Electric Utility Restructuring
Briefing Book
Congressional Research Service Library of Congress
Redistributed as a service of the National Library for the Environment

California Overview

Amy Abel


Chronology | Air Quality Issues |

The Plan

In 1996, California adopted Assembly Bill (AB) 1890, a state electricity restructuring plan to allow for retail competition. The restructuring plan separated the major functions of electric service (generation, transmission, and distribution). Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E) divested of most of their generating capacity to address market power concerns.

The law gave residential and small commercial customers (a customer that has a maximum peak demand of less than 20 kilowatts (kW)) a 10% rate reduction that began on January 1, 1998, and will extend through December 31, 2002. In addition, retail rates were capped through a transition period that extended either through 2002 or until the utility had recovered its stranded costs. AB 1890 also set up procedures giving retail customers the ability to buy electricity either from their incumbent utility or another electricity supplier. In addition to PG&E, SCE, and SDG&E, retail customers of Southern California Water Company Bear Valley District, Kirkwood Gas and Electric, and the California customers of Sierra Pacific Power and PacifiCorp are now able to buy electricity from their incumbent utility or from a non-utility electric service provider. PG&E and SCE are still in this transition period. However, SDG&E has already recovered its stranded costs and now charges market rates to its retail customers.

Independent System Operator and Power Exchange

The California Independent System Operator (ISO) can be likened to an "electron traffic cop". The ISO ensures that all generators have equal opportunity to send their electricity through the transmission system to their customers. It began operation on March 31, 1998, with the mission to "ensure the power grid is safe and reliable and that there is a competitive market for electricity in California." Investor-owned utilities (IOUs) are mandated by state law to release control, but not ownership, of their long-distance transmission lines to the ISO. Currently, the ISO has three transmission owners: Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric. The California restructuring law guarantees that all power marketers doing business in California have the opportunity to generate and/or deliver power over the state's electricity grid. The ISO-controlled portion of the California grid covers 75 percent of the state (see map).

The California ISO manages congestion through pricing. The ISO calculates the cost of congestion and allocates these costs to the appropriate transmission user. The transmission access charges are based on the embedded costs of the transmission owner serving the customer. The ISO procures ancillary services. Ancillary services are services that are necessary to support the transmission of electricity while maintaining reliable operation of the transmission provider's transmission system. Examples include voltage control, reactive power dispatch, spinning reserve, quick-start reserve, and load following. In addition, the ISO manages the ancillary services, real-time imbalance, and congestion markets. The ISO leads a coordinated process for transmission planning. The Federal Energy Regulatory Commission (FERC) regulates the ISO.

Operating separately from the ISO, the California Power Exchange (PX) was set up to manage the day-ahead and hour-ahead markets. Under AB 1890, the three major utilities were required to purchase all of their power needs through the PX, a spot market for electricity. The restructuring plan did not allow the utilities to enter into long-term contracts for electricity supply. The PX matched the sales bids with purchase requests submitted by utility distribution companies and electric service providers. The utility distribution companies were required to use the PX during the transition period. The 1996 restructuring law did not include wholesale price caps, only the retail price caps. The power exchange is regulated by FERC. FERC's December 15, 2000 Order eliminated the mandatory buy/sell requirement for utilities and the Order actually precluded the IOUs from selling all but their surplus generation into the PX (or any other wholesale) markets.

Current Situation

In 1996, California had relatively low natural gas prices, excess generating capacity and market forces were expected to encourage sufficient capacity additions to match any increase in demand. Under the restructuring plan, the major utilities were not allowed to enter into long-term contracts for electricity supply. The PX was supposed to allow utilities to take advantage of these market parameters. However, by relying on the spot market, the utilities had limited options to manage the risk of a market that developed supply constraints and increased fuel costs.

In California, wholesale electricity prices have risen dramatically, leaving the utilities few options since the retail rates are capped. PG&E has stated that in 2000 it was unable to recover $6.6 billion of its electricity costs; SCE has stated it was unable to recover $4.5 billion. As a result, PG&E has filed for bankruptcy. Wholesale prices on December 15, 2000, ranged from $429 per MWh to $565 per MWh. As a comparison, on December 15, 1998, wholesale prices ranged from $12 per MWh to $29 per MWh.

On the federal level, then-Secretary of Energy Richardson issued an emergency order on December 14, 2000, that required certain generators in neighboring states to ship excess power to California. Another reaction has been to allow the utilities to enter into long-term contracts. On December 15, 2000, FERC issued an order that among other things, will eliminate the PX spot market. The PX has filed an emergency petition with the United States Court of Appeals for the Ninth Circuit requesting a stay and rehearing of the FERC order from December 15, 2000. On May 11, 2001, the U.S. Court of Appeals for the Ninth Circuit denied the PX's petition.

On January 19, 2001, the management of the PX declared the PX "extinct" and immediately reduced the workforce by 15%. That day, January 19, 2001, 30,700 MWH were traded on the PX compared to prior daily loads as high as 530,000 MWH. On the same day, Gov. Davis signed an emergency bill granting the state authority to make large-scale purchases of electricity; $400 million was allocated for power purchases, enough for approximately one week's purchases. On January 23, 2001, Energy Secretary Abraham extended the emergency order requiring certain electricity suppliers to ship excess power to California. This order expired on February 7, 2001. On February 9, 2001, U.S. District Judge Frank C. Damrell extended a temporary restraining order he issued on February 6 that ensures that three major suppliers of electricity will continue to provide 4,000 megawatts of power. (See Chronology for additional details)

Supply And Demand

California generates approximately 82% of its electricity needs and imports the rest from neighboring states. California has existing generation capacity of 45,025 MW. Natural gas is used to produce approximately 30 percent of California's electricity generation. In 1996, when restructuring began in California, electric utilities paid approximately $2.75 per thousand cubic feet of natural gas. During the week of January 16 through 19, 2001, natural gas prices ranged from $8.85 per thousand cubic feet to $15.35 per thousand cubic feet. At the highest rate, this translates to an increase in fuel prices for natural gas-fired plants of approximately 450%. During the week of April 30, 2001, natural gas prices ranged from $5.05 to $14.50 per thousand cubic feet. (For additional information on natural gas see, California: Natural Gas)

Electricity imports have been declining in recent years as demand in neighboring states has increased. Since the three major California utilities were not allowed to enter into bilateral long-term contracts, out-of-state generators were under no obligation to provide power to the California utilities. The Secretary of Energy's emergency order requires certain utilities to ship their surplus power to California. Some of these utilities have expressed concerns that they may not be paid for these power shipments because of the precarious financial situation of PG&E and SCE.

No new major power plants have been built in California since before restructuring took place. However, in the four years between 1996 and 2000 electricity consumption grew by approximately 9 percent. Between 1990 and 2000 electricity demand grew by approximately 15 percent (see Table 1). By 2002, approximately 6,300 MW of new capacity is expected to come on line (see Table 2). Some experts argue that an additional 10,000 MW of new capacity is needed. On the other hand, the California Energy Commission predicted in November, 2000 that there is only a 1 in 10 chance that electricity demand will exceed capacity resources during the summer of 2001.

Electricity conservation is one way to mitigate demand. Existing conservation programs in California currently back-out approximately 9,000 MW of electric generating capacity - which means that if these conservation measures were not taken, an additional 9,000 MW of capacity would be needed. In Appendix F of a recent report, the California Energy Commission estimates that existing programs will back-out approximately 8,500 MW of generating capacity by 2005, a 500 MW decline from 2001. These figures do not include potential or "uncommitted" energy efficiency programs or dispatchable load management programs. The data suggest that without additional energy conservation initiatives, energy savings will decline gradually and could require additional generating units to satisfy demand. With price caps, consumers are not receiving adequate price signals to encourage conservation.

Recently, up to 15,000 MW of generation capacity has been off-line for maintenance. Some have argued that some of this maintenance may have been unneeded and was used to influence the price of electricity. None of these allegations have been proven although the California Public Utility Commission and FERC are investigating market power abuse allegations. However, out of total of 45,000 MW of generating capacity within California, 18,000 MW of generating facilities are 30 years old and 8,000 MW are from plants that are 40 years old. It can be expected that plants of this age will require more maintenance than newer facilities.

Transmission.

One constraint in California's electricity supply is the transmission system. Unlike wholesale sales of electricity, the transmission and distribution components of the electricity market are still rate regulated. In the past, California provided a 10% rate of return for transmission investment, but this has not been adequate to encourage construction of new lines. One of the main transmission constraints is on a line between Northern and Southern California called Path 15 (between Gates and Los Banos). In its 2001 Summer Assessment, the California ISO reported that between April 1, 1998, and January 15, 2001, there were 226 incidents where the flow on Path 15 exceeded the south-to-north stability limits. Of these 226 overloads, 51 were for a period longer than 10 minutes. As a result, electricity has been diverted to other transmission lines to move power from south of Path 15 to north of Path 15. Frequently, electricity has been routed from Southern California through Nevada and Oregon and through the DC-intertie between Northern California and Oregon. In addition, the Independent System Operator (ISO) concluded that for the period between September 1999, and December 2000, congestion on Path 15 cost consumers $221.7 million.

Recently, the ISO issued a draft report that identified some of the transmission system constraints that are projected through 2002. The report states that Pacific Gas and Electric (PG&E) and the ISO are working to increase the transfer capability on this transmission line. This would allow additional transfers from Southern California to the more supply constrained Northern California. If the expansion project proceeds, it could be built in three years at an estimated cost of $200 million to $250 million, according to the director of grid planning at the ISO. To overcome the constraints on Path 15, officials have routinely tapped hydroelectric power sources in the Sierra and the Pacific Northwest.

On March 29, 2001, California's Public Utility Commission's president, Loretta Lynch, issued a ruling directing PG&E to file for authority to improve Path 15 to alleviate existing constraints. PG&E filed a Conditional Application on April 13, 2001. PG&E stated in its application that it is "conditional" because PG&E management has not approved the project.

On May 10, 2001, the House Energy and Commerce Subcommittee on Energy and Air Quality approved H.R. 1647, the Electricity Emergency Assistance Act. Section 104 authorizes the Administrator of the Western Area Power Administration (WAPA) to expand its transmission system to eliminate the Path 15 constraint. The expansion costs would be recovered by WAPA through transmission fees. The Department of Energy cites 16 U.S.C. 837g-1 as WAPA's authority to construct such a transmission line. The statute reads:

Notwithstanding the provisions of section 837g of this title, the Secretary of Energy is authorized to construct or participate in the construction of such additional facilities as he deems necessary to allow mutually beneficial power sales between the Pacific Northwest and California and to accept funds contributed by non-Federal entities for that purpose.

This would expand the traditional role of the Power Administrations from marketing federal power to alleviating constraints created by the lack of capacity on an investor-owned transmission line in that utility's service territory. Construction of transmission infrastructure by WAPA could be redundant if PG&E does undertake expansion of Path 15.

Northwest Hydroelectric Issues.

Increased demand for power during the winter months in the Northwest combined with low fall and winter runoff levels have river operators and the Bonneville Power Administration (BPA) concerned about trade-offs among power generation now and the ability of reservoirs to refill in time to meet other needs, such as threatened and endangered species and irrigation demands. These lower-than-desired flows have forced BPA into "purchasing power at incredibly high prices." According to the BPA, the current operational decisions have been made to "meet the Northwest's needs, not California's."

Generally during the winter months the Northwest would receive power from California, to be returned later in the year. The fact that the Northwest is not getting the anticipated California power this time of year, combined with low fall runoff, abnormally low snowpack, and lower than normal projections for precipitation in coming months, make the Northwest's power situation worse than it would be in most years. According to Steve Wright, acting BPA administrator, the power being supplied to California in recent weeks has been through a 2-for-1 exchange and as of January 18, 2001, California had returned 170 percent of the power sent through the exchange. Whether reservoir levels will be adequate to meet BPA's needs and California's later in the year remains to be seen. California may not lay claim to water resources required for generation of electricity that BPA requires to service its customer base. However, recent federal emergency power orders have required BPA and other Northwest utilities to sell "surplus" power to California. Water flow requirements to protect endangered species would not necessarily take priority over a federal emergency power order to provide assistance to California. The BPA believes current operations are consistent with the Biological Opinion of the National Marine Fisheries Service on salmon management because operations of projects beyond targeted flow levels is allowed under limited circumstances.

Table 1. California Electricity Consumption by Sector (million kilowatt hours)

Year Residential Commercial Industrial Agricultural Other All Sectors
1990 67,669 74,562 51,195 20,849 13,763 228,038
1992 69,227 77,929 49,926 15,483 14,423 226,988
1994 69,781 78,546 49,524 16,957 15,290 230,097
1996 72,166 83,366 51,758 16,898 15,415 239,603
1998 75,388 87,093 51,996 14,661 15,270 244,409
2000
(estimate)
77,564 91,771 55,020 18,054 15,462 257,871

Source: California Energy Commission

Table 2. New Capacity Additions

Project Applicant/Host Size
(megawatts)
Fuel Type Capital Cost Location Approval date Estimated Completion Date
Delta Energy Center Calpine and Bechtel 880 Natural Gas $350 million Pittsburg, Contra Costa County 2/9/00 7/02
Elk Hills Sempra/OXY 500 Natural Gas $300 million Elk Hills, Kern County 12/06/00 12/02
High Desert Inland Group and Constellation Energy 720 Natural Gas $350 million Victorville, San Bernardino County 5/3/00 4/01
La Paloma PG&E National Energy Group 1,043 Natural Gas $500 million McKittrick area, Kern County 10/6/99 3/02
Los Medanos Energy Center Calpine 500 Natural Gas $300 million Pittsburg, Contra Coasta County 8/17/99 7/01
Moss Landing Duke Energy 1,060 Natural Gas $475 million Moss Landing, Monetery County 10/25/00 6/02
Pastoria Enron 750 Natural Gas $350 million Tejon Ranch, Kern County 12/20/00 N/A
Sunrise Power Project Texaco Global Gas & Power 320 Natural Gas $200 million Fellows, Kern County 12/6/00 8/01
Sutter Power Calpine 500 Natural Gas $275 million Yuba City area, Sutter County 4/14/99 7/01
Total -- 6,273 -- -- -- -- --

Source: California Energy Commission

Web Sites

California Energy Commission Electricity Page

California Environmental Protection Agency Permits

California Independent System Operator

California Natural Gas Market Conditions

California Power Exchange

Treasury Department Press Release Following the Meetings on California's Electricity Situation (1/10/01)

Page last updated May 25, 2001.

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