California should maintain its commitment to retail energy competition but implement near-term fixes, said key industry stakeholders, including FERC Chairman Curt Hebert Jr., at XENERGY's 10th Executive Forum on Feb. 12. Their proposed solutions include:
- Increasing generation capacity
- Improving price signals to consumers
- Shoring up utility credit worthiness.
According to Hebert, the California energy crisis is one of basic economics, in which supply did not keep up with booming demand. Both he and President George W. Bush support competitive retail energy markets, he said, which have not been robust in California.
“What everyone needs to understand is that California markets have never been competitive and have never fully attempted to deregulate,” he said. “California cannot rely on a federal bailout and needs to solve its own energy problem. But, he cautioned, “bankruptcy (of the California utilities) must be avoided at all costs.”
Power price caps in the spot market are not the long-term answer, Hebert said, but he offered suggestions for potential market fixes that included discouraging reliance on spot markets, an emphasis on forward markets and a move toward transcos (for-profit transmission companies) in the states.
The market fix will not be without pain for customers, according to Stephen L. Baum, CEO of Sempra Energy in San Diego, California, who said there will most likely be a pass-through of power costs through rate increases.
Work Continues on California Path 15California Path 15 consists of two 500-kV circuits and four 230-kV circuits in central California, west of Fresno. This path is the determining link connecting Pacific Gas & Electric's (PG&E) service area to southern California. Essentially, this 3400-MW path is the sole medium to transfer power in a north-south direction, with the 45,000-MW peak load of the California market. Estimates state that in the last quarter of 2000, the constraints of this path to the California market cost at least US$50 million and possibly as much as US$300 million.
Because the 500-kV lines share the same corridor, any line loss must be considered a single outage event, during which the thermal limitations of 230-kV lines determine the post-contingency capability. At present, contingency management consists of several deterministic steps, such as dropping all water system pump loads in 1 sec or ramping down Diablo Canyon at 100 MW/min for 9 min. Even then, assuming worst-case weather conditions and a 60% preload, the 230-kV lines will reach the limiting temperature of 94°C (201°F) in 15 min.
PG&E reviewed options to provide further flexibility in addressing contingency situations. The utility recently installed real-time tension monitoring systems on the limiting 230-kV circuits of Path 15. These CAT-1 transmission line monitoring systems measure line tension, can calculate line temperature and sag, and provide real-time line operating information to PG&E's control center in San Francisco.
On Feb. 7, the California Energy Commission gave Valley Group Inc. in Ridgefield, Connecticut, U.S., a contract to develop related software and procedures for the CAT-1 systems to enable real-time contingency management of the path. The objective of this project is to increase the capabilities of the path by 10% to 20%, and to make at least some of the improvements available for the summer peak of 2001.
Northwest Energy Supply Remains PrecariousSupplies of energy in the Northwest remain on the “razor's edge” through the winter, according to numbers released by the Northwest Power Pool (NWPP). The figures make a strong case for continued energy conservation and constraint,” said Jerry Rust, president and director of the NWPP. “They leave us no cushion if the region hits an extreme cold spell.”
Based on aggregate numbers submitted to the NWPP from throughout the Northwest, electrical energy supplies for February are just a fraction of a percent short of the region's firm obligations to supply energy (known as load). For March, there is little improvement, with the numbers showing a fraction of a percent more energy than load.
- February energy adequacy: 99.668% of resources
- March energy adequacy: 100.777% of resources
These figures assume normal weather and a 15% unplanned generation outage rate. A major concern for regional energy planners is the water condition on the Northwest's hydro system. If dry conditions continue, this would be among the five lowest water years the Northwest has experienced since record keeping began. Estimates indicate that precipitation would have to be 151% of normal through July to bring reservoirs back up to average levels.
NWPP officials caution that if there is a cold spell or other event affecting the system, it does not automatically signal blackouts such as those that have occurred in California. In remarks at the Western Governor's Association Energy Policy Roundtable, Steve Wright, acting administrator of the Bonneville Power Administration (BPA), said a shortage would likely force federal river managers — the BPA, the Corps of Engineers and the Bureau of Reclamation — to run the hydro system harder by releasing more water to generate more electricity. In addition, it could send utilities into the wholesale spot market where prices are at unprecedented levels.
California's Rating Remains Negative on CreditWatchStandard and Poor's reports that California's double-‘A’ GO rating remains on CreditWatch with negative implications. The rating was retained following the additional appropriation on Feb. 14, 2001 of US$500 million of state general fund money to buy electrical power on behalf of Southern California Edison (SCE) and Pacific Gas & Electric Co. (PG&E). The rate retention also followed a proposal for the state to buy these utilities' electrical transmission lines. To date, the state has appropriated US$1.4 billion of general fund money, or 1.8% of general fund 2001 expenditures, to subsidize power purchases. An additional US$500 million appropriation may be necessary before the state's long-term solution is implemented.
California's proposed long-term solution to the current energy crisis involves the potential issuance of about US$10 billion of revenue bonds backed by a portion of retail utility bills and short-term bridge financing. The solution would take place prior to the issuance of the long-term debt for the payment of unpaid power bills. The state expects the revenue bonds to include repayment to the state general fund for its power sale contributions. SCE and PG&E would use bond proceeds to repay power generators for unpaid purchases of electricity.
An additional US$3 billion to $9 billion of revenue bonds could be issued at a later date to acquire SCE and PG&E's transmission lines under pending legislation. This second series of bonds also would be backed by a charge on retail electric users. Unpaid power purchases total more than US$12 billion.
The state's GO rating remains on CreditWatch with negative implications to reflect the uncertainties surrounding the magnitude of potential state general fund contributions before a long-term solution is implemented. It also reflects the potential effect on the state's economy and an examination of the additional financial obligations that may become necessary should the state acquire SCE and PG&E's transmission systems.
SCE and PG&E have been losing an estimated US$2 billion per month since last July due to a mismatch between the cost of power and revenue from retail rates. The state hopes to resolve these problems through:
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A US$10 billion revenue bond issue
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New long-term contracts to reduce the cost of power
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The implementation of the rate surcharge on electric users who consume more than 30% of a baseline formula.
The purchase of electric transmission lines would also provide additional cash to SCE and PG&E but is not expected to restore the utilities to their historically strong financial profiles.
The ratings for the proposed US$10 billion to $19 billion of revenue bonds will depend on the structure and sizing of the transactions, which have not yet been finalized, and the ability of the revenue streams to cover debt service.
Alabama Unlikely to Face California's ProblemsAccording to Alan Martin, Alabama Power's executive vice president, this Birmingham, Alabama, U.S.-based utility's situation is far different than California's. Therefore, it can only speculate about what has caused California's problems.
Martin adds, “Given what we do know and are continuing to learn, it is very unlikely Alabama Power will experience similar problems. It is important to remember that California has entered into a form of deregulation at the retail level. Alabama has chosen not to go in that direction at this time.
“We have a tremendous amount of respect for the Alabama Public Service Commission (PSC) and are confident they will continue to watch events unfold in California and other areas of the country, learn from them and make decisions according to best interests of all Alabamians.”
There are several issues that make the situation in California distinctly different from Alabama's:
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Alabama is not a deregulated state and there are no plans to deregulate at this time. The PSC conducted an extensive study of the issue and concluded, among other things, that deregulation is not in the public interest at this time. California residents are experiencing problems with prices and power supply as a result of deregulation.
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Alabama Power's prices fall well below the national average. Because Alabama is a low-cost state, its PSC does not see deregulation as a pressing issue, as have other high-cost states such as California, where proponents of deregulation believed it would lower costs.
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Alabama Power generates power from a variety of sources. Its plants tap energy from coal, oil, gas, hydroelectric and nuclear technology. That variety provides flexibility in times of high demand. California relies mostly on hydro and natural gas to fuel its plants. High natural gas prices and the drought have added to California's problems.
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Alabama Power's customers have the strength of the Southern Co. system and its 66 generating plants to help ensure availability, reliability and affordability. Alabama Power is building new plants and purchasing long-term wholesale power contracts to bolster its available resources in times of high usage and extreme weather. No new generation plants have been built in California in more than 10 years, and deregulation rules there prohibit long-term wholesale power contracts.
A Stage 1 Emergency notice is declared by the ISO any time it is clear that an operating reserve shortfall (less than the MORC minimum) is unavoidable, or when in real-time operations, the operating reserve is forecast to be less than the minimum after using available resources.
A Stage 2 Emergency notice is declared any time it is clear that an operating reserve shortfall (less than 5%) is unavoidable, or when in real-time operations, the operating reserve is forecast to be less than 5% after dispatching all available resources.
A Stage 3 Emergency notice is declared any time it is clear that an operating reserve shortfall (less than 1.5%) is unavoidable, or when in real-time operations, the operating reserve is forecast to be less than 1.5% after dispatching all available resources.
No Touch notices caution market participants to avoid actions that may unnecessarily jeopardize generator availability.
Source: California Independent System Operator
