Introduction: Electric Power Industry - 1999
| Figure 1. Status of State Electric Utility Deregulation Activity, as of January 2000. |
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Restructuring of the electric power industry (referred to as "industry" in this report) in the United States is continuing with electricity generation markets being opened to competition. The passage of the Energy Policy Act of 1992 and the subsequent issuance of Order Nos. 888 and 889 by the Federal Energy Regulatory Commission (FERC) in 1996 created an environment for competition to emerge in wholesale electricity trade transactions.(1) Since the issuance of the FERC Orders, State-level activity in electricity markets at the retail level has also increased significantly. By the end of 1999, 24 States and the District of Columbia had either enacted restructuring legislation or issued comprehensive regulatory orders on restructuring that enable customers to choose their electricity supplier either immediately or in a phased manner over the next few years (Figure 1).(2)
During 1999, ongoing structural changes within the industry were coupled with continuing growth in the generation of electricity. Electricity generation by the industry reached 3,691 billion kilowatthours (kWh), compared with 3,618 billion kWh in 1998, reflecting an increase of 2.0 percent (Table 1). Utilities generated 86.0 percent (3,174 billion kWh) of that output and nonutilities contributed the balance of 14.0 percent (517 billion kWh).(3) In comparison with generation levels of 1998, utility generation declined by 1.2 percent. In contrast, nonutility generation increased by 27.5 percent to 517 billion kWh in 1999, compared with 406 kWh in 1998. These developments are attributable to the acquisition by nonutilities of generating assets divested by the investor-owned utilities as a part of the ongoing restructuring process. Nonutilities also added 6,769 megawatts (MW) to their capability by bringing 67 new plants on line.(4)
| Table 1. Summary of U.S. Electric Power Statistics, 1999 and 1998 | ||
|---|---|---|
| Item | 1999 | 1998a |
| Capabilityb (megawatts) | 785,990 | 775,885 |
| Utility | 639,143 | 686,692 |
| Nonutility | 146,846 | 89,193 |
| Net Generationc (billion kilowatthours) | 3,691 | 3,618 |
| Utility | 3,174 | 3,212 |
| Nonutility | 517 | 406 |
| Utility Retail Salesb,d (billion kilowatthours) | 3,296 | 3,240 |
| Utility Retail Pricesb (cents per kilowatthour) | 6.60 | 6.74 |
| Stocks | ||
| Coal (million short tons) | 143 | 121 |
| Utilityc | 128 | 121 |
| Nonutilityb | 14 | NA |
| Petroleum (million barrels) | 53 | 54 |
| Utilityc | 44 | 54 |
| Nonutilityb | 9 | NA |
| Utility Fossil Fuel Consumptionc | ||
| Coal (million short tons) | 894 | 911 |
| Petroleum (million barrels) | 144 | 179 |
| Gas (billion cubic feet) | 3,113 | 3,258 |
| Nonutility Fossil Fuel Consumptionb | ||
| Coal (million short tons) | 62 | 57 |
| Petroleum (million barrels) | 43 | 54 |
| Gas (billion cubic feet) | 3,752 | 3,547 |
| Utility Fossil Fuel Costa (dollars per million Btu) | ||
| Coal | 1.22 | 1.25 |
| Petroleum | 2.53 | 2.14 |
| Gas | 2.57 | 2.38 |
| Utility Fossil Fuel Receiptsa | ||
| Coal (million short tons) | 908 | 929 |
| Petroleum (million barrels) | 131 | 165 |
| Gas (billion cubic feet) | 2,809 | 2,923 |
| aData are final.
bData for 1999 are preliminary. cData for 1999 are final. dDoes not include retail sales by all energy service providers (power marketers). Those sales are estimated to total 49 billion kilowatthours in 1999. In 1998, power marketer sales were 24 billion kilowatthours. NA = Not available. Btu = British Thermal Unit. Notes: Except for generation, data exclude petroleum coke. Petroleum coke stocks (thousand short tons) at the end of the year were: utility - 355 (1999), 559 (1998) and nonutility - 143 (1999). Petroleum coke consumption (thousand short tons) was: utility - 1,608 (1999), 1,769 (1998) and nonutility - 3,082 (1999), 4,447 (1998). Utility petroleum coke cost (on a per-million-Btu basis) was 65.4 cents in 1999 (preliminary) and 71.2 cents in 1998 (final). •Utility petroleum coke receipts were 2,906 thousand short tons in 1999 and 3,217 thousand short tons in 1998. •Nonutility data for 1998 represent fuels consumed to produce both electricity and steam. •Totals may not equal sum of components due to independent rounding. Source: Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels, Electric Power Division. |
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Electricity generation is geared to meeting customer demands instantaneously. Therefore, a positive correlation exists between changes in the level of generation and the level of retail sales. Accordingly, compared with 1998, retail sales increased to 3,296 billion kWh (1.7 percent) in tandem with the 1999 increase in generation.(5)
In 1999, wholesale prices spiked in certain areas of the country (as in 1998), reaching $6,000 per megawatthour (MWh) in the Midwest. Price surges (or spikes) have been observed in various parts of the country each year since 1998. A recent report released by the FERC(6) shows that similar surges in prices were evident for ancillary services.(7) According to FERC, factors contributing to these price spikes include:
- Weather (1999 was the second warmest year of this century for the United States)
- Capacity
- Deliverability
- Market manipulation.(8)
The price volatility in the wholesale electricity market during 1999 was not observed in the retail market. Generally, retail rates for electricity are regulated by State utility commissions; and as a consequence, utilities cannot automatically recoup higher costs incurred in the wholesale market through increased retail rates.(9) Average retail prices in 1999 were 6.60 cents per kWh, as compared to an average of 6.74 cents per kWh in 1998.
Endnotes
1. For more detailed information on the changing electric power industry see the Energy Information Administration, Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996) and The Changing Structure of the Electric Power Industry: Selected Issues, 1998, DOE/EIA-0562(98) (Washington, DC, July 1998).
2. The 24 States are Arizona, Arkansas, California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas, Virginia, and West Virginia. For further details on State deregulation activities see the EIA Web Site at: www.eia.doe.gov/gov/fuelelectric.html.
3. Utilities generally consist of investor-owned utilities, Federally owned utilities, other publicly owned utilities, and cooperatively owned utilities); nonutilities consist of cogenerators, small power producers, exempt wholesale generators, other cogenerators and noncogenerators not qualified under the Public Utility Policies Act of 1978. This classification is used throughout our discussion in this publication.
4. All capability values shown in this report are net summer and all capacity is installed nameplate. Capability values for 1999 are estimated; final values are to be released in the Inventory of Electric Utility Power Plants in the United States 2000, DOE/EIA-0095 and Inventory of Nonutility Power Plants in the United States 1999, DOE/EIA-0095.
5. As a result of deregulation occurring in several States, total sales in the retail market by all energy service providers have not been captured. Consequently, the growth in sales is underestimated, in particular for the commercial and industrial sectors. For detailed data on electric utility retail sales, see Appendix A.
6. Federal Energy Regulatory Commission, State of the Markets 2000-Measuring Performance in Energy Market Regulation (March 2000).
7. Ancillary services are those services necessary to support the transmission of electric power from seller to purchaser. These services range from actions taken to effect the transaction (such as scheduling and dispatching services) to services that are necessary to maintain the integrity of the transmission system (such as load following, reactive power support, and system protection services). Ancillary services are also needed to offset effects associated with undertaking a transaction (such as loss compensation and energy imbalance service).
8. Network industries, like the electric power industry, are interconnected and are subject to constraints on the physical capability to deliver power. These characteristics significantly influence formation of different price categories. The present volatility, as witnessed in 1998 and 1999, stems from conditions prevailing in a market that is still in rudimentary stages of development.
9. Franchised territory of San Diego Gas and Electric (SDG&E) in Southern California constitutes an exception to this statement. SDG&E's
rates are currently based on market rates for the power it buys in the wholesale market.