Electric Power Industry 2008: Year in Review

Overview

In 2008, electricity generation and sales were adversely affected by the weakening economy.  Annual net electric power generation decreased for the first time since 2001, dropping 0.9 percent from 4,157 million megawatthours (MWh) in 2007 to 4,119 million MWh in 2008.  Summer peak load (noncoincident) fell by 3.8 percent, from 782,227 megawatts (MW) in 2007 to 752,470 MW in 2008. Winter peak load (noncoincident), which is always smaller than summer peak load, increased in 2008 by 0.9 percent, from 637,905 MW in 2007 to 643,557 MW in 2008. Nationally, the contiguous U.S. experienced an average temperature that was the coolest in more than ten years.¹

Fossil fuel prices showed significant volatility during 2008.  Natural gas spot prices as delivered to electric plants were $8.27 per MMBtu in January, rose to $12.14 per MMBtu in June, and fell to $6.36 per MMBtu in November.  The overall 27.2-percent increase in average fossil fuel costs delivered to electric plants from 2007 contributed to the 6.7-percent increase in average retail electricity prices, from 9.1 to 9.7 cents per kilowatthour (kWh).  Between 2004 and 2008, the average price of fossil fuels delivered to electric plants increased a cumulative 65.7 percent.  Over the same time period, the national average retail price of electricity increased 28.0 percent, from 7.6 cents per kWh in 2004 to 9.7 cents per kWh in 2008.

While electricity generation from the primary fuel sources decreased in 2008 (coal by 1.5 percent, natural gas by 1.5 percent, and nuclear by 0.03 percent), generation from all renewable sources increased, with the exception of wood and wood derived fuels.  Most notably, wind generation increased 60.7 percent, from 34.5 million MWh in 2007 to 55.4 million MWh in 2008.  For the first time, wind generation constituted a larger share of total electric generation than either petroleum or wood and wood-derived fuels.  At the time of this writing, 24 States have put in place Renewable Portfolio Standards and five additional States have nonbinding goals for renewable energy.² Several pieces of recently enacted Federal legislation have also offered substantial financial incentives for renewable electricity production.

In 2008, total net summer generating capacity increased 15,283 MW, a gain of 1.5 percent over 2007. New wind capacity accounted for 53.2 percent of that increase, with 8,136 MW installed during 2008. Wind net summer capacity increased 49.3 percent from 2007 to 2008. New natural gas-fired capacity of 4,556 MW accounted for 29.8 percent of the total net capacity increase. Natural-gas fired capacity additions have been declining since a peak in 2002.

The capacity factor for combined cycle natural gas units increased from 33.5 percent in 2003 to 42.0 percent in 2007, and then fell slightly to 40.7 percent in 2008. The overall improvement in the average capacity factor since 2003 reflects both the increased reliance on combined cycle generation to meet energy requirements and further efficiency gains in combined cycle generation technology. Nuclear and coal-fired generation had the highest average capacity factors at 91.1 percent and 72.2 percent, respectively, in 2008.

Estimated U.S. electric power plant carbon dioxide emissions fell 2.5 percent from 2007 to 2008, from 2,540 million metric tons to 2,477 million metric tons, largely due to decreased fuel consumption.  Sulfur dioxide (SO2) emissions fell 13.4 percent, from 9.0 to 7.8 million metric tons, between 2007 and 2008. This amounts to the largest year-over-year decline since 1995.   The large reductions in SO2 in 2008 result in part from a decline in fuel consumption but mostly from the installation of emissions reduction equipment in response to the Environmental Protection Agency’s Clean Air Interstate Rule (see Emissions section).  2008 data also show significant reductions to emissions of nitrogen oxides (NOx), which dropped 8.8 percent, from 3.7 to 3.3 million metric tons.  Since 1997, sulfur dioxide and nitrogen oxide emissions declined by 41.9 percent and 48.8 percent, respectively.

Generation

Net generation of electric power fell 0.9 percent in 2008, to 4,119 million megawatthours (MWh) from 4,157 million MWh in 2007 (Figure ES1). According to the Bureau of Economic Analysis, the real U.S. gross domestic product increased 0.4 percent in 2008.³ The Federal Reserve Board, however, reported a 2.2 percent decrease in total industrial production.⁴ The National Oceanic and Atmospheric Administration (NOAA) reported that 2008 was the “coolest year in more than ten years.” Heating degree days in 2008 were 5.6 percent higher, while cooling degree days were 8.7 percent lower than they were in 2007. NOAA’s Residential Demand Temperature Index⁵ was 33.0 percent higher in 2008 than it was in 2007. The combination of weak economic activity and reduced summer electricity demand for cooling appears to have contributed to the 0.9 percent decrease in net generation, as compared with the 2.3 percent increase observed in 2007.

Figure ES1. US Electric Power Industry Net Generation, 2008

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report.”

The three primary energy sources for generating electric power in the United States, coal, natural gas, and nuclear energy, consistently provided between 85.0 and 89.5 percent of total net generation during the period 1997 through 2008 (Table 2.1). Petroleum’s relative share of total net generation was down to 1.1 percent in 2008. Although conventional hydroelectric power’s share of generation was up slightly in 2008, the general trend of this share is one of decline. In 2008, generation from conventional hydroelectric plants accounted for 6.2 percent of total net generation, as compared to 10.2 percent in 1997. Excluding conventional hydroelectric, renewable energy sources contributed 3.1 percent of total net electric generation in 2008, up from 2.5 percent in 2007. This marks the fifth consecutive year in which this category’s share of total net generation has increased, and the first time it crossed the three percent threshold. The largest portion of this increase comes from wind generation, which increased from 0.8 percent to 1.3 percent of total net electric generation.

In 2008, electricity generation from coal-fired capacity fell 1.5 percent. Coal-fired generation decreased from 2,016 million MWh in 2007 to 1,986 million MWh in 2008, the lowest coal-fired generation total since 2004. Declines in Pennsylvania, Georgia, North Carolina, and Virginia accounted for 57.8 percent of the national decline. Issues involving individual plants played a key role in the regional decline. In Pennsylvania, 45.4 percent of the drop in coal-fired generation can be attributed to the Homer City plant. Generation at Homer City was down 17.1 percent from its total in 2007, due in part to maintenance outages and economic dispatch. In North Carolina, the Marshall plant’s coal-fired generation level was 13.9 percent lower than it was in 2007. This drop accounted for almost half – 49.4 percent – of the decrease in North Carolina’s coal-fired electricity production.

Coal’s share of total net generation continued its downward trend, accounting for 48.2 percent in 2008 as compared to 48.5 percent in 2007 and 52.8 percent in 1997. Nevertheless, providing 1,986 million MWh, it remains the primary source of baseload generation in the United States.

Following a decade of solid growth, natural gas has increased its share of the electricity market from 13.7 percent in 1997 to 21.4 percent in 2008. Net generation from natural gas-fired capacity fell 1.5 percent, from 897 million MWh in 2007 to 883 million MWh in 2008, the first drop in natural gas-fired generation since 2003. Natural gas-fired generation accounted for 21.4 percent of total net generation in 2008, down from 21.6 percent in 2007. Despite the decrease, natural-gas fired generation was the second leading contributor to total net generation for the third consecutive year, surpassing nuclear generation, which had a 19.6 percent share of total net generation.

Net generation at nuclear plants was down fractionally in 2008 to 806.2 million MWh from 806.4 million MWh. Between 1997 and 2008, the nuclear share of total net generation ranged from a low of 18.0 percent to a high of 20.6 percent, with an annual average growth of 2.3 percent, despite the fact that no new nuclear units have been constructed. Since 1997, average capacity factors for nuclear plants increased from 72.0 percent to 91.8 percent in 2007 (Table 5.3). In 2008, however, the capacity factor for nuclear plants was down slightly to 91.1 percent. In past years, growth in nuclear generation was the result of both improved capacity factors and uprates of existing plants. The net summer capacity of nuclear plants increased due to uprates in 2008 by 489 MW, continuing the overall upward trend. From 1998 through 2008, net summer capacity of existing nuclear plants increased by 3,685 MW.

Net generation from renewable energy sources, excluding conventional hydroelectric generation, increased 19.9 percent in 2008, following an increase of 9.0 percent in 2007 (Table 2.1a). A large part of this growth was due to increased wind generation, which totaled 55.4 million MWh, or 1.3 percent of total net generation. For the first time, wind generation constituted a larger share than biomass, and also a larger share than petroleum. The top 5 wind-generating States were Texas, California, Minnesota, Iowa, and Washington. Texas, where wind generation was up 80.2 percent in 2008, was by far the largest source of wind generation with more than three times that of California, the Nation’s second-largest provider. Nationally, wind generation increased 60.7 percent from its 2007 level. 72.6 percent of the national increase was accounted for by increases in Texas, Colorado, Minnesota, Illinois, Oregon, and Iowa. Wood and wood-derived fuels, representing 0.9 percent of total net generation, accounted for 37 million MWh, down 4.4 percent from 2007. Geothermal power plants supplied 15 million MWh of net generation and other biomass plants generated 18 million MWh; each of these renewable sources accounted for approximately 0.4 percent of total net generation in 2008. Generation from solar thermal and photovoltaic sources was up 41.2 percent from 2007, at 864 thousand MWh. Wood and wood derived fuels and geothermal have maintained fairly stable output levels since 1997, averaging 38 million MWh and 15 million MWh per year, respectively. Other biomass generation has declined from a 23 million MWh peak in 2000 to 18 million MWh in 2008.

Net generation from conventional hydroelectric plants was up 3.0 percent from 248 million MWh in 2007 to 255 million MWh in 2008. Declines in California and Washington were offset by increases in Alabama, New York, and Arkansas. According to the National Climatic Data Center (NCDC), Arkansas had its sixth wettest spring on record in 2008. The largest increase in hydroelectric generation at a single plant in the United States was at the Bull Shoals facility in Arkansas. The absolute rise in hydroelectric generation at the Bull Shoals plant alone exceeded the increase at any other plant nationwide, as well as the increase in every other State (outside of Arkansas), except for Alabama and New York. In the West, March-October 2008 was the driest such eight-month period on record for California and Nevada, according to the NCDC. The largest drop at a single hydroelectric plant in the United States occurred at California’s Edward C. Hyatt plant. The absolute decrease at Edward C. Hyatt exceeded the decreases in hydroelectric generation in every other State outside of California, other than Washington.

Largely due to a sharp rise in oil prices, petroleum-fired generation fell 29.7 percent, to 46 million MWh. Its share of total net generation dropped to 1.1 percent.

Fossil Fuel Stocks at Electric Power Plants

End-of-year coal stocks for 2008 increased 6.9 percent from 151 million tons to 162 million tons (Table 3.4). The 2008 build in coal stocks was similar to the 7.3 percent increase that occurred in 2007, with both considerably less than the 39.4 percent increase in 2006. The increase in 2008 appears to be the result of the decrease in coal-fired generation and the concomitant drop in coal consumption compared to 2007, as well as an increase in receipts of coal at electric power sector facilities The increase in end-of-year stocks is consistent with the finding in the North American Electric Reliability Corporation’s (NERC) 2008/2009 Winter Reliability Assessment⁶ that power plant inventories “appear[ed] to be sufficient going into the winter, particularly with the softening of the international markets that will reduce exports and make importing coal economic again.”

Inventories of petroleum fell 5.7 percent from 47.2 million barrels at the end of 2007 to 44.5 million barrels at the end of 2008. This was the lowest end-of-year petroleum stock level since 2000, when stocks plummeted 24.4 percent from their 1999 year-end level.

Fuel Consumption

Consumption of fossil fuels for electricity generation decreased 0.4 percent (coal), 28.1 percent (petroleum), and 2.7 percent (natural gas) in 2008 (Table 3.1). This tracks with the similar pattern of decreases in generation for the same year: a 1.5 percent decrease in coal generation, 29.7 percent decrease in generation from petroleum, and 1.5 percent decrease in natural gas generation.

Consumption of fossil fuels by combined heat and power plants for useful thermal output is shown in Table 3.2.⁷ Industrial and commercial power producers generally constitute a larger share of fuel consumption for useful thermal output than consumption for electricity generation. Commercial and industrial concerns showed more sensitivity to the weakened economy in 2008 than utilities: fossil fuel consumption for useful thermal output decreased 2.8 percent for coal, 39.2 percent for petroleum, and 9.1 percent for natural gas.

Capacity

Total U.S. net summer generating capacity as of December 31, 2008 was 1,010,171 MW (Figure ES2, Table 1.1), an increase of 1.5 percent from December 31, 2007. During the year, net summer generating capacity increased 15,283 MW, after accounting for retirements, deratings (reductions in power plant generating capability) and other adjustments. For the second year in a row, the net increase to renewable, non-hydroelectric capacity exceeded the net increase to fossil fuel capacity (counting retirements). New wind capacity made up the majority (53.2 percent) of the net summer capacity increase, at 8,136 MW. More new wind capacity came online in 2008 than in the prior two years combined. For most of the past decade, natural gas has been the preferred fuel for new generating capacity. However, in 2008, natural gas-fired generating units accounted for 4,556 MW, or 29.8 percent of the net increase in capacity.

Figure ES2. U.S. Electric Power Industry Net Summer Capacity, 2008

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

As of December 31, 2008, wind generating capacity totaled 24,651 MW, a 49.3 percent increase over the 16,515 MW in operation at the end of 2007 (Table 1.1a). Texas continues to lead the Nation in wind power development with 2,938 MW of new wind capacity placed in service during 2008, increasing its share of the Nation’s wind capacity currently in operation to 30.1 percent. Iowa has the second highest share of total installed wind generating capacity at 2,635 MW. The remainder of the top five wind-producing States are California at 9.6 percent, Minnesota at 5.9 percent and Washington at 5.5 percent of the Nation’s total installed wind generating capacity. Collectively, 15,255 MW or 61.9 percent of total wind generating capacity is located in these 5 States. The States with the biggest increases in wind capacity in 2008 over 2007 include Michigan, South Dakota, Wisconsin, and West Virginia, all with a more than 200-percent increase. The States reporting wind capacity for the first time in 2008 include Indiana, New Hampshire, and Utah, with 130.5, 24.0, and 18.9 MW, respectively. Over the last three years 15,945 MW of wind generating capacity has been placed in service. The overall electric generating capacity from non-hydroelectric renewable energy sources increased 28.0 percent in 2008 to 38,493 MW (Figure ES2), with the additional wind capacity of 8,136 MW accounting for 96.6 percent of the increase.

Natural gas-fired generating capacity represented 397,432 MW or 39.3 percent of total net summer generating capacity in 2008. Although new natural gas-fired combined-cycle plants produce electricity more efficiently than older fossil-fueled plants, high natural gas prices can work against full utilization of these plants if such prices adversely affect economic dispatch. Since 1997, net summer natural gas-fired capacity increased by 220,961 MW, net of retirements and adjustments. As a result, natural gas capacity additions were almost equivalent to the 231,522 MW total increase in net summer capacity over the same time period. In contrast, coal, petroleum and nuclear capacity realized a combined decrease of 14,281 MW over the same time period. The net capacity increase of 24,843 MW from renewables, including hydro, other gases, and other sources accounts for the remainder of the additions since 1997.

Coal-fired generating capacity increased slightly in 2008 to 313,322 MW, or 31.0 percent of total generating capacity. This share of total capacity represents a 0.4 percentage point decline from 2007 (31.4 percent). Retirements of existing coal-fired net summer capacity reported by operators totaled 764 MW, while 1,482 MW were added during the year. This additional capacity is attributed to 2 existing plants and 3 new plants placed in service in 2008. Since 1997, net summer coal-fired capacity has declined 302 MW, after accounting for new additions, upgrades and other adjustments. Nevertheless, net generation from the Nation’s coal-fired plants continues to increase due to gains in operating efficiency.

Nuclear net summer generating capacity totaled 100,755 MW or 10.0 percent of total capacity. Uprates totaling 383 MW of nameplate capacity were completed at the Three Mile Island plant in Pennsylvania, the Clinton Power Station and the Braidwood Generation Station in Illinois, as well as the Prairie Island and Monticello plants in Minnesota. Nuclear plant operators reported that net summer capacity increased by 489 MW and net winter capacity increased by 729 MW.

Conventional hydroelectric generating capacity accounted for 7.7 percent of total capacity with a summer net generating capacity of 77,930 MW. Pumped storage hydroelectric generating capacity totaled 21,858 MW. Combined, conventional and pumped storage generating capacity accounted for 9.9 percent of total capacity. Like coal and nuclear, hydroelectric generating capacity has remained relatively unchanged over the last 10 years.

Petroleum-fired capacity totaled 57,445 MW, up 1,377 MW (or 2.5 percent) from 2007. Petroleum-fired capacity accounted for 5.7 percent of all generating capacity.

As of December 31, 2008, additions with a total nameplate capacity of 87,966 MW are scheduled to start commercial operation between 2009 and 2013 (Table 1.4). This compares with 92,996 MW of planned capacity reported on December 31, 2007, for the 5-year period through 2012. The data also show that over the next two years there will be a notable increase in planned additions relative to the past 2 years, if additions are completed as planned. In 2007 and 2008, the industry added 34,088 MW of nameplate capacity. Planned capacity additions to be placed in service during calendar years 2009 and 2010 total 46,940 MW. However, the weak economy, which has limited access to credit and capital, and lower demand may defer the installation of some of this capacity.

Capacity planning data also reveal an ongoing shift in the fuel mix. Natural gas, coal, and wind additions are projected to play a significant role over the next 5 years. The industry reports that it is planning to add 45,541 MW of natural-gas fired capacity. These planned additions account for 51.8 percent of planned additions over the next 5 years, and are projected to increase the overall natural gas-fired capacity by 10.0 percent. Over the same period, 21,340 MW of coal-fired capacity are planned. This amount represents 24.3 percent of total planned additions and is equivalent to 6.3 percent of existing coal-fired capacity. The Watts Bar Unit 2 nuclear reactor is planned for operation in 2012, adding 1,270 MW of nuclear capacity. This will be the first new reactor to go online since 1995.⁸ Planned wind additions are projected to be 13,650 MW, or 15.5 percent of total additions, and would increase 2008 installed wind capacity by 54.6 percent. Planned solar additions, though only 2.2 percent of total planned additions, are notable in that the projected increase of 1,938 MW will expand the 2008 installed solar capacity by 360 percent.

As expected, nuclear and coal-fired plants have the highest average capacity factors at 91.1 percent and 72.2 percent, respectively (Figure ES3, Table 5.3)). This is consistent with the economies of scale that these forms of capital-intensive baseload generating plants provide. The average capacity factor for coal-fired generation reflects a 1.4-percentage point decrease from the 73.6 percent average capacity factor achieved in 2007. The average capacity factor for nuclear generation decreased from 91.8 percent to 91.1 percent. This compares to the 90.4 percent average over the past five years and the low of 72.0 percent that occurred in 1997. Because the industry continues to rely on new combined cycle natural gas generation to meet rising demand, the average capacity factor⁹ rose from 33.5 percent in 2003 to 42.0 percent in 2007, falling off slightly to 40.7 percent in 2008. The 8.5 percentage point improvement in the average capacity factor reflects both the increased reliance on combined cycle generation to meet energy requirements and further efficiency gains in combined cycle generation technology. In 2008 the average capacity factor for simple cycle natural gas-fired generation was 10.6 percent.

Figure ES3. Average Capacity Factor by Energy Source, 2008

Source: U.S. Energy Information Administration, Form EIA-860, “Annual Electric Generator Report;” Form EIA-923, "Power Plant Operations Report.”

The increases in installed wind capacity are reflected in the reduced performance of renewable resources in aggregate, as measured by a composite capacity factor. The variable, intermittent nature of wind as an energy source leads to a low capacity factor relative to biomass, as wind is only available for generation subject to prevailing wind conditions. Renewable generation other than hydroelectric had a 37.3-percent capacity factor in 2008. This is a significant decrease from the 59.1 percent achieved in 2000, at which time the category was dominated by wood, wood-derived fuels, and other biomass, all of which are dispatchable energy sources. The continuous decline in the average capacity factor for all non-hydroelectric renewable resources is consistent with the significant growth of wind capacity relative to other forms of renewable electricity generation.

Fuel Switching Capacity

The total amount of net summer capacity reporting natural gas as the primary fuel in 2008 was 397,432 MW, of which 119,899 MW (30.2 percent) reported the operational capability as “switchable” between natural gas and oil. The requirement for this operational capability is that the capacity had (in working order) all necessary fuel switching equipment, including fuel storage. However, most of this capacity is subject to environmental regulatory limits on the use of oil, e.g., a restriction on how many hours per year a unit is allowed to burn oil. Of the 119,899 MW of gas-fired capacity that reported the ability to switch to oil, only 38,020 MW (31.7 percent) reported no environmental regulatory constraints or other factors limiting oil-fired operations (Table 1.9).

Fuel-switchable capacity is spread across the major generating technologies. Combustion turbine peaking units account for 44.9 percent (53,859 MW) of this net summer capacity. Steam generators (28,766 MW) and combined cycle units (36,339 MW) account for 24.0 percent and 30.3 percent of total switchable capacity, respectively. Internal combustion engines make up the remaining 0.8 percent. Of the total steam-electric switchable generating capacity, 16,777 MW can burn oil with no limiting factors. Similarly, for gas turbines, 15,167 MW of the total switchable capacity can switch fuels to oil without restriction.

Interconnection Costs

During 2008, 356 generators representing a total nameplate capacity of 16,947 MW were connected for the first time to the electric grid. Interconnection costs are presented by producer type (Table 1.11) and by voltage class (Table 1.12). Total cost for each individual generator interconnection varies based on its components. In turn, the components of the total cost may vary based on whether or not interconnection infrastructure was already in place, the type of equipment for which costs were incurred, or other factors associated with the relevant generator technology. Though the amount of capacity connected to the grid was about the same for both independent power producers (IPP) and electric utilities, the total cost for the IPP sector, as well as the cost per MW, was significantly greater. This was due in part to the high interconnection costs from new wind plants, which are typically sited in relatively remote locations, thereby requiring the construction of longer transmission line extensions than might be required for conventional power plants.

Fuel Costs

The 2008 average delivered cost for all fossil fuels used at electric power plants (coal, petroleum, and natural gas combined) for electricity generation was $4.11 per million British thermal units (MMBtu) (Figure ES4, Table 3.5), an increase of 27.2 percent over the average delivered cost of $3.23 per MMBtu in 2007. This is the largest increase since 2005. All fossil fuel prices increased in 2008. The cost of natural gas delivered to electric power plants increased 26.9 percent, from $7.11 per MMBtu in 2007 to $9.02 per MMBtu in 2008. Annually, there have been larger increases (e.g., the 51.4 percent increase between 2002 and 2003), but 2008 was a particularly volatile year for natural gas prices, which spiked in the summer of 2008. The average daily spot price at Henry Hub¹⁰ peaked at $13.28 per MMBtu on July 2, and was down to $5.71 per MMBtu by December 31st. Petroleum costs followed a similar pattern in 2008, with a nationwide annual increase of 51.5 percent, from $7.17 MMBtu in 2007 to $10.87 per MMBtu in 2008. As a result, petroleum-fired generation was down 29.6 percent in 2008.

Figure ES4. Fuel Costs for Electricity Generation, 1997- 2008

Source: U.S. Energy Information Administration, Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report," Federal Energy Regulatory Commission (FERC), Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants," Form EIA-860, “Annual Electric Generator Report;” Form EIA-923, "Power Plant Operations Report.”

The 2008 delivered cost of coal increased 16.9 percent nationwide, from $1.77 per MMBtu in 2007 to $2.07 MMBtu in 2008. This marked the eighth straight year that coal prices have increased. Since 2000 the delivered cost of coal has increased 72.5 percent (Figure ES4). Every Census Division saw increases in coal costs in 2008, with the exception of the Pacific Noncontiguous Division, as Alaska produces its own coal while Hawaii relies on imported coal. The South Atlantic and East South Central Divisions, which rely heavily on the higher-price Appalachian coal, saw the largest coal cost increases. In the South Atlantic, the delivered cost of coal increased 22.1 percent, from $2.38 per MMBtu in 2007 to $2.91 per MMBtu in 2008. In the East South Central, costs increased to $2.41 per MMBtu in 2008.

Emissions

The estimated carbon dioxide (CO2), sulfur dioxide (SO2), and nitrogen oxide (NOx) emissions for electricity are based on the type and quantity of fossil fuels consumed by electric power plants for the generation of electric power and associated useful thermal output. In the case of SO2 and NOx, boiler configurations and pollution abatement equipment also play a role. The emissions factors used in the estimation methodology are described in the discussion of Air Emissions in the Technical Notes, and are summarized in Tables A1, A2, and A3.

Emissions estimates for CO2, SO2, and NOx all declined in 2008 relative to the previous year, affected by the weak U.S. economy and the decline in electricity production (Table 3.9). SO2 and NOx emissions were further reduced due to increased installations of emission control devices.

Estimated carbon dioxide emissions by U.S. electric generators and combined heat and power facilities fell 2.5 percent from 2007 to 2008 (from 2,540 million metric tons to 2,477 million metric tons), largely due to a fall in fuel consumption at electric power plants. Emissions from coal-fired power plants typically account for four-fifths of CO2 emissions by electric power plants. Coal-fired generation fell 1.5 percent in 2008.

SO2 emissions fell 13.4 percent, from 9.0 to 7.8 million metric tons, between 2007 and 2008. This amounts to the largest year-over-year decline since 1995. There are multiple ways to reduce sulfur emissions in electricity production. One is to change the type of coal burned to a coal rank with lower sulfur content. Other methods are to switch fuels (typically to natural gas) or to shut down plants with high SO2 emissions. The large reductions in SO2 in 2008 mostly resulted from the installation of emissions reduction equipment (flue gas desulfurization (FGD) units) in response to recently-implemented emission reduction legislation.

In March 2005, the Environmental Protection Agency issued its Clean Air Interstate Rule (CAIR), which was intended to achieve the largest reduction in certain air pollutants in more than a decade. CAIR covers 28 Eastern States and the District of Columbia, a region that historically burned high-sulfur coal. CAIR calls for a 70-percent reduction in SO2 (from 2003 levels) by 2015. Although CAIR was vacated and remanded to the EPA by a U.S. Court of Appeals for the District of Columbia in July 2008, it was later reinstated by the same court in December of 2008. The temporary remand of CAIR in 2008 may have put off some SO2 abatement investments; however, much of the planned SO2 control retrofits were already in the pipeline, as indicated by the elevated level of FGD installations in 2008. Furthermore, several States and the EPA have taken actions to reduce SO2 outside of CAIR.

The recent reduction in SO2 emissions is traceable to a significant increase in FGD unit installations during 2008. Nationwide, the count of FGD units increased from 279 to 330, reflecting the largest increase in installations since 1995.¹¹ Use of other SO2 reduction methods was not significant enough to produce a sizable decline in SO2 in 2008. Most of the decline in SO2 emissions between 2007 and 2008 can be traced to coal-related SO2 emissions, but coal consumption did not significantly change (decrease of 0.5 percent). Petroleum represents a small share of electricity generation and due to its smaller carbon content (relative to coal), its contribution to the decline in SO2 emissions was far less significant than coal. Finally, between 2007 and 2008, the average sulfur content of coal used to fire electric power showed a marginal increase, while there was little switching among coal ranks during this time period.

2008 data also show significant reductions in NOx emissions. This too can be traced to the installation of pollution abatement equipment such as low-NOx burners and selective catalytic reduction devices. NOx emissions decreased 8.8 percent (from 3.7 to 3.3 million metric tons) from 2007 to 2008.

Trade

Total wholesale purchases of electric power in the United States increased 4.0 percent to 5,613 million MWh (Table 6.1), reversing a four-year downward trend. Almost half the volume of sales for resale was provided by energy-only providers (i.e., power marketing companies, a class of electric entities authorized by the Federal Energy Regulatory Commission (FERC) to transact at market-based rates, which came into being during the late 1990s with the deregulation of the wholesale power markets). Wholesale sales by wholesale power marketers and retail energy service providers increased from 2,477 million MWh in 2007 to 2,719 million MWh in 2008, which represented 47.9 percent of the wholesale market (Table 6.2). Independent power producers and combined heat and power (CHP) plants accounted for 24.4 percent of wholesale sales in 2008 compared to 25.5 percent in 2007.

The Nation’s only international trade in electric power is with bordering nations Canada and Mexico, with the vast majority of that trade conducted with Canada. Most Mexican electric power trade is conducted with the State of California, while transactions with Canada are conducted through several bordering states. Much of the electricity provided from Canada is hydroelectric generation available for sale as the result of heavy seasonal river flows. On an annual basis, the U.S. is a net importer of electricity.

Total international net imports of electric power in 2008 increased 5.4 percent, from 31.3 million MWh in 2007 to 32.9 million MWh (Table 6.3). Imports to the U.S. increased 5.6 million MWh in 2008 from 51.4 million MWh in 2007 to 57.0 million MWh, while exports increased by 3.9 million MWh. Imports from Canada increased from 50.1 million MWh in 2007 to 55.7 million MWh in 2008, and U.S. exports to Canada increased from 19.6 million MWh to 23.5 million MWh. Electricity trade with Mexico followed a similar pattern of net imports, increasing only fractionally from 2007.

Electricity Prices and Sales

In 2008, the average retail price for all customers rose 0.61 cents per kWh to 9.74 cents per kWh (Table 7.4). This amounted to a 6.7-percent increase over the 9.13 cents per kWh average retail price paid in 2007. Year-over-year, the average retail price for all customers increased in 47 of the 50 States as well as the District of Columbia, with the exceptions being California, Maine, and Nevada. From 2007 to 2008, the average price of electricity increased 10 percent or more in 15 States. Most of the increases were in the 10 to 13 percent range, with the largest increase, 22.0 percent, occurring in Rhode Island. The average retail electric price for all customers declined in only 3 States compared to 11 States in 2007, and only Maine and California had decreases of more than 1 percent. The average retail price of electricity to all customers increased by 4 percent or more in all Census Divisions of the country—except the Pacific Contiguous, which was led by a 2.0 percent decrease in California. In New Jersey the average retail rate for all customers increased 11.0 percent. In the District of Columbia the average price increased 13.4 percent and in Texas it increased 8.7 percent. In Louisiana, the average electricity price for all customers increased 12.5 percent. Most Census Divisions experienced increases of 4 to 9 percent in the average retail price for all customers, with the exception of the East South Central Census Division, which experienced an increase of 12.3 percent. The highest regional price increase was in the Pacific Non-Contiguous Census Division (Alaska and Hawaii), where the average electricity price to all customers increased 29.7 percent over 2007. While both States rely heavily on oil and refined oil products, the regional price increase was primarily driven by increases in Hawaii. Hawaii’s primary fuel for electricity is petroleum, and petroleum prices to that State increased 42.0 percent in 2008.

In 2008, residential prices increased to 11.26 cents per kWh, or 5.7 percent over 2007. The average residential price increased by 10 percent or more in 8 States and the District of Columbia. Most of these jurisdictions have implemented retail competition and the investor-owned utilities operating within these States participate in organized, competitive wholesale markets operated by independent system operators. Residential prices in Rhode Island increased 24.1 percent, from 14.05 cents per kWh in 2007 to 17.43 cents per kWh in 2008. The average residential price in Maryland increased 16.4 percent, from 11.89 cents per kWh in 2007 to 13.84 cents per kWh in 2008. The largest increase in average residential prices was in Hawaii, at 34.7 percent. The increases in Rhode Island and Maryland are the result of the transition to market based rates for the wholesale electricity portion of retail electric service. In order to mitigate the impact of higher retail prices, the Maryland Public Service Commission approved a plan for the largest investor-owned utility in the State that gave customers two payment options. The first option provided for retail prices based on the full market price of wholesale electricity prices, effective June 1, 2008. This option resulted in approximately a 50-percent increase in the average electric bill. The second option provided that the cost of electricity would be phased in over time. Deferred costs would be recovered by December 31, 2009.¹²

The District of Columbia had the fourth largest increase in residential prices, at 13.2 percent, followed by New Jersey (10.8 percent). On a regional basis, the highest average residential price increase was observed in the East South Central Division. New England, Mid-Atlantic, East North Central, South Atlantic, and West South Central all observed increases of between 6 percent and 7 percent. Average residential prices in the New England and Mid-Atlantic Census Divisions increased 6.0 percent and 6.8 percent respectively. Average residential prices fell 1.9 percent in Maine and 4.2 percent in California. These were the only two States to realize a decrease in the residential average retail price of electricity in 2008.

Nationally, average commercial prices increased from 9.65 to 10.36 cents per kWh, a 7.5 percent increase over 2007. The largest regional price increase was in the Pacific Noncontiguous Census Division, at 28.0 percent, followed by a 14.8 percent increase in the East North Central Census Division. By State, the largest increase in average commercial prices was in Illinois, where prices increased 37.6 percent as result of some Illinois utilities reclassifying higher-priced industrial transactions as commercial in 2008. Illinois was followed by increases in Hawaii (35.7 percent), Rhode Island (21.2 percent), Virginia (14.7 percent), Georgia (12.4 percent) and the District of Columbia (12.1 percent). The average commercial price in the East North Central Census Division was 9.75 cents per kWh in 2008, up from 8.49 in 2007. In 2007, the West South Central Census Division was unchanged at 9.26 cents per kWh but increased 9.2 percent in 2008 to 10.11 cents per kWh. The average commercial price declined less than 1 percent in Nevada and 2.2 percent in California. In the Pacific Contiguous Census Division, the average commercial price declined from 11.19 cents per kWh in 2007 to 11.03 cents per kWh in 2008. This was the only region where average commercial prices declined.

Average industrial prices increased 6.9 percent from 6.39 cents per kWh in 2007 to 6.83 cents per kWh in 2008. The largest regional price increase in the industrial sector was in the Pacific Noncontiguous Census Division, at 36.1 percent, with Hawaii observing an increase of 41.7 percent from 18.38 cents per kWh to 26.05 cents per kWh in 2008. Average industrial prices in the District of Columbia increased 33.7 percent followed by increases in Louisiana and Tennessee (both at 21.2 percent), and Georgia (20.6 percent). The average industrial rate in the East North Central Census Division was 5.79 cents per kWh in 2008, a 1.9 percent decrease from 5.90 cents per kWh in 2007. This was driven by a 31.3-percent decrease in Illinois industrial prices, as a result of reclassifying data.

Total U.S. retail sales of electricity were 3,733 million MWh in 2008, a 0.8 percent decrease from 2007 to 2008. Comparatively, the annual growth in electricity sales in 2007 was 2.6 percent, and the average annual growth rate since 1997 was 1.6 percent. The 2008 decrease in annual sales from 2007 marks the first time since 2001 that annual sales decreased from the prior year. This decrease was driven by the residential and industrial sectors, with sales decreases of 0.9 percent and 1.8 percent, respectively. Commercial sales were essentially flat between 2007 and 2008. Since 1997, annual industrial sales have declined four times and overall, load continues to gradually shift away from the industrial sector. The industrial sector accounted for 33.0 percent of total retail sales in 1997, but by 2008 it had declined to 27.0 percent. Over that same time period, the commercial sector’s share of retail sales increased from 29.5 percent to 35.8 percent, while retail sales to the residential sector grew from 34.2 percent to 37.0 percent.

Demand-Side Management

In 2008, electricity providers reported total peak-load reductions of 32,741 MW resulting from demand-side management (DSM) programs, an 8.2 percent increase from the amount reported in 2007 (Table 9.1). Reported DSM costs increased $1.2 billion, up 47.4 percent from the $2.5 billion reported in 2007. DSM costs can vary significantly from year to year because of business cycle fluctuations and regulatory changes. Since costs are reported as they occur, while program effects may appear in future years, DSM costs and effects may not always show a direct relationship. In the five years since 2003, nominal DSM expenditures have increased at a 22.9-percent average annual growth rate. During the same period, actual peak load reductions have grown at a 6.17-percent average annual rate from, 22,904 MW to 32,741 MW. The divergence between the growth rates of load reduction and expenditures is driven in large measure by 2008 expenditures, which are in response to higher overall energy prices. The full effect of these expenditures may appear in additional load reductions in the coming years. The combined DSM energy savings programs (i.e., load management and energy efficiency) increased to 87.8 million MWh in 2008 from 69.0 million MWh in 2007.