Electric Power Annual 2000 Volume II

A Review of 2000

In 2000, the electric power industry experienced continued changes to its sales, finances, power transactions and other industry indicators. The following is a summary of those changes.

Retail Sales and Revenue. In recent years, the Energy Information Administration collected retail sales and revenue information on deregulated markets from retail energy service providers that included the cost of energy to the customer, but not the cost of associated delivery services (i.e., line maintenance, billing, etc.). For the first time, for the year 2000 cycle, the EIA collected information on the revenue received by traditional distribution utilities for delivery services provided to consumers who selected alternate energy suppliers in State "retail wheeling" programs. Thus it is now possible to provide sales and complete revenue data for the approximately 1.5 million consumers who participated in those programs in 2000. Statistics referred to in this text include both fully bundled and unbundled consumers combined (see Tables 2 through 2d), as well as bundled customers only (Tables 3a through 7). Some consumer counts, sales and revenue data provided for unbundled consumers are adjusted by the EIA to account for probable underreporting (for a discussion of this adjustment, and more information on sales in competitive retail markets, see Electric Sales and Revenue 2000, Appendix C).

Electricity sales to full-service and unbundled consumers increased by 3.3 percent to over 3,421 billion kilowatthours (adjusted) in 2000. Sales by competitive energy service providers in State-level "customer choice" programs increased by 47 percent, from 76.2 billion kilowatthours in 1999 to 111.9 billion kilowatthours (adjusted) in 2000. Total retail revenue received by electric utilities and energy service providers increased to over $233 billion (adjusted).

In 2000, full-service sales by traditional distribution utilities continued to account for approximately 97 percent of total retail electricity sales. Sales by traditional distribution utilities increased from 3,236 billion kilowatthours in 1999 to 3,310 billion kilowatthours in 2000, an increase of 2.3 percent. The largest increases in electricity consumption in 2000 occurred in the southern-tier States mostly unaffected by deregulation, but with heavy air conditioner loads (i.e., Texas, Louisiana, Mississippi, Alabama, Florida, and Georgia). Revenue from retail sales by traditional utilities increased from $215 billion in 1999 to $224 billion in 2000.

The national average revenue in cents per kilowatthour increased from 6.66 in 1999 to 6.78 in 2000. This was the first year an increase has been recorded in the average revenue per kilowatthour since the early-nineties. Each major consumer sector, including industrial, experienced increases in the average cost of power. Industrial average revenue increased from 4.43 cents per kilowatthour for fully-bundled consumers to 4.57 cents. However, nominal industrial rates remain the lowest since 1981, and real industrial rates remained among the lowest since 1973.

Financial Statistics. Electric operating revenues for the major investor-owned electric utilities were up $17.1 billion to $214.7 billion in 2000. Electric utility operating expenses, led by combined increases in operation and maintenance expenses, were up $24.0 billion. As a result, electric operating income declined from 1999. This increase in expenses caused net income to decline 22.3 percent to $13.3 billion. Dividends declared on preferred stock continued to decline, with the 2000 amount less than half that reported in 1996. Common dividends fell 10.8 percent to $16.7 billion. The profit margin fell to 5.64 percent, and the current assets to liabilities ratio of 0.85 dropped below the 1996 level.

In 2000, the major investor-owned segment continued to position itself in response to restructuring of the industry. Net electric utility plant continued its decline, dropping 1.0 percent to $307.3 billion. This is 15.5 percent less than the $363.9 billion reported in 1996. Accumulated depreciation continued its increase to $277.8 billion. Other property and investments increased 4.5 percent, whereas deferred debits dropped less than 0.1 percent. Current and accrued assets increased 38.1 percent. Total capitalization declined to $341.2 billion primarily due to the $5.0 billion decrease in common stock equity. A $28.0 billion increase occurred in current and accrued liabilities.

In 2000, the major publicly owned generator electric utilities had a combined operating revenue of $31.8 billion, up by 19.0 percent. Generator electric utility operating expenses increased 23.4 percent, resulting in an increase in net income of 469 million. Total assets for publicly owned generator electric utilities rose by $11.3 billion, ending at $127.5 billion. The electric utility plant per dollar of revenue ratio was 3.5 in 2000.

In 2000, the major publicly owned nongenerator electric utilities had a combined operating revenue of $9.9 billion, a 5.9 percent increase over 1999. Nongenerator electric utility operating expenses increased by 7.0 percent to end the year at $9.4 billion. Net income for nongenerators decreased slightly to $0.5 billion. Total assets for nongenerator electric utilities increased by 10.3 percent to end the year at $14.6 billion. The electric utility plant per dollar of revenue ratio increased to 1.3 in 2000.

U.S. Electric Utility Sales to Bundled Ultimate Consumers by Sector, 2000 U.S. Electric Utility Average Revenue per Kilowatthour by Sector (Bundled Consumers), 2000 U.S. Electric Utility Sales to Bundled Ultimate Consumers by Class of Ownership, 2000 Revenue from U.S. Electric Utility Sales to Bundled Ultimate Consumers by Class of Ownership, 2000

Environmental. Flue gas desulfurization (FGD) equipment, sometimes referred to as scrubbers, uses chemicals such as lime to remove sulfur oxides from the combustion gases of boilers before the gases are discharged into the atmosphere. In 2000, there were 192 generators connected to scrubbers at U.S. power plants, compared with 192 in 1999 and 150 in 1989. The average sulfur content of coal delivered to all U.S. electric utility plants decreased slightly from 1.01 percent by weight in 1999 to 0.93 percent by weight in 2000.¹

Power Transactions. On a national basis in 2000, wholesale power receipts (purchased power plus exchanges received and wheeling received) increased by 436 billion kilowatthours to reach 3,000 billion kilowatthours. Sales to ultimate consumers totaled 3,421 billion kilowatthours (including sales by retail power marketers), of which 1,716 billion kilowatthours or 48 percent was from wholesale trade with other electric utilities (requirement and nonrequirement sales for resale). To supply electric energy in 2001, electric utilities had planned capacity resources on hand of 808 million kilowatts, and 827 million kilowatts for the winter, resulting in national capacity margins of 16.5 percent and 30.4 percent, respectively.

In 2000, the noncoincidental peak load at electric utilities in the contiguous United States showed an increase of 0.6 percent, from 681 to 686 million kilowatts for the summer. The winter peak load was 592 million kilowatts, increasing 21 million kilowatts from 1999 which represented a change of less than 4.0 percent. Both the summer and winter peak loads for the contiguous United States were projected for 2001 to grow to 709 and 606 million kilowatts, respectively. By the year 2005, the noncoincidental peak load is expected to be above the 2000 actual by almost 83 million kilowatts for the summer and 60 million kilowatts for the winter.

Demand-Side Management. In 2000, 962 electric utilities reported having demand-side management (DSM) programs. Of these, 516 were classified as large, and 446 were classified as small utilities. This is an increase of 114 utilities utilities from 1999. DSM costs were slightly increased from 1999 at $1.56 billion.

Energy savings for the 516 large electric utilities increased to 53.7 billion kilowatthours, 2.1 billion kilowatthours more than in 1999. These energy savings represent 1.6 percent of total annual electric sales of 3,421 billion kilowatthours to ultimate consumers in 2000.

Actual peak load reductions for large utilities decreased in 2000 to 22,901 megawatts. Potential peak load reductions of 41,369 megawatts were a decrease of 2,201 megawatts from 1999. In 2000, incremental energy savings for large utilities were 3.3 billion kilowatthours, incremental actual peak load reductions were 1,640 megawatts, and incremental potential peak load reductions were 3,159 megawatts.

U.S. Nonutility Generating Facility Statistics

Generation In 2000, U.S. nonutility generating facilities generated 828 billion kilowatthours of electricity. U.S. nonutility generating facilities received 95 billion kilowatthours from, and delivered 660 billion kilowatthours to, electric utilities and other end users. Nonutility power producers delivered approximately 79.6 percent of their gross generation to electric utilities and other end users and used 263 billion kilowatthours for their own power plant operations and industrial processes. More than one-fourth of national nonutility production of electricity occurred in California and Pennsylvania, with 127 and 111 billion kilowatthours, respectively.

Gross generation for nonutility generating facilities was 52.6 percent higher in 2000 than a year earlier. Slightly more than 40 percent of the generation by nonutility generating facilities was gas-fired, with generation from coal accounting for 34.6 percent of the total. Of the total nonutility generation, 354 billion kilowatthours were from qualifying facilities, approximately 42.7 percent of the total. (See the Chapter titled "Nonutility Power Producers" for a definition of these facilities.) The largest share of gross generation was produced by facilities in the Middle Atlantic Census Division (New Jersey, New York, and Pennsylvania), followed by the Pacific Census Division (Alaska, California, Hawaii, Oregon, and Washington). The transportation and public utilities sector dominates electric generation, with the largest share in the Middle Atlantic Census Division. For the second largest sector, the manufacturing sector is concentrated in the West South Central Census Division, Middle Atlantic Census Division, and South Atlantic Census Division (Delaware, Florida, Georgia, Maryland, North Carolina, South Carolina, Virginia, and West Virginia) where there is a large potential for cogeneration in both the refining and the paper and pulp industries.

Capacity. The total installed capacity of nonutility generating facilities was 228,594 megawatts at the end of 2000, 42.4 percent more than in 1999. The restructuring of the electric power industry has resulted in 50,884 megawatts during 1999 and 47,710 megawatts during 2000 of net summer capability that has been sold (or reclassified) to nonutilities. Nonutility capacity in 2000 was equivalent to 25.3 percent of the total U.S. electric industry capacity. Of all energy sources, gas and other gas accounted for the largest amount of nonutility capacity. The Pacific Census Division accounted for the largest percent of that gas-fired capacity. The second largest share of nonutility capacity was provided by coal, followed by petroleum only and natural gas.

The greatest number (527) of nonutility generating facilities was in the Pacific Census Division, with a capacity of 34,929 megawatts. In the Pacific Census Division, California dominated because the State actively promoted alternative energy sources in the 1970's and 1980's by providing incentives to nontraditional electricity producers. Many of these incentives have since expired or been rescinded, but they served to assist in the development of nonutility generation. The second greatest number (447) of nonutility generating facilities was in the Middle Atlantic Census Division where restructuring of the electric power industry has resulted in the selling of plants from electric utilities (regulated) to nonutilities (unregulated) in all three States of New York, Pennsylvania, and New Jersey.

Consumption. In 2000, consumption by nonutilities included 3,634 billion cubic feet of natural gas, 156 million short tons of coal, and 93 million barrels of petroleum. Compared to 1999, consumption increased 105.2 percent for coal, 13.8 percent for gas, and 10.0 percent for petroleum.

Endnote

1. Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants 1999 Tables, DOE/EIA-0191(99) (Washington DC, 2000).

Contact:

Roger Sacquety

Internet E-Mail: roger.sacquety@eia.doe.gov

Phone: (202) 287-1745