The pace of restructuring in the electric power industry slowed significantly in 2001 according to the latest edition of Electric Power Annual, a summary of electric power industry statistics from the Energy Information Administration (EIA).

Market volatility and power price increases in California and other States in the Northwest led to uncertainty about competitive power markets, and by the end of 2001, restructuring had either been delayed or suspended in 8 States that previously enacted legislation or issued regulatory orders for its implementation. Eighteen other States that had ongoing legislative or regulatory investigations in the year 2000 reported no such activity in 2001.

	Total Net Generation by Facility Type, 1990-2001 Billion Megawatthours
	Source: Energy Information Administration.

Generation
In 2001, total U.S. net generation of electricity was 2 percent lower than in 2000. This is only the second time in over 50 years that net generation has declined.

While net generation dropped for the industry overall, the independent power producers’ (IPP) share of net generation was up sharply in 2001, as a result of plant divestitures by investor-owned utilities and new plant construction.

Net generation by combined-heat-and-power plants (CHP) remained fairly constant from 1996 through 2001 at 8 to 9 percent of the total.

Capacity
In 2001, total net summer generating capacity rose 4.5 percent over the previous year. A 31-percent increase in natural gas capacity drove most of this increase. However, the downward trend in capacity margins reemerged in 2001.

Through most of the period from 1989 to 1998, net internal demand in the contiguous United States grew more rapidly than capacity, and summer capacity margins during that period shrank more than 7 percentage points. Following increases in 1999 and 2000, nationwide capacity margins dropped just over 1 percentage point in 2001. Commitments and planning for new plants also slowed in 2001.

Fuel
Consumption of coal for electricity generation was down 2 percent from the previous year; use of petroleum for electricity generation increased 14 percent; and consumption of natural and other gases increased less than 1 percent. In 2001, the average cost of natural gas to electric utilities increased 4 percent and the average cost of coal rose about 3 percent.

However, these average prices do not reflect the extraordinary volatility in the spot markets for natural gas and coal in 2001. For example, the spot price for natural gas at the Henry Hub trading point exceeded $9.00 per million British thermal units (Btu) in January 2001, but was under $3.00 per million Btu by fall. Coal spot prices were also very high at the beginning of 2001 and moderated as the year progressed.

Sales and Revenue
Total retail sales in 2001 were 3.4 billion megawatthours, down more than 1 percent from the year before. The biggest decreases occurred on the West Coast. The residential, commercial, and industrial sectors accounted for 36 percent, 32 percent, and 29 percent of retail sales, respectively.

Retail sales revenue grew more than 6 percent in 2001 to reach $247 billion, while average revenue per kilowatthour (kWh) rose from 6.8 cents per kWh to 7.3 cents per kWh. Total electric industry operating revenues exceeded $350 billion, up 13 percent from the year before.

Revenues grew faster than operating expenses at investor-owned utilities, but expenditures rose more rapidly than income at publicly-owned and federal utilities. Natural gas prices were a major contributor to higher costs.

Electric Power Annual 2001 contains detailed information about the foregoing topics as well as additional sections on emissions, trade, and demand-side management. The appendices describe the EIA forms used to collect the data and the methodology for estimating power sector fuel use. The publication also has a glossary of terms used in the electric power sector.

Electric Power Annual 2001, DOE/EIA-0348(2001); 95 pages, 48 tables, 9 figures.

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File last modified: April 28, 2003