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Carbon Dioxide Emissions from the

Generation of Electric Power in

the United States

July 2000

Department of Energy

Washington, DC 20585

Environmental Protection Agency

Washington DC 20460

Contacts

This report was prepared jointly by the staff of the U.S. Department of Energy and the U.S. Environmental

Protection Agency. Questions about this publication, as well as other energy inquiries may be directed to

the National Energy Information Center on (202) 586­8800.

Questions regarding specific information in the report may be directed as follows:

Electric Power Data and Carbon Dioxide Emission Estimates:

Wiley Barbour (202­260­6972) e­mail: barbour.wiley@epamail.epa.gov

Channele Carner (202­287­1928) e­mail: channele.carner@eia.doe.gov
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Melvin Johnson (202­287­1754) e­mail: melvin.johnson@eia.doe.gov

Rick Morgan (202­564­9143) e­mail: morgan.rick@epamail.epa.gov

Roger Sacquety (202­287­1745) e­mail: roger.sacquety@eia.doe.gov

Stephen Scott (202­287­1737) e­mail: stephen.scott@eia.doe.gov

Betty Williams (202­287­1927) e­mail: betty.williams@eia.doe.gov

Projected Electricity Generation and Carbon Dioxide Emissions:

Scott Sitzer (202­586­2308) e­mail: scott.sitzer@eia.doe.gov

Voluntary Carbon­Reduction and Carbon­Sequestration Programs:

Paul McArdle (202­586­4445) e­mail: paul.mcardle@eia.doe.gov

Stephen Calopedis (202­586­1156) e­mail: stephen.calopedis@eia.doe.gov

Kate Narburgh (202­564­1846) e­mail: narburgh.kate@epamail.epa.gov

Environmental Effects of Federal Restructuring Legislation:

Tracy Terry (202­586­3383) e­mail: tracy.terry@hq.doe.gov

Contents

Introduction

Electric Power Industry CO2 Emissions and Generation Share by Fuel Type

Factors Contributing to Changes in CO2 Emissions and Generation

Comparison of Projected with Actual CO2 Emissions and Generation by Fuel Type

Voluntary Carbon­Reduction and Carbon­Sequestration Programs

Environmental Effects of Federal Restructuring Legislation

Appendices
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A. Presidential Directive

B. Data Sources and Methodology

Tables

1. Summary of Carbon Dioxide Emissions and Net Generation in the United States, 1998 and 1999

2. Estimated Carbon Dioxide Emissions From Generating Units at U.S. Electric Plants by Census

Division, 1998 and 1999

3. Percent of Electricity Generated at U.S. Electric Plants by Fuel Type and Census Division, 1998

and 1999

4. Estimated Carbon Dioxide Emissions Rate From Generating Units at U.S. Electric Plants by

Census Division, 1998 and 1999

5. U.S. Electric Power Industry Projected and Actual Carbon Dioxide Emissions and Generation,

1999

6. Electric Power Sector Carbon Dioxide Emission Reductions, 1997 and 1998

7. CO2 Emission Reductions and Energy Savings from EPA's Voluntary Programs, 1998 and 1999

Figures

1. Census Regions and Divisions

Introduction

The President issued a directive on April 15, 1999, requiring an annual report summarizing the carbon

dioxide (CO2) emissions produced by the generation of electricity by utilities and nonutilities in the United

States. In response, the U.S. Department of Energy (DOE) and the U.S. Environmental Protection Agency
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(EPA) jointly submitted the first report on October 15, 1999. This is the second annual report

(1)

that

estimates the CO2 emissions attributable to the generation of electricity in the United States. The data on

CO2 emissions and the generation of electricity were collected and prepared by the Energy Information

Administration (EIA), and the report was jointly written by DOE and EPA to address the five areas

outlined in the Presidential Directive.

The emissions of CO2 are presented on the basis of total mass (tons) and output rate (pounds per

kilowatthour). The information is stratified by the type of fuel used for electricity generation and

presented for both regional and national levels. The percentage of electricity generation produced by

each fuel type or energy resource is indicated.

The 1999 data on CO2 emissions and generation by fuel type are compared to the same data for the

previous year, 1998. Factors contributing to regional and national level changes in the amount and

average output rate of CO2 are identified and discussed.

The Energy Information Administration's most recent projections of CO2 emissions and generation

by fuel type for 1999 are compared to the actual data summarized in this report to identify deviations

between projected and actual CO2 emissions and electricity generation.

Information for 1998 on voluntary carbon­reducing and carbon­sequestration projects reported by the

electric power sector and the resulting amount of CO2reductions are presented. Included are

programs undertaken by the utilities themselves as well as programs supported by the Federal

government to support voluntary CO2reductions.

Appropriate updates to the Department of Energy's estimated environmental effects of the

Administration's proposed restructuring legislation are included.

Electric Power Industry CO2 Emissions and

Generation Share by Fuel Type

In 1999,

(2) estimated emissions of CO2

in the United States resulting from the generation of electric power

were 2,245 million metric tons,

(3) an increase of 1.4 percent from the 2,215 million metric tons in 1998.

The estimated generation of electricity from all sources increased by 2.0 percent, going from 3,617 billion

kilowatthours to 3,691 billion kilowatthours. Electricity generation from coal­fired plants, the primary

source of CO2 emissions from electricity generation, was nearly the same in 1999 as in 1998. Much of the

increase in electricity generation was produced by gas­fired plants and nuclear plants. The 1999 national

average output rate,

(4) 1.341 pounds of CO2 per kilowatthour generated, also showed a slight change from

1.350 pounds CO2 per kilowatthour in 1998 (Table 1). While the share of total generation provided by

fossil fuels rose slightly, a reduction in the emission rate for coal­fired generation combined with growth in

the market share of gas­fired generation contributed to the modest improvement in the output rate.

(5)
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Table 1. Summary of Carbon Dioxide Emissions and Net Generation in the United States, 1998 and 1999

1998 1999

p Change

Percent

Change

Carbon Dioxide (thousand metric tons)

a

Coal 1,799,762 1,787,910 ­11,852 ­0.66

Petroleum 110,244 106,294 ­3,950 ­3.58

Gas 291,236 337,004 45,768 15.72

Other Fuels

b 13,596 13,596 ­ ­

U.S. Total 2,214,837 2,244,804 29,967 1.35

Generation (million kWh)

Coal 1,873,908 1,881,571 7,663 0.41

Petroleum 126,900 119,025 ­7,875 ­6.21

Gas 488,712 562,433 73,721 15.08

Other Fuels

b 21,747 21,749 2 ­

Total Fossil­fueled 2,511,267 2,584,779 73,512 2.93

Nonfossil­fueled

c 1,105,947 1,106,294 347 0.03

U.S. Total 3,617,214 3,691,073 73,509 2.04

Output Rate

d

(pounds CO2 per kWh)

Coal 2.117 2.095 ­0.022 ­1.04

Petroleum 1.915 1.969 0.054 2.82

Gas 1.314 1.321 0.007 0.53

Other Fuels

b 1.378 1.378 ­ ­

U.S. Average 1.350 1.341 ­0.009 ­0.67

a One metric ton equals one short ton divided by 1.1023. To convert carbon dioxide to carbon units, divide by

44/12.

b Other fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to

generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.

c Nonfossil includes nuclear, hydroelectric, solar, wind, geothermal, biomass, and other fuels or energy sources

with zero or net zero CO2 emissions. Although geothermal contributes a small amount of CO2 emissions, in this

report it is included in nonfossil.

dU.S. average output rate is based on generation from all energy sources.

P= Preliminary data.

­ = No change.

Note: Data for 1999 are preliminary. Data for 1998 are final.

Sources: •Energy Information Administration, Form EIA­759, "Monthly Power Plant Report"; Form EIA767,"Steam­Electric Plant Operation and Design Report"; Form EIA­860B, "Annual Electric Generator Report ­

Nonutility"; and Form 900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form

423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."

In the United States, about 40.5 percent

(6) of anthropogenic CO2 emissions was attributed to the

combustion of fossil fuels for the generation of electricity in 1998, the latest year for which all data are

available.

(7) The available energy sources used for electricity generation result in varying output rates for

CO2 emissions from region to region across the United States. Although all regions use some fossil fuels

for electricity generation, several States generate almost all electricity at nuclear or hydroelectric plants,

resulting in correspondingly low output rates of CO2 per kilowatthour. For example, Vermont produces
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mostly nuclear power, while Washington, Idaho, and Oregon generate almost all electricity at hydroelectric

plants. At the other extreme, Colorado, Indiana, Iowa, Kentucky, New Mexico, North Dakota, Ohio, West

Virginia, and Wyoming­­a group that includes some of the Nation's largest coal­producing States­­generate

most of their electricity with coal. Regions where coal­fired generators dominate the industry show the

highest rates of CO2 emissions per kilowatthour.

Coal

Estimated emissions of CO2 produced by coal­fired generation of electricity were 1,788 million metric tons

in 1999 (Table 1), 0.7 percent less than in 1998, while electricity generation from coal was 0.4 percent

more than the previous year. The divergent direction of generation and emissions changes may reflect a

combination of thermal efficiency improvements, changes in average fuel characteristics, and variances

associated with both sampling and nonsampling errors. CO2 emissions from coal­fired electricity

generation comprise nearly 80 percent of the total CO2 emissions produced by the generation of electricity

in the United States, while the share of electricity generation from coal was 51.0 percent in 1999 (Table 3).

Coal has the highest carbon intensity among fossil fuels, resulting in coal­fired plants having the highest

output rate of CO2 per kilowatthour. The national average output rate for coal­fired electricity generation

was 2.095 pounds CO2 per kilowatthour in 1999 (Table 4).

Coal­fired generation contributes over 90 percent of CO2 emissions in the East North Central, West North

Central, East South Central, and Mountain Census Divisions and 84 percent in the South Atlantic Census

Division (Table 2). Nearly two­thirds of the Nation's CO2 emissions from electricity generation are

accounted for by the combustion of coal for electricity generation in these five regions where most of the

Nation's coal­producing States are located. Consequently, these regions have relatively high output rates of

CO2 per kilowatthour.

Table 2. Estimated Carbon Dioxide Emissions From Generating Units at U.S. Electric Plants by Census

Division, 1998 and 1999 (Thousand Metric Tons)

Census

Division

1998 1999

Total Coal Petroleum Gas Other

a Total Coal Petroleum Gas Other

a

New England 50,450 16,470 23,068 7,966 2,945 52,822 14,637 24,224 11,015 2,945

Middle Atlantic 189,023 139,821 17,315 28,441 3,447 190,214 134,528 15,232 37,007 3,447

East North

Central 427,580 410,141 4,351 12,039 1,049 423,063 397,266 5,415 19,333 1,049

West North

Central 217,123 209,858 1,521 4,726 1,018 219,104 208,786 1,957 7,342 1,018

South Atlantic 445,435 373,780 43,777 24,515 3,363 452,180 378,018 41,356 29,442 3,363

East South

Central 226,749 212,350 5,018 9,299 82 228,240 214,486 3,212 10,460 82

West South

Central 364,056 214,544 5,461 143,945 106 380,792 221,309 5,744 153,634 106

Mountain 219,147 206,256 888 12,002 * 217,543 202,421 1,278 13,843 *

Pacific

Contiguous 64,668 14,555 2,588 46,165 1,360 70,591 14,563 2,153 52,515 1,360

Pacific

Noncontiguous 10,606 1,985 6,257 2,138 225 10,256 1,895 5,724 2,413 225

U.S. Total 2,214,837 1,799,762 110,244 291,236 13,596 2,244,804 1,787,910 106,294 337,004 13,596
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aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to

generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.

* = the absolute value is less than 0.5.

Note: Data for 1999 are preliminary. Data for 1998 are final.

Sources: •Energy Information Administration, Form EIA­759, "Monthly Power Plant Report"; Form EIA­767,

"Steam­Electric Plant Operation and Design Report"; Form EIA­860B, "Annual Electric Generator Report ­

Nonutility"; Form EIA­900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form

423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."

Table 3. Percent of Electricity Generated at U.S. Electric Plants by Fuel Type and Census Division, 1998 and

1999

(Percent)

Census Division

1998 1999

Coal Petroleum Gas Other

a Nonfossil Coal Petroleum Gas Othera Nonfossil

New England 17.9 24.4 13.8 4.6 39.3 16.3 22.9 18.0 4.6 38.3

Middle Atlantic 38.4 5.2 13.6 1.3 41.5 35.8 4.5 17.5 1.3 40.9

East North Central 76.3 0.8 3.8 0.4 18.8 72.0 0.7 4.4 0.4 22.5

West North Central 75.5 0.7 2.3 0.3 21.1 73.9 0.7 3.0 0.3 22.0

South Atlantic 55.3 7.2 6.6 0.7 30.2 55.5 6.7 7.8 0.7 29.2

East South Central 66.2 2.1 3.2 * 28.4 68.0 1.4 3.9 * 26.7

West South Central 39.1 0.6 42.2 0.3 17.8 40.1 0.7 44.6 0.3 14.3

Mountain 67.9 0.2 6.8 0.1 25.0 67.5 0.3 8.1 0.1 24.1

Pacific Contiguous 4.3 0.7 23.1 0.4 71.4 4.2 0.5 26.2 0.4 68.7

Pacific Noncontiguous 12.2 52.3 21.3 1.9 12.4 11.7 52.2 24.8 1.9 9.4

U.S. Total 51.8 3.5 13.5 0.6 30.6 51.0 3.2 15.2 0.6 30.0

aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to

generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.

* = the absolute value is less than 0.05.

Note: Data for 1999 are preliminary. Data for 1998 are final.

Sources: •Energy Information Administration, Form EIA­759, "Monthly Power Plant Report"; Form EIA­767,

"Steam­Electric Plant Operation and Design Report"; Form EIA­860B, "Annual Electric Generator Report ­

Nonutility"; Form EIA­900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form

423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."

Table 4. Estimated Carbon Dioxide Emissions Rate From Generating Units at U.S. Electric Plants by Census

Division, 1998 and 1999 (Pounds per Kilowatthour)

Census Division

1998 1999

Total Coal Petroleum Gas Other

a Total Coal Petroleum Gas Othera

New England 1.059 1.934 1.984 1.213 1.339 1.077 1.827 2.156 1.250 1.328

Middle Atlantic 1.071 2.062 1.884 1.188 1.502 1.058 2.089 1.872 1.178 1.502

East North Central 1.680 2.113 2.244 1.239 1.124 1.579 2.061 2.759 1.630 1.131

West North Central 1.767 2.262 1.759 1.659 2.422 1.746 2.250 2.207 1.958 2.596

South Atlantic 1.334 2.026 1.821 1.113 1.377 1.342 2.019 1.822 1.115 1.372

East South Central 1.457 2.060 1.515 1.857 3.244 1.470 2.031 1.530 1.734 3.244

West South Central 1.469 2.214 3.955 1.376 0.151 1.529 2.215 3.170 1.382 0.151

Mountain 1.572 2.179 2.802 1.257 0.005 1.542 2.128 3.036 1.214 0.005
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Figure 1. Census Regions and Divisions

Pacific Contiguous 0.417 2.158 2.396 1.287 2.140 0.435 2.152 2.419 1.238 2.108

Pacific Noncontiguous 1.453 2.229 1.641 1.375 1.661 1.393 2.209 1.488 1.319 1.661

U.S. Average 1.350 2.117 1.915 1.314 1.378 1.341 2.095 1.969 1.321 1.378

aOther fuels include municipal solid waste, tires, and other fuels that emit anthropogenic CO2 when burned to

generate electricity. Nonutility data for 1999 for these fuels are unavailable; 1998 data are used.

Note: Data for 1999 are preliminary. Data for 1998 are final.

Sources: •Energy Information Administration, Form EIA­759, "Monthly Power Plant Report"; Form EIA­767,

"Steam­Electric Plant Operation and Design Report"; Form EIA­860B, "Annual Electric Generator Report ­

Nonutility"; Form EIA­900, "Monthly Nonutility Power Report." •Federal Energy Regulatory Commission, FERC Form

423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."

Petroleum

CO2 emissions from petroleum­fired electricity

generation were 106 million metric tons in 1999,

3.6 percent less than in 1998. Generation of

electricity from petroleum­fired plants decreased

from 127 billion kilowatthours in 1998 to 119

billion kilowatthours in 1999. CO2 emissions from

petroleum­fired electricity generation accounted

for 4.7 percent of the national total, while

generation from petroleum plants was 3.2 percent

of the Nation's total electricity generation. The

national average output rate for all petroleum­fired generation was 1.969 pounds CO2 per kilowatthour in

1999.

The New England Census Division generates about one­fourth of its electricity at petroleum­fired plants

which produce approximately 45 percent of that region's CO2 emissions. The Pacific Noncontiguous

Census Division generates about one­half of its electricity at petroleum­fired plants, producing about onehalf of the region's CO2 emissions. The South Atlantic and Middle Atlantic Census Divisions also use

some petroleum for electricity generation, particularly in Florida. The South Atlantic Census Division

contributes the largest share of CO2 emissions from petroleum­fired plants, 1.8 percent of the Nation's total

CO2 emissions from all sources.

Natural Gas

Emissions of CO2from the generation of electricity at natural gas­fired plants were 337 million metric tons

in 1999. Natural gas­fired plants were the only fossil­fueled plants to substantially increase generation from

1998 to 1999. Generation increased an estimated 15.0 percent, with CO2 emissions increasing a

corresponding 15.7 percent. Emissions of CO2from natural gas­fired plants represented 15.0 percent of

total CO2 emissions from electricity generation in 1999, while natural gas­fired electricity generation

accounted for 15.2 percent of total generation. The output rate for CO2from natural gas­fired plants in

1999 was 1.321 pounds CO2 per kilowatthour. Natural gas is the least carbon­intensive fossil fuel.

The West South Central Census Division, which includes Texas, Oklahoma, and Louisiana, is where much
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of the Nation's natural gas­fired capacity is located. The Northeast and Pacific Contiguous Census

Divisions also use natural gas to generate a substantial portion of their electricity. About 40.4 percent of the

West South Central Division's CO2 emissions from the generation of electricity comes from gas­fired

plants, representing approximately 45.6 percent of all CO2 emissions from natural gas combustion for

electricity generation in the Nation. About three­fourths of the Pacific Contiguous Census Division's CO2

emissions are from natural gas­fired plants; however, most of that division's electricity generation is

produced at nonfossil­fueled plants, such as hydroelectric and nuclear plants.

Nonfossil Fuels

Nonfossil­fueled generation from nuclear, hydroelectric, and other renewable sources (wind, solar,

biomass, and geothermal) represented about 30.0 percent of total electricity generation in 1999 and 30.6

percent in 1998. The use of nonfossil fuels and renewable energy sources to generate electricity avoids the

emission of CO2that results from the combustion of fossil fuels. Due to lower marginal costs, nuclear and

hydroelectric power generation typically displace fossil­fueled electricity generation.

Nuclear plants increased their output by 8.1 percent in 1999 as several plants in the East North Census

Division returned to service, contributing to a record capacity factor of 86 percent for nuclear plants in

1999.

(8) Nuclear energy provided 19.7 percent of the Nation's electricity in 1999.(9) Two­thirds of the

Nation's nuclear power is generated in the New England, East North Central, South Atlantic, and Middle

Atlantic Census Divisions, which generate 27.6 percent, 21.0 percent, 26.0 percent, and 35.6 percent,

respectively, of their electricity with nuclear power.

More than one­half of the Nation's hydroelectric capacity is located in the Pacific Contiguous Census

Division, which includes California, Oregon, and Washington. In the Mountain Census Division, Idaho

generates virtually all of its electricity at hydroelectric plants. The availability of hydroelectric power is

affected by both the amount and patterns of precipitation. High snowpack levels in the Northwest increased

hydroelectric generation in Washington and Oregon during 1999, despite the fact that on an annual basis

both States received less precipitation in 1999 than they did in 1998. However, the remainder of the Nation

experienced dry conditions in 1999, decreasing the amount of hydroelectric power available to displace

fossil­fueled generation.

(10)

Factors Contributing to Changes In CO2

Emissions and Generation

The primary factors that alter CO2 emissions from electricity generation from year to year are the growth in

demand for electricity, the type of fuels or energy sources used for generation, and the thermal efficiencies

of the power plants. A number of contributing factors influencing the primary factors can also be identified:

economic growth, the price of electricity, the amount of imported electricity, weather, fuel prices, and the

amount of available generation from hydroelectric, renewable, and nuclear plants. Other contributing

factors include demand­side management programs that encourage energy efficiency, strategies to control

other air emissions to comply with the requirements for the Clean Air Act Amendments of 1990, and the

installation of new capacity utilizing advanced technologies to increase plant efficiency, such as combinedcycle plants and combined heat and power projects. Annual changes in CO2 emissions are a net result of
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these complex and variable factors.

As estimated in this report, the amount of anthropogenic CO2 emissions attributable to the generation of

electricity in the United States increased 1.4 percent since the previous year. In 1999, fossil­fueled

generation increased by about 2.9 percent; however, almost all of the increase was associated with natural

gas, the least carbon­intensive fossil fuel. The increase in CO2 emissions from the combustion of natural

gas for electricity generation amounted to 46 million metric tons, while the CO2 emissions from the

combustion of petroleum and coal decreased 16 million metric tons.

The national average output rate declined from 1.350 pounds of CO2 per kilowatthour in 1998 to 1.341

pounds CO2 per kilowatthour in 1999. The primary driver of this change was the decreased output rate for

coal­fired electricity generation, which went from 2.117 pounds of CO2 per kilowatthour to 2.095 pounds

of CO2 per kilowatthour. A change in the output rate for coal­fired electricity generation in the absence of

significant change in non­emitting generation will have the greatest effect on the national average output

rate of CO2 per kilowatthour both because coal­fired generation dominates the industry and is the most

carbon­intensive fuel.

Economic Growth

Economic factors influence the demand for electric power. In 1999, a strong economy was measured by the

4.2­percent increase in the Gross Domestic Product (GDP).

(11) Electricity consumption grew by 1.7

percent,

(12) while the average national price of electricity decreased 2.1 percent, from 6.74 cents in 1998 to

6.60 cents in 1999.

(13) Although the growing demand for electricity is primarily met by a corresponding

growth in generation, a small amount is met by imported power, primarily from Canada.

Weather

Weather is another factor affecting the year­to­year changes in the demand for electricity. Both 1999 and

1998 were record­breaking years in terms of warm weather in the United States. The availability of

hydroelectric power to displace fossil­fueled power was limited by dry conditions in much of the Nation,

with the exception of the Pacific Northwest States.

During the summer months, the demand for power for air conditioning is a major factor in setting record

high peak demands for some utilities. In 1999, electricity generating plants consumed almost as much coal

as the record amount consumed in 1998 and increased their natural gas consumption to meet the continuing

high demand for electricity in the summer of 1999.

Demand­Side Management (DSM)

Energy efficiency programs and DSM activities, such as improving insulation and replacing lighting and

appliances with more energy efficient equipment, can reduce the demand for electricity. The reductions in

demand achieved by DSM programs contribute to avoided CO2 emissions. In 1998, 49.2 billion

kilowatthours of energy savings were achieved by DSM activities at electric utilities, a decrease from 56.4

billion kilowatthours in 1997. Declining levels of energy savings reflect, in part, lower utility spending on

DSM programs. In 1998, utilities' total expenditures on DSM were $1.4 billion, a decrease of 13.1 percent

from the previous year, and nearly 50 percent below the 1994 spending level.

(14) Data for 1999 are not yet

available.

Fossil and Nonfossil Fuels for Electricity Generation
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The fuel or energy source used to generate electricity is the most significant factor affecting the year­toyear changes in CO2 emissions. Because hydroelectric and nuclear generation displace fossil­fueled

generation when available, CO2emissions increase when hydroelectric or nuclear power is unavailable and

fossil­fueled generation is used as a replacement. Conversely, CO2 emissions can be reduced through a

greater use of nuclear, hydroelectric, and renewable energy for electricity generation. Collectively,

nonfossil­fueled electricity generation by nuclear, hydroelectric, and renewable energy sources that do not

contribute to anthropogenic CO2 emissions remained almost unchanged in 1999 as compared to 1998, with

much of the increase in nuclear generation being offset by an absolute decrease in hydroelectric power

generation and other generation from fuels such as municipal solid waste, tires, and other fuels that emit

anthropogenic CO2 when burned to generate electricity.

As stated previously, the amount of available hydroelectric power is affected by precipitation patterns. In

1999, hydroelectric power generation was lower in all regions, except in the Northwestern States. Oregon,

Idaho, and Washington typically generate more than 90 percent of their power at hydroelectric plants and

export power to California. Hydroelectric power generationincreased in 1999 in these States, reducing the

need for fossil­fueled generation and contributed to keeping CO2 emissions low in the Pacific Contiguous

Census Division. Nationally, hydroelectric power generation decreased by 3.6 percent in 1999.

Nuclear power generation increased by 8.1 percent to a record level in 1999, which contributed to keeping

CO2 emissions lower by displacing fossil­fueled generation, particularly in the East North Central Census

Division. Several nuclear plants came back online in 1999, helping to increase the average nuclear capacity

factor to 86 percent. An absolute increase in the amount of nuclear power more than offset the loss of some

hydroelectric power in 1999.

Fuel Quality and Price

The amount of CO2 emissions from the combustion of fossil fuels to generate electricity varies according

to the quality of the fuels, defined by their carbon content and the associated heating value (Btu).

(15) The

Btu content of fuels is a determinant of the number of kilowatthours that can be produced

(16) and carbon

content is a determinant of the amount of CO2released when the fuel is burned. Fossil fuels are categorized

as either coal, natural gas and other gaseous fuels, or petroleum and petroleum products. Coal­fired

electricity generation has the highest output rate of CO2 per kilowatthour produced, averaging 2.095

pounds per kilowatthour in 1999. Petroleum­fired electricity generation averaged 1.969 pounds per

kilowatthour, and natural gas­fired electricity generation had the lowest rate of 1.321 pounds per

kilowatthour. With coal­fired plants generating the majority of electricity in the Nation and having the

highest output rate, they produced the greatest share of CO2 emissions from electricity generation,

approximately 80 percent of the total.

Some plants are capable of switching fuels to take advantage of the least expensive or the most available

resources. In 1998, the price of crude oil reached its lowest level since 1976, causing the price of petroleum

delivered to electric utilities to fall below that of natural gas for the first time since 1993. This factor is

important when considering the capability of some electric plants to burn the least expensive of these two

fuels. As a result of falling prices in 1998, petroleum­fired generation was higher in 1998 than in 1997.

However during 1999, the price of petroleum began to increase, and generation from petroleum plants

declined. Petroleum has a higher output rate of CO2than natural gas; therefore, switching from petroleum

to natural gas can have a beneficial effect on both the overall amount and output rate of CO2 emissions.

In 1999, virtually all of the increase in fossil­fueled generation was from natural gas­fired plants. Coal­fired

electricity generation was close to unchanged, while petroleum­fired electricity generation fell. Most of the
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increase in CO2 emissions from gas­fired plants was offset by the decline in CO2 emissions from

petroleum­ and coal­fired plants.

Thermal Efficiencies of Power Plants

CO2 emissions from electric power generation are influenced by the efficiency with which fossil fuels are

converted into electricity. In a typical power plant, about one­third of the energy contained in the fuel is

converted into electricity, while the remainder is emitted as waste heat. Substantial improvements in

generation efficiency can be achieved in the future through the replacement of traditional power generators

with more efficient technologies, such as combined­cycle generators and combined heat and power (CHP)

systems. In these types of systems, waste heat is captured to produce additional kilowatthours of electricity

or displace energy used for heating or cooling. Both strategies result in lower CO2 emissions. The national

average thermal efficiency of power generation from fossil fuels in 1999 was estimated to be 32.54 percent,

slightly higher than the previous year's average of 32.42 percent.

(17)

The average thermal efficiency of coal­fired plants went from 33.15 percent to 33.54 percent in 1999. The

improvement in efficiency is also reflected in the national average output rate of pounds of CO2 per

kilowatthour. The output rate for coal­fired plants decreased from 2.117 pounds of CO2 per kilowatthour in

1998 to 2.095 in 1999. Petroleum­fired plants and natural gas­fired plants showed slightly lower thermal

efficiencies in 1999, with a corresponding change in the output rate. The rate for petroleum­fired plants

increased from 1.915 to 1.969 pounds of CO2 per kilowatthour, and natural gas­fired plants' output rate

increased from 1.314 to 1.321 pounds of CO2 per kilowatthour.

Conclusion

The emission of CO2 by electric power plants is not controlled because no standards or required reductions

currently exist. Some technology is available to limit CO2 emissions, but it is extremely expensive. The

options to limit the emission of CO2from electricity generation are to encourage reduction of the overall

consumption of electricity through energy efficiency and conservation initiatives, to improve combustion

efficiency at existing plants or install new units that employ more efficient technologies, such as combinedcycle units and combined heat and power (CHP) systems, and to replace fossil­fueled generation with

nonfossil­fueled alternatives, such as nuclear, hydroelectric, and other renewable energy sources.

Comparison of Projected with Actual CO2

Emissions and Generation by Fuel Type

Each year, the Energy Information Administration prepares the Annual Energy Outlook (AEO), which

contains projections of selected energy information. Projections for electricity supply and demand data,

including CO2 emissions and generation by fuel type, are made for the next 20 years. To evaluate the
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accuracy and usefulness of the forecast, a comparison was made between the latest forecast for 1999 (from

the AEO2000) and the estimated actual data for 1999 (Table 5). The near­term projections in the AEO are

based on a combination of the partial­year data available when the forecast was prepared, the latest shortterm forecast appearing in the Short­Term Energy Outlook, and the regional detail contained in the National

Energy Modeling System (NEMS). Consequently, comparisons with the actual data for 1999 are not a

definitive indicator of the accuracy of the longer­term projections appearing in the AEO. Nevertheless, they

do provide a useful preliminary gauge for tracking and measuring the projections against actual data over

time.

Table 5. U.S. Electric Power Industry Projected and Actual Carbon Dioxide Emissions and

Generation, 1999

Projected Actual

Percentage

Difference

CO2 Emissions (million metric tons)

Coal 1,863 1,788 ­4.0

Petroleum 100 106 6.0

Natural Gas, Refinery and Still Gas 313 337 7.7

Other

a

­­ 14 N/A

Total CO2 Emissions 2,277 2,245 ­1.4

Generation (billion kWh)

Coal 1,878 1,882 0.2

Petroleum 121 119 ­1.7

Natural Gas, Refinery and Still Gas 542 562 3.7

Other

a

20 22 10.0

Non­Fossil Fuels

b 1,072 1,106 3.2

Total Generation 3,632 3,691 1.6

Net Imports 47 29 ­38.0

Total Electricity Supply 3,679 3,720 1.1

Retail Electricity Sales by Utilities (billion kWh) 3,288 3,296 0.2

Nonutility Generation for Own Use/Sales (billion kWh)

c 173 165 ­4.6

Losses and Unaccounted For (billion kWh) 218 259 18.8

aOther fuels include municipal solid waste (MSW), tires, and other fuels that emit anthropogenic

CO2 when burned to generate electricity. MSW generation represents the largest share of this

category. MSW projections in the Annual Energy Outlook 2000 are assumed to have zero net CO2

emissions. Due to a change in the accounting for MSW by the Environmental Protection Agency,

future AEOs will estimate the CO2 emissions attributed to the non­biomass portion of this fuel. If

this had been done for the AEO2000, CO2 emissions for MSW would have been 14 million metric

tons for 1999.

b

Includes nuclear and most renewables, which either do not emit CO2 or whose net CO2

emissions are assumed to be zero.

cData for 1999 are estimated.

Note: Actual data for CO2 emissions and electricity generation for 1999 are preliminary.

Components may not add to total due to independent rounding.

Sources: Projections: Energy Information Administration, Annual Energy Outlook 2000,

DOE/EIA­0383 (2000) (Washington, DC, December 1999) and supporting runs of the National Energy

Modeling System. Actual: Carbon dioxide emissions and generation: Table 1; other data: Energy

Information Administration, Monthly Energy Review, April 2000, DOE/EIA­0035(2000/04)

(Washington, DC, April 2000); Energy Information Administration, Short­Term Energy Outlook, May
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2000 (EIA Web site, www.eia.doe.gov/emeu/steo/pub/contents.html).

Total electricity­related CO2 emissions for fossil fuels in 1999 were 1.4 percent below the projected

emissions level, while the actual total generation from fossil fuels was 0.9 percent above the projected

generation level. The largest percentage difference between projected and actual generation by fuel (other

than for "Other") was for natural gas­fired generation, which was 3.7 percent higher than projected, but

with a corresponding difference in CO2 emissions of 7.7 percent. However, the largest absolute difference

between projected and actual CO2 emissions by fuel was for coal­fired generation, whose emissions were

75 million metric tons, or 4.0 percent, below the projected level, even while generation was 0.2 percent

higher. Three primary factors contribute to the divergence in projected and actual CO2 emissions:

Efficiency of generating units. Average generating efficiencies for coal­fired capacity were higher

in 1999 than those assumed by NEMS, on the order of about 4 percent. On the other hand, the

efficiency of natural gas­fueled capacity was about 4 percent lower than the NEMS assumptions.

Because coal­fired units produce more than three times the generation of natural gas­fired generators,

the impact of the higher efficiencies of coal­burning capacity outweighs the lower actual efficiencies

for natural gas capacity. Efficiencies for petroleum­based generation, a much smaller share of overall

supply, were 5.6 percent lower than the NEMS assumptions.

Total generation requirements. Overall electricity generation was 1.6 percent higher in 1999 than

projected. This was due to the combined effects of higher sales, lower imports, and higher losses for

electricity than expected. The incremental generation requirements were met in part by higher natural

gas­fired generation, as well as greater reliance on nonfossil sources of electricity such as nuclear and

renewables. To the extent that natural gas­fired generation was above the forecast, higher CO2

emissions resulted.

Increased nuclear and hydroelectric generation. Nuclear generation was 30 billion kilowatthours,

or 5.7 percent, above the projected levels in 1999. The difference was due primarily to improving

performance of nuclear generating units, beyond that assumed in the projections. Also, hydroelectric

generation was 13 billion kilowatthours, or 4.3 percent, above projections. Given the same overall

level of generation, higher nuclear and hydroelectric projections would have resulted in less

projected generation from fossil fuels, thus bringing electricity­related CO2 emissions more in line

with actual data.

Voluntary Carbon­Reduction and

Carbon­Sequestration Programs

Both the DOE and the EPA operate voluntary programs for reducing greenhouse gas emissions and

reporting such emission reductions. Voluntary programs that contribute to emission reductions in the

electricity sector include DOE/EIA's Voluntary Reporting of Greenhouse Gases Program and EPA's

ENERGY STAR program.

EIA's Voluntary Reporting of Greenhouse Gases Program collects information from organizations that

have undertaken carbon­reducing or carbon­sequestration projects. Most of the electric utilities that report
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to the Voluntary Reporting Program also participate in voluntary emission reduction activities through

DOE's Climate Challenge Program. In 1998, as part of the Voluntary Reporting Program, 120

organizations in the electric power sector reported on 1,166 projects undertaken in 1998.

(18) By

undertaking these projects, participants indicated that they reduced CO2 emissions by 165.8 million metric

tons

(19)

(Table 6). The organizations almost universally measured their project­level reductions by

comparing emissions with what they would have been in the absence of the project. Reported CO2

reductions from these projects accounted for 7.5 percent of 1998 CO2 emissions attributed to the generation

of electric power in the United States. Foreign reductions, largely from carbon­sequestration projects,

account for 6.0 percent of total electric utility sector reductions reported for 1998.

Table 6. Electric Power Sector Carbon Dioxide Emission Reductions, 1997 and 1998

(Million Metric Tons Carbon Dioxide)

Type of Reduction

Carbon Dioxide

a

1997 1998

Domestic Reductions

Emission Reductions Projects 135.9 155.3

Sequestration Projects 0.3 0.5

Total Domestic Reductions 136.2 155.8

Foreign Reductions

Emission Reductions Projects 0.1 0.1

Sequestration Projects 9.4 9.9

Total Foreign Reductions 9.5 10.0

Total CO2 Reductions Reported 145.8 165.8

aThe Voluntary Reporting of Greenhouse Gases Program is currently in the 1999 data reporting cycle; the most

recent year for which complete data are available is 1998. The 1997 and 1998 data in last year's report were

preliminary and have been revised in this report due to subsequent completion of internal EIA review of those data.

Emission reductions also include those reported by landfill methane operators. The use of landfill methane to

generate electricity displaces fossil fuel power generation and produces a reduction in CO2 emissions equivalent to

the amount of CO2 that would have resulted from fossil fuel power generation. In calculating CO2 reductions, it is

assumed that landfill carbon is biogenic and, thus, the CO2 emissions from landfill gas combustion are zero.

Note: Totals may not equal the sums of the parts due to independent rounding. This data cannot be compared

directly to other figures in this report because reporters to EIA's Voluntary Reporting of Greenhouse Gases Program

may report emission reductions using baselines and valuation methods different from those applied elsewhere.

Source: Energy Information Administration, Form EIA­1605, "Voluntary Reporting of Greenhouse Gases," (long

form) and EIA­1605EZ, "Voluntary Reporting of Greenhouse Gases," (short form), 1997 and 1998 data.

DOE's Climate Challenge Program, a voluntary initiative with the electric utility sector established under

the President's 1993 Climate Change Action Plan, has become the principal mechanism by which electric

utilities participate in voluntary emission reduction activities. Participants that reported the CO2 emission

reductions summarized in this report include electric utilities and holding companies, independent power

producers, and landfill methane operators. Climate Challenge participants negotiate voluntary

commitments with the DOE to achieve a certain level of emission reductions and/or to participate in

specific projects. Companies making Climate Challenge commitments as of 1998 accounted for about 71

percent of 1990 U.S. electric utility generation.

(20) Climate Challenge participants are required to report

their achieved emissions reductions to the Voluntary Reporting of Greenhouse Gases Program.
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Results from the Climate Challenge program cannot be compared directly to other figures in this report

because the Climate Challenge program allows participants to report emissions reductions using baselines

and calculation methods different from those applied elsewhere. For this reason, EIA keeps an accounting

of reports submitted by Climate Challenge participants, but the United States counts only a fraction of these

reported reductions in comprehensive assessments of overall reductions in greenhouse gases.

(21)

The largest reductions claimed for 1998 are from these major U.S. electric utilities: the Tennessee Valley

Authority (26.0 million metric tons of CO2), TXU (19.9 million metric tons of CO2), Duke Energy (12.1

million metric tons of CO2), and FirstEnergy (10.6 million metric tons of CO2).

(22)

These four companies

accounted for about 41.4 percent of the CO2 emissions reductions reported in 1998 by the electric power

sector. Each of these companies owns one or more nuclear power plants, and the bulk of their reported

reductions is calculated by comparing either actual or additional nuclear output from their plants with the

emissions that would have occurred if the same quantity of electricity had been generated using fossil fuels.

Electric power industry companies also reported on projects reducing other greenhouse gases.

(23)

Combining all projects and all greenhouse gases, the electric power sector reporters claimed 176.9 million

metric tons of carbon dioxide equivalent reductions in 1998.

Utilities also undertook a number of carbon­sequestration projects. Although these projects do not directly

affect CO2 emissions, they do offset utility CO2 emissions. Foreign carbon­sequestration projects from the

electric sector were reported to be 9.9 million metric tons of CO2in 1998, while domestic projects were

reported to be 0.5 million metric tons. These activities were dominated by three independent power

producer subsidiaries of the AES Corporation, which reported 7.6 million metric tons of CO2sequestration

annually from three projects with activities in Belize, Bolivia, Ecuador, Peru, and Guatemala. These

projects undertake tropical rain forest management, preservation, or reforestation.

In addition, more than 30 companies reported on their pro­rated share of participation in the Edison Electric

Institute's UtiliTree program.

(24) The UtiliTree program is a carbon­sequestration mutual fund in which

electric utilities purchase shares. UtiliTree uses the funds to participate in forest management and

reforestation projects in the United States and abroad.

The United States' voluntary programs are reducing domestic emissions of greenhouse gases in a number of

sectors across the economy through a range of partnerships and outreach efforts. For example, the

ENERGY STAR Program, run by the EPA in partnership with DOE, reduces energy consumption in homes

and office buildings across the Nation. EPA and DOE set energy­efficiency specifications for a range of

products including office equipment, heating and cooling equipment, residential appliances, televisions and

VCRs, and new homes. The ENERGY STAR label for buildings is based on a performance rating system

that allows building owners to evaluate the efficiency of their buildings relative to others. On average,

buildings across the country can improve efficiency by 30 percent through a variety of improvements.

Manufacturer and retailer partners in the program may place the nationally recognized ENERGY STAR

label on qualifying products.

In the past several years, the ENERGY STAR label has expanded to include more than 30 products and

nearly 7,000 product models. In 1999, energy consumption was reduced by approximately 28 billion

kilowatthours as a result of the program, reducing greenhouse gas emissions by nearly 21 million metric

tons CO2(Table 7). Through EPA's ENERGY STAR Buildings and Green Lights Partnership, more than

15 percent of the square footage in U.S. buildings has undergone efficiency upgrades resulting in electricity

savings in excess of 21 billion kilowatthours and emissions reductions of more than 16 million metric tons

CO2.
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Table 7. CO2 Emission Reductions and Energy Savings from EPA's Voluntary Programs, 1998 and 1999

1998 1999

Million Metric Tons

of CO2 Reduced

Billion kWh

Saved

Million Metric Tons

of CO2 Reduced

Billion kWh

Saved

ENERGY STAR Labeled Products 14.7 20 20.9 28

ENERGY STAR Buildings and Green Lights 8.8 13 16.5 21

Climate Wise 9.9 3 13.9 5

Source: U.S. Environmental Protection Agency, Climate Protection Division, 1998 Annual Report: Driving

Investment in Energy Efficiency, ENERGY STAR and Other Voluntary Programs (EPA 430­R­99­005), forthcoming.

Environmental Effects of

Federal Restructuring Legislation

In April 1999, the Administration submitted to Congress the Comprehensive Electricity Competition Act

(CECA), a bill to restructure the U.S. electricity industry and foster retail competition. CECA was designed

to ensure that the full economic and environmental benefits of electricity restructuring are realized. The

expected environmental benefits are the result of both the effects of competition and specific provisions

included in the Administration's proposal, such as a renewables portfolio standard, a public benefits fund,

and tax incentives for investment in combined heat and power facilities. Competition itself will also

provide incentives to generators to improve their own efficiencies, and create new markets for green power

and end­use efficiency services, all of which reduce greenhouse gas emissions.

Following an exhaustive interagency review, the DOE issued a Supporting Analysis

(25)

that quantified both

the economic and environmental benefits of the Administration's plan in May 1999. The analysis focused

on the impacts of full national retail competition relative to continued cost­of­service regulation. The

results showed that the Administration's proposal will reduce CO2 emissions by 216 million metric tons in

2010. An EIA study

(26) using the same assumptions from the supporting analysis produced similar results.

Carbon dioxide emissions in the EIA report were estimated to be 194 million metric tons lower in the

competitive case than in the cost­of­service reference case in 2010. A number of key uncertainties,

however, can affect these projections, and some of the reductions could be realized due to actions already

taken by individual States. Recognizing uncertainties and the need to avoid double­counting, the

Administration projected that its proposal would reduce CO2 emissions from energy use by 147 to 220

million metric tons annually by 2010.

The DOE and EPA see no recent developments that would change our projection of the expected impact of

the Administration proposal. However, we note that restructuring bills that have recently moved forward in

the Congress differ significantly from the Administration's comprehensive proposal. These bills do not

include key provisions that support the effective functioning of competitive electricity markets and energy

diversity while at the same time providing reductions in CO2 emissions. In addition to maintaining our

capability to reassess the impacts of our own proposal, we are also prepared to provide quantitative

analyses of alternative restructuring bills. Additional measures could offer potential for cost­effective
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April 15, 1999

emissions reductions in the electric power sector, although they are no substitute for comprehensive

restructuring legislation that promotes competitive markets and consumer benefits while providing

important reductions in CO2 emissions from electric power generation.

Appendix A

Presidential Directive

MEMORANDUM FOR THE

SECRETARY OF ENERGY

ADMINISTRATOR OF THE ENVIRONMENTAL PROTECTION AGENCY

SUBJECT: Report on Carbon Dioxide (CO2) Emissions

My Administration's proposal to promote retail competition in the electric power industry, if enacted, will

help to deliver economic savings, cleaner air, and a significant down payment on greenhouse gas emissions

reductions. The proposal exemplifies my Administration's commitment to pursue both economic growth

and environmental progress simultaneously.

As action to advance retail competition proceeds at both the State and Federal levels, the Administration

and the Congress share an interest in tracking environmental indicators in this vital sector. We must have

accurate and frequently updated data.

Under current law, electric power generators report various types of data relating to generation and air

emissions to the Department of Energy (DOE) and the Environmental Protection Agency (EPA). To ensure

that this data collection is coordinated and provides for timely consideration by both the Administration and

the Congress, you are directed to take the following actions:

On an annual basis, you shall provide me with a report summarizing CO2 emissions data collected

during the previous year from all utility and nonutility electricity generators providing power to the
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grid, beginning with 1998 data. This information shall be provided to me no more than 6 months

after the end of the previous year, and for 1998, within 6 months of the date of this directive.

The report, which may be submitted jointly, shall present CO2 emissions information on both a

national and regional basis, stratified by the type of fuel used for electricity generation, and shall

indicate the percentage of electricity generated by each type of fuel or energy resource. The CO2

emissions shall be reported both on the basis of total mass (tons) and output rate (e.g., pounds per

megawatt­hour).

The report shall present the amount of CO2reduction and other available information from voluntary

carbon­reducing and carbon­sequestration projects undertaken, both domestically and internationally,

by the electric utility sector.

The report shall identify the main factors contributing to any change in CO2 emissions or CO2

emission rates relative to the previous year on a national, and, if relevant, regional basis. In addition,

the report shall identify deviations from the actual CO2 emissions, generation, and fuel mix of their

most recent projections developed by the Department of Energy and the Energy Information

Administration, pursuant to their existing authorities and emissions.

In the event that Federal restructuring legislation has not been enacted prior to your submission of the

report, the report shall also include any necessary updates to estimates of the environmental effects of

my Administration's restructuring legislation.

Neither the DOE nor the EPA may collect new information from electricity generators or other

parties in order to prepare the report.

WILLIAM J. CLINTON

Appendix B

Data Sources and Methodology

This section describes the data sources and methodology employed to calculate estimates of carbon

dioxide (CO2) emissions from utility and nonutility electric generating plants. Due to the report being

submitted in June of 2000, the annual census data, on which 1998 emission estimates are based, are

not yet available from the Form EIA­860B and Form EIA­767. The methodology employed for

estimating 1999 CO2 emissions in this report are based on two monthly data collections, Form EIA759 and Form EIA­900. The Form EIA­759 collects monthly generation and fuel consumption from

all utility­owned generating plants, and the Form EIA­900 collects generation and fuel consumption

from nonutility plants with a nameplate capacity of 50 megawatts (MW) or more. The 1999 estimates

of CO2 emissions and net generation are preliminary estimates; final emissions estimates based on

annual census data will be published in the Electric Power Annual Volume II 1999, later this year.

Electric Utility Data Sources

The electric utility data are derived from several forms. The Form EIA­767, "Steam­Electric Plant

Operation and Design Report," collects information annually for all U.S. power plants with a total
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existing or planned organic­ or nuclear­fueled steam­electric generator nameplate rating of 10 MW or

larger. Power plants with a total generator nameplate rating of 100 MW or more must complete the

entire form, providing among other data, information about fuel consumption and quality. Power

plants with a total generator nameplate rating from 10 MW to less than 100 MW complete only part

of the form, including information on fuel consumption.

Form EIA­759, "Monthly Power Plant Report," is a cutoff model sample of approximately 360

electric utilities drawn from the frame of all operators of electric utility plants (approximately 700

electric utilities) that generate electric power for public use. The monthly data collection is from all

utilities with at least one plant with a nameplate capacity of 50 MW or more. For all utility plants not

included in the monthly sample, those with nameplate capacities less than 50 MW, monthly data are

collected annually. Form EIA­759 is used to collect data on net generation; consumption of coal,

petroleum, and natural gas; and end­of­the­month stocks of coal and petroleum for each plant by

fuel­type combination.

The Federal Energy Regulatory Commission (FERC) Form 423, "Monthly Report of Cost and

Quality of Fuels for Electric Plants," is a monthly record of delivered­fuel purchases, submitted by

approximately 230 electric utilities for each electric generating plant with a total steam­electric and

combined­cycle nameplate capacity of 50 MW or more. FERC Form 423 collects data on fuel

contracts, fuel type, coal origin, fuel quality and delivered cost of fuel.

Nonutility Data Sources

Form EIA­860B, "Annual Electric Generator Report ­ Nonutility," (prior Form EIA­867, "Annual

Nonutility Power Producer Report") collects information annually from all nonutility power

producers with a total generator nameplate rating of 1 MW or more, including cogenerators, small

power producers, and other nonutility electricity generators. All facilities must complete the entire

form, providing, among other data, information about fuel consumption and quality; however

facilities with a combined nameplate capacity of less than 25 MW are not required to complete

Schedule V, "Facility Environmental Information," of the Form EIA­860B.

Form EIA­900, "Monthly Nonutility Power Plant Report," is a cutoff model sample of approximately

500 nonutilities drawn from the frame of all nonutility facilities (approximately 2000 nonutilities)

that have existing or planned nameplate capacity of 1 MW or more. The monthly data collection

comes from all nonutilities with a nameplate rating of 50 MW or more. A cutoff model sampling and

estimation are employed using the annual Form EIA­860B.

CO2 Coefficients

The coefficients for determining carbon released from the combustion of fossil fuels were developed

by the Energy Information Administration. A detailed discussion of the development and sources

used is contained in the publication, Emissions of Greenhouse Gases in the United States,

(DOE/EIA­0573), Appendix B. The nonutility coefficients were developed to be consistent with the

utility coefficients.

Methodology for 1998

The methodology for developing the CO2 emission estimates for steam utility plants and nonsteam

utility plants (calculations performed on a plant basis by fuel), as well as for nonutility plants

(calculations performed on a facility basis by fuel), is as follows:

Steam Utility Plants
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Form EIA­767, "Steam­Electric Plant Operation and Design Report"

Form EIA­759, "Monthly Power Plant Report"

FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

Step 1. Sum of Monthly Consumption (EIA­767) times Monthly Average Btu Content (EIA­767)

divided by Total Annual Consumption (EIA­767) = Weighted Annual Btu Content Factor.

Step 2. Annual Consumption (EIA­767) times Weighted Annual Btu Content Factor (Step 1) =

Annual Btu Consumption.

Step 3. Annual Btu Consumption (Step 2) times CO2factors = Annual CO2 Emissions.

Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

Nonsteam Utility Plants

Form EIA­759, "Monthly Power Plant Report"

FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

Step 1(a). If monthly EIA­759 and monthly FERC Form 423 are available: Sum of Monthly

Consumption (EIA­759) times Monthly Average Btu Content (FERC Form 423) divided by Total

Annual Consumption = Weighted Annual Btu Content Factor.

Step 1(b). If monthly EIA­759 is available, but not monthly FERC Form 423: Sum of Monthly

Consumption (EIA­759) times Average Monthly Btu Content (calculated from FERC Form 423)

divided by Total Annual Consumption = Weighted Annual Btu Content Factor.

Step 1(c). If only annual EIA­759 is available: Annual Consumption (EIA­759) times Average

Annual Btu Content (calculated from FERC Form 423) divided by Total Annual Consumption =

Weighted Annual Btu Content Factor.

Step 2. Annual Consumption (EIA­759) times Weighted Annual Btu Content Factor (Step 1) =

Annual Btu Consumption.

Step 3. Annual Btu Consumption (Step 2) times CO2 Factors = Annual CO2 Emissions.

Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

Nonutility Plants

Form EIA­860B, "Annual Electric Generator Report ­ Nonutility"

FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

Step 1. Annual Consumption (EIA­860B) times Average Annual Btu Content (EIA­860B) divided by

Total Annual Consumption = Weighted Annual Btu Content Factor.

Step 2. Annual Consumption (EIA­860B) times Weighted Annual Btu Content Factor (Step 1) =

Annual Btu Consumption.
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Step 3. Annual Btu Consumption (Step 2) x CO2 Factors = Annual CO2 Emissions.

Step 4. Reduce Annual CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

Methodology for 1999

Utility Plants

Form EIA­767, "Steam­Electric Plant Operation and Design Report"

Form EIA­759, "Monthly Power Plant Report"

FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

Step 1(a). If monthly EIA­759 and prior year annual EIA­767 are available: Sum of Monthly

Consumption (EIA­759) times Monthly Average Btu Content (EIA­767) divided by Total Annual

Consumption (EIA­759) = Weighted Annual Btu Content Factor.

Step 1(b). If prior year annual EIA­767 is not available, but monthly EIA­759 and monthly FERC

Form 423 are available: Sum the Monthly Consumption (EIA­759) times the Monthly Average Btu

Content (FERC Form 423) divided by the Total Annual Consumption (EIA­759) = Weighted Annual

Btu Content Factor.

Step 1(c). If prior year annual EIA­767 and monthly FERC Form 423 are not available, but monthly

EIA­759 is available: Sum the Monthly Consumption (EIA­759) times the Average Monthly Btu

Content (calculated at State level from FERC Form 423) divided by the Total Annual Consumption

(EIA­759) = Weighted Annual Btu Content Factor.

Step 1(d). If prior year annual EIA­767, monthly EIA­759 and monthly FERC Form 423 are not

available, but only annual EIA­759 is available: Annual Consumption (EIA­759) times the Average

Annual Btu Content (calculated at State level from FERC Form 423) divided by the Total Annual

Consumption (EIA­759) = Weighted Annual Btu Content Factor.

Step 2. Annual Consumption (EIA­759) times the Weighted Annual Btu Content Factor (Step 1) =

Annual Btu Consumption.

Step 3. Annual Btu Consumption (Step 2) times CO2 Coefficients (Emissions of Greenhouse Gases

in the United States) = Annual Gross CO2 Emissions.

Step 4. Reduce Annual Gross CO2 Emissions (Step 3) by 1 percent to assume 99 percent burn factor.

Nonutility Plants

Form EIA­900, "Monthly Nonutility Power Report"

Form EIA­860B, "Annual Electric Generator Report ­ Nonutility"

FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants"

Step 1(a). If monthly EIA­900 and prior year annual EIA­860B are available: Sum the Monthly

Generation by Census Division and Fuel Type (EIA­900), and apply annual growth factor model to

estimate 1999 Annual Generation. Divide 1999 Annual Generation by 1998 Annual Generation
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(EIA­860B), subtract 1, and multiply by 1998 Total Annual Consumption

(27)

(EIA­860B) = 1999

Total Annual Consumption. 1999 Total Annual Consumption times Average Btu Content (EIA­860B

for prior year) = 1999 Annual Btu Consumption.

Step 1(b). If monthly EIA­900 and FERC Form 423 for 1998 are available: (sold utility plant to

nonutility in 1999): Annual Consumption (EIA­900) times the Average Btu Content (FERC Form

423) = 1999 Annual Btu Consumption.

Step 1(c). If only monthly EIA­900 is available (new nonutility plants): Annual Consumption (EIA900) times the Average Btu Content (calculated at State level from FERC Form 423) = 1999 Annual

Btu Consumption.

Step 2. 1999 Annual Btu Consumption (Step 1) times CO2 Coefficients (Emissions of Greenhouse

Gases in the United States) = Annual Gross CO2 Emissions.

Step 3. Reduce Annual Gross CO2 Emissions (Step 2) by 1 percent to assume 99 percent burn factor.

Endnotes

1. The Presidential directive required the first report by October 15, 1999, and thereafter the report is

required by June 30. See Appendix A for the full text of the directive.

2. Data for 1999 are preliminary. Data for 1998 are final. Last year, 1998 data were preliminary and

have been revised to final numbers.

3. To convert metric tons to short tons, multiply by 1.1023. Carbon dioxide units at full molecular

weight can be converted into carbon units by dividing by 44/12.

4. The average output rate is the ratio of pounds of carbon dioxide emitted per kilowatthour of

electricity produced from all energy sources, both fossil and nonfossil, for a region or the Nation.

5. Caution should be taken when interpreting year­to­year changes in the estimated emissions and

generation due to an undetermined degree of uncertainty in statistical data for the 1999 estimates.

Also, differences in the 1998 and 1999 estimation methodologies have an undetermined effect on the

change from 1998 to 1999 estimates. See Appendix B, "Data Sources and Methodology," for further

information. For more information on uncertainty in estimating carbon dioxide emissions, see

Appendix C, "Uncertainty in Emissions Estimates," Emissions of Greenhouse Gases in the United

States, DOE/EIA­0573(98) (Washington, DC, October 1999). Also, because weather fluctuations and

other transitory factors significantly influence short­run patterns of energy use in all activities,

emissions growth rates calculated over a single year should not be used to make projections of future

emissions growth.

6. About 37 percent of CO2 emissions are produced by electric utility generators, as reported in the

greenhouse gas inventory for 1998. An additional 3.5 percent are attributable to nonutility power

producers, which are included in the industrial sector in the GHG inventory.
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7. Energy Information Administration, Emissions of Greenhouse Gases in the United States 1998,

Chapter 2, "Carbon Dioxide Emissions," DOE/EIA­0573(98) (Washington, DC, October 1999). Data

for 1999 will be available in October 2000.

8. Capacity factor is the ratio of the amount of electricity produced by a generating plant for a given

period of time to the electricity that the plant could have produced at continuous full­power operation

during the same period. Based on national level consumption and generation data presented in the

Electric Power Monthly, and assuming a net summer nuclear capability of 99,000 MW, a 1­percent

increase in the annual nuclear plant capacity factor (equivalent to 8,672,400 megawatthours of

additional nuclear generation) translates into a reduction in annual consumption of either 4.4 million

short tons of coal, 14 million barrels of petroleum, or 92 billion cubic feet of gas, or most likely a

combination of each.

9. Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA­0348(99)/1

(Washington, DC, forthcoming).

10. Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants, 1999,

http://www.eia.doe.gov/cneaf/electricity/cq/cq_sum.html.

11. http://www.bea.doc.gov/bea/dn1.htm, Department of Commerce web site, accessed May 10,

2000.

12. Retail sales by utilities grew 1.73 percent from 1998 to 1999. Retail sales by marketers in

deregulated, competitive retail markets are not included. The addition of an estimated 48 billion

kilowatthours in retail marketer sales would result in an increase in electricity consumption of 2.45

percent from 1998 to 1999.

13. Energy Information Administration, Electric Power Annual 1999, Volume I, DOE/EIA0348(99)/1 (Washington, DC, forthcoming).

14. DSM data for 1999 will be available in the latter part of 2000.

15. Heating value is measured in British thermal units (Btu), a standard unit for measuring the

quantity of heat energy equal to the quantity of heat required to raise the temperature of 1 pound of

water 1 degree Fahrenheit.

16. Boiler type and efficiency, capacity factor, and other factors also affect the number of

kilowatthours that can be produced at a particular plant.

17. The thermal efficiency is a ratio of kilowatthours of electricity produced multiplied by 3,412 Btu

to the fuel consumed, measured in Btu. This ratio is dependent on the estimated generation and fuel

consumption for 1999. Uncertainty and an undetermined degree of variation in both generation and

fuel consumption data for the nonutility sector may contribute to an apparent change in the ratio,

which should be regarded as a preliminary value at this time.

18. The Voluntary Reporting of Greenhouse Gases Program is currently in the 1999 data reporting

cycle; the most recent year for which complete data are available is 1998. The 1997 and 1998 data in

last year's report were preliminary and have been revised in this report due to subsequent completion

of internal EIA review of those data. Emission reductions also include those reported by landfill

methane operators.

19. The EIA also receives numerous reports on projects and emissions reductions from reporters

outside the electric power sector. In addition, many reports submitted to the Voluntary Reporting
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Program (including electric power sector reports) include reductions of greenhouse gases other than

carbon dioxide, such as methane and nitrous oxide and the high Global Warming Potential gases

such as HFCs, PFCs and sulfur hexafluoride.

20. U.S. Department of Energy, Climate Challenge Fact Sheet (1998), and conversation with Larry

Mansueti, August 10, 1999. See also

http://www.eren.doe.gov/climatechallenge/execsumm/execsumm.htm.

21. See the 1997 Climate Change Action Report (the Submission of the United States of America

under the United Nations Framework Convention on Climate Change), p. 100, for one such

assessment.

22. TXU was formerly known as Texas Utilities, while FirstEnergy is the result of a merger between

Ohio Edison and Centerior Energy (Cleveland Electric).

23. Other greenhouse gases include methane eductions from landfills and oil and natural gas systems,

and sulfur hexafluoride (SF6), which has 23,900 times the global warming impact of carbon dioxide

when released into the atmosphere.

24. The more than 40 companies referenced in last year's report are participants in EEI's UtiliTree

program. Of these companies, 31 reported their share of participation to the Voluntary Reporting of

Greenhouse Gases Program for 1998.

25. U.S. Department of Energy, Supporting Analysis for the Comprehensive Electricity Act, May

1999.

26. Energy Information Administration, The Comprehensive Electricity Competition Act: A

Comparison of Model Results. Internet site at http://www.eia.doe.gov/oiaf/servicerpt/ceca.html.

27. 1998 Annual Consumption for cogenerators is adjusted to exclude fuel not used for generation of

electricity.