Generation

Net generation by the electric power industry totaled 3,800 billion kilowatthours (kWh), up 2.6 percent from 1999. This increase can be attributed in-part to growth in the economy⁽⁷⁾ indicated by higher demand for electricity from the commercial and industrial sectors and to a weather-related increase in sales to the residential sector. Total heating and cooling degree-days were above the level of 1999⁽⁸⁾ as the year required more heating but slightly less cooling than 1999.

Coal-fired generation topped the fuel mix with 1,968 billion kWh, or 52 percent of total generation. Generation from nuclear facilities totaled 754 billion kWh or 20 percent of total generation, as the industry posted another improvement in the plant capacity factor. Gas-fired generation rose to 612 billion kWh or 16 percent of total generation due to substantial increases in both California and Texas. Petroleum-fired generation, while less than 3 percent of total generation, posted a double-digit decline, primarily due to much higher petroleum prices. On the renewable energy front, hydroelectric generation fell to 273 billion kWh or 7 percent of total generation, due to substantially less precipitation in the southern and western regions of the Nation.⁽⁹⁾

Figure 5. Shares of Net Generation by Energy Source and Industry Sector, 2000

Coal

Coal-fired generation totaled a record 1,968 billion kWh, up 4 percent from the level of 1999. Likewise, coal consumption set a record of 991 million short tons, up from 953 million short tons. Higher demand for electricity proved favorable for an increase in the use of coal. There were several specific issues that affected coal use by electric generators including record output from nuclear plants, mild weather, reduced levels of hydroelectric generation, and a substantial increase in the price of petroleum and natural gas.

Like 1999, record nuclear generation and mild weather were two important factors limiting the increase in the use of coal. Nuclear generation rose to a record 754 billion kWh, 4 percent higher than in 1999. (Specific information concerning nuclear generation is provided in more detail later in this review.) As for weather conditions, 2000 was the 13th warmest year since 1895, while 1999 was the second warmest.⁽¹⁰⁾ The winter of December 1999 through February 2000 was the mildest on record for the second consecutive year.⁽¹¹⁾ This was followed by the second warmest spring (March through May) since 1895.⁽¹²⁾ Together, the above normal temperatures during the first 5 months of the year reduced demand for electricity and in-turn limited growth in coal-fired generation. During the summer cooling months of June through August, much of the Nation had above normal temperatures. However, summer temperatures in the high population areas of the New England, Middle Atlantic, and East North Central Census Divisions were considerably below normal.⁽¹³⁾ This reduced cooling requirements and thereby reduced electricity demand in those regions. Partially countering the above normal warmth of January through May was the fact that the November through December 2000 period was the coldest on record for the Nation.⁽¹⁴⁾ The accompanying increase in demand for electricity resulted in much higher levels of coal-fired generation during these months.

Figure 6. U.S. National Percent Area Very Warm and Very Cold, January 2000 to December 2000

A reduction in hydroelectric generation from 1999 levels led to higher use of coal by electric generators. Since it is the lowest cost power to generate, hydroelectric generation often displaces the use of fossil fuels. Due to dry conditions throughout the southern and western regions of the Nation, generators turned to fossil fuels to replace hydroelectric power. For example, due to a major drought that has lingered for over 2 years, Alabama Power Company increased its coal burn by over 1 million short tons to compensate for a reduction in hydroelectric generation.⁽¹⁵⁾ In the Mountain Census Division, coal-fired generation rose 3 percent from 1999 levels due in part to a substantial decrease in hydroelectric generation throughout most areas of the West.

Figure 7. Average Cost of Fossil Fuels at U.S. Electric Utilities, 2000 and 1999

Another factor contributing to the increased use of coal in 2000 was the large increase in the cost of competing fossil fuels. High demand for petroleum and gas by all consuming sectors resulted in steadily rising prices. For most of the year, the average cost of each fuel delivered to electric utilities was above $4.00 per million Btu, considerably above the levels of 1999 and prior years.⁽¹⁶⁾ By comparison, the delivered cost of coal to electric utilities averaged $1.20 per million Btu. By year-end, extremely cold weather had heightened concerns about low natural gas inventories, resulting in spot prices spiking to as high as $67 per million Btu in California and petroleum spot prices hovering near $30 per barrel.⁽¹⁷⁾ The result was an increase in demand for coal-fired generation.⁽¹⁸⁾ Texas led the Nation in coal-fired generation with 141 billion kWh, nearly unchanged from 1999. Ohio, Indiana, and Pennsylvania ranked second, third, and fourth, respectively, each with output above the 120 billion kWh level. States where coal accounted for greater than 90 percent of total generation included Indiana, Kentucky, North Dakota, Utah, West Virginia, and Wyoming (see Table 7).

Figure 8. U.S. Statewide Temperature Ranking, June-August, 2000

Figure 9. U.S. Statewide Temperature Ranking, June-August, 2000

Coal consumption followed coal generation, rising to just under 1 billion short tons. Approximately 2 megawatthours (MWh) of electricity were produced for each short ton of coal consumed. At the State level, the ratio ranged from a high of 2.7 (MWh) in Connecticut to a low of 1.2 in North Dakota.⁽¹⁹⁾ The rather substantial range is primarily due to the difference in the Btu content of coal consumed in each State.⁽²⁰⁾ Texas ranked highest in tons of coal consumed with 100 million short tons, while Indiana and Ohio ranked second and third with 59 million and 56 million short tons, respectively. Large volume increases in coal consumed were notable in Alabama, Illinois, Kansas, Minnesota, Ohio, Pennsylvania, South Carolina, Tennessee, and Virginia.

The origin of coal for the electric industry continues to shift toward the western United States, specifically the Powder River Basin (PRB) of Montana and Wyoming. It is estimated that this region supplied approximately 340 million short tons of low sulfur, low Btu coal to electric generators.⁽²¹⁾ Wyoming was the largest producer of coal for the industry with over 300 million short tons. Kentucky and West Virginia were a distant second and third with approximately 100 million short tons each.⁽²²⁾ Imports accounted for approximately 1 percent of all coal consumed by the electric power industry.

Stocks of coal held by electric generators went from excessively high levels at the start of the year to very lean levels by year-end. The industry began 2000 with an inventory of 143 million short tons, the highest start-of-year level since 1993. Some of the build-up can be attributed to Year 2000 concerns about the coal supply-chain. Additionally, mild weather from late 1999 through the first few months of 2000 reduced the burn rate more than expected. Low prices and reduced demand by the electric industry led to production cuts by coal producers.⁽²³⁾ With both producers and electric generators each reducing inventory, some minor spot shortages began to show up in early summer.⁽²⁴⁾ An increased burn rate due to a very cold November and December, coupled with rising spot market prices that discouraged purchases of coal, contributed to year-end stocks falling to 103 million short tons.

On January 1, 2000, the electric industry came under Phase II regulations of the Clean Air Act Amendments of 1990. This Act was primarily designed to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxides. Phase I, which began on January 1, 1995, affected 435 generating units and allowed the release of 2.5 pounds of sulfur dioxide per each million Btu of fuel consumed.⁽²⁵⁾ Under Phase II, coverage increased to more than 2,000 units, while restrictions on emissions were set at 1.2 pounds of sulfur dioxide per million Btu of fuel consumed.⁽²⁶⁾ Since 1995, some generators have over complied with Phase I in order to create excess allowances. This has allowed them to delay enacting additional strategies that would be necessary for compliance with Phase II.⁽²⁷⁾ Strategies that are being used for compliance include fuel switching/ blending, co-firing with natural gas, allowance acquisitions, scrubbers, repowering, and plant retirements.⁽²⁸⁾

Petroleum

Petroleum-fired generation totaled 109 billion kWh, down 12 percent from 1999. Consumption decreased to 173 million barrels, down from 196 million in 1999.⁽²⁹⁾ Most, if not all of the decrease, can be attributed to a substantial increase in the cost of petroleum. The refiner acquisition cost of crude oil rose 61 percent from 1999 levels to $28.23, its highest level since 1984.⁽³⁰⁾ This is reflected in the average cost of heavy oil delivered to electric utilities, which increased to $4.29 per million Btu, up from $2.44 per million Btu in 1999.⁽³¹⁾

Many factors affect the use of petroleum by electric generators. One of the most important is the price of fuel oil in relation to the price of natural gas. Some facilities have the capability to burn either fuel and usually the less expensive of the two fuels is consumed. Petroleum-fired units are often some of the most expensive to operate; this makes them among the last units to be dispatched to meet system load. While there are some companies that continue to use petroleum-fired units as base-load plants, particularly in Florida, Hawaii, and the Northeast, most use them to meet peak power demand. December 2000 brought exactly the right conditions necessary for increased use of petroleum by electric generators. Extreme cold weather over much of the Nation increased demand for power. This, coupled with a spike in natural gas prices to record levels, resulted in petroleum-fired generation reaching levels not seen since January 1994.

As has been the case for the past several years, utilities and nonutilities in the New England, Middle Atlantic, and South Atlantic Census Divisions consumed most of the petroleum used to generate electricity. Petroleum consumption increased in the Middle Atlantic in part due to lower nuclear generation but was down considerably in both the New England and South Atlantic Census Divisions. Each reported gains in both coal-fired and nuclear generation. The South Atlantic Census Division accounted for 41 percent of all petroleum consumption by the electric industry. Florida, with 19 percent of the U.S. petroleum-fired generating capacity, accounted for 55 million barrels (32 percent of total consumption); New York accounted for 26 million barrels (15 percent of total consumption). Connecticut, Hawaii, and Massachusetts were all large users of petroleum, each consuming over 10 million barrels. Hawaii was the State most dependant on petroleum with 73 percent of its electricity being generated from fuel oil.

Number 6 fuel oil is the primary fuel oil product consumed by steam-electric plants, accounting for approximately 80 percent of petroleum consumption by electric utilities. Number 2 fuel oil accounts for most of the remainder and is used primarily for startup and flame stabilization in steam-electric plants, and as a peaking fuel in both diesels and gas turbines. The use of petroleum as a fuel for electric generation has been declining since the mid-70's and accounted for less than 3 percent of total generation in 2000. That percentage is significantly higher in some States including Connecticut, Delaware, Florida, Hawaii, Maine, Massachusetts, and New York, which still have significant amounts of petroleum-fired generating capacity.

Gas

Gas-fired generation totaled 612 billion kWh, an increase of 42 billion kWh or 7 percent from 1999. Consumption of gas totaled 6.3 trillion cubic feet (Tcf), up from 5.7 Tcf in 1999. Specific issues that affected the volume of gas used by the electric industry during the year included above normal summer temperatures in the Southwest, a reduction in the availability of hydroelectric generation, rising natural gas prices, and an increase in gas-fired generating capacity.

During 2000, strong demand, short supplies, and rapidly rising prices were characteristic of the natural gas markets for most of the year. This is in contrast to 1999 when ample supplies and steady prices were common. Total end-use demand was nearly 23 Tcf, up from 22 Tcf in 1999.⁽³²⁾

One factor that resulted in higher demand for gas by the electric sector was above normal temperatures in the southwestern United States during the summer of 2000. This area of the Nation, which consumes nearly one-half of the gas used to produce electricity, had its second warmest June through August period since 1895,⁽³³⁾ continuing the trend of above normal temperatures over the last 7 years. Consumption was also higher in California with the electric sector consuming 1.1 Tcf of gas, up 22 percent from 1999. Demand for electricity was strong from both the residential and commercial sectors. In addition, a decrease in the availability of hydroelectric generation from neighboring States required California to rely more on its gas-fired generating capacity.

Also contributing to an increase in the use of gas by electric generators were new capacity additions. Most of the new capacity added by the industry in recent years uses natural gas as its primary energy source. In 2000, gas-fired capacity additions accounted for 22,238 megawatts (MW) out of 23,453 MW added to the electric grid. Most of these additions were gas turbines, which have found favor over the past several years due to their high efficiency, low capital cost requirements, and relatively short construction period.

The spike in natural gas prices late in the year had the tendency to reduce the use of natural gas. The average cost of gas delivered to electric utilities in December was $8.41 per million Btu, the highest level ever reported.⁽³⁴⁾ Purchased power and the consumption of other fossil fuels such as fuel oil were, in some cases, less expensive alternatives.

Nuclear

Nuclear generation totaled a record 754 billion kWh, up nearly 4 percent from the previous record of 728 billion kWh generated in 1999. The annual capacity factor⁽³⁵⁾ was 88 percent compared with 85 percent in 1999. This was the highest annual capacity factor for nuclear plants since data collection began in 1973.⁽³⁶⁾ The July 2000 capacity factor was an impressive 95 percent. This has major implications on the fossil-fuel requirements of electric utilities because like hydroelectric, nuclear generation displaces fossil-fired generation. (Based on national level consumption and generation data presented in the Electric Power Monthly, and assuming a net summer nuclear capability of 97,557 megawatts, a 1-percent increase in the annual nuclear plant capacity factor (equivalent to 8,545,993 megawatthours⁽³⁷⁾) of additional nuclear generation translates into a reduction in annual consumption of either approximately 4.3 million short tons of coal,⁽³⁸⁾ 14 million barrels of petroleum, or 89 billion cubic feet of gas. Most likely, it would be a combination of each.)

Since 1990, nuclear's share of electricity generation has been relatively stable at 18 to 20 percent.⁽³⁹⁾ Currently, nuclear power represents approximately 12 percent of total generating capacity.⁽⁴⁰⁾ Due to the retirement of generating units, the number of operable units now stands at 104, down from a peak of 112 in 1990.⁽⁴¹⁾

Nuclear generation often displaces fossil-fired generation because of its lower cost of fuel per unit of electricity produced. In 1999, the average cost of uranium for major investor-owned electric utility nuclear plants was 0.52 cents per kilowatthour, while the comparable cost of fuel for fossil-fired steam plants was 1.56 cents per kilowatthour.⁽⁴²⁾ An additional incentive for producing nuclear generation instead of fossil-fired generation is a reduction in emissions of carbon dioxide, sulfur dioxide, and nitrogen oxides. The passage of Title IV of the Clean Air Act Amendments of 1990 set limits on the amount of sulfur dioxide and nitrogen oxides that can be emitted by electric utilities. Since nuclear plants emit neither of these gases, they have become especially important in strategies designed to ensure that a utility is in compliance with air quality emission regulations. Perhaps even more important is the fact that unlike fossil-fired plants, nuclear plants emit no carbon dioxide. The buildup of this gas in the atmosphere is said to affect the global climate.

Nuclear generation rose in all Census divisions except the Middle Atlantic and the Mountain Census Divisions. The East North Central Census Division posted a 12-billion-kWh increase primarily due to higher output from the Clinton and Lasalle County plants in Illinois and the return-to-service of the Donald Cook facility in Michigan. The New England Census Division posted an increase due to an increase in generation from the Millstone facility. A substantial decrease in output from the Indian Point facility (Consolidated Edison Company of New York) contributed to a reduction in nuclear generation from the Middle Atlantic Census Division. Nuclear power provided 33 percent of total electricity generation in the Middle Atlantic Census Division, followed by the New England and South Atlantic Census Divisions at 30 and 26 percent, respectively. At the State level, Illinois ranked highest in nuclear generation with 89 billion kWh, followed by Pennsylvania and South Carolina with 74 billion kWh and 51 billion kWh, respectively.

Hydroelectric

Hydroelectric generation totaled 273 billion kWh, down from 313 billion kWh in 1999. Contributing to this decrease was a drought that covered most of the western half of the Nation including the major hydroelectric producing region of the Pacific Northwest. Above normal precipitation in the Northeast and the Great Lakes region, as well as a continuing drought in the South, also affected hydroelectric generation levels during the year.

Figure 10. U.S. Statewide Precipitation Ranking, 2000

According to the National Oceanic and Atmospheric Administration (NOAA), the Nation recorded its 25^th driest year out of the last 106 years, compared to its 29^th driest in 1999, and the third wettest in 1998.⁽⁴³⁾ Based on the Palmer Drought Index, 36 percent of the Nation was under severe or extreme drought conditions in August 2000, the highest level since 1988.⁽⁴⁴⁾

Below normal levels of precipitation throughout most of the western United States was the principal reason for a 13 percent reduction in hydroelectric generation. Of particular importance was a substantial decline in precipitation in the NOAA Pacific Northwest Region (Oregon, Washington, and Idaho) where most of the Nation's hydroelectric generation is produced. Oregon and Washington recorded their 27^th and 18^th driest year, respectively, out of the last 106 years as compared to their 42^nd and 33^rd wettest in 1999.⁽⁴⁵⁾ The year-to-year change is even more striking when considering the very high levels of precipitation that fell in both States during late 1998 and contributed greatly to the snow pack and stream flow levels of 1999. Though 2000 was dry on an annual basis , the January through April 2000 snow pack in both States was at normal levels due to above normal precipitation early in the year.⁽⁴⁶⁾ In fact, Western storage reservoirs were above average on April 1, 2000.⁽⁴⁷⁾ However, October through December precipitation in the higher elevations of the Cascade Mountain Range that ranged from 35 to 65 percent of normal resulted in snow pack and stream flow levels that were considerably below normal.⁽⁴⁸⁾ By December 2000, hydroelectric generation levels in Washington and Oregon were running 32 percent and 26 percent, respectively, below the levels generated in December 1999.⁽⁴⁹⁾

For the year, hydroelectric facilities in Washington produced 81 billion kWh, down from 97 billion kWh in 1999. Likewise, totals in Oregon were 38 billion kWh, down from 46 billion kWh in 1999. From a historical perspective of 10 years, hydroelectric generation by electric utilities in Washington has ranged from a high of 104 billion kWh in 1997 to a low of 65 billion kWh in 1994.⁽⁵⁰⁾ Output from facilities in Oregon ranged from just over 46 billion kWh in 1997 to a low of 31 billion kWh in 1994. It is important to note that most effects of the late year drought will not be felt until the first quarter of 2001.

Hydroelectric generation in California totaled 39 billion kWh, down from 40 billion kWh in 1999. This occurred despite the fact that the State received more precipitation in 2000 than during 1999. Very heavy precipitation in late 1998 had a substantial affect on hydroelectric generation in 1999. During the first half of 2000, California received above normal levels of precipitation. However, the rain and snow that normally arrives in the Sierra Nevada Mountain Range during the fall never materialized. December precipitation throughout California was less than 25 percent of normal.⁽⁵¹⁾ The result was a mountain snow pack that was under 70 percent of normal as of January 1, 2001.⁽⁵²⁾ Based on data from the past 10 years, hydroelectric generation in California during 2000 was at the upper-end of the scale compared to a high of 49 billion kWh in 1998 and a low of 19 billion kWh in 1992.⁽⁵³⁾

A two-year drought throughout much of the South resulted in hydroelectric generation falling below the already low levels of 1999. Alabama and Georgia experienced their 8^th and 9^th driest years, respectively, in the past 106 years. Alabama reported hydroelectric generation down 45 percent from the pre-drought year of 1998, while Georgia and South Carolina reported decreases of 54 percent and 82 percent, respectively. At the Census division level, hydroelectric generation in the East South Central and the South Atlantic Census Divisions was down 42 percent and 50 percent, respectively, from the levels of 1998. On a positive note, above normal precipitation aided hydroelectric generation in the New England and Middle Atlantic Census Divisions. New York, the largest producer of hydroelectric power after Washington, California, and Oregon, was aided by its 6^th wettest year since 1895.⁽⁵⁴⁾

Endnotes

⁷ United States Department of Commerce, Bureau of Economic Analysis. Extracted from the Internet at http://www.bea.doc.gov/bea/glance.htm.

⁸ Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2000/12) (Washington, DC, May 2001), Tables 1.11 and 1.12.

⁹ National Oceanic and Atmospheric Administration, National Data Climatic Center. Extracted from the Internet at http://www.ncdc.noaa.gov/ol/climate/research/2000/ann/ann.html, on May 29, 2001.

¹⁰ National Oceanic and Atmospheric Administration, National Data Climatic Center. Extracted from the Internet at http://www.ncdc.noaa.gov/ol/climate/research/2000/ann/us_summary.html on May 29, 2001.

¹¹ United States Department of Agriculture, Weekly Weather and Crop Bulletin, Volume 88, No. 03 (January 17, 2001), p. 11.

¹² National Oceanic and Atmospheric Administration, National Data Climatic Center. Extracted from