U.S. Energy Information Administration/Electric Power Annual 2009 1

Electric Power Industry 2009: 

Year in Review

Highlights

Generation. Electricity markets in 2009 were 

keenly affected by economic and environmental 

developments. Electricity generation was down 

4.1 percent, reaching its lowest level since 2003; 

this was the largest decline in 6 decades1 and 

follows a 0.9-percent decline in 2008. The drop 

in power demand reflects a 2.6-percent decline in 

economic activity (GDP) during 2009.2

Summer temperatures during 2009 were 

relatively mild, resulting in a 1.1 percent decline 

in residential electricity sales between 2008 and 

2009.

A 9.1-percent decline in industrial demand for 

electricity, which fell to the lowest level since 

1987, accounted for most of the decline in 

overall electricity consumption. The drop in 

industrial electricity demand reflected the 9.3-

percent drop in industrial output, as measured by 

the Federal Reserve Bank’s index of industrial 

production.3

Emissions. Environmental developments played 

an important role in electricity markets in 2009.

• The policy debate over greenhouse gas 

legislation continued throughout 2009. 

Electric power plant investment and 

operation decisions made during 2009 may 

have been affected by expectations that 

some form of future cap on carbon dioxide 

(CO2) loomed on the horizon.

• CO2, nitrogen oxides (NOx,) and sulfur 

dioxide (SO2) emissions posted the largest 

declines on record.4

 Total CO2 emissions 

were 8.6-percent lower in 2009. Emissions 

from coal-fired plants fell 11.0 percent, 

largely attributable to a 10.3-percent decline 

in coal consumption. 

1 The U.S. Energy Information Administration’s historic electricity 

generation data goes back to 1949.

2 U.S. Department of Commerce Bureau of Economic Analysis, News 

Release: Gross Domestic Product: Second Quarter 2010 (Third 

Estimate), Table 1. 3 U.S. Federal Reserve Bank, Industrial Production and Capacity 

Utilization, (Table 11). 4

The U.S. Energy Information Administration has been estimating 

CO2, NOX, and SO2 emissions since 1989.

• NOx and SO2 emissions from electric power 

plants declined 28.1 and 23.8 percent, 

respectively (Table 3.9) in 2009. For coalfired generation, the declines in NOx and 

SO2 emissions were even greater, at 34.0

percent and 24.7 percent, respectively. 

Fuel costs. The price of natural gas delivered to 

electric power plants fell in 2009 to roughly half 

the 2008 level. In 2009, annual average natural 

gas wellhead prices reached their lowest level 

in 7 years. Increased supply due to the 

availability of shale gas, coupled with mild 

winter temperatures and higher production, 

and storage levels, and significant expansions 

of pipelines capacity also worked to put 

downward pressure on natural gas prices. 5

At the same time, the cost of coal rose 6.8

percent (Table 3.8), largely due to long-term 

contracts signed prior to the recent recession. 6, 7

 

Between 2000 and 2009, coal prices to electric 

power plants rose 84 percent. 

Coal-to-gas switching. The increase in 

delivered coal prices and the decrease in 

delivered natural gas prices, combined with 

surplus capacity at highly-efficient gas-fired 

combined-cycle plants resulted in coal-to-gas 

fuel switching This occurred particularly in 

the Southeast (Alabama, Arkansas, Florida, 

Georgia, Mississippi, and South Carolina) and 

also Pennsylvania. Nationwide, coal-fired 

electric power generation declined 11.6 percent 

from 2008 to 2009, bringing coal’s share of the 

electricity power output to 44.5 percent, the

lowest level since 1978. Coal consumption at 

U.S. power plants paralleled the decline in 

generation, dropping 10.3 percent from 2008. 

In sharp contrast, natural gas-fired generation 

increased 4.3 percent in 2009, despite the 4.1-

percent decline in overall electric generation. 

The natural gas share of generation increased to 

23.3 percent—the highest level since 1970. 

Electricity’s share of the total U.S. natural gas 

consumption has also risen rapidly, growing 

from 17 percent in 1996 to over 30 percent in 

2009.8

5 U.S. Energy Information Administration, Natural Gas Year-inReview, 2009

6 U.S. Energy Information Administration, U.S. Coal Supply and 

Demand: 2009 ”Coal Prices”, p. 12 7 The Southern Company (a large consumer of coal for electricity 

production), reported: “While coal prices reached unprecedented high 

levels in 2008, the recessionary economy pushed prices downward in 

2009. However, the lower prices did not fully offset the higher priced 

coal already in inventory and under long-term contract.” Southern 

Company 2009 10-K, p. II-16.
2 U.S. Energy Information Administration/Electric Power Annual 2009

Wind development. Wind power has been the 

fastest-growing source of new electric power 

generation for several years. In 2009, generation 

from wind power increased 33.5 percent over 

2008, bringing the share of total generation to

1.9 percent. This followed year-over-year 

generation gains of 60.7 percent in 2008, 29.6 

percent in 2007, and 49.3 percent in 2006 (Table 

ES.1). Wind capacity in 2009 totaled 34,296 

megawatts (MW), as compared to 24,651 MW in 

2008. 

In 2009 (and 2010), wind generators were 

eligible for Federal production and investment 

tax credits or a cash grant in lieu of those tax 

credits.9 Since passage of the 2005 Energy Policy 

Act (EPACT2005), interest-free financing via 

Clean Renewable Energy Bonds (CREBs) has 

been available to government entities investing 

in wind. Section 9006, under Title IX of the 

2002 and 2008 Farm Bills, also contains grant 

and loan guarantee provisions for wind projects 

for farmers, ranchers, and other rural businesses. 

Renewable generation is fostered by both 

Federal incentives and State renewable portfolio 

standards. As of October 2010, 29 States, the 

District of Columbia, and Puerto Rico have 

legislated renewable energy portfolio standards, 

and 7 more States have adopted renewable 

portfolio goals.10 

Generation 

Net generation of electric power fell 4.1 percent 

in 2009, to 3,950 million megawatthours (MWh) 

from 4,119 million MWh in 2008 (Figure ES1). 

This is the largest decline in electricity 

generation in at least 60 years. Electricity

generation also declined 0.9 percent in 2008. The 

years 2008 and 2009 represent only the third and 

fourth instances that generation has dropped year 

over year since 1949 (the first two occurrences 

were during recessions in 1982 and 2001). 

 8

U.S. Energy Information Administration, Annual Energy Review, 

2009, Table 6.5.

9 The grant program arose out of Section 1603 of the American 

Economic Recovery and Reinvestment Act of 2009 (ARRA) and was 

intended to allow investors who could not take advantage of tax 

credits to fund these projects with an equivalent government grants. 

This program expires December 31, 2010. See the Database of State 

Incentives for Renewables and Efficiency (DSIRE) at 

http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=U

S53F&re=1&ee=1

10 See the DSIRE database at http://www.dsireusa.org/.

Additionally, this is the first time over the last 6 

decades that generation has declined in two 

consecutive years.

Coal, natural gas, and nuclear generation 

accounted for 88.0 percent of total net generation 

in 2009, and between 85 and 90 percent during 

the period 1997 through 2009. However, the 

relative contribution of these energy sources has 

been shifting; natural gas generation has seen the 

fastest growth in recent years.

Figure ES 1. U.S. Electric Power Industry 

Net Generation, 2009

Source: U.S. Energy Information Administration, Form 

EIA-923, "Power Plant Operations Report.”

Coal. Coal-fired electric generation declined 

11.6 percent between 2008 and 2009. With this 

decline, coal’s share of electricity generation 

reached its lowest level since 1978: 44.5 percent 

of electricity generation in 2009, down from 48.2 

percent in 2008. 

Several factors have worked to erode the 

advantage that coal-fired generation has 

historically derived from its lower fuel costs. 

These factors include lower natural gas prices 

and higher coal prices; surplus capacity at 

efficient natural gas plants, and the cost of 

compliance with current environmental 

regulations. 

Production at the Nation’s coal mines in 2009 

reflected the weakened state of coal demand for 
U.S. Energy Information Administration/Electric Power Annual 2009 3

electricity generation. Appalachian coal 

production fell 13.0 percent in 2009 from the 

previous year. Even Western (Powder River 

Basin) coal production, which has a significant 

price advantage, showed an 8.1-percent decline

in 2009.

11 

Natural gas-fired power generation increased 

by 4.3 percent in 2009, raising natural gas’s 

share of the electricity market to 23.3 percent—

its highest share since 1970. Natural gas’s share 

of the electricity market has been greater than the 

nuclear share since 2006. New capacity, as well 

as the increased utilization of existing generators

(see Table 5.2 on capacity factors), account for 

the increase in share. 

Nuclear power generation accounted for 20.2 

percent of the electricity generated in 2009, a 

0.9-percent decrease from the prior year. The 

decline in nuclear generation in 2009 is the 

result of scheduled and unscheduled plant 

outages and derates.

Hydroelectric power generation fluctuates

perennially with precipitation levels and snow 

accumulation. Overall, generation from 

conventional hydro plants (exclusive of pumped 

storage) increased 7.3 percent from 2008 to 2009 

(Table ES.1). The western States were still 

suffering from a prolonged drought during 2009. 

The Bonneville Power Administration, which is 

the largest producer of hydroelectric power in the 

west, reported reduced runoff for the January 

through July 2009 period as compared to the 

same period in 2008.12 In contrast, many eastern 

States experienced record rainfall: Alabama, 

Georgia, Kentucky, North Carolina, and 

Tennessee all reported substantial gains in hydro 

generation in 2009. The Tennessee Valley 

Authority cited better water conditions, resulting 

in a 71-percent increase in hydropower during 

2009.13

Renewables. Total non-hydro renewable 

generation increased 14.0 percent in 2009, 

following a 19.9-percent increase in 2008. The 

fastest-growing component was wind power 

(33.5-percent increase). Solar generation 

11 U.S. Energy Information Administration .,Annual Coal Report, 

2008 and 2009, Table 6.

12 Bonneville Power Administration, 2009 Annual Report, (10-K),

p. 9. Melting snow creates much of BPA’s runoff. Snowpack in the 

mountains accumulates from December to February (approximately), 

and significant runoff, and therefore peak hydro production, occurs 

March through July (approximately). 

13 Tennessee Valley Authority, 2009 Annual Report (10-K), p.12.

increased 3.1 percent. Since 1998, generation 

from non-hydro renewables has increased 86.6

percent.

In 2009, renewable generation made up 10.6 

percent of total generation. The largest three 

contributors were hydro (6.9 percent), wind (1.9 

percent), followed by wood and wood-derived 

fuels (0.9 percent). Discounting the hydro 

portion, renewable generation made up 3.6 

percent of total generation. 

Petroleum’s contribution to U.S. net electricity 

generation peaked in 1973 at 17 percent, but has 

fallen steadily since to almost insignificant 

levels. Petroleum’s share of power output fell 

below one percent in 2009, reflecting a 15.8-

percent decrease in petroleum-fired power 

generation between 2008 and 2009. 

Nuclear and fossil capacity factors. The 

capacity factor is a measure of how consistently 

a generator is producing power: it represents the 

ratio of actual generation during a time period 

(typically a year) to the maximum possible 

generation assuming continuous full-load output. 

Baseload plants, which have high utilization 

rates due primarily to low variable operating 

costs, typically operate at capacity factors of 70

percent or higher. Intermediate plants, which 

have higher variable operating costs, typically

vary their output during the day to meet changes 

in load. The most expensive peaking plants may 

operate rarely and only to meet the highest 

peaks, usually in the summer or winter.

Due to decreased demand for electricity, the 

average capacity factor for many fuels fell in 

2009 (Table 5.2). Nuclear power plants (which 

in the United States are universally operated as 

baseload units because of their very low fuel 

costs) maintained a high capacity factor (90.3 in 

2009). The capacity factor for coal plants, which 

make up the bulk of U.S. baseload capacity but 

can also operate in load-following mode,14

 

dropped sharply (8.4 percentage points) in 2009, 

from 72.2 percent to 63.8 percent.

The vast majority of natural gas capacity in the 

United States operates as load-following or 

peaking units. In 2009, coal-to-gas switching 

increased the usage of combined-cycle natural 

gas generators; the capacity factor for these units 

14 Despite representing only three quarters of the capacity of natural 

gas plants, coal plants account for approximately twice the amount of 

electricity produced by natural gas plants (Table ES.1)
4 U.S. Energy Information Administration/Electric Power Annual 2009

increased from 40.6 percent in 2008 to 42.5 

percent in 2009. 

Capacity

Total U.S. net summer generating capacity grew 

by 1.5 percent between 2008 and 2009 to 1,025 

gigawatts (GW; Figure ES2). Both in absolute 

and percentage terms, wind generating capacity 

showed the strongest gains: the 9,645 MW of 

wind capacity additions were more than double 

that of natural gas, which had the second-largest 

increase in capacity at 3,812 MW. Coal, nuclear, 

and hydroelectric capacity experienced marginal 

gains.

During 2009, 382 new generators were 

connected to the grid, 51 fewer than in 2008 

(Table 1.11). These new units added 23,144 

MW of capacity, 50.1 percent of which were 

added by independent power producers (IPPs; 

11,590 MW), with nearly all of the remainder 

added by electric utilities (10,939 MW). 

Wind capacity additions accounted for 63.3 

percent of all capacity gains in 2009, 

increasing the amount of installed wind 

capacity by 39.1 percent. With 34.3 GW of 

total capacity, wind now accounts for 3.3 

percent of total U.S. capacity, up from less 

than 3 tenths of a percent 10 years earlier.

Four States accounted for 51 percent of total 

U.S. wind capacity: Texas (9.4 GW), 15 Iowa 

(3.4 GW), California (2.7 GW), and 

Washington (2.0 GW). 

Natural gas capacity. In 2009, natural gas 

capacity increased by 1.0 percent, led by 

installations in California, Florida and Texas. 

About 72 percent of all natural gas plant 

capacity additions during 2009 were highly 

efficient combined-cycle units. In 2009, 

combined-cycle units accounted for 50 percent 

of total natural-gas-fired electricity capacity 

versus 2 percent of natural gas-fired capacity 

two decades ago.

Coal capacity. Coal-fired electric capacity 

increased by 0.3 percent between 2008 and 

2009 to 314,294 MW. A total of 13 new coal15 As of the end of 2009 Texas had 76 wind plants comprising 9.1 

percent of overall Texas electricity capacity. In 2005, Texas 

adopted a RPS which required the state to have 5,880 MW of total 

renewable capacity in place by 2015, and 10,000 MW by 2025. Texas 

is very close to meeting the 2025 standard with its wind capacity 

alone.

fired generators came on line in 2009, notably 

the 682-MW Nebraska City 2 unit (Omaha 

Public Power District) and the 415-MW 

Springerville 4 unit (Salt River Project). Both 

East Kentucky Power Cooperative and Archer 

Daniels Midland installed generators capable 

of co-firing coal with biomass. 

Figure ES2. U.S. Electric Power 

IndustrySummer Capacity, 

2009

Source: U.S. Energy Information Administration, Form 

EIA-860, “Annual Electric Generator Report.”

Coal retirements in 2009 totaled 529 MW. 

Further retirements are planned. For example, 

in December 2009, Progress Energy announced 

that it planned to retire 11 generators (1,500 

MW) at four of its North Carolina coal plants 

that lacked desulfurization equipment, and 

replace the lost capacity with natural gas units. 

Progress Energy’s remaining units are all 

equipped with scrubbers. 16

Solar capacity. Solar power is a rapidly 

growing source of new capacity, albeit from a 

relatively small base. Solar power producers 

added 83 MW of capacity in 2009, a 15.5-

percent increase over 2008. California, with 

450 MW of existing (utility-scale) solar 

capacity, accounted for 72.8 percent of total 

capacity, followed by Nevada, with 14.3 

percent of capacity. Two large plants were 

brought on line in 2009: FPL’s 25 MW 

DeSoto Solar Energy Plant in Florida, 

described as the largest photovoltaic solar 

16 “Progress Energy Plans to Retire Remaining Unscrubbed Coal 

Plants in NC,” December 1, 2009.
U.S. Energy Information Administration/Electric Power Annual 2009 5

plant in the world (at the time), 17 and NRG 

Energy’s 21-MW facility in Blythe, California, 

which was constructed in just 3 months. 

The 20 MW scale of recent solar power plant 

additions far exceeds the average size of the 

current fleet of solar units, but is in turn dwarfed 

by the scale of units in the planning stage. 18 For 

example, by 2013, BrightSource Energy is 

scheduled to bring on line all three units of its 

390-MW Ivanpah concentrated thermal power 

plant in California.

Nuclear uprates. Since 1998, there have been 

104 operable units in the United States. 19 In 

2009, nuclear capacity increased 249 MW, due 

to a combination of uprates (technical 

modifications of existing units) and other net 

capacity adjustments. Through such uprates to 

existing capacity, rather than new builds, 3.6

GW of nuclear capacity have been added to the 

system over the past decade (Table 1.1), 

representing over 3 percent of total U.S. nuclear 

capacity in 2009. This added capacity is the 

equivalent of building several new reactors. 

Prospects for new nuclear reactors. Currently, 

there is one nuclear power unit under 

construction, TVA’s 1,150 MW Watts Bar 2, 

which is scheduled to be in operation in 2012. 

Initial construction of Watts Bar 2, which began 

in 1973, was suspended in 1988 and resumed in 

2007. TVA may also complete Unit 1 at its 

Bellefonte site, which would enter operation in 

the 2018-2019 time frame. TVA suspended 

construction of Bellefonte in 1988.

During 2009, one application was submitted to 

the Nuclear Regulatory Commission (NRC) for 

the construction of two nuclear units at FPL’s 

existing Turkey Point facility. This compares to 

applications for 16 units during 2008 and 8 units 

in 2007. The NRC also granted an Early Site 

Permit to Southern Company’s/Georgia Power’s 

Vogtle nuclear power units 3 and 4 (August, 

2009) and preliminary site preparation has 

begun. 20 

17 FPL. http://www.fpl.com/environment/solar/desoto.shtml. 18 Todd Woody, “Solar Power Projects Face Potential Hurdles,” The 

New York Times, October 28, 2010,

http://www.nytimes.com/2010/10/29/business/energyenvironment/29solar.html?_r=1&scp=1&sq=ivanpah&st=cse. 19 TVA’s Brown Ferry 1 was offline for many years but was officially 

classified as “operable” because it retained a Nuclear Regulatory 

Commission operating license. The unit actually returned to service 

in 2007. 

20 Other investors include Oglethorpe Power (30 percent) and the 

Municipal Electric Authority of Georgia (22.7 percent). Source: 

 Planned Capacity

Capacity plans are constantly evolving as electric 

power producers navigate a dynamic, rapidly 

changing market. Each year, EIA asks electric 

power producers for a snapshot of their plans as 

of the end of the previous year. The information 

below, and in Table 1.4, represents capacity 

plans as of December 31, 2009, as reported to 

EIA during the spring of 2010. EIA also collects 

monthly data on the status of proposed 

generators. 21

Capacity additions by fuel type. As of the end 

of 2009 electric power producers planned to add 

72,157 MW of capacity between 2010 and 2014. 

Of this, 48.3 percent was planned to be fired by 

natural gas (34,828 MW) and 23.1 percent from 

coal (16,685 MW) (Figure ES3). 

Figure ES3. Planned Summer Capacity 

Additions, 2010-2014

Source: U.S. Energy Information Administration, Form 

EIA-860, “Annual Electric Generator Report.”

For the period 2010-2014, planned wind 

additions totaled 11,560 MW, or 16.0 percent of 

total reported planned additions. Wind plants 

have a much shorter planning horizon and are 

built more quickly than fossil fuel-fired plants; 

only 6.2 percent of the reported new wind 

capacity additions were planned to occur after 

2012.

 World Nuclear News, “Georgia Power Accepts Vogtle Loan 

Guarantee,” June 21, 2010. 21U.S. Energy Information Administration, Electric Power Monthly, 

Table ES3, New and Planned U.S. Electric Generating Units.
6 U.S. Energy Information Administration/Electric Power Annual 2009

Solar additions were expected to add 4,087 MW 

of capacity by 2014. The planned completion of 

Watts Bar 2 in 2012 would add 1,122 MW of 

nuclear capacity. The construction of new coal 

plants has been discouraged by increasing costs 

for capital-intensive projects, concerns over 

possible future CO2 and other environmental 

restrictions, and the prospect that natural gas 

prices will remain low over the long-term. 

Electricity Sales and Prices

In 2009, retail sales of electricity fell to 3,597 

billion kilowatthours, a 3.6-percent decline from 

the prior year and the lowest level of sales since 

2004 (Table 7.2). Industrial demand experienced

the greatest decline, falling 9.1 percent from 

2008, to levels unseen since 1987. The 

residential and commercial sectors reported 

declines of 1.1 percent and 2.2 percent, 

respectively. 

Retail sales to industrial customers. The 

Federal Reserve Bank’s index of industrial 

production fell 9.2 percent in 2009, driven by 41 

and 42 percent decreases in the automobile and 

iron and steel components, respectively. 22 In the 

East North Central Census Division, which 

contains some of the Nation’s most 

industrialized States (Illinois, Indiana, Michigan, 

Ohio, and Wisconsin), overall electricity demand 

declined 6.9 percent (Figure ES4), led by a 12.3-

percent decline in industrial demand. The East 

South Central States (Alabama, Kentucky, 

Mississippi, and Tennessee) saw the next largest 

decline at 6.8 percent.

Weather and Retail Sales to Residential 

Customers. Year-over-year (i.e., short term) 

changes in residential electricity sales largely 

reflect changes in the weather. Summer 

temperatures during 2009 were relatively mild in 

the contiguous states. 23 This dampened air 

conditioning demand; for the June through 

August summer period, residential electricity 

sales declined 3.3 percent between 2008 and 

2009. 

22 IHS Global Insight, “U.S. Economic Outlook,” April 2010, p. 92.

23 National Oceanic & Atmospheric Administration, National Data 

Climate Center, State of the Climate National Overview Annual 2009

Figure ES4. Annual Change in Retail 

Sales to Bundled and 

Unbundled Customers, 2008 

to 2009 (Percent Change)

Source: U.S. Energy Information Administration, 

Form EIA-861, “Annual Electric Power Industry 

Report.”

Prices. Overall retail electricity prices rose 0.9 

percent between 2008 and 2009 (from 9.74 cents 

to 9.83 cents per kWh). The overall 25.8-percent 

decline in fossil fuel prices as delivered to 

electric plants had little immediate impact on 

electric power prices to the end user; the lag in 

changes between fuel prices and power prices 

can be a year or two, as changes in retail 

electricity rates are dependent on each State’s 

utility regulatory review process. 

Electric Trade

Wholesale Markets. Wholesale power 

purchases in 2009 totaled 5,029 million MWh.24 

This represents a decrease of 10.4 percent 

between 2008 and 2009, following an increase of 

3.7 percent from 2007 to 2008 (Table 6.1) and a 

peak in 2002 at 8,755 million MWh. Electric 

utilities and energy-only providers (power 

marketers) each account for roughly half of 

wholesale purchases. The power marketers’ 

share of the wholesale market dropped from 69.1 

percent in 2002 to 51.0 percent in 2009, as a 

consequence of the financial failure of many 

marketers and contraction of trade following the 

collapse of Enron. Electric utilities’ wholesale 

purchases have generally remained stable over 

the last decade, but in a shrinking market their 

market share has risen from 29.9 percent in 2002 

to 47.0 percent in 2009. 

24 A single “block” of electricity can be sold multiple times, with each 

purchase appearing in the data reported to EIA. Consequently, total 

wholesale purchases exceed total supply of electricity (3,950 million 

MWh in 2009).
U.S. Energy Information Administration/Electric Power Annual 2009 7

Electricity sales for resale (wholesale power 

sales) fell similarly in 2009, down 10.8 percent 

from 2008 to 5,065 million MWh. Energy-only 

providers made up 44.2 percent of the market in 

2009. Electric utilities comprised 29.5 percent of 

the market in 2009, IPPs 25.6 percent, and

combined heat and power plants less than one 

percent. 

International trade. The U.S. buys from and 

sells electricity to Canada and, to a much smaller 

degree, Mexico. Although the U.S. imported 

slightly less than 1 percent of its electricity 

consumption in 2009, Canadian exports account 

for roughly 8 percent of Canada’s production of 

electricity (Table 6.3).25 Canada is the second 

largest exporter of electricity in the world, 

primarily generated by hydroelectric plants in 

Quebec, Ontario, and British Columbia. 26

Canadian and U.S. electricity markets are highly 

integrated with multiple transmission lines 

crossing the international border. 

Electricity trade with Mexico is much smaller. 

Net purchases from Mexico in 2009 constituted 

0.01 percent of total U.S. supply. 

Fossil Fuels 

Stocks at Electric Power Plants. End-of-year 

coal stocks rose 17.3 percent between 2008 and 

2009 to reach their highest levels in at least 60 

years. At 189 million tons, coal stocks have 

almost doubled since 2005 (Table 3.4), probably 

due to the sharp decline in coal-fired generation 

combined with limited flexibility in coal supply 

contracts to reduce deliveries. 27 In some cases, 

this involuntary inventory accumulation has 

prompted utilities to attempt to renegotiate their 

coal contracts or to petition their PUCs for 

ameliorative actions. 28

25 U..S. Energy Information Administration, International Energy 

Statistics, 

http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid

=2&aid=12. Note: The ratio of Canadian electricity exports to 

domestic generation is for the year 2008.

26 North America Energy Working Group, Security and Prosperity 

Partnership, Energy Picture Experts Group, “North America—The 

Energy Picture II,” January 2006. 27 In its 2009 annual report, the large coal-fired generation company, 

AEP Corp, cited “an increase in coal inventory reflecting decreased

customer demand for electricity” AEP 2009 Annual Report, p. 20. 28Duke Energy Carolinas, Docket No. E-7, Sub 909, and Indiana 

Utility Regulatory Commission, Cause No. 38707 FAC 83, Approved 

March 24, 2010

http://www.in.gov/iurc/files/38707_83order_032410.pdf.

Fossil Fuel Costs. The average delivered 

cost of fossil fuels to electric power plants fell 

26.0 percent in 2009, from $4.11 per MMBtu in 

2008 to $3.04 per MMBtu (Table 3.5). Most of 

this decline relates to natural gas prices; in 2009 

natural gas prices fell to about half their 2008 

levels (Figure ES5). Annual average costs of 

natural gas to the electric power industry 

peaked in 2008 at $9.02 per million Btu—the 

highest nominal dollar level in at least two 

decades—before falling to $4.74 per MMBtu in 

2009. The average cost of coal actually rose 

between 2008 and 2009 from $2.07 to $2.21 per 

MMBtu, due to the prevalence of long-term 

contracts and the relatively small role of the 

coal spot market. 

Emissions

Decreases in all emissions. Estimated emissions 

of carbon dioxide (CO2), sulfur dioxide (SO2), 

and nitrogen oxide (NOx) all declined in 2009 

compared to 2008 (Table 3.9). This was due in 

part to reduced coal-fired generation. Coal 

produces far more emissions per kWh of 

electricity than other major fuels. SO2 and NOx

emissions were further reduced by installations 

of new emission control devices.

SO2 emissions fell 23.8 percent between 2008 

and 2009, from 7,830 thousand metric tons to 

5,970 thousand metric tons (Table 3.9). This is

the largest year-over-year decline since 1989 (the 

Figure ES5. Fossil Fuel Costs for 

Electricity Generation, 

1998-2009

Source: U.S. Energy Information Administration, 

Form EIA-923, "Power Plant Operations Report.”
8 U.S. Energy Information Administration/Electric Power Annual 2009

first year in EIA’s data series). Nationwide, the 

count of generators with SO2 control systems

increased from 327 in 2008 to 384 in 2009 

(Table 3-10), contributing to the reduction in 

SO2 emissions. 

Data for 2009 also show significant reductions in 

NOx emissions, which dropped 28.1 percent 

from 2008, from 3,330 to 2,395 thousand metric 

tons—also the largest decline on record. Since 

1998, sulfur dioxide and nitrogen oxide 

emissions have been reduced by 55.7 percent and 

62.9 percent, respectively, largely due to the 

implementation of the Clean Air Act 

Amendments of 1990.

Estimated CO2 emissions by U.S. electric 

generators and combined heat and power 

facilities fell by 8.6 percent from 2008 to 2009 

(from 2,484 million metric tons to 2,270 million 

metric tons), largely due to decreased coal

consumption. Emissions from coal-fired power 

plants typically account for four fifths of CO2 

emissions produced by the electric power sector. 

The estimated CO2, SO2, and NOx emissions are 

determined by the type and quantity of fossil 

fuels consumed by power plants. In the case of 

SO2 and NOx, boiler configurations and the 

presence of, or absence of, pollution abatement 

equipment play a major role. The methodology 

used to estimate emissions is described in the 

Technical Notes and Tables A1, A2, and A3. 
U.S. Energy Information Administration/Electric Power Annual 2009 9

Table ES1. Summary Statistics for the United States, 1998 through 2009

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Net Generation (thousand megawatthours)

Coal1 ............................................................ 1,755,904 1,985,801 2,016,456 1,990,511 2,012,873 1,978,301 1,973,737 1,933,130 1,903,956 1,966,265 1,881,087 1,873,516

Petroleum2 .................................................... 38,938 46,243 65,739 64,166 122,225 121,145 119,406 94,567 124,880 111,221 118,061 128,800

Natural Gas3 ................................................. 920,797 882,981 896,590 816,441 760,960 710,100 649,908 691,006 639,129 601,038 556,396 531,257

Other Gases4................................................. 10,629 11,707 13,453 14,177 13,464 15,252 15,600 11,463 9,039 13,955 14,126 13,492

Nuclear......................................................... 798,855 806,208 806,425 787,219 781,986 788,528 763,733 780,064 768,826 753,893 728,254 673,702

Hydroelectric Conventional5......................... 273,445 254,831 247,510 289,246 270,321 268,417 275,806 264,329 216,961 275,573 319,536 323,336

Other Renewables6 ....................................... 143,824 126,101R 105,238 96,525 87,329 83,067 79,487 79,109 70,769 80,906 79,423 77,088

Wind........................................................ 73,886 55,363 34,450 26,589 17,811 14,144 11,187 10,354 6,737 5,593 4,488 3,026

Solar Thermal and Photovoltaic............... 891 864 612 508 550 575 534 555 543 493 495 502

Wood and Wood Derived Fuels7.............. 35,596 37,300 39,014 38,762 38,856 38,117 37,529 38,665 35,200 37,595 37,041 36,338

Geothermal.............................................. 15,009 14,840R 14,637 14,568 14,692 14,811 14,424 14,491 13,741 14,093 14,827 14,774

Other Biomass8........................................ 18,443 17,734 16,525 16,099 15,420 15,421 15,812 15,044 14,548 23,131 22,572 22,448

Pumped Storage9 .......................................... -4,627 -6,288 -6,896 -6,558 -6,558 -8,488 -8,535 -8,743 -8,823 -5,539 -6,097 -4,467

Other10 .......................................................... 11,929 11,804R 12,231 12,974 12,821 14,232 14,045 13,527 11,906 4,794 4,024 3,571

All Energy Sources ..................................... 3,949,694 4,119,388 4,156,745 4,064,702 4,055,423 3,970,555 3,883,185 3,858,452 3,736,644 3,802,105 3,694,810 3,620,295

Net Summer Generating Capacity (megawatts)

Coal1............................................................. 314,294 313,322 312,738 312,956 313,380 313,020 313,019 315,350 314,230 315,114 315,496 315,786

Petroleum2 .................................................... 56,781 57,445 56,068 58,097 58,548 59,119 60,730 59,651 66,162 61,837 60,069 66,282

Natural Gas3 ................................................. 401,272 397,460R 392,876 388,294 383,061 371,011 355,442 312,512 252,832 219,590 195,119 180,288

Other Gases4 ................................................. 1,932 1,995 2,313 2,256 2,063 2,296 1,994 2,008 1,670 2,342 1,909 1,520

Nuclear......................................................... 101,004 100,755 100,266 100,334 99,988 99,628 99,209 98,657 98,159 97,860 97,411 97,070

Hydroelectric Conventional5......................... 78,518 77,930 77,885 77,821 77,541 77,641 78,694 79,356 78,916 79,359 79,393 79,151

Other Renewables6 ....................................... 48,552 38,466R 30,069 24,113 21,205 18,717 18,153 16,710 16,101 15,572 15,942 15,444

Wind........................................................ 34,296 24,651 16,515 11,329 8,706 6,456 5,995 4,417 3,864 2,377 2,252 1,720

Solar Thermal and Photovoltaic............... 619 536 502 411 411 398 397 397 392 386 389 335

Wood and Wood Derived Fuels7.............. 6,939 6,864 6,704 6,372 6,193 6,182 5,871 5,844 5,882 6,147 6,795 6,802

Geothermal.............................................. 2,382 2,229R 2,214 2,274 2,285 2,152 2,133 2,252 2,216 2,793 2,846 2,893

Other Biomass11....................................... 4,317 4,186 4,134 3,727 3,609 3,529 3,758 3,800 3,748 3,869 3,660 3,694

Pumped Storage9 .......................................... 22,160 21,858 21,886 21,461 21,347 20,764 20,522 20,371 19,664 19,522 19,565 19,518

Other12 .......................................................... 888 942 788 882 887 746 684 686 519 523 1,023 810

All Energy Sources ..................................... 1,025,400 1,010,171 994,888 986,215 978,020 962,942 948,446 905,301 848,254 811,719 785,927 775,868

Demand, Capacity Resources, and Capacity Margins – Summer

Net Internal Demand (megawatts) ................ 713,106 744,151R 766,786R 776,479 746,470 692,908 696,752 696,376 674,833 680,941 653,857 638,086

Capacity Resources (megawatts) .................. 916,449 909,504R 914,397R 891,226 882,125 875,870 856,131 833,380 788,990 808,054 765,744 744,670

Capacity Margins (percent)........................... 22.2 18.2 16.1 12.9 15.4 20.9 18.6 16.4 14.5 15.7 14.6 14.3

Fuel

Consumption of Fossil Fuels for Electricity Generation

Coal (thousand tons)1............................. 934,683 1,042,335 1,046,795 1,030,556 1,041,448 1,020,523 1,014,058 987,583 972,691 994,933 949,802 946,295

Petroleum (thousand barrels)2................ 67,666 80,932 112,615 110,634 206,785 203,494 206,653 168,597 216,672 195,228 207,871 222,640

Natural Gas (millions of cubic feet)3 ..... 7,120,585 6,895,843 7,089,342 6,461,615 6,036,370 5,674,580 5,616,135 6,126,062 5,832,305 5,691,481 5,321,984 5,081,384

Other Gases (millions of Btu)4 ............... 83,593 96,757 114,904 114,665 109,916 135,144 156,306 131,230 97,308 125,971 126,387 124,988

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

Coal (thousand tons)1............................. 20,507 22,168 22,810 23,227 23,833 24,275 17,720 17,561 18,944 20,466 20,373 20,320

Petroleum (thousand barrels)2................ 13,164 12,016 19,775 20,371 24,408 25,870 17,939 14,811 18,268 22,266 26,822 28,845

Natural Gas (millions of cubic feet)3 ..... 816,787 793,537 872,579 942,817 984,340 1,052,100 721,267 860,019 898,286 985,263 982,958 949,106

Other Gases (millions of Btu)4 ............... 175,671 203,236 214,321 226,464 238,396 218,295 137,837 146,882 166,161 230,082 223,713 208,828

Consumption of Fossil Fuels for Electricity Generation and Useful Thermal Output

Coal (thousand tons)1............................. 955,190 1,064,503 1,069,606 1,053,783 1,065,281 1,044,798 1,031,778 1,005,144 991,635 1,015,398 970,175 966,615

Petroleum (thousand barrels)2................ 80,830 92,948 132,389 131,005 231,193 229,364 224,593 183,408 234,940 217,494 234,694 251,486

Natural Gas (millions of cubic feet)3 ..... 7,937,372 7,689,380 7,961,922 7,404,432 7,020,709 6,726,679 6,337,402 6,986,081 6,730,591 6,676,744 6,304,942 6,030,490

Other Gases (millions of Btu)4 ............... 259,264 299,993 329,225 341,129 348,312 353,438 294,143 278,111 263,469 356,053 350,100 333,816

Stocks at Electric Power Sector Facilities (year end)

Coal (thousand tons)13............................ 189,467 161,589 151,221 140,964 101,137 106,669 121,567 141,714 138,496 102,296 141,604 120,501

Petroleum (thousand barrels)14............... 46,181 44,498 47,203 51,583 50,062 51,434 53,170 52,490 57,031 40,932 54,109 56,591

Receipts of Fuel at Electricity Generators15

Coal (thousand tons)1............................. 981,477 1,069,709 1,054,664 1,079,943 1,021,437 1,002,032 986,026 884,287 762,815 790,274 908,232 929,448

Petroleum (thousand barrels)2................ 88,951 96,341 88,347 100,965 194,733 186,655 185,567 120,851 124,618 108,272 145,939 181,276

Natural Gas (millions of cubic feet)16 .... 8,118,550 7,879,046 7,200,316 6,675,246 6,181,717 5,734,054 5,500,704 5,607,737 2,148,924 2,629,986 2,809,455 2,922,957

Cost of Fuel at Electricity Generators (cents per million Btu)15

Coal1........................................................ 221 207 177 169 154 136 128 125 123 120 122 125

Petroleum2 ............................................... 702 1,087 717 623 644 429 433 334 369 418 236 202

Natural Gas16 ........................................... 474 902 711 694 821 596 539 356 449 430 257 238

Emissions (thousand metric tons)

Carbon Dioxide (CO2) .................................. 2,269,508 2,484,012R 2,547,032R 2,488,918R 2,543,838R 2,486,982R 2,445,094R 2,423,963R 2,418,607R 2,470,834R 2,366,302R 2,351,600R

Sulfur Dioxide (SO2) .................................... 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 11,174 11,963 12,843 13,464

Nitrogen Oxides (NOX)................................. 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 5,290 5,638 5,955 6,459

Trade (million megawatthours)

Purchases...................................................... 5,029 5,613 5,411 5,503 6,092 6,999 6,980 8,755 7,555 2,346 2,040 2,021

Sales for Resale ............................................ 5,065 5,681 5,479 5,493 6,072 6,759 6,921 8,569 7,345 2,355 1,998 1,922

Electricity Imports and Exports (thousand megawatthours)

Imports ......................................................... 52,191 57,019R 51,396 42,691 43,929R 34,210 30,395 36,779 38,500 48,592 43,215 39,513

Exports ......................................................... 18,138 24,198R 20,144 24,271 19,151R 22,898 23,975 15,796 16,473 14,829 14,222 13,656

See end of table for Notes and Sources.
10 U.S. Energy Information Administration/Electric Power Annual 2009

Table ES1. Summary Statistics for the United States, 1998 through 2009

(Continued)

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Retail Sales and Revenue Data – Bundled and Unbundled

Number of Ultimate Customers (thousands)

Residential.................................................... 125,177 124,937 123,950 122,471 120,761 118,764 117,280 116,622 114,890 111,718 110,383 109,048

Commercial .................................................. 17,562 17,563 17,377 17,172 16,872 16,607 16,550 15,334 14,867 14,349 14,074 13,887

Industrial ...................................................... 758 775 794 760 734 748 713 602 571 527 553 540

Transportation .............................................. 1 1 1 1 1 1 1 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 1,067 1,030 974 935 933

All Sectors.................................................... 143,497 143,276 142,122 140,404 138,367 136,119 134,544 133,624 131,359 127,568 125,945 124,408

Sales to Ultimate Customers (thousand megawatthours)

Residential.................................................... 1,364,474 1,379,981 1,392,241 1,351,520 1,359,227 1,291,982 1,275,824 1,265,180 1,201,607 1,192,446 1,144,923 1,130,109

Commercial .................................................. 1,307,168 1,335,981 1,336,315 1,299,744 1,275,079 1,230,425 1,198,728 1,104,497 1,083,069 1,055,232 1,001,996 979,401

Industrial ...................................................... 917,442 1,009,300 1,027,832 1,011,298 1,019,156 1,017,850 1,012,373 990,238 996,609 1,064,239 1,058,217 1,051,203

Transportation .............................................. 7,781 7,700 8,173 7,358 7,506 7,224 6,810 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 105,552 113,174 109,496 106,952 103,518

All Sectors.................................................... 3,596,865 3,732,962 3,764,561 3,669,919 3,660,969 3,547,479 3,493,734 3,465,466 3,394,458 3,421,414 3,312,087 3,264,231

Direct Use..................................................... 126,938 132,197R 125,670R 146,927 150,016 168,470 168,295 166,184 162,649 170,943 171,629 160,866

Total Disposition .......................................... 3,723,803 3,865,159R 3,890,231R 3,816,845 3,810,984 3,715,949 3,662,029 3,631,650 3,557,107 3,592,357 3,483,716 3,425,097

Revenue From Ultimate Customers (million dollars) 

Residential.................................................... 157,008 155,433 148,295 140,582 128,393 115,577 111,249 106,834 103,158 98,209 93,483 93,360

Commercial .................................................. 134,106 138,469 128,903 122,914 110,522 100,546 96,263 87,117 85,741 78,405 72,771 72,575

Industrial ...................................................... 61,459 68,920 65,712 62,308 58,445 53,477 51,741 48,336 50,293 49,369 46,846 47,050

Transportation .............................................. 829 827 792 702 643 519 514 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 7,124 8,151 7,179 6,796 6,863

All Sectors.................................................... 353,403 363,650 343,703 326,506 298,003 270,119 259,767 249,411 247,343 233,163 219,896 219,848

Average Retail Price (cents per kilowatthour)

Residential.................................................... 11.51 11.26 10.65 10.40 9.45 8.95 8.72 8.44 8.58 8.24 8.16 8.26

Commercial .................................................. 10.26 10.36 9.65 9.46 8.67 8.17 8.03 7.89 7.92 7.43 7.26 7.41

Industrial ...................................................... 6.70 6.83 6.39 6.16 5.73 5.25 5.11 4.88 5.05 4.64 4.43 4.48

Transportation .............................................. 10.65 10.74 9.70 9.54 8.57 7.18 7.54 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 6.75 7.20 6.56 6.35 6.63

All Sectors.................................................... 9.83 9.74 9.13 8.90 8.14 7.61 7.44 7.20 7.29 6.81 6.64 6.74

Revenue and Expense Statistics (million dollars)

Major Investor Owned

Utility Operating Revenues ........................... 276,124 298,962 270,964R 275,501 265,652 238,759 230,151 219,609 267,276 233,915 213,090 214,849

Utility Operating Expenses............................ 244,243 267,263 241,198R 245,589 236,786 206,960 201,057 189,062 234,910 210,250 180,467 183,954

Net Utility Operating Income ........................ 31,881 31,699 29,766R 29,912 28,866 31,799 29,094 30,548 32,366 23,665 32,623 30,896

Major Publicly Owned (with Generation Facilities)

Operating Revenues ...................................... NA NA NA NA NA NA 33,906 32,776 38,028 31,843 26,767 26,155

Operating Expenses....................................... NA NA NA NA NA NA 29,637 28,638 32,789 26,244 21,274 20,880

Net Electric Operating Income ...................... NA NA NA NA NA NA 4,268 4,138 5,238 5,598 5,493 5,275

Major Publicly Owned (without Generation Facilities)

Operating Revenues ...................................... NA NA NA NA NA NA 12,454 11,546 10,417 9,904 9,354 8,790

Operating Expenses....................................... NA NA NA NA NA NA 11,481 10,703 9,820 9,355 8,737 8,245

Net Electric Operating Income ...................... NA NA NA NA NA NA 974 843 597 549 617 545

Major Federally Owned

Operating Revenues ...................................... NA NA NA NA NA NA 11,798 11,470 12,458 10,685 10,186 9,780

Operating Expenses....................................... NA NA NA NA NA NA 8,763 8,665 10,013 8,139 7,775 7,099

Net Electric Operating Income ...................... NA NA NA NA NA NA 3,035 2,805 2,445 2,546 2,411 2,681

Major Cooperative Borrower Owned

Operating Revenues ...................................... 42,189 42,087R 38,208 36,723 34,088 30,650 29,228 27,458 26,458 25,629 23,824 23,988

Operating Expenses....................................... 38,337 38,511R 34,843 33,550 31,209 27,828 26,361 24,561 23,763 22,982 21,283 21,223

Net Electric Operating Income ...................... 3,852 3,576R 3,365 3,173 2,879 2,822 2,867 2,897 2,696 2,647 2,541 2,764

Demand-Side Management (DSM) Data17

Actual Peak Load Reductions (megawatts)

Total Actual Peak Load Reduction ................ 31,682 31,735R 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455 27,231

DSM Energy Savings (thousand megawatthours)

Energy Efficiency.......................................... 76,891 74,861R 67,134 62,951 58,891 52,662 48,245 52,285 52,946 52,827 49,691 48,775

Load Management......................................... 1,015 1,813R 1,857 865 1,006 2,047 2,020 1,790 990 875 872 392

DSM Cost (million dollars)

Total Cost ................................................... 3,594 3,175R 2,523 2,051 1,921 1,557 1,297 1,626 1,630 1,565 1,424 1,421

 

 

1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste and synthetic coal are included starting in 2002. 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 Includes a small number of generators for which waste heat is the primary energy source.

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 5 Conventional hydroelectric power excluding pumped storage facilities.

6 Other renewables represents the summation of the sub-categories of Wind, Solar Thermal and Photovoltaic, Wood and Wood Derived Fuels, Geothermal, and Other Biomass. 7 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor. 8 Biogenic municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, 

methane, and other biomass gases).

9 Pumped storage is the capacity to generate electricity from water previously pumped to an elevated reservoir and then released through a conduit to turbine generators located at a lower 

level. The generation from a hydroelectric pumped storage facility is the net value of production minus the energy used for pumping.. 10 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies. 11 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and 

other biomass gases).
U.S. Energy Information Administration/Electric Power Annual 2009 11

 12 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies. 13 Anthracite, bituminous, subbituminous, lignite, and synthetic coal; excludes waste coal. 14 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). Data prior to 2004 includes small quantities of waste oil. 15 For 2002 through 2007, includes data from the Form EIA-423 for independent power producers, and commercial and industrial power-producing facilities. Beginning in 2008, data are

collected on the Form EIA-923 for utilities, independent power producers, and commercial and industrial power-producing facilities. Receipts, cost, and quality data are collected from

plants above a 50 MW threshold, and imputed for plants between 1 and 50 MW. Therefore, there may be a notable increase in fuel receipts beginning with 2008 data. Receipts of coal 

include imported coal.

16 Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. 17 Data presented are reflective of large utilities.

NA = Not available. 

R = Revised. 

Note: ·See Glossary reference for definitions.·See Technical Notes Table A5 for conversion to different units of measure.·Capacity by energy source is based on the capacity associated 

with the energy source reported as the most predominant (primary) one, where more than one energy source is associated with a generator.·Dual-fired capacity returned to respective fuel 

categories for current and all historical years. New fuel switchable capacity tables have replaced dual-fired breakouts.·Totals may not equal sum of components because of ind

Sources: U.S. Energy Information Administration Form EIA-411, "Coordinated Bulk Power Supply Program Report;" Form EIA-412, "Annual Electric Industry Financial Report" The 

Form EIA-412 was terminated in 2003; Form EIA-767, "Steam-Electric Plant Operation and Design Report" was suspended; Form EIA-860, "Annual Electric Generator Report;" Form 

EIA-861, "Annual Electric Power Industry Report;" Form EIA-923, "Power Plant Operations Report" replaces several form(s) including: Form EIA-906, "Power Plant Report;" Form EIA920 "Combined Heat and Power Plant Report;" Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report; and FERC Form 423, "Monthly Report of Cost and Quality 

of Fuels for Electric Plants," and their predecessor forms. Federal Energy 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;" Rural Utilities Service (RUS) Form 7, "Operating Report;" RUS Form 12, "Operating Report;" Imports and Exports: 

DOE, Office of Electricity Delivery and Energy Reliability, Form OE-781R, " Annual Report of International Electric Export/Import Data," predecessor forms, and National Energy Board 

of Canada. For 2001 forward, data from the California Independent System Operator are used in combination with the Form OE-781R values to estimate electricity trade with Mexico.
12 U.S. Energy Information Administration/Electric Power Annual 2009

Table ES2. Supply and Disposition of Electricity, 1998 through 2009

(Million Megawatthours)

Category 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Supply

Generation ..........................................................

 Electric Utilities.......................................... 2,373 2,475 2,504 2,484 2,475 2,505 2,462 2,549 2,630 3,015 3,174 3,212

 Independent Power Producers..................... 1,278 1,332 1,324 1,259 1,247 1,119 1,063 955 781 458 201 91

 Combined Heat and Power, Electric............ 159 167 177 165 180 184 196 194 170 165 155 154

 Electric Power Sector Generation Subtotal ....... 3,810 3,974 4,005 3,908 3,902 3,808 3,721 3,698 3,580 3,638 3,530 3,457

 Combined Heat and Power, Commercial..... 8 8 8 8 8 8 7 7 7 8 9 9

 Combined Heat and Power, Industrial......... 132 137 143 148 145 154 155 153 149 157 156 154

 Industrial and Commercial Generation Subtotal 140 145 151 157 153 162 162 160 157 165 165 163

Total Net Generation .......................................... 3,950 4,119 4,157 4,065 4,055 3,971 3,883 3,858 3,737 3,802 3,695 3,620

Total Imports ...................................................... 52 57 51 43 44R 34 30 37 39 49 43 40

Total Supply ...................................................... 4,002 4,176 4,208 4,107 4,099R 4,005 3,914 3,895 3,775 3,851 3,738 3,660

Disposition

 Retail Sales.......................................................

 Full-Service Providers................................. 3,289 3,434 3,468 3,438 3,413 3,318 3,285 3,324 3,297 3,310 3,236 3,240

 Energy-Only Providers................................ 296 286 283 219 237 222 189 141 98 112 76 24

 Facility Direct Retail Sales.......................... 13 14 14 12 11 8 20 NA NA NA NA NA

Total Electric Industry Retail Sales..................... 3,597 3,733 3,765 3,670 3,661 3,547 3,494 3,465 3,394 3,421 3,312 3,264

Direct Use........................................................... 127 132R 126R 147 150 168 168 166 163 171 172 161

Total Exports ...................................................... 18 24 20 24 19R 23 24 16 16 15 14 14

Losses and Unaccounted For .............................. 260 287R 298R 266 269 266 228 248 202 244 240 221

Total Disposition ............................................... 4,002 4,176 4,208 4,107 4,099R 4,005 3,914 3,895 3,775 3,851 3,738 3,660

NA = Not available. 

R = Revised. 

Notes: • Facility Direct Retail Sales typically represent bilateral electric power sales between industrial and commercial generating facilities. • Direct Use represents commercial and 

industrial facility use of onsite net electricity generation; electricity sales or transfers to adjacent or co-located facilities; and barter transactions. Losses and Unaccounted For includes: (1) 

reporting by utilities and power marketers that represent losses incurred in transmission and distribution, as well as volumes unaccounted for in their own energy balance; and (2) 

discrepancies among the differing categories upon balancing the table. • Totals may not equal sum of components because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-861, "Annual Electric Power Industry Report;" and predecessor forms. Imports 

and Exports: Mexico data - DOE, Fossil Fuels, Office of Fuels Programs, Form OE-781R, "Annual Report of International Electrical Export/Import Data:" Canada data - National Energy 

Board of Canada (metered energy firm and interruptible).