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Electric Power Annual

Electric Power Annual with data for 2009

Report Released: November 23, 2010

Report Revised: January 4, 2011

Next Release Date: November 2011

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 decades 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.

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.

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. 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.

NOx and SO2 emissions from electric power plants declined 28.1 and 23.8 percent,

respectively (Table 3.9) in 2009. For coal-fired 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.

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. , 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.

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. 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.

(Printer-friendly version )

Tables by Chapter Formats

Year in Review Chap. 1 Chap. 2 Chap. 3 Chap. 4

Chap. 5 Chap. 6 Chap. 7 Chap. 8 Chap. 9

Appendices Figures Back Issues

Electric Power Industry: Year in Review pdf

Summary Statistics

ES1. Summary Statistics for the United

States html xls pdf

ES2. Supply and Disposition of Electricity html xls pdf

Chapter 1. Capacity pdf

Existing

1.1. Net Summer Capacity by Energy Source

and Producer Type html xls pdf

1.1.A. Net Summer Capacity of Other

Renewables by Producer Type html xls pdf

1.2. Capacity by Energy Source html xls pdf

1.3. Capacity by Producer Type html xls pdf

Planned

1.4. Generating Capacity Additions from New

Generators, by Energy Source html xls pdf

1.5. Capacity Additions, Retirements and

Changes by Energy Source html xls pdf

Capacity of

1.6.A. Dispersed Generators by Technology

Type html xls pdf

1.6.B. Distributed Generators by Technology

Type html xls pdf

1.6.C. Total Capacity of Dispersed and

Distributed Generators by Technology Type html xls pdf

Fuel-Switching Capacity of

1.7. Generators Reporting Natural Gas as

the Primary Fuel, by Producer Type html xls pdf

1.8. Generators Reporting Petroleum Liquids

as the Primary Fuel, by Producer Type html xls pdf

1.9. Fuel-Switching Capacity: From Natural

Gas to Petroleum Liquids, by Type of Prime

Mover

html xls pdf

1.10. Fuel-Switching Capacity: From Natural

Gas to Petroleum Liquids, by Year of Initial

Commercial Operation

html xls pdf

Interconnection Cost and Capacity for New Generators,

1.11. by Producer Type html xls pdf

1.12. Interconnection Cost and Capacity for

New Generators, by Grid Voltage Class html xls pdf

Chapter 2. Generation and Useful Thermal

Output pdf

Net Generation by

2.1. Energy Source by Type of Producer html xls pdf

2.1.A. Selected Renewables by Type of

Producer html xls pdf

2.2. Useful Thermal Output by Energy Source

by Combined Heat and Power Producers html xls pdf

Chapter 3. Fuel and Emissions pdf

Consumption of Fossil Fuels for

3.1. Electricity Generation by Type of Power

Producer html xls pdf

3.2. Useful Thermal Output by Type of

Combined Heat and Power Producers html xls pdf

3.3. Electricity Generation and for Useful

Thermal Output html xls pdf

3.4. End-of-Year Stocks of Coal and

Petroleum by Type of Producer html xls pdf

3.5. Receipts, Average Cost, and Quality of

Fossil Fuels for the Electric Power Industry html xls pdf

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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.

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). 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. US Electric Power Industry Net Generation, 2009

Sources: U.S. Energy Information Administration, Form EIA-923, "Pow er 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

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.

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. 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

Fossil Fuels for the Electric Power Industry

3.6. Receipts and Quality of Coal Delivered

for the Electric Power Industry html xls pdf

3.7. Average Quality of Fossil Fuel Receipts

for the Electric Power Industry html xls pdf

3.8. Weighted Average Cost of Fossil Fuels

for the Electric Power Industry html xls pdf

3.9. Emissions from Energy Consumption at

Conventional Power Plants and CombinedHeat-and-Power Plantshtml xls pdf

3.10. Number and Capacity of Fossil-Fuel

Steam-Electric Generators with

Environmental Equipment

html xls pdf

3.11. Average Flue Gas Desulfurization

Costs html xls pdf

Chapter 4. Demand, Capacity Resources,

and Capacity Margins pdf

4.1. Noncoincident Peak Load, Actual and

Projected by North American Electric

Reliability Corporation Region

html xls pdf

Net Internal Demand

4.2. Capacity Resources, and Capacity

Margins by North American Electric Reliability

Corporation Region, Summer

html xls pdf

4.3. Actual or Planned Capacity Resources,

and Capacity Margins by North American

Electric Reliability Corporation Region,

Summer

html xls pdf

4.4. Actual or Planned Capacity Resources,

and Capacity Margins by North American

Electric Reliability Corporation Region,

Winter

html xls pdf

Chapter 5. Characteristics of the Electric

Power Industry

pdf

5.1. Count of Electric Power Industry Power

Plants, by Sector, by Predominant Energy

Sources within Plant

html xls pdf

Average

5.2. Capacity Factors by Energy Source html xls pdf

5.3. Operating Heat Rate for Selected Energy

Sources html xls pdf

5.4. Heat Rates by Prime Mover and Energy

Source html xls pdf

5.5. Planned Transmission Capacity

Additions, by High-Voltage Size html xls pdf

Chapter 6. Trade pdf

Electric Power Industry

6.1. Electricity Purchases html xls pdf

6.2. Electricity Sales for Resale html xls pdf

6.3. U.S. Electricity Imports from and

Electricity Exports to Canada and Mexico html xls pdf

Chapter 7. Retail Customers, Sales, and

Revenue pdf

7.1. Number of Ultimate Customers Served

by Sector, by Provider html xls pdf

7.2. Retail Sales and Direct Use of Electricity

to Ultimate Customers by Sector, by Provider html xls pdf

7.3. Revenue from Retail Sales of Electricity

to Ultimate Customers by Sector, by Provider html xls pdf

7.4. Average Retail Price of Electricity to

Ultimate Customers by End-Use Sector html xls pdf

7.5. Net Metering and Green Pricing

Customers by End Use Sector html xls pdf

Chapter 8. Revenue and Expense Statistics pdf

8.1. Revenue and Expense Statistics for

Major U.S. Investor-Owned Electric Utilities html xls pdf

8.2. Average Power Plant Operating

Expenses for Major U.S. Investor-Owned

Electric Utilities

html xls pdf

Revenue and Expense Statistics for

8.3. Major U.S. Publicly Owned Electric

Utilities (With Generation Facilities) html xls pdf

8.4. Major U.S. Publicly Owned Electric

Utilities (Without Generation Facilities) html xls pdf

8.5. U.S. Federally Owned Electric Utilities html xls pdf

8.6. U.S. Cooperative Borrower Owned

Electric Utilities html xls pdf

Chapter 9. Demand-Side Management pdf

9.1. Demand-Side Management Actual Peak

Load Reductions by Program Category html xls pdf

Demand-Side Management Program

9.2. Annual Effects by Program Category html xls pdf

9.3. Incremental Effects by Program Category html xls pdf

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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.

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 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, 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 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), 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 coal-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 ES 2. U.S. Electric Power Industry Net Summer Capacity, 2009

9.4. Annual Effects by Sector html xls pdf

9.5. Incremental Effects by Sector html xls pdf

9.6. Energy Savings html xls pdf

9.7. Direct and Indirect Costs html xls pdf

Appendices pdf

Appendix A. Technical Notes

A1. Sulfur Dioxide Uncontrolled Emission

Factors

html xls pdf

A2. Nitrogen Oxide Uncontrolled Emission

Factors html xls pdf

A3. Carbon Dioxide Uncontrolled Emission

Factors html xls pdf

A4. Nitrogen Oxide Control Technology

Emissions Reduction Factors html xls pdf

A5. Unit-of-Measure Equivalents html xls pdf

Illustrations

U.S. Electric Power Industry

Figure ES.1 Net Generation html pdf

Figure ES.2 Net Summer Capacity html pdf

Figure ES.3 Planned Capacity Additions html pdf

Figure ES.4 Annual Change in Retail Sales

to Bundled and Unbundled Customers html pdf

Figure ES.5 Fossil Fuel Costs for Electricity

Generation html pdf

Figure 1.1 Generating Capacity by State html pdf

Figure 2.1 Net Generation by State html pdf

Figure 4.1 Historical North American Electric

Reliability Council Regions for the

Contiguous U.S.

html pdf

Figure 4.2 Consolidated North American

Electric Reliability Corporation Regional

Entities

html pdf

Figure 7.1 Total Ultimate Customers by State html pdf

Figure 7.2 Total Retail Sales by State html pdf

Figure 7.3 Total Revenues by State html pdf

Figure 7.4 Average Retail Price of Electricity

by State html pdf

Figure 7.5 Average Residential Price of

Electricity by State html pdf

Figure 7.6 Average Commercial Price of

Electricity by State html pdf

Figure 7.7 Average Industrial Price of

Electricity by State html pdf

Appendix A. EIA Electric Industry Data

Collection html pdf

EPA Back Issues

Back Issues pdf

Historical Spreadsheets - Annual 1990 to 2009 xls

Historical Spreadsheets - Monthly 2001 to present xls

Related Links

Electricity Database Files dbf

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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.

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 plant in the world (at the time), 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. 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. 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.

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.

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).

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.

Figure ES 3. Planned Capacity Additions, 2010-2014

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

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. 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.

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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 Pow er Industry Report."

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. This dampened air conditioning demand; for the June through

August summer period, residential electricity sales declined 3.3 percent between 2008 and 2009.

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. 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.

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). Canada is

the second largest exporter of electricity in the world, primarily generated by hydroelectric plants in Quebec, Ontario, and British Columbia. 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. 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.

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.

Figure ES5. Fossil Fuel Costs for Electricity Generation, 1998-2009

Source: U.S. Energy Information Administration, Form EIA-923, "Pow er Plant Operations Report."

Emissions

Decreases in all emissions. Estimated emissions of carbon dioxide (CO2

), sulfur dioxide (SO2), and nitrogen oxide (NOx) all declined in 2009 compared to

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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 yearover-year decline since 1989 (the 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.

The U.S. Energy Information Administration's historic electricity generation data goes back to 1949.

U.S. Department of Commerce Bureau of Economic Analysis, New s Release: Gross Domestic Product: Second Quarter 2010 (Third Estimate), Table 1.

U.S. Federal Reserve Bank, Industrial Production and Capacity Utilization, (Table 11).

The U.S. Energy Information Administration has been estimating CO2, NOX, and SO2 emissions since 1989.

U.S. Energy Information Administration, Natural Gas Year-in-Review , 2009

U.S. Energy Information Administration, U.S. Coal Supply and Demand: 2009 "Coal Prices", p. 12

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

dow nw ard in 2009. How ever, the low er 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.

U.S. Energy Information Administration, Annual Energy Review , 2009, Table 6.5.

The grant program arose out of Section 1603 of the American Economic Recovery and Reinvestment Act of 2009 (ARRA) and w as intended to allow investors w ho could not take advantage of tax

credits to fund these projects w ith an equivalent government grants. This program expires December 31, 2010. See the Database of State Incentives for Renew ables and Efficiency (DSIRE) at

http://w w w .dsireusa.org/incentives/incentive.cfm?Incentive_Code=US53F&re=1&ee=1

See the DSIRE database at http://w w w .dsireusa.org/.

U.S. Energy Information Administration .,Annual Coal Report, 2008 and 2009, Table 6.

Bonneville Pow er Administration, 2009 Annual Report, (10-K), p. 9. Melting snow creates much of BPA's runoff. Snow pack in the mountains accumulates from December to February

(approximately), and significant runoff, and therefore peak hydro production, occurs March through July (approximately).

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

Despite representing only three quarters of the capacity of natural gas plants, coal plants account for approximately tw ice the amount of electricity produced by natural gas plants (Table ES.1)

As of the end of 2009 Texas had 76 w ind plants comprising 9.1 percent of overall Texas electricity capacity. In 2005, Texas adopted a RPS w hich required the state to have 5,880 MW of total

renew able capacity in place by 2015, and 10,000 MW by 2025. Texas is very close to meeting the 2025 standard w ith its w ind capacity alone.

"Progress Energy Plans to Retire Remaining Unscrubbed Coal Plants in NC," December 1, 2009.

FPL. http://w w w .fpl.com/environment/solar/desoto.shtml.

Todd Woody, "Solar Pow er Projects Face Potential Hurdles," The New York Times, October 28, 2010, http://w w w .nytimes.com/2010/10/29/business/energy-environment/29solar.html?

_r=1&scp=1&sq=ivanpah&st=cse.

TVA's Brow n Ferry 1 w as offline for many years but w as officially classified as "operable" because it retained a Nuclear Regulatory Commission operating license. The unit actually returned to

service in 2007.

Other investors include Oglethorpe Pow er (30 percent) and the Municipal Electric Authority of Georgia (22.7 percent). Source: World Nuclear New s, "Georgia Pow er Accepts Vogtle Loan

Guarantee," June 21, 2010.

U.S. Energy Information Administration, Electric Pow er Monthly, Table ES3, New and Planned U.S. Electric Generating Units.

IHS Global Insight, "U.S. Economic Outlook," April 2010, p. 92.

National Oceanic & Atmospheric Administration, National Data Climate Center, State of the Climate National Overview Annual 2009

A single "block" of electricity can be sold multiple times, w ith each purchase appearing in the data reported to EIA. Consequently, total w holesale purchases exceed total supply of electricity (3,950

million MWh in 2009).

U.S. Energy Information Administration, International Energy Statistics, http://w w w .eia.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.

North America Energy Working Group, Security and Prosperity Partnership, Energy Picture Experts Group, "North America—The Energy Picture II," January 2006.

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.

Duke Energy Carolinas, Docket No. E-7, Sub 909, and Indiana Utility Regulatory Commission, Cause No. 38707 FAC 83, Approved March 24, 2010,

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

Contact:

Orhan Yildiz

Email: Orhan Yildiz

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