,172

1991................................ 173 89 115 1,076 1 -- 1,824 6,092 -- 9,369

1992................................ 384 110 102 2,052 1 -- 1,978 6,296 -- 10,924

1993................................ 528 114 104 2,112 -- -- 2,026 6,478 -- 11,362

1994................................ 702 117 258 2,843 -- -- 2,108 6,728 -- 12,755

1995................................ 719 121 296 2,791 -- -- 2,151 6,887 -- 12,964

1996................................ 719 130 386 2,834 -- -- 2,171 6,850 -- 13,091

1997................................ 719 130 556 2,950 -- -- 2,103 6,695 -- 13,153

1998................................ 6,132 670 9,580 8,265 -- -- 3,074 6,955 -- 34,675

1999................................ 27,725 2,502 18,024 26,534 -- 2,381 4,763 8,794 -- 90,724

2000................................ 44,164 8,611 35,493 34,995 -- 11,892 6,011 8,994 -- 150,159

2001................................ 60,785 13,919 58,995 56,326 -- 35,099 7,445 9,743 -- 242,314

Combined Heat and Power, Electric Power 7

1990................................ 2,420 109 3,851 4,353 -- -- -- 481 -- 11,215

1991................................ 2,864 344 4,455 4,795 -- -- -- 474 -- 12,932

1992................................ 3,519 265 4,343 6,598 4 -- -- 458 -- 15,187

1993................................ 3,798 263 6,332 6,407 -- -- -- 464 -- 17,263

1994................................ 4,453 268 9,564 6,757 -- -- -- 498 -- 21,540

1995................................ 4,756 329 10,048 6,991 -- -- -- 610 -- 22,733

1996................................ 4,950 332 11,542 7,175 -- -- -- 626 -- 24,625

1997................................ 4,895 333 11,553 7,583 5 -- -- 707 -- 25,076

1998................................ 5,021 352 14,064 6,015 -- -- -- 749 -- 26,202

1999................................ 5,230 237 11,821 8,430 -- -- -- 741 -- 26,459

2000................................ 5,044 437 15,058 6,116 262 -- -- 736 -- 27,653

2001................................ 4,544 363 16,965 3,633 287 -- 8 728 28 26,555

Combined Heat and Power, Commercial8

1990................................ 266 151 168 581 -- -- 30 208 -- 1,405

1991................................ 232 106 155 576 -- -- 30 238 -- 1,339

1992................................ 234 117 266 611 -- -- 31 251 -- 1,510

1993................................ 283 113 302 639 -- -- 31 267 -- 1,637

1994................................ 287 160 348 934 -- -- 32 297 -- 2,057

1995................................ 315 182 350 950 -- -- 31 303 -- 2,131

1996................................ 321 205 398 907 -- -- 31 446 -- 2,309

1997................................ 314 194 412 930 -- -- 32 450 -- 2,333

1998................................ 317 243 568 657 -- -- 32 463 -- 2,281

1999................................ 317 262 455 771 -- -- 32 465 -- 2,302

2000................................ 314 259 633 602 -- -- 33 399 -- 2,240

2001................................ 295 271 1,382 596 -- -- 22 348 -- 2,912

Combined Heat and Power, Industrial 9

1990................................ 4,799 888 8,081 2,223 1,265 -- 551 4,556 501 22,865

1991................................ 4,725 826 7,831 2,259 1,410 -- 565 5,060 539 23,214

1992................................ 4,849 820 8,426 2,167 1,373 -- 578 5,068 545 23,826

1993................................ 4,905 831 9,076 1,933 1,233 -- 590 5,232 550 24,349

1994................................ 5,032 854 9,276 1,943 1,395 -- 1,115 5,221 550 25,386

1995................................ 5,028 844 9,524 1,932 1,370 -- 1,106 5,171 550 25,524

1996................................ 4,972 828 9,645 1,913 1,602 -- 1,106 5,308 550 25,923

1997................................ 4,830 1,000 10,276 1,746 1,315 -- 1,102 5,376 552 26,198

1998................................ 4,577 989 10,796 1,260 1,465 -- 1,139 5,210 581 26,019

1999................................ 4,443 844 11,507 1,588 1,689 -- 1,097 5,151 799 27,119

2000................................ 4,601 761 12,453 1,313 2,023 -- 1,079 4,607 510 27,348

2001................................ 4,156 1,010 13,340 898 1,327 -- 1,041 4,382 399 26,553

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

7

 Electric utility CHP plants are included in Electric Generators, Electric Utilities.

8

 Small number of commercial electricity-only plants included.

9

 Small number of industrial electricity -only plants included.

 * = For detailed data, the absolute value is less than 0.5, for percentage calculations, the absolute value is less than 0.05 percent.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 17

SD

WY

IA

OH

WV

SC

MD

DC

VA

NC

CT

RI

MA

NJ

DE

PA

NY

KY

TN

LA

KS

NV

VT NH

2.8

9.2

29.6

19.4

26.1

20.1

15.8

11.8

1.2

7.9

16.1

2.7

11.9

0.8

37.7

35.7

17.6

20.2

21.7

10.1

6.9

1 2.8

AL

AR

AZ

CA

CO

FL

GA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OK

OR

TX

UT

WA

WI

23.8

16.7

54.5

8.9

42.8

29.5

3.2

40.1 24.2

10.4

4.2

26.9

11.1

18.9

11.1

5.1

4.7

6

5.7

14.9

11.8

88

5.3

26.6

14.1

6.3

AK

2.1

HI

2.3

Total: 848.3 Thousand MW

Net Summer Capacity

(Thousand Megawatts)

0 - 4.0

4.1 - 10.0

10.1 - 15.0

15.1 - 25.0

25.1 - 88.5

Figure 2.1 U.S. Electric Power Industry

Existing Net Summer Capacity by State, 2001

(Thousand Megawatts)

Source: Enegy Information Administration, Form EIA-860, "Annual Electric Generator Report."
18 Energy Information Administration/Electric Power Annual 2001

Table 2.2. Existing Capacity by Energy Source, 2001

(Megawatts)

Energy Source Number of 

Generators

Generator 

Nameplate Capacity 

(MW)

Net Summer 

Capacity (MW)

Net Winter 

Capacity (MW)

Coal1....................................................... 1,600 336,868 314,230 316,148

Petroleum2............................................. 2,967 44,626 39,714 43,670

Natural Gas........................................... 2,561 140,891 125,798 134,896

Dual Fired............................................. 2,886 170,444 153,482 162,903

Other Gases3......................................... 89 1,813 1,670 1,678

Nuclear.................................................. 104 104,933 98,159 99,468

Hydroelectric4...................................... 4,143 95,844 98,580 98,397

Other Renewables5............................. 1,497 18,133 16,180 16,737

Other6..................................................... 18 573 440 440

Total................................................ 15,865 914,124 848,254 874,338

1

 Anthracite, bitumi nous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

 Notes: ·Where there is more than one energy source used in a plant, the predominant energy source is reported here.·Totals may not equal sum of components because of independent 

rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.

Table 2.3. Existing Capacity by Producer Type, 2001

(Megawatts)

Producer Type Number of 

Generators

Generator Nameplate 

Capacity (MW)

Net Summer 

Capacity 

(MW)

Net Winter 

Capacity 

(MW)

Electricity Generators

Electricity Generators, Electric Utilities................................................ 8,798 584,574 549,920 561,382

Electricity Generators, Independent Power Producers....................... 3,803 265,503 242,314 253,287

Electricity Generators, Total................................................................. 12,601 850,077 792,234 814,669

Combined Heat and Power

Combined Heat and Power, Electric Power.......................................... 541 31,084 26,555 28,543

Combined Heat and Power, Commercial .............................................. 626 3,463 2,912 3,179

Combined Heat and Power, Industrial.................................................... 2,097 29,500 26,553 27,947

Combined Heat and Power, Total....................................................... 3,264 64,047 56,020 59,669

Total Electric Power Sector ......................................................................... 15,865 914,124 848,254 874,338

 Notes: ·See Glossary for definitions.·Totals may not equal s um of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.

Table 2.4. Planned Nameplate Capacity Additions by Energy Source, 2002 through 2006

(Megawatts)

Energy Source 2002 2003 2004 2005 2006

Coal1................................................................. 669 1,714 60 4,624 2,011

Petroleum2....................................................... 1,119 356 1 213 386

Natural Gas..................................................... 84,979 103,629 69,525 38,437 10,437

Other Gases3................................................... 205 -- -- 580 580

Nuclear............................................................. -- -- -- -- --

Hydroelectric4................................................. 22 72 -- 9 --

Other Renewables5........................................ 218 49 373 77 --

Other6................................................................ -- 281 -- -- --

Total................................................................. 87,211 106,101 69,959 43,939 13,414

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

 Notes: ·Where there is more than one energy source used in a plant, the predominant energy source is reported here.·Totals may not equal sum of components because of independent 

rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 19

Table 2.5. Planned Capacity Additions by Energy Source, 2002-2006

(Megawatts)

Energy Source Number of Generators Generator Nameplate Capacity 

(MW)

Net Summer Capacity (MW) Net Winter Capacity (MW)

2002

U.S. Total..................................... 836 87,211 80,249 83,917

Coal1......................................... 3 669 595 595

Petroleum2............................... 122 1,119 1,045 1,078

Natural Gas............................. 644 84,979 78,225 81,839

Other Gases3........................... 5 205 193 197

Nuclear.................................... -- -- -- --

Hydroelectric4........................ 9 22 22 22

Other Renewables5............... 53 218 170 186

Other6....................................... -- -- -- --

2003

U.S. Total..................................... 653 106,101 99,804 104,433

Coal1......................................... 5 1,714 1,691 1,691

Petroleum2............................... 29 356 335 341

Natural Gas............................. 586 103,629 97,379 102,008

Other Gases3........................... -- -- -- --

Nuclear.................................... -- -- -- --

Hydroelectric4........................ 13 72 72 72

Other Renewables5............... 19 49 46 40

Other6....................................... 1 281 281 281

2004

U.S. Total..................................... 405 69,959 64,400 67,868

Coal1......................................... 1 60 60 60

Petroleum2............................... 1 1 1 1

Natural Gas............................. 397 69,525 63,967 67,435

Other Gases3........................... -- -- -- --

Nuclear.................................... -- -- -- --

Hydroelectric4........................ -- -- -- --

Other Renewables5............... 6 373 372 372

Other6....................................... -- -- -- --

2005

U.S. Total..................................... 186 43,939 41,014 42,278

Coal1......................................... 10 4,624 4,265 4,288

Petroleum2............................... 2 213 173 202

Natural Gas............................. 166 38,437 35,927 37,138

Other Gases3........................... 2 580 580 580

Nuclear.................................... -- -- -- --

Hydroelectric4........................ 2 9 9 9

Other Renewables5............... 4 77 60 62

Other7....................................... -- -- -- --

2006

U.S. Total..................................... 54 13,414 11,946 12,584

Coal1......................................... 4 2,011 1,882 1,882

Petroleum2............................... 2 386 306 364

Natural Gas............................. 45 10,437 9,178 9,758

Other Gases3........................... 3 580 580 580

Nuclear.................................... -- -- -- --

Hydroelectric4........................ -- -- -- --

Other Renewables5............... -- -- -- --

Other6....................................... -- -- -- --

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

5

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

6

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

 Notes: ·Where there is more than one energy source used in a plant, the predominant energy source is reported here.·Totals may not equal sum of components because of independent 

rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.
20 Energy Information Administration/Electric Power Annual 2001

Table 2.6. Capacity Additions and Retirements by Energy Source, 2001

(Megawatts)

Additions1 Retirements

Energy Source Number of 

Generators

Generator 

Nameplate 

Capacity 

(MW)

Net 

Summer 

Capacity 

(MW)

Net Winter 

Capacity 

(MW)

Number of 

Generators

Generator 

Nameplate 

Capacity 

(MW)

Net 

Summer 

Capacity 

(MW)

Net Winter 

Capacity 

(MW)

Coal2.................................................... -- -- -- -- 9 52 48 62

Petroleum3.......................................... 113 502 425 438 82 153 137 149

Natural Gas........................................ 313 30,211 25,638 28,467 20 336 290 318

Dual Fired.......................................... 102 11,583 9,805 11,741 16 253 227 228

Other Gases4...................................... -- -- -- -- 1 10 9 9

Nuclear............................................... -- -- -- -- -- -- -- --

Hydroelectric5................................... 8 21 20 19 1 * * *

Other Renewables6.......................... 104 1,621 1,572 1,586 18 103 97 98

Other7.................................................. -- -- -- -- 1 * * *

Total............................................. 640 43,938 37,460 42,251 148 908 808 865

1

 Generator re-ratings and revisions/corrections to previously reported data are not included.

2

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

3

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

4

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

5

 Conventional hydroelectric power and hydroelectric pumped storage facility production minus energy used for pumping.

6

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, tires, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and 

wind.

7

 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

 * = For detailed data, the absolute value is less than 0.5, for percentage calculations, the absolute value is less than 0.05 percent.

 Notes: ·Where there is more than one energy source used in a plant, the predominant energy source is reported here.·Totals may not equal sum of components because of independent 

rounding.

 Source: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 21

Chapter 3. Demand, Capacity Resources, and Capacity Margins
22 Energy Information Administration/Electric Power Annual 2001

Table 3.1. Noncoincident Peak Load, Actual and Projected by North American Electric Reliability 

Council Region, 1997 through 2006

(Megawatts)

North American Electric Actual

Reliability Council Region 1997 1998 1999 2000R

2001

Summer

ECAR............................................................................. 93,492 93,784 99,239 92,033 100,235

ERCOT.......................................................................... 50,541 54,666 55,529 57,606 55,201

FRCC ............................................................................. 35,375 38,730 37,493 37,194 39,062

MAAC........................................................................... 49,464 48,445 51,645 49,477 54,015

MAIN............................................................................. 45,887 47,509 51,535 52,552 56,344

MAPP (U.S.) ............................................................... 29,787 30,722 31,903 28,605 28,321

NPCC (U.S.) ............................................................... 49,269 49,566 52,855 50,057 55,949

SERC.............................................................................. 137,382 143,226 149,685 R156,088 149,293

SPP................................................................................. 36,479 37,724 38,609 40,199 40,273

WSCC (U.S.) .............................................................. 110,001 115,921 113,629 114,602 109,119

Contiguous U.S. ........................................................ 637,677 660,293 682,122 R678,413 687,812

Winter

ECAR............................................................................. 75,670 84,401 86,239 84,546 85,485

ERCOT.......................................................................... 37,966 41,876 39,164 44,641 44,015

FRCC ............................................................................. 33,076 39,975 40,178 38,606 40,922

MAAC........................................................................... 37,217 36,532 40,220 43,256 39,458

MAIN............................................................................. 34,973 37,410 39,081 41,943 40,529

MAPP (U.S.) ............................................................... 25,390 26,080 25,200 24,536 21,815

NPCC (U.S.) ............................................................... 41,338 44,199R45,227 43,852 42,670

SERC.............................................................................. 122,649 127,416 128,563 139,146 135,182

SPP................................................................................. 27,437 27,847 27,963 30,576 29,614

WSCC (U.S.) .............................................................. 94,158 101,822 99,080 97,324 96,622

Contiguous U.S. ........................................................ 529,874 567,558 570,915 588,426 576,312

North American Electric Projected

Reliability Council Region 2002 2003 2004 2005 2006

Summer

ECAR............................................................................. 99,346 101,871 104,548 106,541 109,113

ERCOT.......................................................................... 57,898 60,727 63,190 64,965 66,857

FRCC ............................................................................. 40,145 41,335 42,292 43,279 44,274

MAAC........................................................................... 54,188 55,089 55,956 56,872 57,809

MAIN............................................................................. 56,888 57,693 58,575 59,753 60,799

MAPP (U.S.) ............................................................... 28,191 28,681 29,729 30,726 31,257

NPCC (U.S.) ............................................................... 54,675 55,813 56,531 57,198 57,903

SERC.............................................................................. 160,384 164,001 167,879 171,439 174,795

SPP................................................................................. 41,483 42,490 43,556 44,678 45,197

WSCC (U.S.) .............................................................. 116,852 119,465 122,089 124,541 126,886

Contiguous U.S. ........................................................ 710,050 727,165 744,345 759,992 774,890

Winter

ECAR............................................................................. 87,133 89,228 90,796 92,586 94,404

ERCOT.......................................................................... 45,818 47,802 49,217 50,708 52,193

FRCC ............................................................................. 43,199 44,219 45,237 46,242 47,215

MAAC........................................................................... 44,747 45,367 46,019 46,668 47,288

MAIN............................................................................. 43,028 43,750 43,935 44,740 45,264

MAPP (U.S.) ............................................................... 23,234 23,654 24,323 24,702 25,167

NPCC (U.S.) ............................................................... 45,308 45,943 46,447 46,995 47,489

SERC.............................................................................. 139,527 142,730 146,754 148,624 151,445

SPP................................................................................. 30,382 30,743 31,761 32,464 32,732

WSCC (U.S.) .............................................................. 103,314 105,611 107,953 110,023 112,384

Contiguous U.S. ........................................................ 605,690 619,047 632,442 643,752 655,581

 R = Revised.

 Notes: ·Actual data are final.·Projected data are updated annually.·NERC Regional Council names may be found in the Glossary.·In 1998, several utilities realigned from SPP to 

SERC.·On January 1, 1997, FRCC became the tenth NERC region, separating from SERC.·Represents an hour of a day during the associated peak period.·The summer peak period begins 

on June 1 and extends through September 30.·The winter peak period begins on December 1 and extends through March 31 of the following year. For example, winter 2001 begins 

December 1, 2001, and extends through March 31, 2002.·Totals may not equal sum of components because of independent rounding.

 Sources: Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program."
Energy Information Administration/Electric Power Annual 2001 23

Table 3.2. Net Internal Demand, Capacity Resources, and Capacity Margins by North American 

Electric Reliability Council Region, Summer, 1990 through 2001

(Megawatts)

Region and Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

ECAR

Net Internal Demand ...................... 100,235 98,651 94,072 92,359 91,103 88,573 85,643 84,967 83,530 80,536 79,948 79,370

Capacity Resources......................... 113,136 115,379 107,451 105,545 105,106 104,953 103,003 101,605 101,910 100,027 98,993 97,588

Capacity Margin (percent)............ 11.4 14.5 12.5 12.5 13.3 15.6 16.9 16.4 18.0 19.5 19.2 18.7

ERCOT

Net Internal Demand ...................... 55,106 53,649 51,697 50,254 47,746 45,636 44,990 43,630 42,629 43,093 43,516 41,915

Capacity Resources......................... 70,797 69,622 65,423 59,788 55,771 55,230 55,074 54,219 54,323 54,994 53,954 53,549

Capacity Margin (percent)............ 22.2 22.9 21.0 15.9 14.4 17.4 18.3 19.5 21.5 21.6 19.3 21.7

FRCC

Net Internal Demand ...................... 38,932 35,666 34,832 34,562 32,874 31,868 31,649R30,537 29,435 28,898 27,773 27,162

Capacity Resources......................... 42,290 43,083 40,645 39,708 39,613 38,237 38,282R37,577 36,225 34,565 33,669 33,964

Capacity Margin (percent)............ 7.9 17.2 14.3 13.0 17.0 16.7 17.3 R18.7 18.7 16.4 17.5 20.0

MAAC

Net Internal Demand ...................... 54,015 51,358 49,325 47,626 46,548 45,628 45,224 44,571 44,198 44,348 43,794 43,341

Capacity Resources......................... 59,533 60,679 57,831 55,511 56,155 56,774 56,881 56,271 55,328 55,272 55,347 54,132

Capacity Margin (percent)............ 9.3 15.4 14.7 14.2 17.1 19.6 20.5 20.8 20.1 19.8 20.9 19.9

MAIN

Net Internal Demand ...................... 53,032 51,845 47,165 45,570 45,194 44,470 43,229 42,611 42,001 41,304 41,083 40,466

Capacity Resources......................... 65,950 64,170 55,984 52,722 52,160 52,880 52,112 50,963 50,333 49,104 48,471 48,244

Capacity Margin (percent)............ 19.6 19.2 15.8 13.6 13.4 15.9 17.0 16.4 16.6 15.9 15.2 16.1

MAPP (U.S.)

Net Internal Demand ...................... 27,125 28,006 30,606 29,766 28,221 27,298 27,487 26,855 25,901 26,050 26,168 24,055

Capacity Resources......................... 32,271 34,236 35,373 34,773 34,027 33,121 32,665 32,267 31,964 32,411 31,975 32,063

Capacity Margin (percent)............ 15.9 18.2 13.5 14.4 17.1 17.6 15.9 16.8 19.0 19.6 18.2 25.0

NPCC (U.S.)

Net Internal Demand ...................... 55,888 54,270 53,450 51,760 50,240 48,950 48,290 47,465 46,380 46,007 45,952 46,016

Capacity Resources......................... 63,760 63,376 63,077 60,439 60,729 58,592 62,368 61,906 62,049 61,960 59,972 60,878

Capacity Margin (percent)............ 12.3 14.4 15.3 14.4 17.3 16.5 22.6 23.3 25.3 25.7 23.4 24.4

SERC

Net Internal Demand ...................... 144,399 151,527 142,726 R138,146 134,968 109,270 105,785 R101,885 99,287 97,448 94,767 93,893

Capacity Resources......................... 171,530 169,760 160,575 R158,360 155,016 126,196 127,562 R120,044 117,375 115,635 114,690 112,112

Capacity Margin (percent)............ 15.8 10.7 11.1 R12.8 12.9 13.4 17.1 15.1 15.4 15.7 17.4 16.3

SPP

Net Internal Demand ...................... 38,807 39,056 37,807 36,402 37,009 59,017 57,951 56,395 55,067 52,183 51,537 51,554

Capacity Resources......................... 45,530 46,109 43,111 42,554 43,591 69,344 69,354 69,198 67,922 67,472 67,472 67,333

Capacity Margin (percent)............ 14.8 15.3 12.3 14.5 15.1 14.9 16.4 18.5 18.9 22.7 23.6 23.4

WSCC (U.S.)

Net Internal Demand ...................... 107,294 116,913 112,177 111,641 104,486 101,728 99,612 99,724 96,613 94,595 93,408 91,052

Capacity Resources......................... 124,193 141,640 136,274 135,270 135,687 135,049 130,180 127,533 127,931 125,992 127,794 127,478

Capacity Margin (percent)............ 13.6 17.5 17.7 17.5 23.0 24.7 23.5 21.8 24.5 24.9 26.9 28.6

Contiguous U.S.

Net Internal Demand ................... 674,833 680,941 653,857 R638,086 618,389 602,438 589,860 578,640 565,041 554,462 547,946 538,824

Capacity Resources...................... 788,990 808,054 765,744 R744,670 737,855 730,376 727,481 711,583 705,360 697,432 692,337 687,341

Capacity Margin (percent) ........ 14.5 15.7 14.6 14.3 16.2 17.5 18.9 18.7 19.9 20.5 20.9 21.6

 R = Revised.

 Notes: ·NERC Regional Council names may be found in the Glossary.·In 1998, several utilities realigned from SPP to SERC.·On January 1, 1997, FRCC became the tenth NERC region, 

separating from SERC.·Represents an hour of a day during the associated peak period.·The summer peak period b egins on June 1 and extends through September 30.·Totals may not equal 

sum of components because of independent rounding.

 Sources: Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program."
24 Energy Information Administration/Electric Power Annual 2001

Table 3.3. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by 

North American Electric Reliability Council Region, Summer, 2001 through 2006

(Megawatts)

North American Electric 

Reliability Council Region

Net Internal 

Demand

Capacity 

Resources

Capacity 

Margin 

(percent)

Net Internal 

Demand

Capacity 

Resources

Capacity 

Margin 

(percent)

2001 2002

ECAR ..................... 100,235 113,136 11.4 96,328 122,995 21.7

ERCOT................... 55,106 70,797 22.2 57,736 76,482 24.5

FRCC..................... 38,932 42,290 7.9 37,400 44,735 16.4

MAAC .................... 54,015 59,533 9.3 52,569 64,003 17.9

MAIN ..................... 53,032 65,950 19.6 53,352 70,842 24.7

MAPP (U.S.)............ 27,125 32,271 15.9 26,490 32,967 19.6

NPCC (U.S.)............ 55,888 63,760 12.3 54,617 67,992 19.7

SERC...................... 144,399 171,530 15.8 154,289 176,456 12.6

SPP ........................ 38,807 45,530 14.8 39,942 47,591 16.1

WSCC (U.S.)............ 107,294 124,193 13.6 115,132 142,880 19.4

Contiguous U.S........ 674,833 788,990 14.5 687,855 846,943 18.8

2003 2004

ECAR ..................... 98,795 139,170 29.0 101,436 151,831 33.2

ERCOT................... 60,565 80,150 24.4 63,028 82,649 23.7

FRCC..................... 38,605 47,112 18.1 39,569 48,828 19.0

MAAC .................... 53,470 68,167 21.6 54,337 73,421 26.0

MAIN ..................... 54,361 73,316 25.9 55,288 76,505 27.7

MAPP (U.S.)............ 27,312 33,297 18.0 28,355 32,185 11.9

NPCC (U.S.)............ 55,755 71,207 21.7 56,474 76,745 26.4

SERC...................... 157,884 180,296 12.4 162,185 184,382 12.0

SPP ........................ 40,820 48,737 16.2 41,880 49,062 14.6

WSCC (U.S.)............ 117,744 156,554 24.8 120,334 176,571 31.8

Contiguous U.S........ 705,311 898,006 21.5 722,886 952,179 24.1

2005 2006

ECAR ..................... 103,428 154,974 33.3 106,012 155,274 31.7

ERCOT................... 64,803 82,423 21.4 66,695 81,847 18.5

FRCC..................... 40,559 49,982 18.9 41,561 50,375 17.5

MAAC .................... 55,253 73,421 24.7 56,190 72,971 23.0

MAIN ..................... 56,466 76,975 26.6 57,503 76,930 25.3

MAPP (U.S.)............ 29,348 32,051 8.4 29,876 32,372 7.7

NPCC (U.S.)............ 57,139 77,593 26.4 57,842 77,540 25.4

SERC...................... 165,753 187,737 11.7 169,103 192,112 12.0

SPP ........................ 42,915 49,128 12.6 43,428 49,458 12.2

WSCC (U.S.)............ 122,789 196,618 37.5 125,133 204,966 38.9

Contiguous U.S........ 738,453 980,902 24.7 753,343 993,845 24.2

 Notes: ·Data are projected and updated annually.·NERC Regional Council names may be found in the Glossary.·In 1998, several utilities realigned from SPP to SERC.·On January 1, 

1997, FRCC became the tenth NERC region, separating from SERC.·Represents an hour of a day during the associat ed peak period.·The summer peak period begins on June 1 and extends 

through September 30.·Totals may not equal sum of components because of independent rounding.

 Sources: Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program."
Energy Information Administration/Electric Power Annual 2001 25

Table 3.4. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by 

North American Electric Reliability Council Region, Winter, 2001 through 2006

(Megawatts)

North American Electric 

Reliability Council Region

Net Internal 

Demand

Capacity 

Resources

Capacity 

Margin 

(percent)

Net Internal 

Demand

Capacity 

Resources

Capacity 

Margin 

(percent)

2001/ 2002 2002/ 2003

ECAR .................................................. 82,831 115,926 28.5 84,474 125,251 32.6

ERCOT................................................ 43,908 72,644 39.6 45,656 80,426 43.2

FRCC.................................................. 39,699 44,336 10.5 39,565 49,165 19.5

MAAC ................................................. 39,458 63,604 38.0 44,048 65,871 33.1

MAIN .................................................. 38,412 63,209 39.2 40,628 67,780 40.1

MAPP (U.S.)......................................... 21,575 30,809 30.0 22,689 31,878 28.8

NPCC (U.S.)......................................... 42,551 66,314 35.8 45,194 73,071 38.2

SERC................................................... 130,311 169,580 23.2 134,614 176,653 23.8

SPP ..................................................... 28,571 45,290 36.9 29,441 47,267 37.7

WSCC (U.S.)......................................... 95,395 119,254 20.0 101,865 144,664 29.6

Contiguous U.S..................................... 562,711 790,966 28.9 588,174 862,026 31.8

2003/ 2004 2004/ 2005

ECAR .................................................. 86,608 141,808 38.9 88,213 154,469 42.9

ERCOT................................................ 47,640 83,012 42.6 49,055 85,085 42.3

FRCC.................................................. 40,588 51,312 20.9 41,596 51,375 19.0

MAAC ................................................. 44,668 74,594 40.1 45,320 74,898 39.5

MAIN .................................................. 41,327 71,972 42.6 42,271 74,608 43.3

MAPP (U.S.)......................................... 23,098 32,633 29.2 23,758 32,259 26.4

NPCC (U.S.)......................................... 45,821 75,528 39.3 46,306 81,740 43.3

SERC................................................... 137,804 180,275 23.6 141,812 184,540 23.2

SPP ..................................................... 29,679 48,325 38.6 30,697 48,444 36.6

WSCC (U.S.)......................................... 104,141 166,052 37.3 106,481 187,760 43.3

Contiguous U.S..................................... 601,374 925,511 35.0 615,509 975,178 36.9

2005/ 2006 2006/ 2007

ECAR .................................................. 90,040 157,612 42.9 91,930 157,912 41.8

ERCOT................................................ 50,546 84,508 40.2 52,031 83,525 37.7

FRCC.................................................. 42,588 53,758 20.8 43,548 53,671 18.9

MAAC ................................................. 45,969 74,898 38.6 46,589 74,898 37.8

MAIN .................................................. 43,086 75,629 43.0 43,604 74,976 41.8

MAPP (U.S.)......................................... 24,125 32,115 24.9 24,604 32,352 23.9

NPCC (U.S.)......................................... 46,811 81,644 42.7 47,305 81,678 42.1

SERC................................................... 143,667 185,577 22.6 146,472 188,393 22.3

SPP ..................................................... 31,320 49,068 36.2 31,588 49,206 35.8

WSCC (U.S.)......................................... 108,547 200,780 45.9 110,908 201,622 45.0

Contiguous U.S..................................... 626,699 995,589 37.1 638,579 998,233 36.0

 Notes: ·Actual data are final.·Projected data are updated annually.·NERC Regional Council names may be found in the Glossary.·In 1998, several utilities realigned from SPP to 

SERC.·On January 1, 1997, FRCC became the tenth NERC region, separating from SERC.·Represents an hour of a day during the associated peak period.·The summer peak period begins 

on June 1 and extends through September 30.·The winter peak period begins on December 1 and extends through March 31 of the following year. For example, winter 2001/2002 begins 

December 1, 2001, and extends through March 31, 2002.·Totals may not equal sum of components because of independent rounding.

 Sources: Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program".
Energy Information Administration/Electric Power Annual 2001 27

Chapter 4. Fuel
28 Energy Information Administration/Electric Power Annual 2001

Table 4.1. Consumption of Fossil Fuels for Electricity Generation by Type of Power Producer, 1990 

through 2001

Type of Power Producer and Period Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Thousand Mcf)3

Total

1990.......................................................................................... 792,457 218,997 3,691,563 632,328

1991.......................................................................................... 793,666 203,669 3,764,778 616,179

1992.......................................................................................... 805,140 172,241 3,899,718 716,587

1993.......................................................................................... 842,153 192,462 3,928,653 758,648

1994.......................................................................................... 848,796 183,618 4,367,148 727,389

1995.......................................................................................... 860,594 132,578 4,737,871 844,741

1996.......................................................................................... 907,209 144,626 4,312,458 998,556

1997.......................................................................................... 931,949 159,715 4,564,770 519,581

1998.......................................................................................... 946,295 222,640 5,081,384 503,292

1999.......................................................................................... 949,802 207,871 5,321,984 600,070

2000.......................................................................................... 994,933 195,228 5,691,481 551,355

2001.......................................................................................... 973,076 222,294 5,768,117 515,707

Electricity Generators, Electric Utilities

1990.......................................................................................... 773,549 200,152 2,787,332 0

1991.......................................................................................... 772,268 188,494 2,789,014 0

1992.......................................................................................... 779,860 152,329 2,765,608 0

1993.......................................................................................... 813,508 168,556 2,682,440 0

1994.......................................................................................... 817,270 155,377 2,987,146 0

1995.......................................................................................... 829,007 105,956 3,196,507 0

1996.......................................................................................... 874,681 116,680 2,732,107 0

1997.......................................................................................... 900,361 132,147 2,968,453 0

1998.......................................................................................... 910,867 187,461 3,258,054 0

1999.......................................................................................... 894,120 151,868 3,113,419 0

2000.......................................................................................... 859,335 125,788 3,043,094 0

2001.......................................................................................... 806,269 133,475 2,686,287 0

Electricity Generators, Independent Power Producers

1990.......................................................................................... 664 1,094 6,778 6

1991.......................................................................................... 915 1,403 33,144 22

1992.......................................................................................... 1,326 2,099 63,389 16

1993.......................................................................................... 3,050 1,965 72,653 43

1994.......................................................................................... 3,939 1,998 77,414 43

1995.......................................................................................... 3,921 2,342 91,064 40

1996.......................................................................................... 4,143 2,169 91,617 32

1997.......................................................................................... 3,884 4,010 70,774 25

1998.......................................................................................... 9,486 9,676 285,878 1,489

1999.......................................................................................... 30,572 30,037 615,756 433

2000.......................................................................................... 107,745 45,011 1,049,636 1,320

2001.......................................................................................... 140,453 64,237 1,439,780 329

Combined Heat and Power, Electric Power 4

1990.......................................................................................... 7,088 3,499 353,179 55,954

1991.......................................................................................... 9,470 912 393,898 59,451

1992.......................................................................................... 12,204 3,291 495,967 84,115

1993.......................................................................................... 13,293 8,513 589,147 104,664

1994.......................................................................................... 14,904 12,011 693,923 90,594

1995.......................................................................................... 14,926 11,366 806,202 123,825

1996.......................................................................................... 15,575 11,320 836,086 115,579

1997.......................................................................................... 14,764 11,046 863,968 15,288

1998.......................................................................................... 13,773 12,310 871,881 34,115

1999.......................................................................................... 13,197 12,440 914,600 22,300

2000.......................................................................................... 15,634 13,147 921,341 43,692

2001.......................................................................................... 15,225 12,420 965,359 108,918

Combined Heat and Power, Commercial5

1990.......................................................................................... 417 953 27,544 1,932

1991.......................................................................................... 403 576 26,806 1,884

1992.......................................................................................... 371 429 32,674 1,836

1993.......................................................................................... 404 672 37,435 1,752

1994.......................................................................................... 404 694 40,828 1,842

1995.......................................................................................... 569 649 42,700 --

1996.......................................................................................... 656 645 42,380 *

1997.......................................................................................... 630 790 38,975 9

1998.......................................................................................... 440 802 40,693 21

1999.......................................................................................... 481 931 39,045 *

2000.......................................................................................... 514 823 37,029 *

2001.......................................................................................... 473 869 37,090 *

Combined Heat and Power, Industrial6

1990.......................................................................................... 10,740 13,299 516,729 574,436

1991.......................................................................................... 10,610 12,283 521,916 554,822

1992.......................................................................................... 11,379 14,093 542,081 630,619

1993.......................................................................................... 11,898 12,755 546,978 652,189

1994.......................................................................................... 12,279 13,537 567,836 634,910

1995.......................................................................................... 12,171 12,265 601,397 720,876

1996.......................................................................................... 12,153 13,813 610,268 882,944

1997.......................................................................................... 12,311 11,723 622,599 504,259

1998.......................................................................................... 11,728 12,392 624,878 467,666

1999.......................................................................................... 11,432 12,595 639,165 577,336

2000.......................................................................................... 11,706 10,459 640,381 506,344

2001.......................................................................................... 10,654 11,294 639,602 406,461

1

 Anthracite, bituminous coal, subbituminous coal, lignite, synthetic coal, and waste coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Electric utility CHP plants are included in Electric Generators, Electric Utilities.

5

 Small number of commercial electricity-only plants included.

6

 Small number of industrial electricity -only plants included.

 * = For detailed data, the absolute value is less than 0.5, for percentage calculations, the absolute value is less than 0.05 percent.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 29

Table 4.2. Consumption of Fossil Fuels for Useful Thermal Output by Type of Combined Heat and 

Power Producer, 1990 through 2001

Type of Power Producer and Period Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Thousand Mcf)3

Total

1990......................................................................................... 19,081 26,002 654,749 809,773

1991......................................................................................... 18,458 23,039 663,963 750,704

1992......................................................................................... 19,372 24,077 717,860 849,446

1993......................................................................................... 19,750 26,394 733,584 831,806

1994......................................................................................... 20,609 27,929 784,015 793,898

1995......................................................................................... 20,418 25,562 834,382 654,799

1996......................................................................................... 20,806 27,873 865,774 809,558

1997......................................................................................... 21,005 28,802 868,569 839,718

1998......................................................................................... 20,320 28,845 949,106 841,769

1999......................................................................................... 20,373 26,822 982,958 873,137

2000......................................................................................... 20,466 22,266 985,263 902,345

2001......................................................................................... 19,949 20,379 977,823 663,977

Electric Power 4

1990......................................................................................... 1,266 1,805 97,330 51,551

1991......................................................................................... 1,221 1,101 99,868 59,243

1992......................................................................................... 1,704 1,229 122,908 48,716

1993......................................................................................... 1,794 1,591 128,743 33,074

1994......................................................................................... 2,241 1,791 144,062 59,648

1995......................................................................................... 2,376 2,784 142,753 38,671

1996......................................................................................... 2,520 2,424 147,091 38,835

1997......................................................................................... 2,355 2,466 161,608 11,079

1998......................................................................................... 2,493 1,322 172,471 10,494

1999......................................................................................... 3,033 1,423 175,757 7,280

2000......................................................................................... 3,107 1,412 192,253 27,549

2001......................................................................................... 3,128 1,082 196,548 50,348

Commercial

1990......................................................................................... 773 1,104 18,913 235

1991......................................................................................... 826 761 25,295 233

1992......................................................................................... 804 807 29,672 185

1993......................................................................................... 968 843 27,738 234

1994......................................................................................... 940 931 31,457 339

1995......................................................................................... 850 596 34,964 --

1996......................................................................................... 1,005 601 40,075 *

1997......................................................................................... 1,108 794 47,941 10

1998......................................................................................... 1,002 1,006 46,527 17

1999......................................................................................... 1,009 682 44,991 *

2000......................................................................................... 1,034 792 47,844 *

2001......................................................................................... 1,038 985 46,133 *

Industrial

1990......................................................................................... 17,041 23,093 538,506 757,987

1991......................................................................................... 16,412 21,177 538,800 691,229

1992......................................................................................... 16,864 22,041 565,279 800,544

1993......................................................................................... 16,988 23,960 577,103 798,497

1994......................................................................................... 17,428 25,207 608,496 733,911

1995......................................................................................... 17,192 22,182 656,665 616,128

1996......................................................................................... 17,281 24,848 678,608 770,723

1997......................................................................................... 17,542 25,541 659,021 828,629

1998......................................................................................... 16,824 26,518 730,108 831,258

1999......................................................................................... 16,330 24,718 762,210 865,858

2000......................................................................................... 16,325 20,062 745,165 874,796

2001......................................................................................... 15,783 18,312 735,142 613,629

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

4

 Electric utility CHP plants are included in Table 4.1 with Electric Generators, Electric Utilities.

 * = For detailed data, the absolute value is less than 0.5, for percentage calculations, the absolute value is less than 0.05 percent.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.
30 Energy Information Administration/Electric Power Annual 2001

Table 4.3. Consumption of Fossil Fuels for Electricity Generation and for Useful Thermal Output, 

1990 through 2001

Period Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Thousand Mcf)3

Total

1990............................................................................................... 811,538 244,998 4,346,311 1,442,101

1991............................................................................................... 812,124 226,708 4,428,742 1,366,884

1992............................................................................................... 824,512 196,318 4,617,578 1,566,033

1993............................................................................................... 861,904 218,855 4,662,236 1,590,454

1994............................................................................................... 869,405 211,547 5,151,163 1,521,287

1995............................................................................................... 881,012 158,140 5,572,253 1,499,540

1996............................................................................................... 928,015 172,499 5,178,232 1,808,114

1997............................................................................................... 952,955 188,517 5,433,338 1,359,299

1998............................................................................................... 966,615 251,486 6,030,490 1,345,061

1999............................................................................................... 970,175 234,694 6,304,942 1,473,207

2000............................................................................................... 1,015,398 217,494 6,676,744 1,453,701

2001............................................................................................... 993,025 242,673 6,745,940 1,179,685

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3

 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels.

 Notes: ·See Glossary for definitions.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.

Table 4.4. End-of-Year Stocks of Coal and Petroleum, by Type of Producer, 1990 through 2001

Electricity Generators Electric Power Industry

Electric Utilities Independent Power Producers

Period Coal

(Thousand 

Tons)1

Petroleum

(Thousand 

Barrels)2

Coal

(Thousand 

Tons)

Petroleum

(Thousand 

Barrels)

Coal

(Thousand Tons)

Petroleum

(Thousand 

Barrels)

1990.................................. 156,166 83,970 156,166 83,970 NA NA

1991.................................. 157,876 75,343 157,876 75,343 NA NA

1992.................................. 154,130 72,183 154,130 72,183 NA NA

1993.................................. 111,341 62,890 111,341 62,890 NA NA

1994.................................. 126,897 63,333 126,897 63,333 NA NA

1995.................................. 126,304 50,821 126,304 50,821 NA NA

1996.................................. 114,623 48,146 114,623 48,146 NA NA

1997.................................. 98,826 51,138 98,826 51,138 NA NA

1998.................................. 120,501 56,591 120,501 56,591 NA NA

1999.................................. 142,846 55,254 129,041 46,169 11,058 7,322

2000.................................. 103,440 41,956 90,115 30,502 10,477 9,803

2001.................................. 140,583 59,214 117,150 37,392 19,542 18,171

Combined Heat and Power3

Period Electric Power Commercial Industrial

Coal

(Thousand Tons)

Petroleum

(Thousand Barrels)

Coal

(Thousand Tons)

Petroleum

(Thousand Barrels)

Coal

(Thousand Tons)

Petroleum

(Thousand Barrels)

1990................................ NA NA NA NA NA NA

1991................................ NA NA NA NA NA NA

1992................................ NA NA NA NA NA NA

1993................................ NA NA NA NA NA NA

1994................................ NA NA NA NA NA NA

1995................................ NA NA NA NA NA NA

1996................................ NA NA NA NA NA NA

1997................................ NA NA NA NA NA NA

1998................................ NA NA NA NA NA NA

1999................................ 1,505 618 54 162 1,188 984

2000................................ 1,703 627 18 63 1,126 961

2001................................ 1,817 1,308 165 404 1,908 1,940

1

 Anthracite, bituminous coal, subbituminous coal, and lignite, excludes waste coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion me thodology), and waste oil.

3

 This category includes stocks for both electricity generation and for useful thermal output.

 NA = Not available.

 Notes: ·Values are estimates based on a cutoff model sample - see Technical Notes for a discussion of the sample design for Form EIA-906. See Technical Notes for the adjustment 

methodology.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-906, "Power Plant Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 31

Table 4.5. Receipts, Average Cost, and Quality of Fossil Fuels at Electric Utilities, 1990 through 

2001 

Coal1 Petroleum2 Natural Gas 

All 

Fossil 

Fuels 

Receipts Average Cost Receipts Average Cost Receipts Average 

Cost 

Average 

Cost Period 

(thousand 

tons) 

(cents/ 

106 Btu) 

(dollars/

ton) 

Avg. 

Sulfur 

Percent 

by 

Weight 

(thousand 

barrels) 

(cents/ 

106 Btu) 

(dollars/ 

barrel) 

Avg. 

Sulfur 

Percent 

by 

Weight 

(thousand 

Mcf) 

(cents/ 

106 Btu) 

(cents/ 

106 Btu) 

1990......................... 786,627 145.5 30.45 1.35 212,118 335.3 21.06 1.02 2,490,979 232.1 168.8

1991......................... 769,923 144.7 30.02 1.30 172,051 252.7 15.93 1.11 2,630,818 215.3 160.2

1992......................... 775,963 141.2 29.36 1.29 147,825 251.4 15.87 1.19 2,637,678 232.8 158.9

1993......................... 769,152 138.5 28.58 1.18 154,144 237.3 14.95 1.32 2,574,523 256.0 159.4

1994......................... 831,929 135.5 28.03 1.17 149,258 242.3 15.19 1.21 2,863,904 223.0 152.5

1995......................... 826,860 131.8 27.01 1.08 89,908 256.6 16.10 1.18 3,023,327 198.4 145.2

1996......................... 862,701 128.9 26.45 1.10 113,678 302.6 18.98 1.24 2,604,663 264.1 151.8

1997......................... 880,588 127.3 26.16 1.11 128,749 273.0 17.18 1.35 2,764,734 276.0 152.0

1998......................... 929,448 125.2 25.64 1.06 181,276 202.1 12.71 1.46 2,922,957 238.1 143.5

1999......................... 908,232 121.6 24.72 1.01 145,939 235.9 14.81 1.47 2,809,455 257.4 143.8

2000......................... 790,274 120.0 24.28 .93 108,272 417.9 26.30 1.31 2,629,986 430.2 173.5

2001......................... 762,815 123.1 24.68 .89 124,618 369.3 23.20 1.40 2,152,366 448.6 173.0 

1

 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil. 

 

 Notes: ·Totals may not equal sum of components because of independent rounding.·As of 1991, data are for electric generating plants with a total steam-electric and combined-cycle 

nameplate capacity of 50 or more megawatts.·Data for 1990 are for steam-electric plants with a generator nameplate capacity of 50 or more megawatts.·Mcf = thousand cubic 

feet.·Monetary values are expressed in nominal terms. 

 Source: Federal Energy Regulatory Commission, FERC Form 423, "Monthly Cost and Quality of Fuels for Electric Plants Report." 

Table 4.6. Receipts and Quality of Coal Delivered to Electric Utilities, 1990 through 2001 

(Thousand Tons) 

Anthracite Bituminous Subbituminous Lignite 

Period 

Receipts 

Sulfur 

percent 

by 

weight 

Ash 

percent 

by 

weight 

Receipts 

Sulfur 

percent 

by 

weight 

Ash 

percent 

by 

weight 

Receipts 

Sulfur 

percent 

by 

weight 

Ash 

percent 

by 

weight 

Receipts 

Sulfur 

percent 

by 

weight 

Ash 

percent 

by 

weight 

1990......................... 753 .71 32.7 477,782 1.86 10.5 232,660 .43 7.2 75,432 .92 14.0

1991......................... 723 .64 33.4 450,462 1.84 10.3 239,929 .42 6.9 78,810 .95 14.9

1992......................... 503 .67 32.0 453,732 1.81 10.2 241,291 .43 7.0 80,438 .97 14.6

1993......................... 392 .69 33.0 422,690 1.71 10.2 265,180 .41 7.0 80,890 .94 14.4

1994......................... 689 .56 36.8 456,733 1.69 10.1 295,752 .41 6.9 78,756 .94 13.8

1995......................... 857 .53 37.4 432,586 1.60 10.2 316,195 .39 6.7 77,222 .99 14.0

1996......................... 735 .52 37.7 454,814 1.64 10.3 328,874 .39 6.6 78,278 .92 13.6

1997......................... 751 .53 36.7 466,104 1.65 10.5 336,805 .40 6.7 76,928 .98 13.8

1998......................... 511 .55 37.6 478,252 1.61 10.5 373,496 .38 6.6 77,189 .95 13.8

1999......................... 137 .64 37.8 444,399 1.57 10.2 386,271 .38 6.6 77,425 .90 14.2

2000......................... 11 .64 37.2 375,673 1.45 10.1 341,242 .35 6.3 73,349 .91 14.2

2001......................... -- -- -- 348,703 1.42 10.4 349,340 .35 6.1 64,772 .98 13.9 

 Note: Totals may not equal sum of components because of independent rounding. 

 Source: Federal Energy Regulatory Commission, FERC Form 423, "Monthly Cost and Quality of Fuels for Electric Plants Report." 
32 Energy Information Administration/Electric Power Annual 2001

Table 4.7. Average Quality of Fossil Fuels Burned at Electricity Generators, 1990 through 2001

(Thousand Tons)

Coal1 Petroleum2 Natural Gas

Year

Average Btu 

per Pound

Sulfur 

Percent by 

Weight

Ash Percent 

by Weight

Average Btu 

per Gallon

Sulfur Percent 

by Weight

Average Btu per

Cubic Foot

1990.................................... 10,465 1.35 9.85 149,682 .97 1,027

1991.................................... 10,378 1.30 9.76 150,282 1.06 1,024

1992.................................... 10,395 1.29 9.71 150,630 1.12 1,024

1993.................................... 10,315 1.18 9.55 150,685 1.22 1,023

1994.................................... 10,338 1.17 9.36 150,033 1.10 1,023

1995.................................... 10,248 1.08 9.23 150,2 07 1.00 1,019

1996.................................... 10,263 1.10 9.22 150,234 1.07 1,017

1997.................................... 10,275 1.11 9.36 151,007 1.12 1,019

1998.................................... 10,241 1.06 9.18 150,780 1.21 1,022

1999.................................... 10,163 1.01 9.01 150,700 1.18 1,019

2000.................................... 10,115 .93 8.84 150,817 1.07 1,020

2001.................................... 10,019 .89 8.75 150,6 73 1.16 1,027

1

 Anthracite, bituminous coal, subbituminous coal, lignite coal, synthetic fuel, and waste coal.

2

 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Federal Energy Regulatory Commission, FERC Form 423, "Monthly Cost and Quality of Fuels for Electric Plants Report," and predecessor forms.
Energy Information Administration/Electric Power Annual 2001 33

Chapter 5. Emissions
34 Energy Information Administration/Electric Power Annual 2001

Table 5.1. Emissions, 1990 through 2001

(Thousand Metric Tons)

Emission 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Carbon Dioxide (CO2)............ 2,290,045 2,327,868 2,222,525 2,209,983 2,123,263 2,058,980 1,985,162 1,970,581 1,945,346 1,865,680 1,851,086 1,853,975

Sulfur Dioxide (SO2) ............ 13,038 10,678 11,791 12,534 12,484 12,125 11,469 13,721 14,246 14,337 14,604 14,779

Nitrogen Oxides (NOx) ..........6,118 5,191 5,549 5,999 6,085 6,137 5,908 6,732 6,927 6,717 6,816 6,887

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report;" Form EIA-906, "Power Plant Report;" and predecesor forms. Nitrogen 

oxides adjusted by the Environmental Protection Agency's Continuous Emission Monitoring System.

Table 5.2. Number and Capacity of Fossil-Fueled Steam-Electric Generators with Environmental 

Equipment, 1990 through 2001

Scrubbers Particulate Collectors Cooling Towers Total2

Capacity3

Year1

Number of 

Generators (megawatts)

Number of 

Generators

Capacity3 

(megawatts)

Number of 

Generators

Capacity3 

(megawatts)

Number of 

Generators

Capacity3 

(megawatts)

1990.......................................... 153 69,122 1,177 349,319 478 162,557 1,360 376,894

1991.......................................... 155 70,734 1,173 352,910 485 164,632 1,353 378,883

1992 ......................................... 155 71,531 1,168 353,365 484 165,030 1,345 379,034

1993.......................................... 154 71,106 1,156 350,808 486 164,807 1,330 376,831

1994.......................................... 168 80,617 1,135 351,180 480 165,452 1,309 376,899

1995.......................................... 178 84,677 1,134 351,198 471 165,295 1,295 375,691

1996.......................................... 182 85,842 1,134 352,154 477 166,749 1,299 377,144

1997.......................................... 183 86,605 1,133 352,068 480 166,886 1,301 377,195

1998.......................................... 186 87,783 1,130 351,790 474 166,896 1,294 377,117

1999.......................................... 192 89,666 1,148 353,480 505 175,520 1,343 387,192

2000.......................................... 192 89,675 1,141 352,727 505 175,520 1,336 386,438

2001.......................................... 266 99,417 1,043 295,0 08 609 180,634 1,934 478,134

1

 Includes plants under the Clean Air Act that were monitored by the Environmental Protection Agency even if sold to an unregulated entity.

2

 Components are not additive since some generators are included in more than one category and not all have environmental equipment.

3

 Nameplate capacity

 Notes: ·These data are for plants with a fossil-fueled steam-electric capacity of 100 megawatts or more .·In 2001, data for plants with combustible renewable steam-electric capacity of 

100 megawatts or more also included.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report." Unregulated data are included beginning with 2001 data.

Table 5.3. Average Flue Gas Desulfurization Costs, 1990 through 2001

Year1 Average Overhead & Maintenance Costs

(mills per kilowatthour)2

Average Installed Capital Costs

(dollars per kilowatt)

1990.......................................................... 1.35 118.00

1991.......................................................... 1.40 130.00

1992.......................................................... 1.32 132.00

1993.......................................................... 1.19 125.00

1994.......................................................... 1.14 127.00

1995.......................................................... 1.16 126.00

1996.......................................................... 1.07 128.00

1997.......................................................... 1.09 129.00

1998.......................................................... 1.12 126.00

1999.......................................................... 1.13 125.00

2000.......................................................... .96 124.00

2001.......................................................... .92 112.00

1

 Includes plants under the Clean Air Act that were monitored by the Environmental Protection Agency even if sold to an unregulated entity.

2

 A mill is one tenth of one cent.

 Notes: ·These data are for plants with a fossil-fueled steam-electric capacity of 100 megawatts or more.·In 2001, data for plants with combustible renewable steam-electric capacity of 100 

megawatts or more also included.·Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report." Unregulated data are included beginning with 2001 data.
Energy Information Administration/Electric Power Annual 2001 35

Chapter 6. Trade
36 Energy Information Administration/Electric Power Annual 2001

Table 6.1. Electric Power Industry - Purchases, 1990 through 2001

(Million Kilowatthours)

2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

U.S. Total................................ 2,976,254 2,345,540 2,039,969 2,020,622 1,966,447 1,797,720 1,617,715 1,528,222 1,492,370 1,395,789 1,340,593 1,191,222

Electric Utilities........................ 2,976,254 2,250,382 1,949,574 1,927,198 1,878,099 1,694,192 1,528,068 1,435,591 1,407,419 1,312,605 1,267,106 1,114,590

IPP and CHP1.......................... NA 95,158 90,395 93,423R

88,348R103,528 R89,647R92,631R84,951R83,184R73,487R76,632R

1

 IPP are independent power producers and CHP are combined heat and power producers.

 NA = Not available.

 R = Revised.

 Notes: ·Restructuring of the electric power industry has dramatically increased trade in various locations.·See Glossary for definitions.·Totals may not equal sum of components because 

of independent rounding.

 Sources: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report," For unregulated entities prior to 2001, Form EIA-860B, "Annual Electric 

Generator Report - Nonutility," and predecessor forms.

Table 6.2. Electric Power Industry - Sales for Resale, 1990 through 2001

(Million Kilowatthours)

2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

U.S. Total................................ 2,081,384 2,325,652 1,977,753 1,914,916 1,838,539 1,656,090 1,495,015 1,387,966 1,387,137 1,284,273 1,250,314 1,115,946

Electric Utilities........................ 2,081,384 1,715,582 1,635,614 1,664,081 1,616,318 1,431,179 1,276,356 R

1,185,352 1,200,047 1,119,948 1,116,655 999,268

IPP and CHP1.......................... NA 610,069 342,138 250,835 222,221 224,911 218,660 202,614 187,090 164,324 133,659 116,677

1

 IPP are independent power producers and CHP are combined heat and power producers.

 NA = Not available.

 R = Revised.

 Notes: ·Restructuring of the electric power industry has dramatically increased trade in various locations.·See Glossary for definitions.·Totals may not equal sum of components because 

of independent rounding.

 Sources: Energy Information Administration, Fo rm EIA-861, "Annual Electric Power Industry Report." For unregulated entities prior to 2001, Form EIA-860B, "Annual Electric 

Generator Report - Nonutility," and predecessor forms.

Table 6.3. Electric Power Industry - U.S. Electricity Imports from and Electricity Exports to Canada 

and Mexico, 1990 through 2001

(Megawatthours)

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

International Imports and Exports

Canada

Imports................................ 38,379,753 48,801,972 42,619,118 39,513,588 43,008,951 42,233,376 40,596,119 44,821,858 29,364,197 26,224,179 19,815,290 16,494,107

Exports................................ 17,805,808 12,684,706 12,731,850 11,255,694 7,470,332 1,986,361 2,468,244 941,214 2,691,723 1,836,692 1,687,950 15,543,122

Mexico1

Imports2................................ 98,645 76,800 303,439 11,249 22,279 1,263,152 2,257,411 2,011,319 1,993,328 2,022,419 2,115,739 1,951,288

Exports................................ 367,680 2,144,676 1,268,284 1,973,203 1,503,707 1,315,625 1,154,421 1,068,668 849,167 989,887 616,628 590,462

Total Imports................................ 38,478,398 48,878,772 42,922,557 39,524,837 43,031,230 43,496,528 42,853,530 46,833,177 31,357,525 28,246,598 21,931,029 18,445,395

Total Exports................................ 18,173,488 14,829,382 14,000,134 13,228,897 8,974,039 3,301,986 3,622,665 2,009,882 3,540,890 2,826,579 2,304,578 16,133,584

1

 For the reporting year 2001,California - ISO reported electricity purchases from Mexico of 98,645 MWh. They exported 65,475 MWh, thereby having a total net trade of 33,170 MWh of 

imported electricity.

2

 Contract terminations in 1997 and 2000.

 Note: Totals may not equal sum of components because of independent rounding.

 Sources: Canada: National Energy Board of Canada; Mexico: Office of Fuels Programs, Fossil Energy, Form FE-781R, "Annual Report of International Electric Export/Import Data," 

Data provided by the California - ISO.
Energy Information Administration/Electric Power Annual 2001 37

Chapter 7. Retail Customers, Sales, and Revenues
38 Energy Information Administration/Electric Power Annual 2001

Table 7.1. Number of Ultimate Customers Served by Sector, by Provider, 1990 through 2001

(Number)

Period Residential Commercial Industrial Others1 All Sectors

Total Electric Industry

1990......................................... 97,094,514 12,081,942 525,486 858,800 110,560,742

1991......................................... 98,295,518 12,178,694 518,272 887,499 111,879,983

1992......................................... 99,512,728 12,367,205 547,990 857,614 113,285,537

1993......................................... 100,860,071 12,526,377 553,231 795,298 114,734,977

1994......................................... 102,320,846 12,733,153 583,935 850,770 116,488,704

1995......................................... 103,917,312 12,949,365 580,626 882,422 118,329,725

1996......................................... 105,343,005 13,181,065 586,198 893,884 120,004,152

1997......................................... 107,065,589 13,542,374 563,223 951,863 122,123,049

1998......................................... 109,048,343 13,887,066 539,903 932,838 124,408,150

1999......................................... 110,383,238 14,073,764 552,690 935,311 125,945,003

2000......................................... 111,717,711 14,349,067 526,554 974,185 127,567,517

2001......................................... 114,317,707 14,939,895 574,361 1,008,212 130,840,175

Full-Service Providers

1990......................................... 97,094,514 12,081,942 525,486 858,800 110,560,742

1991......................................... 98,295,518 12,178,694 518,272 887,499 111,879,983

1992......................................... 99,512,728 12,367,205 547,990 857,614 113,285,537

1993......................................... 100,860,071 12,526,377 553,231 795,298 114,734,977

1994......................................... 102,320,846 12,733,153 583,935 850,770 116,488,704

1995......................................... 103,917,312 12,949,365 580,626 882,422 118,329,725

1996......................................... 105,341,408 13,180,632 586,169 893,884 120,002,093

1997......................................... 107,033,338 13,540,374 562,972 951,863 122,088,547

1998......................................... 108,736,845 13,832,662 538,167 932,838 124,040,512

1999......................................... 109,817,057 13,963,937 527,329 934,260 125,242,583

2000......................................... 110,505,820 14,058,271 512,551 953,756 126,030,398

2001......................................... 112,533,187 14,535,461 558,381 1,001,641 128,628,670

Energy-Only Providers 

1990......................................... -- -- -- -- -- 

1991......................................... -- -- -- -- -- 

1992......................................... -- -- -- -- -- 

1993......................................... -- -- -- -- -- 

1994......................................... -- -- -- -- -- 

1995......................................... -- -- -- -- -- 

1996......................................... 1,597 433 29 0 2,059

1997......................................... 32,251 2,000 251 0 34,502

1998......................................... 311,498 54,404 1,736 0 367,638

1999......................................... 566,181 109,827 25,361 1,051 702,420

2000......................................... 1,211,891 290,796 14,003 20,429 1,537,119

2001......................................... 1,784,520 404,434 15,980 6,571 2,211,505

1

 Miscellaneous sales, such as sales for public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales included.

 Notes: ·See Glossary for definitions.·The number of ultimate customers is an average of the number of customers at the close of each month.·Utilities and energy service providers may 

classify commercial and industrial customers based on either NAICS codes or demands or usage falling within specified limits by rate schedule.·Changes from year to year in consumer 

counts, sales and revenues, particularly involving the commercial and industrial consumer sectors, may result from respondent implementation of changes in the definitions of consumers, 

and reclassifications. 

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 39

MD

DC

DE

NC

IL IN

TN

KY

OH

WV

NJ

CT

RI

MA

PA

NY

VT NH

GA

SC

NV

KS

LA

4,212

2,071

5,339 2,901 5,429

958

222

1,541

3,647

384

2,250

469

2,871

2,061

5,941

2,836

7,688

3,958

948

1,365

330 640

2,085

AL

AR

AZ

CA

CO

FL

IA

ID

ME

MI

MN

MO

MS

MT

ND

NE

NM

OK

OR SD

TX

UT

VA

WA

WI

WY

2,285

1,377

2,288

13,555

2,177

8,350

1,446

648

749

4,637

2,331

2,812

1,388

509

347

909

859

1,757

1,689 389

9,679

873

3,181

2,795

2,668

281

Customers

(Thousand Customers)

200 to 640

641 to 1,400

1,401 to 2,285

2,286 to 3,900

3,901 to 13,555

AK

279

HI

435

Total: 130,840 Thousand Customers

Figure 7.1 U.S. Electric Power Industry

Total Ultimate Customers by State, 2001

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
40 Energy Information Administration/Electric Power Annual 2001

Table 7.2. Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 1990 through 

2001

(Megawatthours)

Period Residential Commercial Industrial Others1 All Sectors

Total Electric Industry

1990......................................... 924,018,699 751,0 26,562 945,521,695 91,987,709 2,712,554,665

1991......................................... 955,417,350 765,663,613 946,583,391 94,338,686 2,762,003,040

1992......................................... 935,938,788 761,270,543 972,713,990 93,442,150 2,763,365,449

1993......................................... 994,780,818 794,573,370 977,164,250 94,943,902 2,861,462,340

1994......................................... 1,008,481,682 820,269,462 1,007,981,245 97,830,475 2,934,562,864

1995......................................... 1,042,501,471 862,684,775 1,012,693,350 95,406,993 3,013,286,589

1996......................................... 1,082,511,751 887,445,174 1,033,631,379 97,538,719 3,101,127,023

1997......................................... 1,075,880,098 928,632,774 1,038,196,892 102,900,664 3,145,610,428

1998......................................... 1,130,109,120 979,400,928 1,051,203,115 103,517,589 3,264,230,752

1999......................................... 1,144,923,069 1,001,995,720 1,058,216,608 106,951,684 3,312,087,081

2000......................................... 1,192,446,491 1,055,232,090 1,064,239,393 109,496,292 3,421,414,266

2001......................................... 1,202,646,738 1,089,153,700 964,224,282 113,756,089 3,369,781,529

Full-Service Providers

1990......................................... 924,018,699 751,026,562 945,521,695 91,987,709 2,712,554,665

1991......................................... 955,417,350 765,663,613 946,583,391 94,338,686 2,762,003,040

1992......................................... 935,938,788 761,270,543 972,713,990 93,442,150 2,763,365,449

1993......................................... 994,780,818 794,573,370 977,164,250 94,943,902 2,861,462,340

1994......................................... 1,008,481,682 820,269,462 1,007,981,245 97,830,475 2,934,562,864

1995......................................... 1,042,501,471 862,684,775 1,012,693,350 95,406,993 3,013,286,589

1996......................................... 1,082,490,541 887,424,657 1,030,356,028 97,538,719 3,097,809,945

1997......................................... 1,075,766,590 928,440,265 1,032,653,445 102,900,664 3,139,760,964

1998......................................... 1,127,734,988 968,528,009 1,040,037,873 103,517,589 3,239,818,459

1999......................................... 1,140,761,016 970,600,943 1,017,7 83,037 106,754,043 3,235,899,039

2000......................................... 1,183,137,429 1,000,865,367 1,017,722,945 107,824,323 3,309,550,064

2001......................................... 1,168,538,228 1,020,839,106 930,011,833 105,436,926 3,224,826,813

Energy-Only Providers 

Providers 1990......................................... -- -- -- -- -- 

1991......................................... -- -- -- -- -- 

1992......................................... -- -- -- -- -- 

1993......................................... -- -- -- -- -- 

1994......................................... -- -- -- -- -- 

1995......................................... -- -- -- -- -- 

1996......................................... 21,210 20,517 3,275,351 0 3,317,078

1997......................................... 113,508 192,509 5,543,447 0 5,849,464

1998......................................... 2,374,132 10,872,919 11,165,242 0 24,412,293

1999......................................... 4,162,053 31,394,777 40,433,571 197,641 76,188,042

2000......................................... 9,309,062 54,366,723 46,516,448 1,671,969 111,864,202

2001......................................... 34,108,510 68,314,594 34,212,449 8,319,163 144,954,716

1

 Miscellaneous sales, such as sales for public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales included.

 Notes: ·See Glossary for definitions.·Utilities and energy service providers may classify commercial and industrial customers based on either NAICS codes or demands or usage falling 

within limits specified by a rate schedule.·Changes from year to year in consumer counts, sales and revenues, particularly involving the commercial and industrial consumer sectors, may 

result from respondent implementation of changes in the definitions of consumers, and reclassifications.·As a consequence of unrecoverable high average wholesale power costs in 

California in 2000 and early 2001, the credit ratings of California's three major investor-owned utilities fell below investment grade by early 2001. The rapid and dramatic decline in the 

credit-worthiness of California's major investor-owned utilities virtually eliminated their ability through wholesale markets to meet the power requirements of their retail consumers. In 

response to the looming energy shortfall, the California State legislature authorized the California Department of Water Resources (CDWR), using its undamaged borrowing capability, to 

enter the wholesale markets on behalf of the California retail consumer effective on January 17, 2001 and for the period ending December 31, 2002. Also the California Public Utility 

Commission (CPUC) was required by statute to establish the procedures for facilitating the CDWR's participation in California retail sales, as well as retail revenue recovery mechanisms. 

Energy provided by the CDWR was delivered by the major investor-owned utilities in California. For this reason, and by agreement with the CDWR, energy sales for the calendar year 

2001 of approximately 58.9 million megawatthours and associated revenue, related to the CDWR's intervention in the crisis, are identified as "Energy Only Providers." 

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 41

NC

DC

MD SC

VA

DE

NJ

WV

KY

OH

PA

IN

TN

MS

CT

RI

MA

AL

LA

IL

GA

CA

NV

VT NH

AR

KS

NY

117,623

96,123

27,669

74,832

79,975

154,459

137,894

97,734

141,399

95,320

52,663

7,847

30,531

72,340

10,665

59,800

9,410 44,287

41,732

79,234

74,681

135,685

28,167

5,617 10,316

35,847

AZ

CO

FL

IA

ID

ME

MI

MN

MO

MT

ND

NE

NM

OK

OR SD

TX

UT

WA

WI

WY

62,282

235,439

44,236

199,698

117,790

39,213

21,097

11,836

101,955

60,288

73,213

11,165

9,810

24,723

18,727

49,667

45,885 8,627

316,062

23,217

79,666

65,184

12,950

Total Retail Sales

(Thousand MWh)

5,001 to 15,000

15,001 to 40,000

40,001 to 70,000

70,001 to 100,000

100,001 to 316,062

AK

5,428

HI

9,776

Total: 3,369,782 Thousand MWh

Figure 7.2 U.S. Electric Power Industry

Total Retail Sales by State, 2001

(Thousand MWh)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
42 Energy Information Administration/Electric Power Annual 2001

Table 7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 

1990 through 2001

(Million Dollars)1

Period Residential Commercial Industrial Others2 All Sectors

Total Electric Industry

1990......................................... 72,378 55,117 44,857 5,891 178,243

1991......................................... 76,828 57,655 45,737 6,138 186,359

1992......................................... 76,848 58,343 46,993 6,296 188,480

1993......................................... 82,814 61,521 47,357 6,528 198,220

1994......................................... 84,552 63,396 48,069 6,689 202,706

1995......................................... 87,610 66,365 47,175 6,567 207,717

1996......................................... 90,503 67,829 47,536 6,741 212,609

1997......................................... 90,704 70,497 47,023 7,110 215,334

1998......................................... 93,360 72,575 47,050 6,863 219,848

1999......................................... 93,483 72,771 46,846 6,796 219,896

2000......................................... 98,209 78,405 49,369 7,179 233,163

2001......................................... 103,671 86,354 48,573 7,999 246,597

Full-Service Providers

1990......................................... 72,378 55,117 44,857 5,891 178,243

1991......................................... 76,828 57,655 45,737 6,138 186,359

1992......................................... 76,848 58,343 46,993 6,296 188,480

1993......................................... 82,814 61,521 47,357 6,528 198,220

1994......................................... 84,552 63,396 48,069 6,689 202,706

1995......................................... 87,610 66,365 47,175 6,567 207,717

1996......................................... 90,501 67,827 47,385 6,741 212,455

1997......................................... 90,694 70,482 46,772 7,110 215,059

1998......................................... 93,164 71,769 46,550 6,863 218,346

1999......................................... 93,142 70,492 45,056 6,783 215,473

2000......................................... 97,086 73,704 46,465 6,988 224,243

2001......................................... 100,004 79,901 46,040 7,242 233,187

Energy-Only Providers 

Providers 1990......................................... -- -- -- -- -- 

1991......................................... -- -- -- -- -- 

1992......................................... -- -- -- -- -- 

1993......................................... -- -- -- -- -- 

1994......................................... -- -- -- -- -- 

1995......................................... -- -- -- -- -- 

19963....................................... 2 2 151 0 154

19973....................................... 10 15 251 0 275

19983....................................... 196 806 500 0 1,502

19993....................................... 340 2,279 1,791 13 4,423

2000......................................... 530 3,175 2,374 75 6,153

2001......................................... 2,607 4,978 1,984 640 10,209

Delivery-Only Service

1990......................................... -- -- -- -- -- 

1991......................................... -- -- -- -- -- 

1992......................................... -- -- -- -- -- 

1993......................................... -- -- -- -- -- 

1994......................................... -- -- -- -- -- 

1995......................................... -- -- -- -- -- 

1996......................................... -- -- -- -- -- 

1997......................................... -- -- -- -- -- 

1998......................................... -- -- -- -- -- 

1999......................................... -- -- -- -- -- 

2000......................................... 593 1,527 531 116 2,767

2001......................................... 1,060 1,475 549 117 3,201

1

 All "dollars" are nominal dollars.

2

 Miscellaneous sales, such as sales for public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales included.

3

 Revenue estimated based on retail sales reported on the Form EIA-861.

 Notes: ·See Glossary for definitions.·Utilities and energy service providers may classify commercial and industrial customers based on either NAICS codes or demands or usage falling 

within specified limits by a rate schedule.·Changes from year to y ear in consumer counts, sales and revenues, particularly involving the commercial and industrial consumer sectors, may 

result from respondent implementation of changes in the definitions of consumers, and reclassifications.·As a consequence of unrecoverable high average wholesale power costs in 

California in 2000 and early 2001, the credit ratings of California's three major investor-owned utilities fell below investment grade by early 2001. The rapid and dramatic decline in the 

credit-worthiness of California's major investor-owned utilities virtually eliminated their ability through wholesale markets to meet the power requirements of their retail consumers. In 

response to the looming energy shortfall, the California State legislature authorized the California Department of Water Resources (CDWR), using its undamaged borrowing capability, to 

enter the wholesale markets on behalf of the California retail consumer effective on January 17, 2001 and for the period ending December 31, 2002. Also the California Public Utility 

Commission (CPUC) was required by statute to establish the procedures for facilitating the CDWR's participation in California retail sales, as well as retail revenue recovery mechanisms. 

Energy provided by the CDWR was delivered by the major investor-owned utilities in California. For this reason, and by agreement with the CDWR, energy sales for the calendar year 

2001 of approximately 58.9 million megawatthours and associated revenue, related to the CDWR's intervention in the crisis, are identified as "Energy Only Providers."·Totals may not 

equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 43

NY

PA

VT

MD

DC

DE

NJ

TN

KY CT

MA

RI

SC

NC

WV

NH

NV

OH

LA

KS

16,449

748

3,983

6,813

740

3,393

5,360

847

2,937

6,062

5,951

1,403

10,274

7,804

4,317

2,213

5,200

607 1,129

AL

AR

AZ

CA

CO

FL

GA

IA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OK

OR SD

TX

UT

VA

WA

WI

WY

4,444

2,524

4,526

27,740

2,662

15,376

7,524

2,408

1,037

9,361 5,177

2,236

1,270

7,115

3,643

4,414

2,775

730

538

1,333

1,340

3,032

2,494

10,832

548

23,396

1,211

4,193

3,961

577

AK

572

OR

HI

1,374

Total: 246,597 Million Dollars

Total Revenues

(Millions of Dollars)

501 to 1,200

1,201 to 2,500

2,501 to 4,200

4,201 to 7,000

7,001 to 27,740

Figure 7.3 U.S. Electric Power Industry

Total Revenues by State, 2001

(Millions of Dollars)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
44 Energy Information Administration/Electric Power Annual 2001

Table 7.4. Average Revenue per Kilowatthour from Retail Sales to Ultimate Customers by Sector, by 

Provider, 1990 through 2001

(Cents)

Period Residential Commercial Industrial Others1 All Sectors

Total Electric Industry

1990......................................... 7.83 7.34 4.74 6.40 6.57

1991......................................... 8.04 7.53 4.83 6.51 6.75

1992......................................... 8.21 7.66 4.83 6.74 6.82

1993......................................... 8.32 7.74 4.85 6.88 6.93

1994......................................... 8.38 7.73 4.77 6.84 6.91

1995......................................... 8.40 7.69 4.66 6.88 6.89

1996......................................... 8.36 7.64 4.60 6.91 6.86

1997......................................... 8.43 7.59 4.53 6.91 6.85

1998......................................... 8.26 7.41 4.48 6.63 6.74

1999......................................... 8.16 7.26 4.43 6.35 6.64

2000......................................... 8.24 7.43 4.64 6.56 6.81

2001......................................... 8.62 7.93 5.04 7.03 7.32

Full-Service Providers

1990......................................... 7.83 7.34 4.74 6.40 6.57

1991......................................... 8.04 7.53 4.83 6.51 6.75

1992......................................... 8.21 7.66 4.83 6.74 6.82

1993......................................... 8.32 7.74 4.85 6.88 6.93

1994......................................... 8.38 7.73 4.77 6.84 6.91

1995......................................... 8.40 7.69 4.66 6.88 6.89

1996......................................... 8.36 7.64 4.60 6.91 6.86

1997......................................... 8.43 7.59 4.53 6.91 6.85

1998......................................... 8.26 7.41 4.48 6.63 6.74

1999......................................... 8.16 7.26 4.43 6.35 6.66

2000......................................... 8.21 7.36 4.57 6.48 6.78

2001......................................... 8.56 7.83 4.95 6.87 7.23

Energy-Only Providers

1990......................................... -- -- -- -- -- 

1991......................................... -- -- -- -- -- 

1992......................................... -- -- -- -- -- 

1993......................................... -- -- -- -- -- 

1994......................................... -- -- -- -- -- 

1995......................................... -- -- -- -- -- 

19962....................................... 8.36 7.64 4.60 -- 6.86

19972....................................... 8.43 7.59 4.53 -- 6.85

19982....................................... 8.26 7.41 4.48 -- 6.74

19992....................................... 8.16 7.26 4.43 6.35 6.66

2000......................................... 12.07 8.65 6.24 11.42 7.97

2001......................................... 10.75 9.45 7.41 9.09 9.25

1

 Miscellaneous sales, such as sales for public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales included.

2

 Average revenue estimated based on retail sales reported on the Form EIA-861.

 Notes: ·See Glossary for definitions.·Utiliti es and energy service providers may classify commercial and industrial customers based on either NAICS codes or demands or usage falling 

within specified limits by rate schedule.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric P ower Industry Report."
Energy Information Administration/Electric Power Annual 2001 45

NY

VT NH

PA

CT

MD

DC

MA

RI

NJ

NC DE TN

KY

WV

NV

KS

LA

11.63

7.87

6.66

11.51

10.79

9.62

9.42

7.01

10.8 10.95

6.63

5.07

5.62

4.24

7.86

6.96

AL

AR

AZ

CA

CO

FL

GA

IA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OH

OK

OR

SC

SD

TX

UT

VA

WA

WI

WY

5.61

6.05

7.27

11.78

6.02

7.7

6.39

6.14

4.92

6.9 5.3

6.24

10.73

6.98

6.04

6.03

6.26

6.54

5.48

5.39

7.16

6.65

6.1

5.44

7.86

5.77

6.35

7.4

5.21

6.19

5.26

6.08

4.46

AK

10.53

HI

14.05

U.S. Total Average Revenue per kWh is 7.32 Cents

Average Revenue

(Cents per kWh)

4.00 to 5.59

5.60 to 6.14

6.15 to 6.40

6.41 to 8.00

8.01 to 14.05

Figure 7.4 U.S. Electric Power Industry

Average Revenue per Kilowatthour by State, 2001

(Cents per kWh)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
46 Energy Information Administration/Electric Power Annual 2001

NV

KS

TN

KY

WV

LA

NY

VT NH

PA

MD

DC

DE

NJ NC

CT

MA

9.08 8.71 RI

6.26

6.32

7.92

14.06

12.67

8.12

12.49

12.13

10.91

12.48

10.24

8.61

7.7

7.83

AL

AR

AZ

CA

CO

FL

GA

IA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OH

OK

OR

SC

SD

TX

UT

VA

WA

WI

WY

7.01

7.72

8.3

12.65

7.47

8.59

7.72

8.41

6.01

6.92

7.66

5.58

11.65

8.26

7.61

7

7.37

6.88

6.47

6.5

8.74

8.37

7.27

6.29

9.62

7.69

7.42

8.86

6.72

7.8

5.7

7.9

6.77

AK

12.12

HI

16.34

U.S. Residential Average Revenue per kWh is 8.62 Cents

Residential Average Revenue

(Cents per kWh)

5.00 to 6.89

6.90 to 7.65

7.66 to 8.29

8.30 to 10.19

10.20 to 16.34

Figure 7.5 U.S. Electric Power Industry

Residential Average Revenue per Kilowatthour by State, 2001

(Cents per kWh)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 47

KS WV

NC

NV

TN

KY

LA

MD

DC

DE

NJ

PA

VT

NY

CT

NH

RI

MA

6.2

7.96

6.42

5.44

8.45

7.58

12.98

11.1 10.53

6.98

6.42

9.19

7.96

9.26

10.03

11.24

AL

AR

AZ

CA

CO

FL

GA

IA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OH

OK

OR

SC

SD

TX

UT

VA

WA

WI

WY

6.53

6.19

7.36

12.49

5.67

7.08

6.61

6.69

5.13

7.29 5.29

5.2

10.75

7.54

6.03

5.89

6.94

6.11

5.99

5.48

7.5

8.45

6.35

5.45

6.45

6.55

7.72

5.58

5.85

5.45

6.34

5.41

AK

10.28

HI

14.81

U.S. Commercial Average Revenue per kWh is 7.93 Cents

Commercial Average Revenue

(Cents per kWh)

5.00 to 5.69

5.70 to 6.34

6.35 to 6.99

7.00 to 8.49

8.50 to 14.81

Figure 7.6 U.S. Electric Power Industry

Commercial Average Revenue per Kilowatthour by State, 2001

(Cents per kWh)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
48 Energy Information Administration/Electric Power Annual 2001

SC

GA

NC

CT

RI

MA

MD

NJ

DC

DE

VT NH

PA

NY

WV

TN

KY

NV

LA

KS

4.72

4.28

10.13

9.79

7.62

8.27

5.08

4.41

4.81

7.89 9.11

5.51

4.12

4.92 6.56

3.74

5.58

AL

AR

AZ

CA

CO

FL

IA

ID

IL IN

ME

MI

MN

MO

MS

MT

ND

NE

NM

OH

OK

OR SD

TX

UT

VA

WA

WI

WY

3.8

4.43

5.24

9.81

4.48

5.33

4.18

3.71

4.11

4.55

3.04

8.62

5.09

4.52

4.39

4.4

6.54

3.98

3.76

5.45

4.3

4.29

4.21

5.89

3.86

4.46

5.31

3.53

4.17

4.48

4.37

3.43

AK

7.61

HI

11.68

U.S. Industrial Average Revenue per kWh is 5.04 Cents

Industrial Average Revenue

(Cents per kWh)

3.00 to 3.99

4.00 to 4.29

4.30 to 4.69

4.70 to 5.99

6.00 to 11.68

Figure 7.7 U.S. Electric Power Industry

Industrial Average Revenue per Kilowatthour by State, 2001

(Cents per kWh)

Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 49

Chapter 8. Revenue and Expense Statistics
50 Energy Information Administration/Electric Power Annual 2001

Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1990 

through 2001

(Million Dollars)1

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Utility Operating Revenues 267,525 235,336 214,160 218,175 215,083 207,459 199,967 196,282 193,638 185,493 182,451 173,000

Electric Utility........................................................... 244,219 214,707 197,578 201,970 195,898 188,901 183,655 179,307 176,354 169,488 166,804 157,279

Other Utility............................................................... 23,306 20,630 16,583 16,205 19,185 18,558 16,312 16,974 17,283 16,005 15,647 15,721

Utility Operating Expenses 235,198 210,324 182,258 186,498 182,796 173,920 165,321 164,207 161,908 153,682 150,362 142,471

Electric Utility........................................................... 213,733 191,329 167,266 171,689 165,443 156,938 150,599 148,663 146,118 139,009 135,948 127,901

Operation................................................................ 159,929 132,662 108,461 110,759 104,337 97,207 91,881 93,108 91,328 87,272 85,934 81,086

Production.............................................................. 136,089 107,352 83,555 85,956 80,153 73,437 68,983 69,269 68,781 66,980 66,102 62,501

Cost of Fuel................................ 29,490 32,555 29,826 31,252 31,861 30,706 29,122 30,108 31,214 30,254 31,312 32,635

Purchased Power................................98,231 61,969 43,258 42,612 37,991 32,987 29,981 29,213 27,716 26,212 24,169 20,341

Other................................................................ 8,368 12,828 10,470 12,092 10,301 9,744 9,880 9,948 9,851 10,513 10,620 9,526

Transmission................................ 2,365 2,699 2,423 2,197 1,915 1,503 1,425 1,361 1,354 1,308 1,247 1,130

Distribution............................................................ 3,217 3,115 2,956 2,804 2,700 2,604 2,561 2,581 2,595 2,499 2,530 2,444

Customer Accounts................................4,434 4,246 4,195 4,021 3,767 3,848 3,613 3,546 3,418 3,347 3,203 3,247

Customer Service ................................ 1,856 1,839 1,889 1,955 1,197 1,920 1,922 1,956 1,852 1,531 1,452 1,181

Sales................................................................282 403 492 514 501 435 348 232 203 199 203 212

Administrative and General.............................. 11,686 13,009 12,951 13,311 13,384 13,458 13,028 14,163 13,124 11,409 11,196 10,371

Maintenance............................................................ 11,167 12,185 12,276 12,486 12,368 12,050 11,767 12,022 12,447 12,195 12,024 11,779

Depreciation ............................................................ 20,845 22,761 23,968 24,122 23,072 21,194 19,885 18,679 18,099 17,092 16,127 14,889

Taxes and Other................................ 21,792 23,721 22,561 24,322 25,667 26,488 27,065 24,854 24,244 22,450 21,863 20,146

Other Utility............................................................... 21,465 18,995 14,992 14,809 17,353 16,983 14,722 15,544 15,790 14,673 14,414 14,571

Net Utility Operating Income............................... 32,327 25,012 31,902 31,677 32,286 33,539 34,646 32,074 31,730 31,811 32,089 30,529

1

 All "dollars" are nominal dollars.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Electric Utilities, Licensees and Others."

Table 8.2. Average Operating Expenses for Major U.S. Investor-Owned Electric Utilities, 1990 

through 2001

(Mills per Kilowatthour)

Plant Type 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Operation

Nuclear.......................................................................... 8.30 8.41 8.93 9.98 11.02 9.47 9.43 9.79 10.20 10.43 10.49 10.04

Fossil Steam................................................................. 2.40 2.31 2.21 2.17 2.22 2.25 2.38 2.32 2.37 2.38 2.29 2.21

Hydroelectric1.............................................................. 5.79 4.74 4.17 3.85 3.29 3.87 3.69 4.53 3.82 4.33 3.88 3.35

Gas Turbine and Small Scale 2................................. 3.15 4.57 5.16 3.85 4.43 5.08 3.57 4.58 6.47 10.18 9.61 8.76

Maintenance

Nuclear.......................................................................... 5.01 4.93 5.13 5.79 6.90 5.68 5.21 5.20 5.73 5.93 5.50 5.68

Fossil Steam................................................................. 2.61 2.45 2.38 2.41 2.43 2.49 2.65 2.82 2.96 2.95 2.98 2.97

Hydroelectric1.............................................................. 3.97 2.99 2.60 2.00 2.49 2.08 2.19 2.90 2.65 3.30 2.89 2.58

Gas Turbine and Small Scale2................................. 3.33 3.50 4.80 3.43 3.43 4.98 4.28 5.39 7.52 12.15 12.93 12.23

Fuel

Nuclear.......................................................................... 4.67 4.95 5.17 5.39 5.42 5.50 5.75 5.87 5.88 6.12 6.71 7.18

Fossil Steam................................................................. 18.13 17.69 15.62 15.94 16.80 16.51 16.07 16.67 17.65 17.49 17.91 18.55

Hydroelectric1.............................................................. -- -- -- -- -- -- -- -- -- -- -- --

Gas Turbine and Small Scale2................................. 43.56 39.19 28.72 23.02 24.94 30.58 20.83 22.19 26.39 28.59 30.96 32.57

Total

Nuclear.......................................................................... 17.98 18.28 19.23 21.16 23.33 20.65 20.39 20.86 21.80 22.48 22.70 22.91

Fossil Steam................................................................. 23.14 22.44 20.22 20.52 21.45 21.25 21.11 21.80 22.97 22.83 23.17 23.72

Hydroelectric1.............................................................. 9.76 7.73 6.77 5.86 5.78 5.95 5.89 7.43 6.47 7.63 6.76 5.93

Gas Turbine and Small Scale2................................. 50.04 47.26 38.68 30.30 32.80 40.64 28.67 32.16 40.38 50.92 53.51 53.56

1

 Conventional hydro and pumped storage.

2

 Gas turbine, internal combustion, photovoltaic, and wind plants.

 Notes: ·Expenses are average expenses weighted by net generation.·A mill is a monetary cost and billing unit equal to 1/1000 of the U.S. dollar (equivalent to 1/10 of one cent).·Totals 

may not equal sum of components because of independent rounding.

 Source: Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Electric Utilities, Licensees and Others."
Energy Information Administration/Electric Power Annual 2001 51

Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With 

Generation Facilities), 1990 through 2001

(Million Dollars)1

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Operating Revenue - Electric ............................... 38,028 31,843 26,767 26,155 25,397 24,207 23,473 23,267 22,522 21,686 21,083 20,470

Operating Expenses - Electric .............................. 32,811 26,244 21,274 20,880 20,425 19,084 18,959 18,649 18,162 17,191 16,887 16,461

Operation Including Fuel ................................ 25,941 19,575 15,386 15,120 14,917 13,768 13,653 13,578 13,242 12,527 12,155 11,948

Production............................................................... 21,783 15,742 11,923 11,608 11,481 11,080 10,385 10,445 10,254 9,712 9,465 9,525

Transmission.......................................................... 785 781 732 773 725 344 628 610 580 535 509 472

Distribution............................................................. 605 574 516 603 538 497 426 430 408 389 363 329

Customer Accounts................................ 600 507 415 390 390 365 323 317 315 299 289 273

Customer Service ................................ 263 211 160 127 133 103 102 104 94 83 74 60

Sales................................................................ 73 66 49 51 46 18 20 22 17 18 18 18

Administrative and General............................... 1,832 1,695 1,591 1,567 1,602 1,360 1,769 1,651 1,573 1,492 1,437 1,271

Maintenance ............................................................... 1,905 1,815 1,686 1,631 1,609 1,638 1,575 1,584 1,565 1,565 1,446 1,456

Depreciation and Amortization........................... 4,009 3,919R3,505R3,459R3,239R3,160R2,934 2,721R2,596R2,417R2,301 2,076

Taxes and Tax Equivalents................................ 954 936 697 670 660 662 797 766 759 681 596 550

Net Electric Operating Income............................ 5,217 5,598 5,493 5,275 4,972 5,123 4,514 4,618 4,360 4,496 4,196 4,010

1 All “dollars” are nominal dollars.

 R = Revised.

 Notes: ·Totals may not equal sum of components because of independent rounding.·The 1998-2001 data represent those utilities meeting a threshold of 150 million kilowatthours of 

customer sales or resales. The 1990-1997 data represent those utilities meeting a threshold of 120 million kilowatthours of customer sales or resales.

 Source: Energy Information Administration, EIA Form-412, "Annual Electric Industry Financial Report," and predecessor forms.

Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without 

Generation Facilities), 1990 through 2001

(Million Dollars)1

Description 200122000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Operating Revenue - Electric ............................... 10,417 9,904 9,354 8,790 8,586 8,582 8,435 7,996 7,523 7,247 7,120 6,979

Operating Expenses - Electric .............................. 9,820 9,355 8,737 8,245 8,033 8,123 7,979 7,567 7,063 6,844 6,860 6,741

Operation Including Fuel ................................ 8,864 8,424 7,874 7,437 7,117 7,359 7,173 6,858 6,425 6,245 6,119 6,030

Production............................................................... 7,863 7,486 7,015 6,661 6,240 6,578 6,422 6,185 5,761 5,617 5,524 5,479

Transmission.......................................................... 61 64 48 44 57 51 35 34 34 33 32 30

Distribution............................................................. 311 280 261 230 304 234 204 190 189 176 164 145

Customer Accounts................................ 164 155 143 130 139 141 125 119 117 109 102 99

Customer Service ................................ 26 22 22 21 16 18 18 17 17 16 16 14

Sales................................................................ 15 16 14 9 13 12 10 10 9 12 12 11

Administrative and General............................... 423 402 371 342 348 325 358 303 298 282 270 252

Maintenance ............................................................... 304 286 272 263 338 244 250 234 207 193 186 192

Depreciation and Amortization........................... 405 394R369R330R354R322R313 274R257R251R247 231

Taxes and Tax Equivalents................................ 247 251 223 215 225 206 244 201 175 155 138 133

Net Electric Operating Income............................ 597 549 617 545 552 459 457 429 460 404 260 238

1 All “dollars” are nominal dollars.

2

 For 2001, California Department of Water Resources - Electric Energy Fund data were excluded from these statistics. In response to the looming energy shortfall in California, the 

California State legislature authorized the California Department of Water Resources, using its undamaged borrowing capability, to enter the wholesale markets on behalf of the California 

retail customers effective on January 17, 2001, and for the period ending December 31, 2002. Their 2001 revenues collected were $5,501,000,000 with purchase power costs of 

$12,055,000,000. The California Public Utility Commission was required by statute to establish the procedure for retail revenue recovery mechanisms for these purchase power costs in 

the future.

 R = Revised.

 Notes: ·Totals may not equal sum of components because of independent rounding.·The 1998-2001 data represent those utilities meeting a threshold of 150 million kilowatthours of 

customer sales or resales. The 1990-1997 data represent those utilities meeting a threshold of 120 million kilowatthours of customer sales or resales.

 Source: Energy Information Administration, EIA Form-412, "Annual Electric Industry Financial Report," and predecessor forms.
52 Energy Information Administration/Electric Power Annual 2001

Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1990 through 

2001

(Million Dollars)1

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Operating Revenue - Electric ............................... 12,136 10,685 10,186 9,780 8,833 9,082 8,743 8,552 8,141 7,872 8,194 8,197

Operating Expenses - Electric .............................. 9,785 8,139 7,775 7,099 5,999 6,390 6,162 6,303 6,056 5,883 5,288 5,428

Operation Including Fuel ...................................... 7,033 5,873 5,412 5,184 4,073 4,514 4,615 4,877 4,827 4,595 4,115 3,989

Production............................................................... 5,912 5,497 4,890 4,735 3,686 4,109 4,219 4,464 4,272 4,144 3,650 3,564

Transmission.......................................................... 334 332 349 323 327 328 290 304 319 272 260 298

Distribution............................................................. 1 2 2 2 1 1 2 2 2 2 3 2

Customer Accounts.............................................. 16 6 1 1 1 3 2 4 4 3 4 4

Customer Service .................................................. 60 48 50 51 42 46 29 28 27 26 23 22

Sales......................................................................... 6 10 28 14 13 7 41 9 6 5 4 4

Administrative and General............................... 705 467 528 535 444 451 431 442 578 537 529 424

Maintenance ............................................................... 521 488 436 476 441 432 398 377 381 394 358 329

Depreciation and Amortization........................... 1,915 1,471 1,623 1,175 1,214 1,187 896 746 611 653 572 826

Taxes and Tax Equivalents................................... 315 308 304 264 272 256 252 56 237 241 243 283

Net Electric Operating Income............................ 2,352 2,546 2,411 2,681 2,834 2,692 2,581 2,249 2,085 1,989 2,906 2,769

1 All “dollars” are nominal dollars.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-412, "Annual Electric Industry Financial Report," and predecessor forms.

Table 8.6. Revenue and Expense Statistics for Major U.S. Cooperative Borrower Owned Electric 

Utilities, 1990 through 2001

(Million Dollars)1

Description 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Operating Revenue - Electric ............................... 26,402 25,629 23,824 23,988 23,321 24,424 24,6 09 23,777 24,873 23,325 22,784 22,226

Operation and Maintenance Expenses ............. 23,714 22,982 21,283 21,223 20,715 23,149 21,741 20,993 21,675 20,353 19,887 19,169

Operation Including Fuel ................................ 21,661 20,942 19,336 19,280 18,405 20,748 19,334 18,650 19,292 18,038 17,655 17,037

Production............................................................... 17,618 17,080 15,706 15,683 15,105 17,422 15,907 15,471 16,101 15,059 14,836 14,347

Transmission.......................................................... 551 525 466 452 339 372 366 322 336 324 313 318

Distribution............................................................. 1,601 1,530 1,451 1,440 1,134 1,133 1,127 1,053 1,044 980 917 874

Customer Accounts.............................................. 515 487 455 446 382 375 383 374 386 369 349 334

Customer Service .................................................. 135 133 132 132 118 118 112 105 101 95 89 83

Sales......................................................................... 88 82 81 77 61 72 72 61 57 52 47 42

Administrative and General............................... 1,154 1,104 1,045 1,050 1,266 1,257 1,367 1,265 1,265 1,160 1,104 1,039

Depreciation and Amortization........................... 1,889 1,820 1,747 1,732 1,727 1,787 1,778 1,742 1,768 1,709 1,639 1,617

Taxes and Tax Equivalents................................ 164 220 200 211 583 614 628 601 616 605 593 515

Net Electric Operating Income............................ 2,688 2,647 2,541 2,764 2,606 2,872 2,868 2,784 3,197 2,973 2,897 3,057

1 All “dollars” are nominal dollars.

 Note: Totals may not equal sum of components because of independent rounding. 

 Source: U.S. Department of Agriculture, Rural Utilities Service (prior Rural Electrification Administration), Statistical Report, Rural Electric Borrowers publications, as compiled from 

RUS Form 7 and RUS Form 12.
Energy Information Administration/Electric Power Annual 2001 53

Chapter 9. Demand-Side Management
54 Energy Information Administration/Electric Power Annual 2001

Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1990 

through 2001

(Megawatts)

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Total Actual Peak Load Reduction1........................... 24,955 22,901 26,455 27,231 25,284 29,893 29,561 25,001 23,069 17,204 15,619 13,704

Energy Efficiency .......................................................... 13,027 12,873 13,452 13,591 13,326 14,243 13,212 11,662 10,368 7,890 NA NA

Load Management......................................................... 11,928 10,027 13,003 13,640 11,958 15,650 16,347 13,340 12,701 9,314 NA NA

1

 Represents the actual reduction in annual peak load achieved by all program participants during the reporting year, at the time of annual peak load, as opposed to the installed peak load 

reduction capability (Potential Peak Load Reduction).

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1990 through 

2001

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Annual Effects – Energy Efficiency

Large Utilities1

Actual Peak Load Reduction (MW)2........................ 13,027 12,873 13,452 13,591 13,327 14,243 13,212 11,662 10,368 7,890 NA NA

Energy Savings (Thousand MWh) ........................... 52,946 52,827 49,691 48,775 55,453 59,853 55,328 49,720 41,119 31,779 NA NA

Annual Effects – Load Management

Large Utilities 1

Actual Peak Load Reduction (MW).......................... 11,928 10,027 13,003 13,640 11,958 15,650 16,349 13,339 12,701 9,314 NA NA

Potential Peak Load Reductions (MW) 3................. 27,730 28,496 30,118 27,840 27,911 34,101 33,817 31,255 29,140 24,552 NA NA

Energy Savings (Thousand MWh) ........................... 1,816 875 872 392 953 1,989 2,093 2,763 4,175 4,114 NA NA

1

 Refers to electric utilities with sales to ultimate customers or sales for resale greater than or equal to 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

2

 Represents the actual reduction in annual peak load achieved by customers, at the time of annual peak load.

3

 Represents the potential peak load reduction as a result of load management, and also includes the actual p eak load reduction achieved by energy efficiency programs.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1990 

through 2001

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Incremental Effects – Energy Efficiency

Large Utilities1

Actual Peak Load Reduction (MW)2........................ 999 720 695 796 1,065 1,381 1,561 1,751 1,839 1,501 NA NA

Energy Savings (Thousand MWh)............................ 4,402 3,284 3,027 3,324 4,661 6,361 7,901 8,054 8,601 5,338 NA NA

Small Utilities3

Actual Peak Load Reduction (MW)2........................ 20 25 22 12 12 2 7 9 9 17 NA NA

Energy Savings (Thousand MWh)............................ 8 8 8 37 10 7 16 11 12 12 NA NA

Incremental Effects – Load Management

Large Utilities 1

Actual Peak Load Reduction (MW) 2....................... 1,297 919 1,568 1,821 1,261 5,027 3,039 1,418 2,809 2,437 NA NA

Potential Peak Load Reductions (MW)4.................. 2,448 2,439 6,457 2,832 2,475 2,309 4,930 5,153 5,298 6,077 NA NA

Energy Savings (Thousand MWh)............................ 905 63 67 37 171 482 321 178 508 447 NA NA

Small Utilities 3

Actual Peak Load Reduction (MW) 2....................... 45 137 54 124 130 50 29 56 110 315 NA NA

Potential Peak Load Reductions (MW) 4................. 177 190 84 160 183 90 41 81 291 657 NA NA

Energy Savings (Thousand MWh)............................ 4 9 2 7 19 6 3 8 11 37 NA NA

1

 Refers to electric utilities with sales to ultimate customers or sales for resale greater than or equal to 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

2

 Represents the actual reduction in annual peak load achieved by customers, at the time of annual peak load.

3

 Refers to electric utilities with sales to ultimate customers or sales for resale less than 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

4

 Represents the potential peak load reduction as a result of load management, and also includes the actual peak load reduction achieved by energy efficiency programs.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 55

Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1990 through 2001

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Actual Peak Load Reductions1(MW) 

Large Utilities2

Residential............................................... 9,619 9,446 9,976 9,327 10,799 11,471 10,930 9,638 8,851 7,606 NA NA

Commercial............................................. 8,210 6,987 7,777 9,482 8,174 8,678 8,057 6,927 7,541 4,598 NA NA

Industrial.................................................. 6,553 6,141 6,360 7,927 5,812 9,083 10,033 7,977 6,270 4,467 NA NA

Other.......................................................... 573 327 2,342 495 498 661 545 460 407 532 NA NA

Total.................................................... 24,955 22,901 26,455 27,231 25,284 29,893 29,561 25,001 23,069 17,204 15,619 13,704

Potential Peak Load Reductions3(MW)

Large Utilities 2

Residential............................................... 12,274 12,970 12,812 13,022 16,662 14,697 14,047 13,851 12,868 11,058 NA NA

Commercial............................................. 10,469 9,114 8,868 12,210 12,896 12,452 11,495 9,915 11,821 7,002 NA NA

Industrial.................................................. 17,344 18,775 17,237 15,512 11,035 20,275 20,715 18,271 13,957 13,367 NA NA

Other.......................................................... 670 510 4,653 686 644 921 772 881 862 1,014 NA NA

Total.................................................... 40,757 41,369 43,570 41,430 41,237 48,344 47,029 42,917 39,508 32,442 NA NA

Energy Savings (Thousand MWh)

Large Utilities 2

Residential............................................... 16,027 16,287 16,263 16,564 17,830 20,585 20,253 21,028 19,241 15,322 NA NA

Commercial............................................. 24,217 25,660 23,375 25,125 27,898 29,186 26,187 21,773 16,567 12,301 NA NA

Industrial.................................................. 11,313 9,160 8,156 3,347 8,684 10,493 9,620 8,568 8,644 7,192 NA NA

Other.......................................................... 3,206 2,593 2,770 831 1,694 1,578 1,360 1,114 842 748 NA NA

Total.................................................... 54,762 53,701 50,563 49,167 56,406 61,842 57,421 52,483 45,294 35,563 24,848 20,458

1 Represents the actual reduction in annual peak load achieved by customers, at the time of annual peak load.

2

 Refers to electric utilities with sales to ultimate customers or sales for resale greater than or equal to 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

3 Represents the potential peak load reduction as a result of load management, and also includes the actual peak load reduction achieved by energy efficiency programs.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.5. Demand-Side Management Program Incremental Effects by Sector, 1990 through 2001

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Actual Peak Load Reductions1 (MW)

Large Utilities2

Residential............................................... 790 572 605 599 743 792 860 1,083 1,147 1,112 NA NA

Commercial............................................. 742 515 684 1176 699 935 1176 1,244 1,427 1,251 NA NA

Industrial.................................................. 640 502 929 799 836 1,870 2,426 785 2,014 1,451 NA NA

Other......................................................... 124 50 45 43 48 93 139 57 61 108 NA NA

Total................................................... 2,296 1,640 2,263 2,617 2,326 3,690 4,601 3,169 4,648 3,922 NA NA

Small Utilities3

Residential............................................... 32 37 27 35 40 30 20 27 76 139 NA NA

Commercial............................................. 15 37 22 34 21 9 10 7 35 32 NA NA

Industrial.................................................. 16 62 7 56 61 8 4 24 47 113 NA NA

Other......................................................... 2 26 19 10 20 5 2 6 28 48 NA NA

Total................................................... 65 162 76 136 142 52 36 65 185 332 NA NA

U.S. Total...................................................... 2,361 1,802 2,339 2,753 2,468 3,742 4,637 3,234 4,833 4,254 NA NA

Potential Peak Load Reductions4 (MW)

Large Utilities 2

Residential............................................... 900 699 753 751 960 950 1,231 1,467 NA NA NA NA

Commercial............................................. 1,115 565 718 1,863 853 1,512 1,697 2,115 NA NA NA NA

Industrial.................................................. 1,277 1,815 5,612 1,438 1,669 3,800 3,368 1,997 NA NA NA NA

Other......................................................... 155 79 68 76 58 146 195 326 NA NA NA NA

Total................................................... 3,447 3,159 7,151 3,628 3,540 6,408 6,491 5,905 7,157 7,578 NA NA

Small Utilities 3

Residential............................................... 158 55 41 49 59 46 27 38 NA NA NA NA

Commercial............................................. 19 51 25 41 35 17 13 12 NA NA NA NA

Industrial.................................................. 18 64 9 70 72 16 6 31 NA NA NA NA

Other......................................................... 2 44 31 12 30 13 2 8 NA NA NA NA

Total................................................... 197 215 106 172 196 92 48 89 300 674 NA NA

U.S. Total...................................................... 3,644 3,374 7,257 3,800 3,736 6,500 6,539 5,994 7,457 8,252 NA NA

Energy Savings (Thousand MWh)

Large Utilities 2

Residential............................................... 1,365 856 990 909 1,055 1,179 1,630 2,194 2,780 2,165 NA NA

Commercial............................................. 1,867 1,780 1,502 1,703 2,382 3,537 4,594 4,449 4,557 3,333 NA NA

Industrial.................................................. 1,698 547 475 645 1,059 1,787 1,678 1,325 1,518 1,014 NA NA

Other......................................................... 376 164 127 104 336 341 320 262 125 151 NA NA

Total................................................... 5,307 3,347 3,094 3,361 4,832 6,844 8,222 8,230 8,980 6,664 NA NA

Small Utilities 3

Residential............................................... 5 9 4 8 10 7 9 13 13 14 NA NA

Commercial............................................. 3 4 3 6 3 3 5 3 4 5 NA NA

Industrial.................................................. 2 1 1 3 8 2 5 1 3 26 NA NA

Other......................................................... 1 3 1 1 7 1 2 1 2 3 NA NA

Total................................................... 12 17 9 18 28 13 21 18 22 48 NA NA

U.S. Total...................................................... 5,318 3,364 3,103 3,379 4,860 6,857 8,243 8,248 9,002 6,712 NA NA

1

 Represents the actual reduction in annual peak load achieved by customers, at the time of annual peak load.

2

 Refers to electric utilities with sales to ultimate customers or sales for resale greater than or equal to 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

3

 Refers to electric utilities with sales to ultimate customers or sales for resale less than 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

4

 Represents the potential peak load reduction as a result of load management, and also includes the actual peak load reduction achieved by energy efficiency programs.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
56 Energy Information Administration/Electric Power Annual 2001

Table 9.6. Demand-Side Management Program Energy Savings, 1990 through 2001

(Megawatts)

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Total Energy Savings1................................ 54,762 53,701 50,563 49,167 56,406 61,842 57,421 52,483 45,294 35,563 24,848 20,458

Energy Efficiency..............................................52,946 52,827 49,691 48,775 55,453 59,853 55,328 49,720 41,119 31,779 NA NA

Load Management............................................. 1,816 875 872 392 953 1,989 2,093 2,763 4,175 4,114 NA NA

1

 Refers to electric utilities with sales to ultimate customers or sales for resale greater than or equal to 150 million kilowatthours in 1998 -2001 and 120 million kilowatthours in 1990-1997.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.7. Demand-Side Management Program Direct and Indirect Costs, 1990 through 2001

(Thousand Dollars)

Item 2001 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990

Direct Cost1................................................................ 1,463,423 1,384,232 1,250,689 1,233,018 1,347,245 1,623,588 2,004,942 2,254,059 2,289,267 NA NA NA

Energy Efficiency................................ 1,101,517 938,666 820,108 766,384 892,468 1,051,922 1,408,542 1,592,125 1,607,952 NA NA NA

Load Management................................ 361,906 445,566 430,581 466,634 454,777 571,666 596,400 661,934 681,315 NA NA NA

Indirect Cost2................................................................ 176,001 180,669 172,955 187,902 288,775 278,609 416,342 461,598 454,266 NA NA NA

Total DSM Cost3................................1,639,424 1,564,901 1,423,644 1,420,920 1,636,020 1,902,197 2,421,284 2,715,657 2,743,533 2,348,094 1,803,773 1,177,457

1

 Reflects electric utility cost incurred during the year that are identified with one of the demand-side program categories.

2

 Reflects costs not directly attributable to specific programs.

3

 Reflects the sum of the total incurred direct and indirect utility cost for the year. Utility costs reflect the total cash expenditures for the year, in nominal dollars, that flows out to support 

demand-side management programs.

 NA = Not available.

 Note: Totals may not equal sum of components because of independent rounding.

 Source: Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
Energy Information Administration/Electric Power Annual 2001 57

Appendices
Energy Information Administration/Electric Power Annual 2001 59

Appendix A

Technical Notes

The Energy Information Administration (EIA) has

comprehensively reviewed and revised how it collects, 

estimates, and reports fuel use for facilities producing 

electricity. Appendix B provides detail on these changes 

and describes the reasoning behind the changes and their 

effects on EIA forms and publications. Following is a 

description of the ongoing data quality efforts and sources 

of data for the Electric Power Annual.

Data Quality

The Electric Power Annual (EPA) is prepared by the

Electric Power Division, Office of Coal, Nuclear, Electric 

and Alternate Fuels (CNEAF), Energy Information

Administration (EIA), U.S. Department of Energy. 

Quality statistics begin with the collection of the correct 

data. To assure this, the CNEAF office performs routine 

reviews of the data collected and the forms on which it is 

collected. Additionally, to assure that the data is collected 

from the correct parties, CNEAF routinely reviews the 

frames for each data collection. 

Automatic, computerized verification of keyed input,

review by subject matter specialists, and follow-up with 

non-respondents also assure quality statistics. To ensure 

the quality standards established by the EIA, formulas that 

use the past history of data values in the database have 

been designed and implemented to check data input for 

errors automatically. Data values that fall outside the

ranges prescribed in the formulas are verified by

telephoning respondents to resolve any discrepancies. 

Also survey non-respondents are identified and contacted. 

Reliability of Data 

Annual survey data have nonsampling errors. Nonsampling errors can be attributed to many sources: (1) 

inability to obtain complete information about all cases in 

the sample (i.e., nonresponse); (2) response errors; (3) 

definitional difficulties; (4) differences in the

interpretation of questions; (5) mistakes in recording or 

coding the data obtained; and (6) other errors of collection, 

response, coverage, and estimation for missing data. 

Although no direct measurement of the biases due to

nonsampling errors can be obtained, precautionary steps 

were taken in all phases of the frame development and 

data collection, processing, and tabulation processes, in an 

effort to minimize their influence. See the Data 

Processing and Data System Editing section for each EIA 

Form for an in depth discussion of how the sampling and 

nonsampling errors are handled in each case. 

Data Revision Procedure

The CNEAF office has adopted the following policy with 

respect to the revision and correction of recurrent data in 

energy publications:

 1. Annual survey data collected by CNEAF are 

published either as preliminary or final when 

first appearing in a data report. Data initially 

released as preliminary will be so noted in the 

report. These data will be revised, if necessary, 

and declared final in the next publication of the 

data.

 2. All monthly survey data collected by this office 

are published as preliminary. These data are 

typically revised only after the completion of 

the 12-month cycle of the data. No revisions 

are made to the published data before this

unless major errors are discovered that may 

affect the national total.

 3. The magnitudes of changes due to revisions experienced in the past will be included in the data 

reports, so that the reader can assess the

accuracy of the data.

 4. After data are published as final, corrections 

will be made only in the event of a difference of 

one percent or greater at the national level. 

Corrections for differences that are less than the 

one percent or greater threshold are left to the 

dis cretion of the Office Director.

The Electric Power Annual presents the most current

annual data available to the EIA. The statistics may differ 

from those published previously in EIA publications due 

to corrections, revisions, or other adjustments to the data 

subsequent to its original release. On a chapter basis, the 

status (preliminary versus final) of the data contained in 

the EPA follows:

• Chapter 1, Generation Based on data from the 

Form EIA-906. All data are final.

• Chapter 2, Capacity Based on data from the 

Form EIA-860. All data are final.

• Chapter 3, Demand, Capacity Resources, and 

Capacity Margins Based on data from the Form 

EIA-411. All data are final.

• Chapter 4, Fuel Based on data from the Form 

EIA-906 and FERC Form 423. All data are final.

• Chapter 5, Emissions Based on data from the 

Form EIA-767 and the Form EIA-906. All data 

are final.

• Chapter 6, Trade Based on data from the Form 

EIA-861 and on import/export data from the

National Energy Board of Canada and the Office 

of Fuels Programs, Fossil Energy, Form FE781R. All data are final.
60 Energy Information Administration/Electric Power Annual 2001

x100,

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1

2 1

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• Chapter 7, Retail Customers, Sales, and

Revenues Based on data on sales, revenue, and 

average revenue per kilowatthour from the Form 

EIA-861. All data are final.

• Chapter 8, Revenue and Expense Statistics

Based on financial data from the Federal Energy 

Regulatory Commission Form 1, Form EIA-412, 

RUS Form 7, and RUS Form 12. All data are 

final.

• Chapter 9, Demand-Side Management Based 

on data on demand-side management from the 

Form EIA-861. All data are final.

Data Sources

For Electric Power Annual

Data published in the Electric Power Annual are compiled 

from forms filed annually or aggregated to an annual basis 

from monthly forms by electric utilities and electricity 

generators. The EIA forms used are: 

• Form EIA-411, “Coordinated Bulk Power Supply 

Program Report;” 

• Form EIA-412, “Annual Electric Industry

Financial Report;” 

• Form EIA-767, “Steam-Electric Plant Operation 

and Design Report;” 

• Form EIA-860, “Annual Electric Generator

Report;” 

• Form EIA-861, “Annual Electric Power Industry 

Report;” and 

• Form EIA-906, “Power Plant Report.”

Each of these forms is summarized below.

Survey data from other Federal sources is also utilized for 

this publication. They include: 

• Fossil Energy Form FE-781R, “Annual Report of 

International Electric Export/Import Data;” 

(Department of Energy, Office of Emergency

Planning Department of Energy, Office of Fuels

Programs); 

• Federal Energy Regulatory Commission (FERC) 

Form 1, “Annual Report of Major Electric

Utilities, Licensees, and Others;” 

• Federal Energy Regulatory Commission Form

423, “Cost and Quality of Fuels for Electric

Plants;” 

• Rural Utility Services (RUS) Form 7, “Financial 

and Statistical Report;” and 

• Rural Utility Services Form 12, “Operating

Report – Financial.”

In addition to the above-named forms, the historical data 

published in the EPA are compiled from the following 

sources: Form EIA-759, “Monthly Power Plant Report,” 

Form EIA-860A, “Annual Electric Generator Report–

Utility,” Form EIA-860B, “Annual Electric Generator

Report–Nonutility,” and Form EIA-900, “Monthly

Nonutility Power Report.” A brief description of each of 

these forms can be found on the EIA website on the

Internet with the following URL:

http://www.eia.doe.gov/cneaf/electricity/datamatrix.html.

Additionally, some data reported in this publication were 

acquired from the National Energy Board of Canada.

Form EIA-411

The Form EIA-411 is filed annually as a voluntary report. 

The information reported includes: (1) actual energy and 

peak demand for the preceding year and five additional 

years; (2) existing and future generating capacity; (3) 

scheduled capacity transfers; (4) projections of capacity, 

demand, purchases, sales, and scheduled maintenance; and 

(5) bulk power system maps. These reports present various 

NERC Regional council aggregate totals for their member 

electric utilities, with some nonmember information

included.

Instrument and Design History. The Form EIA-411 

program was initiated under the Federal Power

Commission Docket R-362, reliability and adequacy of

electric service, and Orders 383-2, 383-3, and 383-4. The 

Department of Energy, established in October 1977,

assumed the responsibility for this activity. This form is 

considered voluntary under the authority of the Federal 

Power Act (Public Law 88-280), The Federal Energy

Administration Act of 1974 (Public Law 93-275), and the

Department of Energy Organization Act (Public Law 95-

91). The responsibility for collecting these data had been 

delegated to the Office of Emergency Planning and

Operations within the Department of Energy and was

returned to EIA for the reporting year 1996.

Data Processing and Data System Editing. The 10 

North American Electric Reliability Councils file the

Form EIA-411 annually on June 1. The forms are

compiled from data furnished by electricity generators

(members, associates, and nonmembers) within the 

council areas. 

Rounding Rules for Data. Not applicable.

Percent Difference. The following formula is used to

calculate percent differences.
Energy Information Administration/Electric Power Annual 2001 61

x100,

x ( t )

x (t ) - x (t )

1

2 1

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Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. Most of the data collected on 

the Form EIA-411 are not considered confidential. 

However, plant latitudes and longitudes and tested heat 

rate data are considered confidential and must adhere to 

EIA's “Policy on the Disclosure of Individually

Identifiable Energy Information in the Possession of the 

EIA” (45Federal Register 59812 (1980)). 

Form EIA-412

The Form EIA-412 is a restricted-universe census used 

annually to collect accounting, financial, and operating 

data from major publicly owned electric utilities in the 

United States. Those publicly owned electric utilities

engaged in the generation, transmission, or distribution of 

electricity which had 150,000 megawatthours of sales to 

ultimate consumers and/or 150,000 megawatthours of

sales for resale for the two previous years, as reported on 

the Form EIA-861, “Annual Electric Utility Report,” must 

submit the Form EIA-412. Beginning with the 2001 data 

collection, the plant statistics reported on Schedule 9 were 

also collected fro m unregulated entities that own plants 

with a nameplate capacity of 10 MW or greater. Also 

beginning with the 2002 collection, the transmission data 

reported in Schedules 10 and 11 were collected from each 

generation and transmission cooperative owing

transmission lines having a nominal voltage of 132 kV or 

greater. The 1999-1997 data represent those electric

utilities meeting a threshold of 120,000 megawatthours for 

ultimate consumers' sales and or resales. The criteria used 

to select the respondents for this survey results in

approximately 500 publicly owned electric utilities. 

Federal electric utilities are required to file the Form EIA412. The financial data for the U.S. Army Corps of

Engineers (except for Saint Mary's Falls at Sault Ste. 

Marie, Michigan); the U.S. Department of Interior, Bureau 

of Reclamation; and the U.S. International Boundary and 

Water Commission were collected on the Form EIA-412 

from the Federal power marketing administrations.

Instrument and Design History. The FPC created the

FPC Form 1M in 1961 as a mandatory survey. It became 

the responsibility of the EIA in October 1977 when the

FPC was merged with DOE. In 1979, the FPC Form 1M 

was superseded by the Economic Regulatory

Administration (ERA) Form ERA-412, and in January 

1980 by the Form EIA-412. 

Data Processing and Data System Editing. The 

processing of data reported on this survey is the

responsibility of the Electric Power Division within the 

Office of Coal, Nuclear, Electric and Alternate Fuels. The 

completed surveys are due in this office on or before April 

30. Non-response follow-up procedures are used to attain 

100-percent response. Edit checks of the data are

performed through computer programs. The program edits 

include both deterministic checks, in which records are 

checked for the presence of data in required fields, and 

statistical checks, in which the data are checked against a 

range of values based on historical data values and for 

logical or mathematical consistency with data elements

reported in the survey. Discrepancies found in the data, as 

a result of these checks, are resolved either by the

processing office or by further information obtained from 

a telephone call to the respondent company.

Rounding Rules for Data. Not applicable.

Percent Difference. The following formula is used to 

calculate percent differences.

Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. The unregulated entity data 

collected on Schedule 9, plant fuel cost data, of this survey 

are considered confidential and will not be made available 

to the public. State and national level aggregations will be 

published in this report if sufficient data are available to 

avoid disclosure of individual company and facility level 

costs. 

Form EIA-767

The Form EIA-767 is a mandatory restricted-universe 

census of all electric power plants with a total existing or 

planned organic-fueled or combustible renewable steamelectric generator nameplate rating of 10 or more 

megawatts. The entire form is filed by approximately 700 

power plants with a nameplate capacity of 100 or more 

megawatts. An additional 600 power plants with a

nameplate capacity under 100 megawatts submit

information only on fuel consumption/quality,

boiler/generator configuration, and flue gas desulfurization 

equipment, if applicable. The Form EIA-767 is used to 

collect data annually on plant operations and equipment 

design (including boiler, generator, cooling system, flue 

gas desulfurization, flue gas particulate collectors, and 

stack data). 
62 Energy Information Administration/Electric Power Annual 2001

x100,

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x (t ) - x (t )

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Instrument and Design History. The Federal Energy 

Administration Act of 1974 (Public Law 93-275) defines 

the legislative authority to collect these data. The

predecessor form, FPC-67, “Steam-Electric Plant Air and 

Water Quality Control Data,” was used to collect data

from 1969 to 1980, when the form number was changed to 

Form EIA-767. In 1982, the form was completely

redesigned and given the name Form EIA-767, “SteamElectric Plant Operation and Design Report.” In 1986, the 

respondent universe of 700 was increased to 900 to

include plants with nameplate capacity from 10 megawatts 

to 100 megawatts. Respondents for these 200 additional 

plants complete only pages 1, 5, 6, and, if applicable, 13, 

and 14.

Data Processing and Data System Editing. The Form 

EIA-767 is mailed to respondents in January to collect 

data as of the end of the preceding calendar year. The 

completed forms are to be returned to the EIA by April 30. 

Equipment design data for each respondent are preprinted 

from the applicable data base. Respondents are instructed 

to verify all preprinted data and to supply missing data. 

The data are manually reviewed before being keyed for 

automatic data processing. Computer programs containing 

additional edit checks are run. Respondents are

telephoned to obtain correction or clarification of reported 

data and to obtain missing data, as a result of the manual 

and automatic editing process. 

Rounding Rules for Data. Given a number with r digits 

to the left of the decimal and d+t digits in the fraction 

part, with d being the place to which the number is to be 

rounded and t being the remaining digits which will be 

truncated, this number is rounded to r+d digits by adding 5 

to the (r+d+1)th digit when the number is positive or by 

subtracting 5 when the number is negative. The t digits 

are then truncated at the (r+d+1)th digit. The symbol for a 

number rounded to zero is (*).

Percent Difference. The following formula is used to

calculate percent differences.

Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. Most of the data collected 

on the Form EIA-860 are not considered confidential. 

However, plant latitudes and longitudes are considered 

confidential and must adhere to EIA's “Policy on the

Disclosure of Individually Identifiable Energy Information 

in the Possession of the EIA” (45Federal Register 59812 

(1980)). 

Form EIA-860

Beginning with data collected for the year 2001, the Forms 

EIA-860A and EIA-860B are obsolete. The infrastructure 

data collected on those forms are now collected on the 

Form EIA-860 and the monthly and annual versions of the 

Form EIA-906. 

The Form EIA-860 is a mandatory census of all existing 

and planned electric generating facilities in the United 

States with a total generator nameplate capacity of 1 or 

more megawatts. The survey is used to collect data on 

existing power plants and 5-year plans for constructing 

new plants, generating unit additions, modifications, and 

retirements in existing plants. Data on the survey are

collected at the generator unit level. 

Instrument and Design History. The Form EIA-860 was 

originally implemented in January 1985 to collect plant 

data on electric utilities as of year-end 1984. In January 

1999, the Form EIA-860 was renamed the Form EIA860A and was implemented to collect data as of January 1, 

1999.

In 1989, the Form EIA-867, "Annual Nonutility Power 

Producer Report," was initiated to collect plant data on 

unregulated entities with a total generator nameplate

capacity of 5 or more megawatts. In 1992, the reporting 

threshold of the Form EIA-867 was lowered to include all 

facilities with a combined nameplate capacity of 1 or more 

megawatts. Previously, data were collected every 3 years 

from facilities with a nameplate capacity between 1 and 5 

megawatts. In 1998, the Form EIA-867, was renamed 

Form EIA-860B, "Annual Electric Generator Report -

Non-utility." The Form EIA-860B was a mandatory

survey of all existing and planned nonutility electric

generating facilities in the United States with a total

generator nameplate capacity of 1 or more megawatts. 

Beginning with data collected for the year 2001, the

infrastructure data collected on the Form EIA-860A and 

the Form EIA-860B were combined into the new Form 

EIA-860 and the monthly and annual versions of the Form 

EIA-906. The Federal Energy Administration Act of 1974 

(Public Law 93-275) defines the legislative authority to 

collect these data.

Data Processing and Data System Editing. The Form 

EIA-860 is mailed to approximately 2,000 respondents to 

collect data as of January 1 of the reporting year. Respondents have the option of filing Form EIA-860 directly with 

the EIA or through an agent, such as the respondent's

regional electric reliability council. Data reported through 
Energy Information Administration/Electric Power Annual 2001 63

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the regional electric reliability councils are submitted to 

the EIA electronically from the North American Electric 

Relia bility Council (NERC). 

Data for each respondent are preprinted. Respondents are 

instructed to verify all preprinted data and to supply

missing data. Computer programs containing edit checks 

are run to identify errors. Respondents are telephoned to 

obtain correction or clarification of reported data and to 

obtain missing data, as a result of the editing process.

Rounding Rules for Data. Not applicable.

Percent Difference. The following formula is used to

calculate percent differences.

Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. Most of the data collected on 

the Form EIA-860 are not considered confidential. 

However, plant latitudes and longitudes and tested heat 

rate data are considered confidential and must adhere to 

EIA's “Policy on the Disclosure of Individually

Identifiable Energy Information in the Possession of the 

EIA” (45Federal Register 59812 (1980)). 

Form EIA-861

The Form EIA-861 is a mandatory census of electric

power industry participants in the United States. The 

survey is used to collect information on power production 

and sales data from approximately 4,900 respondents. 

About 3,300 are electric utilities, and the remainder are 

nontraditional entities such as independent power

producers, and the unregulated subsidiaries of electric 

utilities. The data collected are used to maintain and 

update the EIA's electric power industry participant frame 

database. 

Instrument and Design History. The Form EIA-861 was 

implemented in January 1985 for collection of data as of 

year-end 1984. The Federal Administration Act of 1974 

(Public Law 93-275) defines the legislative authority to 

collect these data.

Data Processing and Data System Editing. The Form 

EIA-861 is mailed to the respondents in January of each 

year to collect data as of the end of the preceding calendar 

year. The data are edited when entered into the interactive 

on-line system. Internal edit checks are performed to 

verify that current data total across and between schedules, 

and are comparable to data reported the previous year. 

Edit checks are also performed to compare data reported 

on the Form EIA-861 and similar data reported on the 

Forms EIA-826 and the EIA-412, “Annual Electric

Industry Financial Report.” Respondents are telephoned to 

obtain clarification of reported data and to obtain missing 

data.

Data for the Form EIA-861 are collected at the owner 

level from all electric utilities in the United States, its 

territories, and Puerto Rico. Form EIA -861 data in this 

publication are for the United States only.

Average revenue per kilowatthour represents the cost per 

unit of electricity sold and is calculated by dividing retail 

electric revenue by the corresponding sales of electricity. 

The average revenue per kilowatthour is calculated for all 

consumers and for each end-use sector. A ratio estimation 

procedure is used for estimation of revenue per

kilowatthour at the State level.

The electric revenue used to calculate the average revenue 

per kilowatthour is the operating revenue reported by the 

electric power industry participant. Operating revenue

includes energy charges, demand charges, consumer

service charges, environmental surcharges, fuel

adjustments, and other miscellaneous charges. Electric 

power industry participant operating revenues also include 

State and Federal income taxes and taxes other than

income taxes paid by the utility. 

The average revenue per kilowatthour reported in this 

publication by sector represents a weighted average of

consumer revenue and sales within sectors and across 

sectors for all consumers, and does not reflect the per kWh 

rate charged by the electric power industry participant to 

the individual consumers. Electric utilities typically

employ a number of rate schedules within a single sector. 

These alternative rate schedules reflect the varying

consumption levels and patterns of consumers and their 

associated impact on the costs to the electric power

industry participant for providing electrical service. 

Rounding Rules for Data. Given a number with r digits to 

the left of the decimal and d+t digits in the fraction 

part, with d being the place to which the number is to be 

rounded and t being the remaining digits which will be 

truncated, this number is rounded to r+d digits by adding 5 

to the (r+d+1)th digit when the number is positive or by 

subtracting 5 when the number is negative. The t digits 

are then truncated at the (r+d+1)th digit. The symbol for a 

number rounded to zero is (*).

Percent Difference. The following formula is used to

calculate percent differences.
64 Energy Information Administration/Electric Power Annual 2001

x100,

x ( t )

x (t ) - x (t )

1

2 1

















Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. Data collected on the Form 

EIA-861 are not considered to be confidential.

Form EIA-906

As of January 2001, Form EIA-906 superseded Forms 

EIA-759 and 900. The Form EIA-906 is used to collect 

monthly plant-level data on generation, fuel consumption, 

stocks, fuel heat content, and useful thermal output from 

electric utilities and nonutilities from a model-based 

sample of approximately 260 electric utilities and 900

nonutilities. Fuel consumption for combined heat and 

power facilities is apportioned between fuel for generation 

of electricity and fuel for production of useful thermal 

output, by assuming they are additive. Fuel usage for 

these facilities is assumed to have an efficiency of 80 

percent. The consumption for useful thermal output is 

obtained by dividing the reported or estimated value for 

useful thermal output by 0.8. This value is then subtracted 

from total fuel consumption by facility to arrive at the fuel 

consumption to be associated with the generation of

electricity. The form is also used to collect these statistics 

from the rest of the frame on an annual basis.

Instrument and Design History. In January 2001, Form 

EIA-906 superseded Forms EIA-759 and EIA -900. The 

Federal Administration Act of 1974 (Public Law 93-275) 

defines the legislative authority to collect these data.

Relating to the Form EIA-759, the Bureau of Census and 

the U.S. Geological Survey collected, compiled and

published data on the electric power industry prior to 

1936. After 1936, the Federal Power Commission (FPC) 

assumed all data collection and publication responsibilities 

for the electric power industry and implemented the Form 

FPC-4. The Federal Power Act, Section 311 and 312, and 

FPC Order 141 define the legislative authority to collect 

power production data. The Form EIA-759 replaced the 

Form PFC-4 in January 1982.

In 1996, the Form EIA-900 was initiated to collect sales 

for resale data from unregulated entities. In 1998, the form 

was modified to collect sales for resale, gross generation, 

and sales to end user data. In 1999, the form was modified 

to collect net generation, consumption, and ending stock 

data. In 2000, the form was modified to include useful 

thermal output data.

Data Processing and Data System Editing. In 2001 and 

2002, the Form EIA-906 was received by the EIA as a

hard copy, typically via fax, and manually entered into a 

computerized database. Anomalous data were identified 

via range checks, comparisons with historical data, and 

consistency checks (for example, whether the fuel

consumption and generation numbers for a given facility 

and month are consistent).

The review of the Form EIA -906 filings for non-regulated 

facilities in 2001 uncovered widespread problems with the 

data reporting. The most prevalent problems were

reported fuel consumption inconsistent with generation 

and, most significantly, incorrect reporting of useful

thermal output (UTO) by combined heat and power (CHP) 

facilities.

UTO is the thermal output from a CHP facility applied to 

a production process other than electricity generation. 

Many facilities either misunderstood EIA’s definition or 

did not meter internally such that they could easily

estimate CHP. This was an important problem in the data 

collection effort. If UTO is reported incorrectly, then the 

reported data cannot be used to estimate fuel for

electricity.

EIA’s preferred means of resolving any questionable

response is via direct communication with the respondent, 

usually via phone or e-mail. In cases where the reported 

data appeared to be incorrect or was missing, and EIA was 

unable to resolve the matter with the respondent, the

following estimation approaches were used for the 2001 

data:

• In cases where electric generation appeared

reasonable but fuel consumption was inconsistent 

with generation, fuel consumption by prime

mover was estimated using 2000 heat rates and 

the assumption that the fuel shares for that prime 

mover in 2001 were the same as in 2000.

• If the reported electric generation data appeared 

to be in error, or if the facility was a nonrespondent, a regression methodology was used 

to estimate generation and fuel consumption for 

the facility. The regression methodology relied 

on 2000 and 2001 data for other facilities to make 

estimates for erroneous or missing responses. 

The basic technique employed is described in the 

paper Model-Based Sampling and Inference,

found on the EIA web site at

http://www.eia.doe.gov/cneaf/electricity/page/for

ms.html .

• UTO was estimated by applying the power to

steam ratio calculated for the facility in 2000 to 

2001.
Energy Information Administration/Electric Power Annual 2001 65

x100,

x ( t )

x (t ) - x (t )

1

2 1

















Overall, of the approximately 2600 facilities in the Form 

EIA-906 frame for 2001, some estimation was performed 

for 803 facilities. These facilities account for

approximately 4 percent of the generation in the frame and 

about 20 percent of the fuel consumption.

Relative Standard Error. The relative standard error

(RSE) statistic, usually given as a percent, describes the 

magnitude of sampling error that might reasonably be

incurred. The RSE is the square root of the estimated 

variance, divided by the variable of interest. The variable 

of interest may be the ratio of two variables, or a single 

variable.

The sampling error may be less than the nonsampling 

error. In fact, large RSE estimates found in preliminary 

work with these data have often indicated nonsampling 

errors, which were then identified and corrected.

Nonsampling errors may be attributed to many sources, 

including the response errors, definitional difficulties, 

differences in the interpretation of questions, mistakes in 

recording or coding data obtained, and other errors of 

collection, response, or coverage. These nonsampling 

errors also occur in complete censuses. In a complete 

census, this problem may become unmanageable. 

Using the Central Limit Theorem, which applies to sums 

and means such as are applicable here, there is approximately a 68-percent chance that the true sampling error is 

less than the corresponding RSE. Note that reported RSEs 

are always estimates, themselves, and are usually, as here, 

reported as percents. As an example, suppose that a net 

generation from coal value is estimated to be 1,507 million 

kilowatthours with an estimated RSE of 4.9 percent. This 

means that, ignoring any nonsampling error, there is

approximately a 68-percent chance that the true million 

kilowatthour value is within approximately 4.9 percent of 

1,507 million kilowatthours (that is, between 1,433 and 

1,581 million kilowatthours). There is approximately a 

95-percent chance of a true sampling error being 2 RSEs 

or less. 

Note that there are times when a model may not apply, 

such as in the case of a substantial reclassification of sales, 

when the relationship between the variable of interest and 

the regressor data does not hold. In such a case, the new 

information represents only itself, and such numbers are 

added to model results when estimating totals. Further, 

there are times when sample data may be known to be in 

error, or are not reported. Such cases are treated as if they 

were never part of the model-based sample, and values are 

imputed.

Adjusting Monthly Data to Annual Data. As a final 

adjustment based on our most complete data, use is made 

of annual Form EIA-906 data, when available. The annual 

totals of the monthly Form EIA-906 data by State and enduse sector are compared to the corresponding annual Form 

EIA-861 values for sales and revenue. The ratio of these 

two values in each case is then used to adjust each

corresponding monthly value.

Average Heat Content. The average heat content values 

collected on the Form EIA-906 were used to convert the 

consumption data into Btu. Therefore, the results may not 

be completely representative.

Rounding Rules for Data. Given a number with r digits 

to the left of the decimal and d+t digits in the fraction part, 

with d being the place to which the number is to be

rounded and t being the remaining digits which will be 

truncated, this number is rounded to r+d digits by adding 5 

to the (r+d+1)th digit when the number is positive or by 

subtracting 5 when the number is negative. The t digits 

are then truncated at the (r+d+1)th digit. The symbol for a 

number rounded to zero is (*).

Percent Difference. The following formula is used to

calculate percent differences.

Percent Difference = 

where x (t1) and x (t2) denote the quantity at year t1 and 

subsequent year t2.

Confidentiality of the Data. Most of the data collected 

on the Form EIA-906 are not considered confidential. 

However, the reported fuel stocks at the end of the

reporting period are considered confidential and must 

adhere to EIA's “Policy on the Disclosure of Individually 

Identifiable Energy Information in the Possession of the 

EIA” (45Federal Register 59812 (1980)).

Conversion of Petroleum Coke to Liquid Petroleum.

The quantity conversion is 5 barrels (of 42 U.S. gallons 

each) per short ton (2,000 pounds). Coke from petroleum 

has a heating value of 6.024 million Btus.
66 Energy Information Administration/Electric Power Annual 2001

Air Emissions

This section describes the methodology employed to

calculate estimates of carbon dioxide (CO2), sulfur dioxide 

(SO2), and nitrogen oxides (NOX) emissions from electric 

generating plants.

The CO2 air emissions are estimated using information 

contained on Form EIA-906, “Power Plant Report.” The 

Form EIA-906 collects information from all electric power 

plants in the United States either monthly or annually. 

Data collected on this form include electric power

generation, energy source consumption, and useful

thermal output from combined heat and power producers. 

The Form EIA-906 sample of monthly respondents is a

representation of electric power plants by State and by 

energy source. Electric power plants that do not report 

data monthly are to submit data annually on this form.

The SO2 and NOX air emissions are estimated using

information contained on Form EIA-767, “ Steam-Electric 

Plant Operation and Design Report.” Form EIA-767 

collects information annually for all U.S. power plants 

with a total existing or planned organic-fueled or

combustible renewable steam-electric plant that has a

generator nameplate rating of 10 megawatts or larger. If a 

plant has a nameplate capacity of 100 megawatts or

greater, the entire form must be completed which provides 

information about fuel consumption and quality, legal air 

emission limits, and flue gas desulfurization (FGD). If a 

plant has a nameplate rating of 10 megawatts, but less than 

100 megawatts, only part of the form must be completed 

which provides information on fuel consumption and

quality, NOX emission controls, and FGD sulfur removal 

efficiency, if applicable. The SO2 and NOX calculations 

are reduced for plants that have the Environmental

Protection Agency’s Continuous Emissions Monitoring 

System.

Uncontrolled Air Pollutant Emissions. Uncontrolled air 

pollutant emissions are those emissions that would occur 

in the absence of any control equipment. Uncontrolled 

CO2, SO2, and NOX emissions are determined by

multiplying the quantity of fuel burned by an emission 

factor. An emission factor is the average quantity of a 

pollutant released from a boiler when a unit of fuel is 

burned.

The coefficients for determining emissions of CO2 from 

electric power plants come from the publication,

Emissions of Greenhouse Gases in the United States,

(DOE/EIA-0573). The source of the SO2 and NOX

emission factors, when available, is the Environmental 

Protection Agency report AP-42, “Compilation of Air 

Pollutant Emission Factors” (Tables A1 and A3).1

Emissions of SO2 and NOX have been revised from the 

updated Air Pollutant Emissions Factor (AP-42 5th

edition, through Supplement E) of the Environmental

Protection Agency on July 1999. Environmental

Protection Agency emission factors are based on boiler 

type, firing configuration, and fuel burned. 

Methodology 

CO2 emissions for power producers include emis sions 

from combined heat and power (CHP) facilities that

produce electric power as an integral part of a

manufacturing or other thermal consuming process.

Emissions are directly proportional to the quantities of

fuels consumed. To calculate emissions for the production 

of electricity, a methodology was developed to estimate 

the consumption of fuel associated for the production of 

electricity by CHP facilities. The methodology is based on 

the following:

1. A steam boiler efficiency rate of 80 percent was

assumed.

2. The reported or estimated value for useful thermal 

output (in Btu) was divided by 0.8 to estimate the fuel 

used to generate this amount of thermal output.

3. This value was subtracted from total fuel consumption 

and the remainder was assumed to be the amount used for 

electric generation.

Coal Rank and Emissions. In 1992, a special study of the 

relationship between the heat and carbon content of coal 

was completed by the Energy Information

Administration's Analysis and Systems Division of the 

Office of Coal, Nuclear, Electric and Alternate Fuels. The 

hypothesis underlying this study was that the ratio of

carbon-to-heat content varies not only by coal rank (i.e., 

anthracite, bituminous, subbituminous, and lignite), but 

also by geographic location of the coal. In this study, the 

hypothesis was tested and the results of the analysis

supported the hypothesis. That is, it was concluded from 

the analysis that coal rank and location of the coal are 

significant factors in the variation of the ratio of carbonto-heat content. After this determination, a set of emission 

factors, by rank and State were derived on the basis of data 

contained in EIA's Coal Analysis File.2

1 “Compilation of Air Pollutant Emission Factors, Vol. 1: 

Stationary Point and Area Sources (AP-42);” 5th Edition 

(through Supplement E) Research Triangle Park, North 

Carolina, July 1999.

2

For a description of the methodology and data used to 

develop the EIA CO22 emission factors, see B. D. Hong 

and E. R. Slatick, “Carbon Dioxide Emission Factors for 

Coal,” Quarterly Coal Report, January-March 1994, 
Energy Information Administration/Electric Power Annual 2001 67

In editions prior to 1992 of this publication, separate

conversion factors by coal rank were published and used 

to estimate emissions of CO2. The special study by EIA 

concluded that since geographic location of coal in

addition to rank of coal is a significant factor in

determining the carbon/heat content relationship, the use 

of emission factors that consider both of these elements 

may yield more accurate estimates of CO2 emissions. The 

emission factors for coal were developed in the units of 

pounds of CO2 per million Btu of coal.

The emission factors for CO2 (Table A2) from coal are 

applied by power plant, based on the rank, amount of coal 

received, and the State from which the coal originated, as 

reported in FERC Form 423, “Cost and Quality of Fuels 

for Electric Plants.” Thus, a weighted average emissions 

factor is obtained by plant and multiplied by the quantity 

of coal consumed by plant, as reported on Form EIA-906, 

“Power Plant Report,” to determine the emissions of CO2. 

The emission factors for CO2 are based on 100-percent 

combustion of the carbon in the fuel. Since a small 

percentage of the carbon in the coal is not converted to 

CO2, this publication assumes 99 percent combustion. The 

1 percent of emissions is deducted at the State/National 

level. The emissions at the State level are based on the 

State in which the plant is located. Uncontrolled

emissions of SO2 and NOX do not always accurately depict 

the quantity of emissions released into the atmosphere 

because they fail to reflect reductions from control

equipment and/or operating technologies. Consequently, 

controlled emissions are calculated to provide a more

accurate estimate of actual air emissions.

Controlled Sulfur Dioxide Emissions. Because of

environmental regulations controlling SO2 emissions,

many generating plants are required to install FGD units at 

their coal-fired plants.3 FGD units typically remove

between 70 to 90 percent of SO2 from the boiler flue gas 

although higher removal efficiencies can be achieved.

Electric generating plants report both sulfur removal

efficiency (percent) and their most stringent SO2 emission 

limits on the Form EIA-767. To determine controlled SO2

emissions, the uncontrolled emissions are reduced by the 

annual average removal efficiencies reported on the Form 

EIA-767. This emission is the controlled emission. As a 

check, the controlled emission is compared with the most 

stringent legal limit reported on the Form EIA -767. The 

controlled emission should be less than the legal limit 

because research indicates that electric generating plants 

routinely remove more SO2 than required to assure an 

 

DOE/EIA-0121(94/1Q) (Washington, DC, August 1994), 

Energy Information Administration.

3

Flue gas desulfurization units may also reduce sulfur dioxide emissions from 

plants that burn oil and petroleum coke.

operating margin of safety. If the controlled emission is 

not less than the most stringent legal limit, it implies that 

the plant or facility is out of legal compliance and could be 

subject to fines and other penalties.

Electric generating plants are permitted to take credit for 

sulfur that remains in bottom ash – ash remaining in the 

bottom of the furnace after the coal is burned. For

example, if a plant or facility is required to remove 90 

percent of the sulfur in the coal and 3 percent remains in 

the ash, it has to remove only 87 percent using scrubbers. 

This credit is included in emissions data in this report. It is 

likely, however, that in many cases the credit is not taken. 

In order to take the ash credit, generating facilities need to 

monitor the coal consumed on a daily basis; this is both 

time-consuming and costly. To the extent that generating 

facilities do not take the ash credit, emissions might be 

slightly overstated.

Sulfur Dioxide Emission Comparison. Title IV of the 

Clean Air Act Amendments of 1990 requires annual sulfur 

dioxide (SO2) emissions from electric power plants to be 

reduced 10 million tons below their 1990 level by the year 

2010. The Clean Air Act required electric generating units 

covered under the Acid Rain Program (units 25 megawatts 

and greater) to be equipped with continuous emission

monitoring systems (CEMS). CEMS is the industry

standard for measuring and recording hourly SO2, nitrogen 

oxide (NOX), and carbon dioxide (CO2) emissions. In

1994, the first 263 generating units covered under the Acid 

Rain Program were required to install CEMS and submit a 

year's worth of emissions data to the Environmental 

Protection Agency (EPA). In 1995, the operators of more 

than 2,000 additional units were required to measure and 

report emissions data. EPA started publishing CEMS

emissions data by State and plant in its publication Acid 

Rain Program, Emissions Scorecard (EPA430/R-97-025). 

Controlled Nitrogen Oxide Emissions. The controlled 

NOX emission is calculated by applying the appropriate 

reduction factor in Table A4. Prior to 1995 for boilers with 

regulated nitrogen oxide emission limits, the annual

controlled estimate used was the lesser of the controlled 

estimate or the annual limitation. When more than one 

control technology is reported, the highest single reduction 

factor is used to estimate the annual controlled NOX

emission. A degree of complexity is added to this

approach, however, because air emission standards are not 

reported in consistent units. In some rare instances,

emission standards are reported in units that cannot be

directly compared with estimated uncontrolled emission 

rates. Examples of such standards are ones that specify the 

concentration of NOX allowed in the flue gas or the

ambient concentration of NOX (parts per million). In cases 

where these types of standards are reported, the

uncontrolled emission estimate is used. Such standards 
68 Energy Information Administration/Electric Power Annual 2001

are uncommon, however, and do not significantly affect 

the results.

Carbon Dioxide Emissions. There are no Federal

regulations that limit CO2 emissions. Information pertinent 

to the estimation of controlled CO2 emissions is not

collected on the Form EIA-767; therefore, no estimates of 

controlled CO2 emissions are made. 

Air Emissions from Small Plants. The Form EIA-767 

does not collect data for generators powered by internal 

combustion engines, gas turbines, combined cycle units 

(for example, gas turbines with waste heat boilers), and 

boilers at steam-electric plants with a total nameplate

capacity of less than 10 MW. Accordingly, air emissions 

from these generators are not estimated by the

methodology. An estimate of air emissions from these

generating units based on a similar methodology using 

consumption data reported on the Form EIA-906, “Power 

Plant Report,” and predecessor forms was performed. 

Business Classification

The nonutility industry consists of all manufacturing,

agricultural, forestry, transportation, finance, service and 

administrative industries, based on the Office of

Management and Budget's Standard Industrial

Classification (SIC) Manual. In 1997, the SIC Manual 

name was changed to North American Industry

Classification System (NAICS). The following is a list of 

the main classifications and the category of primary 

business activity within each classification.

Agriculture, Forestry, and Fishing

111 Agriculture production-crops

112 Agriculture production, livestock and animal 

specialties

115 Agricultural services

114 Fishing, hunting, and trapping

113 Forestry

Mining

2122 Metal mining

2121 Coal mining

211 Oil and gas extraction

2123 Mining and quarrying of nonmetallic minerals 

except fuels

Construction

23

Manufacturing

311 Food and kindred products

3122 Tobacco products

314 Textile and mill products

315 Apparel and other finished products made from 

fabrics and similar materials

321 Lumber and wood products, except furniture

337 Furniture and fixtures

322 Paper and allied products (other than 322122

or 32213)

322122 Paper mills, except building paper

32213 Paperboard mills

323 Printing and publishing

325 Chemicals and allied products (other than

325188, 325211, 32512, or 325311)

325188 Industrial Inorganic Chemicals

325211 Plastics materials and resins

32512 Industrial organic chemicals

325311 Nitrogenous fertilizers

324 Petroleum refining and related industries (other than 

32411)

32411 Petroleum refining

326 Rubber and miscellaneous plastic products

316 Leather and leather products

327 Stone, clay, glass, and concrete products (other than 

32731)

32731 Cement, hydraulic

331 Primary metal industries (other than 331111 or 

331312)

331111 Blast furnaces and steel mills

331312 Primary aluminum

332 Fabricated metal products, except machinery and 

transportation equipment

333 Industrial and commercial equipment and components 

except computer equipment

335 Electronic and other electrical equipment and 

components except computer equipment

336 Transportation equipment

3345 Measuring, analyzing, and controlling instruments, 

photographic, medical, and optical goods, watches and 

clocks

339 Miscellaneous manufacturing industries

Transportation and Public Utilities

482 Railroad transportation

485 Local and suburban transit and interurban highway 

passenger transport

484 Motor freight transportation and warehousing

491 United States Postal Service

483 Water transportation

481 Transportation by air

486 Pipelines, except natural gas

487 Transportation services

513 Communications

22 Electric, gas, and sanitary services

2212 Natural gas transmission

2213 Water supply

22132 Sewerage systems

562212 Refuse systems

22131 Irrigation systems

Wholesale Trade

421 to 422

Retail Trade

441 to 454
Energy Information Administration/Electric Power Annual 2001 69

Finance, Insurance, and Real Estate

521 to 533

Services

721 Hotels

812 Personal services

514 Business services

8111 Automotive repair, services, and parking

811 Miscellaneous repair services

512 Motion pictures

713 Amusement and recreation services

622 Health services

541 Legal services

611 Education services

624 Social services

712 Museums, art galleries, and botanical and zoological 

gardens

813 Membership organizations

561 Engineering, accounting, research, management, and 

related services

814 Private households

514199 Miscellaneous services

Public Administration

92
70 Energy Information Administration/Electric Power Annual 2001

Table A1. Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide Emission Factors

Emission Factors

Fuel

Boiler Type/

Firing 

Configuration Sulfur Dioxide1 Nitrogen Oxides2 Carbon Dioxide3

Electricity Generators

Coal and Other Solid Fuels Lbs per ton Lbs per ton Lbs per 106 Btu

Bituminous4.................................................. cyclone 38.00 x S 33.0 See Table A2

fluidized bed531.00 x S 5.0 See Table A2

spreader stoker 38.00 x S 11.0 See Table A2

tangential 38.00 x S 15.0(14) See Table A2

all Others 38.00 x S 22.0(31) See Table A2

Subbituminous............................................. cyclone 35.00 x S 17.0 See Table A2

fluidized bed531.00 x S 5.0 See Table A2

spreader stoker 38.00 x S 8.8 See Table A2

Tangential 35.00 x S 8.4 See Table A2

all Others 35.00 x S 12.0(24) See Table A2

Lignite............................................................ Cyclone 30.00 x S 15.00 See Table A2

fluidized bed510.00 x S 3.60 See Table A2

front/opposed 30.00 x S 13.00 See Table A2

spreader stoker 30.00 x S 5.80 See Table A2

tangential 30.00 x S 7.10 See Table A2

all Others 30.00 x S 7.10(13) See Table A2

Petroleum Coke6.......................................... fluidized bed539.00 x S 21.00 225.13

all Others 39.00 x S 21.00 225.13

Refuse ............................................................. all types 3.90 5.00 199.82

Wood.............................................................. all types 0.08 1.50 0.00

Petroleum and Other Liquid Fuels lbs per 103 gal lbs per 103 gal lbs per 106 Btu

Residual Oil7................................................. Tangential 157.00 x S 32.0 173.72

Vertical 157.00 x S 47.0 173.72

all Others 157.00 x S 47.0 173.72

Distillate Oil 7................................................ all types 150.00 x S 24.0 161.27

Methanol........................................................ all types See Table A3 See Table A3 138.15

Propane (liquid) .......................................... all types 86.5 19.00 139.04

Coal-Oil Mixture......................................... all types See Table A3 See Table A3 173.72

Natural Gas and Other Gaseous Fuels lbs per 106 cf lbs per 106 cf lbs per 106 Btu

Natural Gas................................................... Tangential 0.60 170.00 116.97

all Others 0.60 280.00 116.97

Blast Furnace Gas........................................ all types 950.00 280.00 116.97

Combined Heat and Power Producers

Coal and Other Solid Fuels lbs per ton lbs per ton lbs per 106 Btu

Anthracite Culms ......................................... all types 39.00 x S 1.80 See Table A2

Bituminous.................................................... all types 38.00 x S 22.0 See Table A2

Bituminous Gob........................................... all types 38.00 x S 22.0 See Table A2

Subbituminous............................................. all types 35.00 x S 12.0 See Table A2

Lignite............................................................ all types 30.00 x S 12.0 See Table A2

Lignite Waste ............................................... all types 30.00 x S 12.0 See Table A2

Peat.................................................................. all types 30.00 x S 12.0 0

Agricultural Waste...................................... all types See Table A3 See Table A3 0

Black Liquor................................................. all types See Table A3 See Table A3 0

Chemicals...................................................... all types See Table A3 See Table A3 0

Closed Loop Biomass................................. all types See Table A3 See Table A3 0

Internal........................................................... all types See Table A3 See Table A3 0

See footnotes at end of table.
Energy Information Administration/Electric Power Annual 2001 71

Table A1. Sulfur Dioxide, Nitrogen Oxide, and Carbon Dioxide Emission Factors

(Continued)

Emission Factors

Fuel

Boiler Type/

Firing 

Configuration Sulfur Dioxide1 Nitrogen Oxides2 Carbon Dioxide 3

Coal and Other Solid Fuels (Continued) Lbs per ton lbs per ton lbs per 106 Btu

Liquid Acetonitrile Waste......................... all types See Table A3 See Table A3 150.76

Liquid Waste ................................................ all types 2.80 2.30 163.29

Municipal Solid Waste............................... all types 1.70 5.90 189.48

Petroleum Coke............................................ all types 39.00 x S 14.00 225.13

Pitch................................................................ all types See Table A3 See Table A3 0

RailRoad Ties............................................... all types See Table A3 See Table A3 0

Red Liquor.................................................... all types See Table A3 See Table A3 0

Sludge............................................................. all types 2.80 5.00 0

Sludge Waste................................................ all types 2.80 5.00 0

Sludge Wood................................................ all types 2.80 5.00 0

Spent Sulfite Liquor.................................... all types See Table A3 See Table A3 0

Straw............................................................... all types See Table A3 See Table A3 0

Sulfur.............................................................. all types 7.00 0.00 0

Tar Coal......................................................... all types See Table A3 See Table A3 0

Tires................................................................ all types See Table A3 See Table A3 0

Waste Byproducts....................................... all types 1.70 2.30 163.29

Waste Coal.................................................... all types See Table A3 See Table A3 0

Wood/Wood Waste..................................... all types 0.08 1.50 0

Petroleum and Other Liquid Fuels lbs per 103 gal lbs per 10

3

 gal lbs per 106 Btu

Heavy Oil7..................................................... all types 157.00 x S 47.00 173.72

Light Oil 7....................................................... all types 142.00 x S 20.00 159.41

Diesel.............................................................. all types 142.00 x S 20.00 161.27

Kerosene........................................................ all types 142.00 x S 20.00 159.41

Butane (liquid)............................................. all types 0.09 21.00 143.20

Fish Oil........................................................... all types See Table A3 See Table A3 0

Methanol........................................................ all types See Table A3 See Table A3 138.15

Oil Waste....................................................... all types 147.00 x S 19.00 163.61

Propane (liquid)........................................... all types 0.50 19.00 139.04

Sludge Oil...................................................... all types 147.00 x S 19.00 0

Tar Oil............................................................ all types See Table A3 See Table A3 0

Waste Alcohol.............................................. all types See Table A3 See Table A3 138.15

Natural Gas and Other Gaseous Fuels lbs per 106 cf lbs per 106 cf lbs per 106 Btu

Natural Gas................................................... all types 0.60 280.00 116.97

Butane (Gas)................................................. all types 0.60 21.00 143.20

Hydrogen ....................................................... all types See Table A3 550.00 0

Landfill Gas.................................................. all types See Table A3 550.00 115.12

Methane ......................................................... all types See Table A3 550.00 115.11

Other Gas....................................................... all types See Table A3 550.00 141.54

Propane (Gas)............................................... all types 0.60 19.00 139.04

1

 Uncontrolled sulfur dioxide emission factors. "x S" indicates that the constant must be multiplied by the percentage (by weight) of sulfur in the fuel. Sulfur dioxide emission estimates 

from facilities with flue gas desulfurization equipment are calculated by multiplying uncontrolled emission estimates by one minus the reported sulfur removal efficiencies. Sulfur dioxide 

emission factors also account for small quantities of sulfur trioxide and gaseous sulfates.

2

 Parenthetic values are for wet bottom boilers; otherwise dry bottom boilers. If bottom type is unknown, dry bottom is assumed. Emission factors are for boilers with a gross heat rate of 

100 million Btu per hour or greater. See Table A4 for nitrogen oxide reduction factors used to calculate controlled nitrogen oxide emission estimates.

3

 Uncontrolled carbon dioxide emission estimates are reduced by 1 percent to account for unburned carbon.

4

 Coal types are categorized by Btu content as follows: bituminous (greater than or equal to 9,750 Btu per pound), subbituminous (equal to 7,500 to 9,750 Btu per pound), and lignite (less 

than 7,500 Btu per pound).

5

 Sulfur dioxide emission estimates from fluidized bed boilers assume a sulfur removal efficiency of 90 percent.

6

 Emission factors for petroleum coke are assumed to be the same as those for anthracite. If the sulfur content of 

petroleum coke is unknown, a 6 percent sulfur content is assumed.

7 Oil types are categorized by Btu content as follows: heavy (greater than or equal to 144,190 Btu per gallon), and light 

(less than 144,190 Btu per gallon). 
72 Energy Information Administration/Electric Power Annual 2001

Table A2. Carbon Dioxide Emission Factors for Coal by Rank and State of Origin

Rank State of Origin Factors

(Pounds per Million Btu)

Anthracite Pennsylvania 227.38

Bituminous Alabama 205.46

Bituminous Arizona 209.68

Bituminous Arkansas 211.60

Bituminous Colorado 206.21

Bituminous Illinois 203.51

Bituminous Indiana 203.64

Bituminous Iowa 201.57

Bituminous Kansas 202.79

Bituminous Kentucky: East 204.80

Bituminous Kentucky: West 203.23

Bituminous Maryland 210.16

Bituminous Missouri 201.3 1

Bituminous Montana 209.62

Bituminous New Mexico 205.71

Bituminous Ohio 202.84

Bituminous Oklahoma 205.93

Bituminous Pennsylvania 205.72

Bituminous Tennessee 204.79

Bituminous Texas 204.39

Bituminous Utah 204.08

Bituminous Virginia 206.23

Bituminous Washington 203.62

Bituminous West Virginia 207.10

Bituminous Wyoming 206.48

Subbituminous Alaska 214.00

Subbituminous Colorado 212.72

Subbituminous Iowa 200.79

Subbituminous Missouri 201.31

Subbituminous Montana 213.42

Subbituminous New Mexico 208.84

Subbituminous Utah 207.09

Subbituminous Washington 208.69

Subbituminous Wyoming 212.71

Lignite Arkansas 213.54

Lignite California 216.31

Lignite Louisiana 213.54

Lignite Montana 220.59

Lignite North Dakota 218.76

Lignite South Dako ta 216.97

Lignite Texas 213.54

Lignite Washington 211.68

Lignite Wyoming 215.59

 Source: Energy Information Administration, Quarterly Coal Report, Jan.-Mar. 1994, DOE-EIA-0121(94/Q1) (Washington, D.C, August 1994), pp. 1 -8.)
Energy Information Administration/Electric Power Annual 2001 73

Table A3. Sulfur Dioxide and Nitrogen Oxide Factors for Specific Fuels

Emission Factors

Fuel

Boiler Type/

Firing 

Configuration Sulfur Dioxide1 Nitrogen Oxides2

Electricity Generators lbs per 103 gal lbs per 103 gal

Methanol........................................................ all types 0.05 12.40

Coal-Oil Mixt ure......................................... all types 185.00 x S 50.00

Combined Heat and Power Producers lbs per ton lbs per ton

Agricultural Waste...................................... all types 0.08 1.20

Black Liquor................................................. all types 7.00 1.50

Chemicals...................................................... all types 7.00 1.50

Closed Loop Biomass................................. all types 0.08 1.50

Internal........................................................... all types 0.08 1.50

Liquid Acetonitrile Waste......................... all types 7.00 1.50

Pitch................................................................ all types 30.00 x S 11.10

Railroad Ties................................................ all types 0.08 1.50

Red Liquor.................................................... all types 7.00 1.50

Spent Sulfite Liquor.................................... all types 7.00 1.50

Straw............................................................... all types 0.08 1.50

Tar Coal......................................................... all types 30.00 x S 11.10

Tires................................................................ all types 38.00 x S 21.70

Waste Coal.................................................... all types 38.00 x S 21.70

lbs per 103 gal lbs per 103 gal

Fish Oil........................................................... all types 0.50 12.40

Methanol........................................................ all types 0.50 12.40

Tar Oil............................................................ all types 162.70 x S 67.00

Waste Alcohol.............................................. all types 0.50 12.40

lbs per 106 cf lbs per 106 cf

Hydrogen ....................................................... all types 0.00 550.00

Landfill Gas.................................................. all types 0.60 550.00

Methane ......................................................... all types 0.60 550.00

Other Gas....................................................... all types 0.60 550.00

3

1

 Uncontrolled sulfur dioxide emission factors. "x S" indicates that the constant must be multiplied by the percentage (by weight) of sulfur in the fuel. Sulfur dioxide emission estimates 

from facilities with flue gas desulfurization equipment are calculated by multiplying uncontrolled emission estimates by one minus the reported sulfur removal efficiencies. Sulfur dioxide 

emission factors also account for small quantities of sulfur trioxide and gaseous sulfates.

2

 If bottom type is unknown, dry bottom is assumed. Emission factors are for boilers with a gross heat rate of 100 million Btu per hour or greater. See Table A4 for nitrogen oxide 

reduction factors used to calculate controlled nitrogen emission estimates.

 Sources: Nitrogen Oxide emission factors from Hydrogen, Landfill Gas, Methane, and Other Gas calculated from Environmental Protection Agency, Compilation of Air Pollutant 

Emission Factors, Volume I: Stationary Point and Area Sources, Fifth Edition (through Supplement E), Research Triangle Park, North Carolina, July, 1999. All other fuels calculated by 

the Office of Integrated Analysis and Forecasting.
74 Energy Information Administration/Electric Power Annual 2001

Table A4. Nitrogen Oxide Reduction Factors

Nitrogen Oxide

Control Technology EIA-767 Code(s) EIA-860 Code(s) Reduction Factor(Percent)

Advanced Overfire Air.............................. AA -- 301

Alternate Burners........................................ BF -- 20

Flue Gas Recirculation FR FG 40

Fluidized Bed Combustor.......................... CF -- 20

Fuel Reburning............................................. FU -- 30

Low Excess Air............................................ LA LE 20

Low Nitrogen Oxide Burners................... LN LN 301

Other (or Unspecified)............................... OT OT 20

Overfire Air................................................... OV OA 201

Selective Catalytic Reduction.................. SR CC 70

Selective Catalytic Reduction

With Low Nitrogen Oxide Burners... SR and LN CC and LN 90

Selective Noncatalytic Reduction........... SN -- 30

Selective Noncatalytic Reduction...........

With Low Nitrogen Oxide Burners... SR and LN -- 50

Slagging......................................................... SC -- 20

Steam or Water Injection........................... -- SW 20

1

Starting with 1995 data, reduction factors for advanced overfire air, low nitrogen oxide burners, and overfire air were reduced by 10. 

 Source: Babcock and Wilcox, Steam: Its Generation and Use, 40th Edition, 1992.

Table A5. Unit-of-Measure Equivalents

Unit Equivalent

Kilowatt (kW) ...................................................... 1,000 (One Thousand) Watts

Megawatt (MW) .................................................. 1,000,000 (One Million) Watts

Gigawatt (GW).................................................... 1,000,000,000 ( One Billion) Watts

Terawatt (TW) ..................................................... 1,000,000,000,000 (One Trillion) Watts

Gigawatt................................................................. 1,000,000 (One Million) Kilowatts

Thousand Gigawatts............................................ 1,000,000,000 (One Billion) Kilowatts

Kilowatthours (kWh) ......................................... 1,000 (One Thousand) Watthours

Megawatthours (MWh) ..................................... 1,000,000 (One Million) Watthours

Gigawatthours (GWh) ....................................... 1,000,000,000 (One Billion) Watthours

Terawatthours (TWh) ........................................ 1,000,000,000,000 (One Trillion) Watthours

Gigawatthours....................................................... 1,000,000 (One Million) Kilowatthours

Thousand Gigawatthours................................... 1,000,000,000 (One Billion) Kilowatthours

U.S. Dollar............................................................. 1,000 (One Thousand) Mills

U.S. Cent................................................................ 10 (Ten) Mills

 Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate fuels.
Energy Information Administration/Electric Power Annual 2001 75

Appendix B

Estimating and Presenting Power Sector Fuel Use 

I. Background

The Energy Information Administration (EIA) has comprehensively reviewed and revised how it collects, estimates, and reports 

fuel use for facilities producing electricity. The review addressed inconsistent reporting of the fuels used for electric power and

changes in the electric power marketplace that have been inconsistently represented in various EIA survey forms and publications. 

For example:

• In some cases fuel use by combined-heat-and-power (CHP) plants1 has been reported as industrial sector fuel use, while in 

other cases it has been reported as electric power sector fuel use.

• Electricity generation and fuel consumption have been categorized and reported in several different ways, such as (1) 

utility only; (2) utility and independent power producers; or (3) utility, independent power producers, and CHP plants. 

The restructuring of the power industry is making some of these categories less meaningful.

The goal of EIA’s comprehensive review was to improve the quality and consistency of its electric power data throughout all data 

and analysis products. Because power facilities operate in all sectors of the economy (e.g., in commercial buildings, such as 

hospitals and college campuses, and industrial facilities, such as paper mills and refineries) and use many fuels, any change to 

electric power data affects data series in nearly all fuel areas and causes changes in a wide variety of EIA publications.

As a result of the comprehensive review, EIA has made the following changes:

• EIA has adjusted all presentations of data on electric power to a consistent format and defined the electric power sector to 

include electricity-only and CHP plants whose primary business is to sell electricity, or electricity and heat, to the public.

• EIA is providing detail within the electric power sector, commercial sector, and industrial sector on fuel used by CHP 

plants in those sectors. 

• EIA has changed the sources of data on fuel used by components of the electric power sector. All tabulations and 

publications will use data obtained from EIA’s surveys of electric power generators. This change in data source

contributes to changes in total fuel consumption of natural gas.

• EIA has revised its historical data on electric power to resolve data anomalies. The revisions contribute to changes in 

EIA’s electricity series as well as the fuel-use series.

Appendix B describes the reasoning behind the changes and their effect on electric power publications. It is organized as follows:

• Section II provides an overview of the key changes.

• Section III provides specific information for electric power publications.

The Annual Energy Review (AER) 2001, the first of the annual publications to be released with the new formats, provides detail on 

changes for publications on coal, natural gas, petroleum, renewable energy, and greenhouse gas emissions. 

II. Overview of Key Changes

The many changes that will occur because of the fuel review generally fall into three broad categories: (1) the categorization of 

electric power facilities, (2) the reporting of combined-heat-and-power plant fuel use, and (3) data series revisions resulting from 

revised electric power fuel use estimates. Each of these areas is discussed below.

Categorization of Electric Power Facilities

Until the 1990s, most electric power generation and fuel use data could be meaningfully categorized into electric utilities and 

nonutility power producers.2 Electric utilities were generally structured as vertically integrated3 power companies that were 

1

 Combined-heat-and-power plants (CHP) produce both electricity and useful thermal output. EIA formerly referred to these plants as cogenerators, but has determined that CHP better 

describes the facilities because some of the plants included in EIA’s data do not produce heat and power in a sequential fashion, and as a result do not meet the legal definition of 

cogeneration specified in the Public Utility Regulatory Policies Act (PURPA).

2

 For an example of this, see Electric Power Annual 1998, Volume II, DOE/EIA-0348(98)/2, December 1999.

3

 In this context “integrated” means that the company is involved in the three main sectors of the electric power business—generation, transmission, and distribution.
76 Energy Information Administration/Electric Power Annual 2001

responsible for generating, transmitting, and distributing power to consumers within their franchised service territory. Nonutility 

power producers were generally independent generators—mostly combined-heat-and-power plants—that produced some power for 

their own use and sold the remainder to utilities for distribution to consumers. However, in recent years, many formerly integrated 

utilities have split apart, spinning off the generating part of their business into separate companies. Independent developers have 

built most of the new generating capacity that has been installed in recent years. As a result, the distinction between utility and 

nonutility power plants has become much less meaningful. In fact, a large portion of the growth in nonutility generation in recent 

years is due to the reclassification of utility power plants as nonutility power plants.

To reflect the changing industry structure, EIA is now organizing electric power generation and fuel use data into two new 

categories: electricity-only and combined-heat-and-power (CHP) plants. These categories separate power plants by function; i.e., 

power only or power plus thermal, rather than by ownership class.

Electricity-only plants represent all plants, whether owned by utilities or nonutilities that produce only electricity. CHP plants 

represent entities that produce both electricity and some form of thermal energy. Both categories will have some facilities that are 

owned by traditional utilities and independent companies. 

In addition, EIA is now presenting data for an electric power sector that includes electricity-only plants and CHP plants whose 

primary business is to sell electricity, or electricity and heat, to the public (North American Industry Classification System code 

22). This contrasts with some previous data presentations in which the electric power sector included industrial and commercial 

CHP plants as well. Figure B1 provides an example from the Annual Energy Review (AER).

Figure B1. Electric Power Sector in AER 2001 and AER 2000

 AER 2001 AER 2000

Electric Power Sector

Electricity 

Only CHP Total

In some tables and publications, the electric power sector will continue to be broken down into electric utilities and independent 

power producers for customers who have expressed an interest in this breakout. For example, Table 8.1 of AER 2001 presents an 

electricity overview and shows data on net generation for electric utilities and independent power producers separately. It is the 

only table in AER 2001 that has this break-out (Figure B2). 

Figure B2. Electric Utilities and Independent Power Producers are shown separately in Electricity 

Overview 

Table 8.1 Electricity Overview, 1949-2001

(Billion Kilowatthours)

Net Generation

Electric Power Sector 1

Year

Electric 

Utilities

Independent 

Power Producers Total

Commercial

Sector 2

Industrial

Sector 3

Total

1

The electric power sector (electric utilities and independent power producers) comprises electricity -only and combined-heat-and-power (CHP) plants whose primary 

business is to sell electricity, or electricity and heat, to the public—i.e., NAICS 22 plants. Due to the restructuring of the electric power sector, the sale of generation assets 

is resulting in a reclassification of plants from electric utilities to independent power producers.

2

Commercial combined-heat-and-power (CHP) and commercial electricity-only plants. See Appendix G for commercial sector NAICS codes.

3

Industrial combined-heat-and-power (CHP) and industrial electricity -only plants. Through 1988, includes industrial hydroelectric power only. See Appendix G for industrial 

sector NAICS codes.

Reporting of CHP Facility Fuel Use

Historically, fuel consumption in CHP plants has been combined with other uses in many EIA publications. For example, in some 

tables the use of natural gas in commercial and industrial CHP plants was included with other commercial and industrial uses. 

Further, some of the fuel consumption (the portion associated with electricity production) at these same facilities was also reported 

under the column labeled “Nonutility Power Producers.” Based on questions received, it became clear that this categorization led 

to confusion for many EIA customers.

EIA is now distinguishing within the industrial, commercial, and electric power sectors what portion of fuel consumption is used in 

CHP facilities and non-CHP facilities. For example:

Electric Power Sector

Electric 

Utilities

Nonutility

Power 

Producers Total
Energy Information Administration/Electric Power Annual 2001 77

• In tabulations of energy use by economic sector, if a commercial or industrial facility has a CHP unit, the total fuel 

consumption for that unit will be reported under commercial or industrial, but it will be identified separately from other 

commercial or industrial consumption. CHP plants that report their primary business is generating and selling power to 

others will be reported in a separate column in the electric power sector.

• In tabulations of energy use to produce electric power, the total fuel consumption reported by CHP plants will be further 

separated into that which is used to produce electricity and that which is used to produce thermal energy.4 Figure B3 

shows a schematic for combined heat and power producers.

Figure B3. Schematic for Combined Heat and Power Plants

Steam

Boiler

Shaft

Alternator

Condenser

Heat from condenser used in

factory for process heat.

Steam

Electricity

Steam Flow

Turbine 

Furnace

Feed water

pump

Fuel

The separation between electricity and thermal uses is being done because many EIA data users have expressed interest in knowing 

how much fuel is used to produce electricity in the United States.

Data Series Revisions Resulting From Changes in Electric Power Fuel Use Estimates

The revisions to electric power data affect many areas. For example, historically, to estimate natural gas use, EIA surveyed natural 

gas pipeline-companies and local gas utilities to obtain data on natural gas used by residential, commercial, industrial, and electric 

utility sectors, and nonutility generators.5 However, EIA also surveyed electric utilities on their natural gas use. These data 

obtained directly from the end user were generally thought to be more accurate than the data obtained from natural gas suppliers. 

As a result, total natural gas use was estimated by adding together the data from natural gas companies on residential, commercial, 

industrial, and nonutility power producer use to the amount reported directly by electric utilities. The data collected for nonutility 

power producers were included with industrial use in previous EIA natural gas publications.

With the changing structure of the electricity sector, this reporting approach no longer appears reasonable. EIA has decided to 

follow the procedure described for electric utilities and use data obtained from its direct surveys of nonutility electric generators 

rather than the natural gas supplier surveys.6 

4

 For the method used to separate the fuel used at CHP plants between electricity and useful thermal energy production, see Section III.

5

 Energy Information Administration, Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply and Disposition.”

6

 Energy Information Administration, Form EIA-759, “Monthly Power Plant Report” for electric utilities and Forms EIA-867 and EIA-860B, “Annual Electric Generator Report –

Nonutility” for nonutilities. Starting with 2001, data for both utilities and nonutilities are collected on a new survey, Form EIA-906, “Power Plant Report.”
78 Energy Information Administration/Electric Power Annual 2001

Data changes are also occurring because of the extensive review of reported data that was undertaken in this process. Since it was 

decided that data reported directly by utilities and nonutility power generators would be the primary source of fuel consumption 

data for the power sector, an examination of heat rates,7 capacity factors,8and power-to-steam ratios across 12 years of reported 

data was conducted. As a result, data for nonutility power producers for 1989 through 2000 have been revised. The data review 

procedure is described in Section III under the heading “Efforts to Improve Data.” As a result of the review by expert EIA 

analysts, anomalous values have been investigated and resolved and the result is higher quality data at aggregated levels.

Revisions resulting from changing the source of fuel consumption data for nonutilities and from EIA’s data review affect data 

beyond the category of nonutilities. Appendix H of AER 2001 provides examples. 

III. Electric Power Surveys and Publications

Summary of Key Changes

EIA previously presented data on electric power, such as generation and fuel consumption, in the following categories:

• Electric utilities,

• Nonutility power producers (independent power producers and combined-heat-and power plants),

• Electric power industry (sum of electric utilities and nonutility power producers).

Now EIA is presenting data for the following new categories:

• Electricity-only-plants

• Combined-heat-and-power (CHP) plants,

• U.S. power producers (sum of electricity-only plants and CHP plants and equal to the prior “electric power industry” 

category).

Data on electricity-only plants are disaggregated for utilities and independent power producers, as there are customers who are 

interested in maintaining this distinction. Data on CHP plants are disaggregated by the end-use category (commercial, industrial, 

electric power) they report as their major line of business. The categorization is based on their North American Industrial 

Classification System code. For example, a CHP plant that is part of a hospital will be classified as “commercial.” Similarly, a 

CHP plant that reports that it is part of a paper mill will be classified as “industrial,” and a plant that reports that its primary 

business is selling power to others will be classified as “electric power.”

In addition, EIA has estimated and is presenting data on the amount of fuel used to generate electricity and the amount of fuel used 

for useful thermal output. Furthermore, during the course of recategorizing the data, EIA performed a thorough data quality review 

and revised data to resolve anomalies.

Efforts to Improve Data

EIA reviewed electric power-data from 1989 through 2001 to determine whether there were anomalies. The 1989–2000 data for 

nonutilities were from Form EIA-860B, “Annual Electric Generator Report-Nonutility,” and its predecessor, Form EIA-867, 

“Annual Nonutility Power Producer Report.” The 2001 data are from Form EIA-906, “Power Plant Report.” These forms collect 

data on fuel consumption, generation, and, with the exception of 1995 through 1997, useful thermal output. When anomalies were 

identified in the data for the more recent years (1998–2001), EIA contacted selected respondents to resolve the inconsistencies. 

For the historical data it was not possible to contact respondents. In this situation EIA made data adjustments to resolve the 

anomalies.

EIA reviewed data for facilities with heat rates greater than 40,000 Btu per kilowatthour and less than 5,500 Btu per kilowatthour. 

The upper limit was chosen to allow for the heat rates of older non-electricity boilers. In addition, EIA reviewed data for facilities 

with overall efficiency of greater than 100 percent and identified facilities with thermal output that were not designated as CHP 

plants. To ensure consistency, EIA compared North American Industry Classification System (NAICS) codes, cogenerator status, 

fuel consumption, electric generation, and thermal output levels over time. Moreover, EIA analysts also reviewed and evaluated 

aggregate-level data by State, NAICS code, fuel type, and generator type. For the historical data (1989–1997), EIA also:

7

 Heat rates are computed by dividing the heat content of the fuel burned to generate electricity by the resulting net kilowatthour generation.

8

 Capacity factors are the ratio of the electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous 

full power operation during the same period.
Energy Information Administration/Electric Power Annual 2001 79

• Estimated a value for useful thermal output for 1995 through 1997 (when useful thermal output was not included on the 

survey form) that produced a heat rate between 5,500 and 40,000 Btu per kilowatthour and an efficiency rate consistent 

with that observed in other years (see discussion below on CHP fuel use methodology).

• Corrected errors in units reported for fuel consumption.

• Compared data on fuel consumption with data on electric generation and adjusted data on fuel consumption or generation 

to maintain a consistent ratio.

• Adjusted data on useful thermal output for those respondents with heat rates outside the 5,500-to-40,000 Btu per 

kilowatthour range and an efficiency rate consistent with other years.

The review included an examination of both respondent-level data and aggregate-level data. For the 1998-2000 data, the review 

also included a comparison for consistency with data reported by manufacturing plants on Form EIA-3, “Quarterly Coal 

Consumption—Manufacturing Plants,” since a subset of the EIA-3 manufacturing plants generate electricity and also reported on 

the electric generator survey Form EIA-860B. In general, there was good correspondence between the data submissions. In 

situations where there were inconsistencies, selected respondents were contacted to explain the differences. The analysis revealed 

that in some instances there were legitimate explanations for high percentage differences, such as a respondent reporting data for a 

facility on one survey that should not be included in the other survey.

Allocating CHP Fuel Use

Because respondents do not keep records on how much fuel a CHP plant uses exclusively to produce electricity, EIA developed the 

following method for estimating how the total fuel consumed in the boiler is split between electricity generation and useful thermal 

output:

• First, a steam boiler efficiency rate of 80 percent was assumed9

• Then the reported or estimated value for useful thermal output (in Btu) was divided by 0.8 to estimate the fuel used to 

generate this amount of thermal output.

• Next, this value was subtracted from total fuel consumption and the remainder was assumed to be the amount used for 

electric generation.

Electric Powe r Publication Tables Affected

In both the Electric Power Monthly and the Electric Power Annual:

• Data will be shown for the following categories throughout most of the report: (1) U.S. power producers, (2) electricityonly plants, and (3) CHP plants (commercial, industrial, and electric power). Data on fuel consumption are shown for 

both electric generation and thermal output.

• The lowest level of aggregation is at the State level.

• Data on petroleum coke are converted to barrels and included in petroleum consumption and stocks tables.

• Fuel types are revised to be consistent with the Annual Energy Review.

9

 Arthur D. Little, Report to the Energy Information Administration, Industrial Model: Update on Energy Use and Industrial Characteristics, (September 2001), Appendix C, "Average 

Boiler Efficiencies."
Energy Information Administration/Electric Power Annual 2001 81

Glossary

Anthracite: The highest rank of coal; used primarily for 

residential and commercial space heating. It is a hard,

brittle, and black lustrous coal, often referred to as hard 

coal, containing a high percentage of fixed carbon and a 

low percentage of volatile matter. The moisture content of 

fresh-mined anthracite generally is less than 15 percent. 

The heat content of anthracite ranges from 22 to 28 

million Btu per ton on a moist, mineral-matter-free basis. 

The heat content of anthracite coal consumed in the

United States averages 25 million Btu per ton, on the asreceived basis (i.e., containing both inherent moisture and 

mineral matter). Note: Since the 1980's, anthracite refuse 

or mine waste has been used for steam electric power 

generation. This fuel typically has a heat content of 15 

million Btu per ton or less.

Ash: Impurities consisting of silica, iron, aluminum, and 

other noncombustible matter that are contained in coal. 

Ash increases the weight of coal, adds to the cost of

handling, and can affect its burning characteristics. Ash 

content is measured as a percent by weight of coal on a 

"received" or a "dry" (moisture-free, usually part of a

laboratory analysis) basis.

Ash Content: The amount of ash contained in the fuel 

(except gas) in terms of percent by weight.

Average Revenue per Kilowatthour: The average

revenue per kilowatthour of electricity sold by sector (residential, commercial, industrial, or other) and geographic 

area (State, Census division, and national), is calculated by 

dividing the total monthly revenue by the corresponding 

total monthly sales for each sector and geographic area.

Barrel: A unit of volume equal to 42 U.S. gallons.

Biomass: Organic non-fossil material of biological origin 

constituting a renewable energy resource. 

Bituminous Coal: A dense coal, usually black, sometimes 

dark brown, often with well-defined bands of bright and 

dull material, used primarily as fuel in steam-electric 

power generation, with substantial quantities also used for 

heat and power applications in manufacturing and to make 

coke. Bituminous coal is the most abundant coal in active 

U.S. mining regions. Its moisture content usually is less 

than 20 percent. The heat content of bituminous coal

ranges from 21 to 30 million Btu per ton on a moist,

mineral-matter-free basis. The heat content of bituminous 

coal consumed in the United States averages 24 million 

Btu per ton, on the as-received basis (i.e., containing both 

inherent moisture and mineral matter).

British Thermal Unit: The quantity of heat required to 

raise the temperature of 1 pound of liquid water by 1 

degree Fahrenheit at the temperature at which water has its 

greatest density (approximately 39 degrees Fahrenheit). 

Btu: The abbreviation for British thermal unit(s). 

Capacity: See Generator Capacity and Generator Name 

Plate Capacity (Installed). 

Census Divisions: Any of nine geographic areas of the 

United States as defined by the U.S. Department of

Commerce, Bureau of the Census. The divisions, each

consisting of several States, are defined as follows: 

1) New England: Connecticut, Maine, Massachusetts, 

New Hampshire, Rhode Island, and Vermont; 

2) Middle Atlantic: New Jersey, New York, and

Pennsylvania; 

3) East North Central: Illinois, Indiana, Michigan,

Ohio, and Wisconsin; 

4) West North Central: Iowa, Kansas, Minnesota,

Missouri, Nebraska, North Dakota, and South

Dakota; 

5) South Atlantic: Delaware, District of Columbia,

Florida, Georgia, Maryland, North Carolina, South 

Carolina, Virginia, and West Virginia; 

6) East South Central: Alabama, Kentucky,

Mississippi, and Tennessee; 

7) West South Central: Arkansas, Louisiana,

Oklahoma, and Texas; 

8) Mountain: Arizona, Colorado, Idaho, Montana,

Nevada, New Mexico, Utah, and Wyoming; 

9) Pacific: Alaska, California, Hawaii, Oregon, and 

Washington. 

Note: Each division is a sub-area within a broader Census 

Region. In some cases, the Pacific division is subdivided 

into the Pacific Contiguous area (California, Oregon, and 

Washington) and the Pacific Noncontiguous area (Alaska 

and Hawaii).

Coal: A readily combustible black or brownish-black rock 

whose composition, including inherent moisture, consists 

of more than 50 percent by weight and more than 70 

percent by volume of carbonaceous material. It is formed 

from plant remains that have been compacted, hardened, 

chemically altered, and metamorphosed by heat and

pressure over geologic time.

Coke (Petroleum): A residue high in carbon content and 

low in hydrogen that is the final product of thermal 

decomposition in the condensation process in cracking. 

This product is reported as marketable coke or catalyst 

coke. The conversion is 5 barrels (of 42 U.S. gallons each) 

per short ton. Coke from petroleum has a heating value of 

6.024 million Btu per barrel.

Combined Cycle: An electric generating technology in 

which electricity is produced from otherwise lost waste 

heat exiting from one or more gas (combustion) turbinegenerators. The exiting heat from the combustion

turbine(s) is routed to a conventional boiler or to a heat 

recovery steam generator for utilization by a steam turbine 

in the production of additional electricity. 

Combined Heat and Power (CHP): Includes plants

designed to produce both heat and electricity from a single 
82 Energy Information Administration/Electric Power Annual 2001

heat source. Note: This term is being used in place of the 

term "cogenerator" that was used by EIA in the past. CHP 

better describes the facilities because some of the plants 

included do not produce heat and power in a sequential 

fashion and, as a result, do not meet the legal definition of 

cogeneration specified in the Public Utility Regulatory 

Policies Act (PURPA). 

Commercial Sector: An energy-consuming sector that 

consists of service-providing facilities and equipment of: 

businesses; Federal, State, and local governments; and 

other private and public organizations, such as religious, 

social, or fraternal groups. The commercial sector includes 

institutional living quarters. It also includes sewage

treatment facilities. Common uses of energy associated 

with this sector include space heating, water heating, air 

conditioning, lighting, refrigeration, cooking, and running 

a wide variety of other equipment. Note: This sector

includes generators that produce electricity and/or useful 

thermal output primarily to support the activities of the 

above-mentioned commercial establishments.

Consumption (Fuel): The use of energy as a source of 

heat or power or as a raw material input to a

manufacturing process.

Cooperative Electric Utility: An electric utility legally 

established to be owned by and operated for the benefit of 

those using its service. The utility company will generate, 

transmit, and/or distribute supplies of electric energy to a 

specified area not being serviced by another utility. Such 

ventures are generally exempt from Federal income tax 

laws. Most electric cooperatives have been initially

financed by the Rural Utilities Service (prior Rural

Electrification Administration), U.S. Department of

Agriculture.

Cost: The amount paid to acquire resources, such as plant 

and equipment, fuel, or labor services.

Delivery-Only Service: Only services that involve the 

distribution of energy to retail customers, where another 

entity supplies the energy to be delivered.

Demand (Electric): The rate at which electric energy is 

delivered to or by a system, part of a system, or piece of 

equipment, at a given instant or averaged over any

designated period of time.

Demand-Side Management: The planning,

implementation, and monitoring of utility activities

designed to encourage consumers to modify patterns of 

electricity usage, including the timing and level of

electricity demand. It refers only to energy and load-shape 

modifying activities that are undertaken in response to 

utility-administered programs. It does not refer to energy 

and load-shape changes arising from the normal operation 

of the marketplace or from government-mandated energyefficiency standards. Demand-Side Management (DSM) 

covers the complete range of load-shape objectives,

including strategic conservation and load management, as 

well as strategic load growth.

Diesel: A distillate fuel oil that is used in diesel engines 

such as those used for transportation and for electric 

power generation.

Distillate Fuel Oil: A general classification for one of the 

petroleum fractions produced in conventional distillation 

operations. It includes diesel fuels and fuel oils. Products 

known as No. 1, No. 2, and No. 4 diesel fuel are used in 

on-highway diesel engines, such as those in trucks and 

automobiles, as well as off-highway engines, such as those 

in railroad locomotives and agricultural machinery.

Products known as No. 1, No. 2, and No. 4 fuel oils are 

used primarily for space heating and electric power

generation.

1) No. 1 Distillate: A light petroleum distillate that can be 

used as either a diesel fuel (see No. 1 Diesel Fuel) or a 

fuel oil. See No. 1 Fuel Oil.

• No. 1 Diesel Fuel: A light distillate fuel oil that 

has distillation temperatures of 550 degrees

Fahrenheit at the 90-percent point and meets the 

specifications defined in ASTM Specification D 

975. It is used in high-speed diesel engines, such 

as those in city buses and similar vehicles. See No. 

1 Distillate above.

• No. 1 Fuel Oil: A light distillate fuel oil that has 

distillation temperatures of 400 degrees Fahrenheit 

at the 10-percent recovery point and 550 degrees 

Fahrenheit at the 90-percent point and meets the 

specifications defined in ASTM Specification D 

396. It is used primarily as fuel for portable

outdoor stoves and portable outdoor heaters. See 

No. 1 Distillate above. 

2) No. 2 Distillate: A petroleum distillate that can be used 

as either a diesel fuel (see No. 2 Diesel Fuel definition 

below) or a fuel oil. See No. 2 Fuel oil below. 

• No. 2 Diesel Fuel: A fuel that has distillation 

temperatures of 500 degrees Fahrenheit at the 10-

percent recovery point and 640 degrees

Fahrenheit at the 90-percent recovery point and 

meets the specifications defined in ASTM

Specification D 396. It is used in atomizing type 

burners for domestic heating or for moderate

capacity commercia l/industrial burner units. See 

No. 2 Distillate above. 

3) No. 4 Fuel: A distillate fuel oil made by blending 

distillate fuel oil and residual fuel oil stocks. It

conforms with ASTM Specification D 396 or Federal 

Specification VV-F-815C and is used extensively in 

industrial plants and in commercial burner installations 

that are not equipped with preheating facilities. It also 

includes No. 4 diesel fuel used for low- and medium-
Energy Information Administration/Electric Power Annual 2001 83

speed diesel engines and conforms to ASTM

Specification D 975. 

• No. 4 Diesel Fuel and No. 4 Fuel Oil: See No. 4 

Fuel above. 

Distribution System: The portion of the transmission and 

facilities of an electric system that is dedicated to

delivering electric energy to an end-user. 

Electric Industry Restructuring: The process of

replacing a monopolistic system of electric utility

suppliers with competing sellers, allowing individual retail 

customers to choose their supplier but still receive delivery 

over the power lines of the local utility. It includes the 

reconfiguration of vertically integrated electric utilities.

Electric Plant (Physical): A facility containing prime 

movers, electric generators, and auxiliary equipment for 

converting mechanical, chemical, and/or fission energy 

into electric energy. 

Electric Power Sector: An energy-consuming sector that 

consists of electricity-only and combined-heat-and-power 

(CHP) plants whose primary business is to sell electricity, 

or electricity and heat, to the public-- i. e., North American 

Industry Classification System 22 plants.

Electric Utility: A corporation, person, agency, authority, 

or other legal entity or instrumentality aligned with

distribution facilities for delivery of electric energy for use 

primarily by the public. Included are investor-owned 

electric utilities, municipal and State utilities, Federal 

electric utilities, and rural electric cooperatives. A few 

entities that are tariff based and corporately aligned with 

companies that own distribution facilities are also

included. Note: Due to the issuance of FERC Order 888 

that required traditional electric utilities to functionally 

unbundle their generation, transmission, and distribution 

operations, "electric utility" currently has inconsistent

interpretations from State to State. 

Electricity: A form of energy characterized by the

presence and motion of elementary charged particles

generated by friction, induction, or chemical change.

Electricity Generation: The process of producing electric 

energy or the amount of electric energy produced by

transforming other forms of energy, commo nly expressed 

in kilowatthours (kWh) or megawatthours (MWh).

Electricity Generators: The facilities that produce only 

electricity, commonly expressed in kilowatthours (kWh) 

or megawatthours (MWh). 

1) Electric Utility – A corporation, person, agency,

authority, or other legal entity or instrumentality

aligned with distribution facilities for delivery of

electric energy for use primarily by the public.

Included are investor-owned electric utilities,

municipal and State utilities, Federal electric utilities, 

and rural electric cooperatives. A few entities that are 

tariff based and corporately aligned with companies 

that own distribution facilities are also included. Note:

Due to the issuance of FERC Order 888 that required 

traditional electric utilities to functionally unbundle 

their generation, transmission, and distribution

operations, "electric utility" currently has inconsistent 

interpretations from State to State.

2) Independent Power Producer – A corporation, person, 

agency, authority, or other legal entity or instrumentality that owns or operates facilities for the

generation of electricity for use primarily by the

public, and is not an electric utility. 

Energy: The capacity for doing work as measured by the 

capability of doing work (potential energy) or the

conversion of this capability to motion (kinetic energy). 

Energy has several forms, some of which are easily 

convertible and can be changed to another form useful for 

work. Most of the world's convertible energy comes from 

fossil fuels that are burned to produce heat that is then 

used as a transfer medium to mechanical or other means in 

order to accomplish tasks. Electrical energy is usually 

measured in kilowatthours, while heat energy is usually 

measured in British thermal units.

Energy Conservation Features: This includes building 

shell conservation features, HVAC conservation features, 

lighting conservation features, any conservation features, 

and other conservation features incorporated by the

building. However, this category does not include any

demand-side management (DSM) program participation 

by the building. Any DSM program participation is

included in the DSM Programs. 

Energy Efficiency: Refers to programs that are aimed at 

reducing the energy used by specific end-use devices and 

systems, typically without affecting the services provided. 

These programs reduce overall electricity consumption 

(reported in megawatthours), often without explicit

consideration for the timing of program-induced savings. 

Such savings are generally achieved by substituting 

technically more advanced equipment to produce the same 

level of end-use services (e.g. lighting, heating, motor

drive) with less electricity. Examples include highefficiency appliances, efficient lighting programs, highefficiency heating, ventilating and air conditioning

(HVAC) systems or control modifications, efficient

building design, advanced electric motor drives, and heat 

recovery systems. 

Energy Service Provider: An energy entity that provides 

service to a retail or end-use customer. 

Energy Source: Any substance or natural phenomenon 

that can be consumed or transformed to supply heat or 

power. Examples include petroleum, coal, natural gas,

nuclear, biomass, electricity, wind, sunlight, geothermal, 

water movement, and hydrogen in fuel cells. 
84 Energy Information Administration/Electric Power Annual 2001

Energy-Only Service: Retail sales services for which the 

company provided only the energy consumed, where

another entity provides delivery services.

Federal Power Authority: Any of several federal

agencies, operating under the U.S. Department of Energy, 

primarily involved in generating electricity, marketing

wholesale electrical power, and operating and marketing 

transmission services. 

Flue Gas Desulfurization: Equipment used to remove 

sulfur oxides from the combustion gases of a boiler plant 

before discharge to the atmosphere. Also referred to as 

scrubbers. Chemicals such as lime are used as scrubbing 

media. 

Flue-Gas Desulfurization Unit (Scrubber): Equipment 

used to remove sulfur oxides from the combustion gases 

of a boiler plant before discharge to the atmosphere.

Chemicals such as lime are used as the scrubbing media. 

Flue-Gas Particulate Collector: Equipment used to

remove fly ash from the combustion gases of a boiler plant 

before discharge to the atmosphere. Particulate collectors 

include electrostatic precipitators, mechanical collectors 

(cyclones), fabric filters (baghouses), and wet scrubbers. 

Fossil Fuel: An energy source formed in the earths crust 

from decayed organic material. The common fossil fuels 

are petroleum, coal, and natural gas.

Franchised Service Area: A specified geographical area 

in which a utility has been granted the exclusive right to 

serve customers. A franchise allows an entity to use city 

streets, alleys and other public lands in order to provide, 

distribute, and sell services to the community. 

Fuel: Any material substance that can be consumed to 

supply heat or power. Included are petroleum, coal, and 

natural gas (the fossil fuels), and other consumable

materials, such as uranium, biomass, and hydrogen. 

Full Service Provi der: An utility/company that provides 

both energy and delivery services of retail sales to ultimate 

consumers.

Gas: A fuel burned under boilers and by internal

combustion engines for electric generation. These include 

natural, manufactured and waste gas. 

Gas Turbine Plant: An electric generating facility in 

which the prime mover is a gas (combustion) turbine. A 

gas turbine typically consists of an air compressor and one 

or more combustion chambers where either liquid or

gaseous fuel is burned. The resulting hot gases are passed 

through the turbine where they expand to drive both an 

electric generator and the compressor.

Generating Unit: Any combination of physically

connected generators, reactors, boilers, combustion

turbines, or other prime movers operated together to

produce electric power. 

Generator: A machine that converts mechanical energy 

into electrical energy.

Generator Capacity: The maximum output, commonly 

expressed in megawatts (MW), that generating equipment 

can supply to system load, adjusted for ambient

conditions. 

Generator Nameplate Capacity (Installed): The 

maximum rated output of a generator, prime mover, or 

other electric power production equipment under specific 

conditions designated by the manufacturer. Installed

generator nameplate capacity is commonly expressed in

megawatts (MW) and is usually indicated on a nameplate 

physically attached to the generator.

Geothermal: Pertaining to heat within the Earth.

Geothermal Energy: Hot water or steam extracted from 

geothermal reservoirs in the earth's crust. Water or steam 

extracted from geothermal reservoirs can be used for

geothermal heat pumps, water heating, or electricity

generation.

Gigawatt (GW): One billion watts.

Gigawatthour (GWh): One billion watthours.

Grid: The layout of an electrical distribution system. 

Gross Generation: The total amount of electric energy 

produced by generating units and measured at the

generating terminal in kilowatthours (kWh) or

megawatthours (MWh).

Heat Content: The amount or number of British thermal 

units (Btu) produced by the combustion of fuel, measured 

in Btu/unit of measure. 

Hydroelectric Power: The production of electricity from 

the kinetic energy of falling water.

Hydroelectric Power Generation: Electricity generated 

by an electric power plant whose turbines are driven by 

falling water. It includes electric utility and industrial

generation of hydroelectricity, unless otherwise specified. 

Generation is reported on a net basis, i.e., on the amount 

of electric energy generated after the electric energy 

consumed by station auxiliaries and the losses in the

transformers that are considered integral parts of the

station are deducted.

Hydroelectric Pumped Storage: Hydroelectricity that is 

generated during peak loads by using water previously 

pumped into an elevated storage reservoir during off-peak 

periods when excess generating capacity is available to do 

so. When additional generating capacity is needed, the

water can be released from the reservoir through a conduit 

to turbine generators located in a power plant at a lower 

level. 

Hydrogen: A colorless, odorless, highly flammable

gaseous element. It is the lightest of all gases and the most 

abundant element in the universe, occurring chiefly in 
Energy Information Administration/Electric Power Annual 2001 85

combination with oxygen in water and also in acids, bases, 

alcohols, petroleum, and other hydrocarbons. 

Incremental Effects: The annual changes in energy use 

(measured in megawatthours) and peak load (measured in 

kilowatts) caused by new participants in existing DSM 

(Demand-Side Management) programs and all participants 

in new DSM programs during a given year. Reported 

Incremental Effects are annualized to indicate the program 

effects that would have occurred had these participants 

been initiated into the program on January 1 of the given 

year. Incremental effects are not simply the Annual

Effects of a given year minus the Annual Effects of the 

prior year, since these net effects would fail to account for 

program attrition, equipment degradation, building

demolition, and participant dropouts. Please note that

Incremental Effects are not a monthly disaggregate of the 

Annual Effects, but are the total year's effects of only the 

new participants and programs for that year. 

Independent Power Producer: A corporation, person, 

agency, authority, or other legal entity or instrumentality 

that owns or operates facilities for the generation of

electricity for use primarily by the public, and that is not 

an electric utility. 

Industrial Sector: An energy-consuming sector that

consists of all facilities and equipment used for producing, 

processing, or assembling goods. The industrial sector

encompasses the following types of activity:

manufacturing (NAICS codes 31-33); agriculture, forestry, 

and fisheries (NAICS code 11); mining, including oil and 

gas extraction (NAICS code 21); natural gas transmission 

(NAICS code 2212); and construction (NAICS code 23). 

Overall energy use in this sector is largely for process heat 

and cooling and powering machinery, with lesser amounts 

used for facility heating, air conditioning, and lighting. 

Fossil fuels are also used as raw material inputs to

manufactured products. Note: This sector includes

generators that produce electricity and/or useful thermal 

output primarily to support the above-mentioned industrial

activities. 

Interdepartmental Service (Electric): Interdepartmental 

service includes amounts charged by the electric

department at tariff or other specified rates for electricity 

supplied by it to other utility departments. 

Internal Combustion Plant: A plant in which the prime 

mover is an internal combustion engine. An internal

combustion engine has one or more cylinders in which the 

process of combustion takes place, converting energy

released from the rapid burning of a fuel-air mixture into 

mechanical energy. Diesel or gas-fired engines are the

principal types used in electric plants. The plant is usually 

operated during periods of high demand for electricity. 

Investor-Owned Utility (IOU): A privately-owned electric utility whose stock is publicly traded. It is rate

regulated and authorized to achieve an allowed rate of 

return. 

Jet Fuel: A refined petroleum product used in jet aircraft 

engines. It includes kerosene-type jet fuel and naphthatype jet fuel.

Kerosene: A light petroleum distillate that is used in 

space heaters, cook stoves, and water heaters and is

suitable for use as a light source when burned in wick-fed 

lamps. Kerosene has a maximum distillation temperature 

of 400 degrees Fahrenheit at the 10-percent recovery 

point, a final boiling point of 572 degrees Fahrenheit, and 

a minimum flash point of 100 degrees Fahrenheit.

Included are No. 1-K and No. 2-K, the two grades

recognized by ASTM Specification D 3699 as well as all 

other grades of kerosene called range or stove oil, which 

have properties similar to those of No. 1 fuel oil. 

Kilowatt (kW): One thousand watts.

Kilowatthour (kWh): One thousand watthours.

Light Oil: Lighter fuel oils distilled off during the refining 

process. Virtually all petroleum used in internal

combustion and gas-turbine engines is light oil.

Lignite: The lowest rank of coal, often referred to as

brown coal, used almost exclusively as fuel for steamelectric power generation. It is brownish-black and has a 

high inherent moisture content, sometimes as high as 45 

percent The heat content of lignite ranges from 9 to 17 

million Btu per ton on a moist, mineral-matter-free basis. 

The heat content of lignite consumed in the United States 

averages 13 million Btu per ton, on the as-received basis 

(i.e., containing both inherent moisture and mineral

matter).

Load (Electric): The amount of electric power delivered 

or required at any specific point or points on a system. The 

requirement originates at the energy-consuming 

equipment of the consumers. 

Load Management Techniques: Utility demand

management practices directed at reducing the maximum 

kilowatt demand on an electric system and/or modifying 

the coincident peak demand of one or more classes of

service to better meet the utility system capability for a 

given hour, day, week, season, or year. 

Manufactured Gas: A gas obtained by destructive

distillation of coal, or by thermal decomposition of oil, or 

by the reaction of steam passing through a bed of heated 

coal or coke. Examples are coal gases, coke oven gases, 

producer gas, blast furnace gas, blue (water) gas, and 

carbureted water gas

Mcf: One thousand cubic feet.

Megawatt (MW): One million watts of electricity. 

Megawatthour (MWh): One million watthours.

Municipal Utility: A nonprofit utility, owned by a local 

municipality and operated as a department thereof,

governed by a city council or an independently elected or 
86 Energy Information Administration/Electric Power Annual 2001

appointed board; primarily involved in the distribution 

and/or sale of retail electric power. 

Natural Gas: A gaseous mixture of hydrocarbon

compounds, the primary one being methane. Note: The 

Energy Information Administration measures wet natural 

gas and its two sources of production, associated/dissolved 

natural gas and nonassociated natural gas, and dry natural 

gas, which is produced from wet natural gas. 

1) Wet Natural Gas: A mixture of hydrocarbon

compounds and small quantities of various

nonhydrocarbons existing in the gaseous phase or in 

solution with crude oil in porous rock formations at 

reservoir conditions. The principal hydrocarbons

normally contained in the mixture are methane, ethane, 

propane, butane, and pentane. Typical nonhydrocarbon 

gases that may be present in reservoir natural gas are 

water vapor, carbon dioxide, hydrogen sulfide,

nitrogen and trace amounts of helium. Under reservoir 

conditions, natural gas and its associated liquefiable 

portions occur either in a single gaseous phase in the 

reservoir or in solution with crude oil and are not 

distinguishable at the time as separate substances.

Note: The Securities and Exchange Commission and 

the Financial Accounting Standards Board refer to this 

product as natural gas. 

• Associated-dissolved natural gas: Natural gas that 

occurs in crude oil reservoirs either as free gas 

(associated) or as gas in solution with crude oil 

(dissolved gas). 

• Nonassociated natural gas: Natural gas that is not 

in contact with significant quantities of crude oil 

in the reservoir. 

2) Dry Natural Gas: Natural gas which remains after: 1) 

the liquefiable hydrocarbon portion has been removed 

from the gas stream (i.e., gas after lease, field, and/or 

plant separation); and 2) any volumes of nonhydrocarbon gases have been removed where they occur in 

sufficient quantity to render the gas unmarketable. 

Note: Dry natural gas is also known as consumer-grade 

natural gas. The parameters for measurement are cubic 

feet at 60 degrees Fahrenheit and 14.73 pounds per 

square inch absolute. 

Net Generation: The amount of gross generation less the 

electrical energy consumed at the generating station(s) for 

station service or auxiliaries. Note: Electricity required for 

pumping at pumped-storage plants is regarded as

electricity for station service and is deducted from gross 

generation.

Net Summer Capacity: The maximum output, commonly 

expressed in megawatts (MW), that generating equipment 

can supply to system load, as demonstrated by a multihour test, at the time of summer peak demand (period of 

May 1 through October 31). This output reflects a

reduction in capacity due to electricity use for station 

service or auxiliaries. 

Net Winter Capacity: The maximum output, commonly 

expressed in megawatts (MW), that generating equipment 

can supply to system load, as demonstrated by a multihour test, at the time of peak winter demand (period of 

November 1 though April 30). This output reflects a

reduction in capacity due to electricity use for station 

service or auxiliaries.

North American Electric Reliability Council (NERC): 

A council formed in 1968 by the electric utility industry to 

promote the reliability and adequacy of bulk power supply 

in the electric utility systems of North America. The 

NERC Regions are: 

1) ECAR – East Central Area Reliability Coordination Agreement 

2) ERCOT – Electric Reliability Council of Texas

3) FRCC – Florida Reliability Coordinating Council

4) MAIN – Mid -America Interconnected Network

5) MAAC – Mid-Atlantic Area Council

6) MAPP – Mid-Continent Area Power Pool

7) NPCC – Northeast Power Coordinating Council

8) SERC – Southeastern Electric Reliability Council

9) SPP – Southwest Power Pool

10) WSCC – Western Systems Coordinating Council

North American Industry Classification System

(NAICS): A set of codes that describes the possible

purposes of a facility.

Nuclear Electric Power: Electricity generated by an

electric power plant whose turbines are driven by steam 

produced by the heat from the fission of nuclear fuel in a 

reactor.

Other Customers: Includes public street and highway 

lighting, other sales to public authorities, sales to railroads 

and railways, sales for irrigation, and interdepartmental 

sales.

Other Generation: Electricity originating from these

sources: manufactured, supplemental gaseous fuel,

propane, and waste gasses, excluding natural gas;

biomass; geothermal; wind; solar thermal; photovoltaic; 

synthetic fuel; purchased steam; and waste oil energy

sources.

Percent Change: The relative change in a quantity over a 

specified time period. It is calculated as follows: the 

current value has the previous value subtracted from it; 

this new number is divided by the absolute value of the 

previous value; then this new number is multiplied by 100. 

Petroleum: A broadly defined class of liquid hydrocarbon 

mixtures. Included are crude oil, lease condensate,

unfinished oils, refined products obtained from the
Energy Information Administration/Electric Power Annual 2001 87

processing of crude oil, and natural gas plant liquids. 

Note: Volumes of finished petroleum products include

nonhydrocarbon compounds, such as additives and

detergents, after they have been blended into the products.

Petroleum Coke: See Coke (Petroleum).

Photovoltaic Energy: Direct-current electricity generated 

from sunlight through solid-state semiconductor devices 

that have no moving parts.

Plant: A term commonly used either as a synonym for an 

industrial establishment or a generation facility or to refer 

to a particular process within an establishment.

Potential Peak Reduction: The potential annual peak 

load reduction (measured in kilowatts) that can be

deployed from Direct Load Control, Interruptible Load, 

Other Load Management, and Other DSM Program

activities. (Please note that Energy Efficiency and Load 

Building are not included in Potential Peak Reduction.) It 

represents the load that can be reduced either by the direct 

control of the utility system operator or by the consumer in 

response to a utility request to curtail load. It reflects the 

installed load reduction capability, as opposed to the

Actual Peak Reduction achieved by participants, during 

the time of annual system peak load. 

 Power: The rate at which energy is transferred. Electrical 

energy is usually measured in watts. Also used for a 

measurement of capacity.

Power Production Plant: All the land and land rights, 

structures and improvements, boiler or reactor vessel

equipment, engines and engine-driven generator, turbo

generator units, accessory electric equipment, and

miscellaneous power plant equipment are grouped

together for each individual facility. 

Production (Electric): Act or process of producing

electric energy from other forms of energy; also, the

amount of electric energy expressed in watthours (Wh). 

Propane: A normally gaseous straight-chain hydrocarbon, 

(C3H8). It is a colorless paraffinic gas that boils at a

temperature of -43.67 degrees Fahrenheit. It is extracted 

from natural gas or refinery gas streams. It includes all 

products covered by Gas Processors Association

Specifications for commercial propane and HD-5 propane 

and ASTM Specification D 1835.

Public Street and Highway Lighting Service: Includes 

electricity supplied and services rendered for the purpose 

of lighting streets, highways, parks and other public

places; or for traffic or other signal system service, for 

municipalities, or other divisions or agencies of State or 

Federal governments.

Publicly Owned Electric Utility: A class of ownership 

found in the electric power industry. This group includes 

those utilities operated by municipalities and State and 

Federal power agencies. 

Purchased Power: Power purchased or available for

purchase from a source outside the system.

Railroad and Railway Electric Service: Electricity 

supplied to railroads and interurban and street railways, 

for general railroad use, including the propulsion of cars or 

locomotives, where such electricity is supplied under

separate and distinct rate schedules.

Receipts: Purchases of fuel.

Relative Standard Error: The standard deviation of a 

distribution divided by the arithmetic mean, sometimes 

multiplied by 100. It is used for the purpose of comparing 

the variabilities of frequency distributions but is sensitive 

to errors in the means. 

Residential: An energy-consuming sector that consists of 

living quarters for private households. Common uses of 

energy associated with this sector include space heating, 

water heating, air conditioning, lighting, refrigeration,

cooking, and running a variety of other appliances. The 

residential sector excludes institutional living quarters.

Residual Fuel Oil: A general classification for the heavier 

oils, known as No. 5 and No. 6 fuel oils, that remain after 

the distillate fuel oils and lighter hydrocarbons are distilled 

away in refinery operations. It conforms to ASTM

Specifications D 396 and D 975 and Federal Specification 

VV-F-815C. No. 5, a residual fuel oil of medium

viscosity, is also known as Navy Special and is defined in 

Military Specification MIL-F-859E, including Amendment 2 (NATO Symbol F-770). It is used in steampowered vessels in government service and inshore

powerplants. No. 6 fuel oil includes Bunker C fuel oil and 

is used for the production of electric power, space heating, 

vessel bunkering, and various industrial purposes.

Retail: Sales covering electrical energy supplied for

residential, commercial, and industrial end-use purposes. 

Other small classes, such as agriculture and street lighting, 

also are included in this category.

Revenues: The total amount of money received by a firm 

from sales of its products and/or services, gains from the 

sales or exchange of assets, interest and dividends earned 

on investments, and other increases in the owner's equity 

except those arising from capital adjustments.

Sales: The transfer of title to an energy commodity from a 

seller to a buyer for a price or the quantity transferred 

during a specified period.

Sales for Resale: A type of wholesale sales covering 

energy supplied to other electric utilities, cooperatives,

municipalities, and Federal and state electric agencies for 

resale to ultimate consumers. 

Service Classifications (Sectors): Consumers grouped by 

similar characteristics in order to be identified for the 

purpose of setting a common rate for electric service. 

Usually classified into groups identified as residential, 

commercial, industrial and other. 
88 Energy Information Administration/Electric Power Annual 2001

Service to Public Authorities: Public authority service 

includes electricity supplied and services rendered to

municipalities or divisions or agencies of State and

Federal governments, under special contracts or

agreements or service classifications applicable only to 

public authorities. 

Solar Energy: The radiant energy of the sun that can be 

converted into other forms of energy, such as heat or

electricity. Electricity produced from solar energy heats a 

medium that powers an electricity-generating device.

State Power Authority: A nonprofit utility owned and 

operated by a state government agency, primarily involved 

in the generation, marketing, and/or transmission of

wholesale electric power.

Steam-Electric Power Plant (Conventional): A plant in 

which the prime mover is a steam turbine. The steam used 

to drive the turbine is produced in a boiler where fossil 

fuels are burned.

Stocks of Fuel: A supply of fuel accumulated for future 

use. This includes coal and fuel oil stocks at the plant site, 

in coal cars, tanks, or barges at the plant site, or in separate 

storage sites.

Subbituminous Coal: A coal whose properties range

from those of lignite to those of bituminous coal and used 

primarily as fuel for steam-electric power generation. It 

may be dull, dark brown to black, soft and crumbly, at the 

lower end of the range, to bright, jet black, hard, and 

relatively strong, at the upper end. Subbituminous coal 

contains 20 to 30 percent inherent moisture by weight. The 

heat content of subbituminous coal ranges from 17 to 24 

million Btu per ton on a moist, mineral-matter-free basis. 

The heat content of subbituminous coal consumed in the 

United States averages 17 to 18 million Btu per ton, on the 

as-received basis (i.e., containing both inherent moisture 

and mineral matter).

Sulfur: A yellowish nonmetallic element, sometimes

known as "brimstone." It is present at various levels of 

concentration in many fossil fuels whose combustion

releases sulfur compounds that are considered harmful to 

the environment. Some of the most commonly used fossil 

fuels are categorized according to their sulfur content, 

with lower sulfur fuels usually selling at a higher price. 

Note: No. 2 Distillate fuel is currently reported as having 

either a 0.05 percent or lower sulfur level for on-highway 

vehicle use or a greater than 0.05 percent sulfur level for 

off-highway use, home heating oil, and commercial and 

industrial uses. Residual fuel, regardless of use, is

classified as having either no more than 1 percent sulfur or 

greater than 1 percent sulfur. Coal is also classified as 

being low- sulfur at concentrations of 1 percent or less or 

high-sulfur at concentrations greater than 1 percent.

Sulfur Content: The amount of sulfur contained in the 

fuel (except gas) in terms of percent by weight.

Supplemental Gaseous Fuel Supplies: Synthetic natural 

gas, propane-air, coke oven gas, refinery gas, biomass gas, 

air injected for Btu stabilization, and manufactured gas 

commingled and distributed with natural gas. 

Synthetic Fuel: A gaseous, liquid, or solid fuel that does 

not occur naturally. Synfuels can be made from coal (coal 

gasification or coal liquefaction), petroleum products, oil 

shale, tar sands, or plant products. Among the synfuels 

are various fuel gases, including but not restricted to

substitute natural gas, liquid fuels for engines (e.g.,

gasoline, diesel fuel, and alcohol fuels) and burner fuels 

(e.g., fuel heating oils).

Terrawatt: One trillion watts.

Terrawatthour: One trillion kilowatthours.

Ton: A unit of weight equal to 2,000 pounds.

Turbine: A machine for generating rotary mechanical 

power from the energy of a stream of fluid (such as water, 

steam, or hot gas). Turbines convert the kinetic energy of 

fluids to mechanical energy through the principles of

impulse and reaction, or a mixture of the two.

Two-Party Wheeling: An arrangement between two

entities in which one entity agrees to transmit electricity 

owned by the other.

Ultimate Consumer: A consumer that purchases

electricity for its own use and not for resale. 

Useful Thermal Output: The thermal energy made

available in a combined heat or power system for use in 

any industrial or commercial process, heating or cooling 

application, or delivered to other end users, i.e., total

thermal energy made available for processes and

applications other than electrical generation.

Waste Coal: As a fuel for electric power generation, 

waste coal includes anthracite refuse or mine waste, waste 

from anthracite preparation plants, and coal recovered

from previously mined sites. 

Waste Gases: As a fuel for electric power generation, 

waste gasses are those gasses that are produced from

gasses recovered from a solid-waste or wastewater

treatment facility, or the gaseous by-products of oilrefining processes. 

Waste Oil: As a fuel for electric power generation, waste 

oil includes recycled motor oil, and waste oil from

transformers.

Watt (W): The unit of electrical power equal to one 

ampere under a pressure of one volt. A Watt is equal to 

1/746 horsepower.

Watthour (Wh): The electrical energy unit of measure 

equal to one watt of power supplied to, or taken from, an 

electric circuit steadily for one hour.
Energy Information Administration/Electric Power Annual 2001 89

Wind Energy: The kinetic energy of wind converted into 

mechanical energy by wind turbines (i.e., blades rotating 

from the hub) that drive generators to produce electricity.

Year to Date: The cumulative sum of each month's value 

starting with January and ending with the current month of 

the data.