The dual crises – the electricity crisis and the financial crisis – motivated many “reforms of the reforms.” Some changes occurred during the crisis, other have been being implemented in the years since the crisis was over.
Fundamental Market Flaws
Happily, the most fundamental market flaws – the reliance on spot markets and the retail price controls – have been repaired.
The inappropriate over-reliance on spot markets has been eliminated. Utilities are no longer relying on spot market purchases for other than small fractions of electricity purchases. Almost all of their electricity is acquired through a combination of self-generation (dominantly, but not entirely, from generating units in existence before the crisis), from the long-term contracts negotiated by the DWR, and from QF contracts from before the crisis. A few new shorter-term contracts have been entered by the utilities.
Very little other electricity is being transacted on the organized spot markets. The PX is defunct; no electricity has been sold on that market since 2001. Real time purchases on the CAISO are sharply reduced from during the crises, since IOUs are no longer systematically under-
scheduling on those markets. The FERC has instituted penalties for under-scheduling into the CAISO and the IOUs, with most of their electricity purchased on term markets have no incentive to try exercising market power through under-scheduling.
The CPUC has ordered resource adequacy rules for IOUs, including minimum planning reserve margins of 15%. At least 90% of the necessary resources must be acquired at least one year in
advance67. This represents a fundamental shift in the regulations, a shift motivated by the
experiences of the crisis.
Retail price controls no longer are operational; normal ratemaking procedures now govern retail pricing. Of course, normal procedures do not allow wholesale market price fluctuations to be quickly incorporated into retail prices. Thus, short-run demand functions for electricity still are quite unresponsive to wholesale price changes. However, longer-term trends in cost changes can be incorporated into retail rates. This possibility allows demand functions to adjust over the course of a few months to changes in wholesale prices and it helps assure that IOUs will not face
a similar financial crisis if wholesale prices do systematically increase68.
Retail Competition on Hold
During the crises, the California legislature recognized that the long-term power purchase contracts, then being signed by the DWR, would obligate the State to acquire those contractual quantities of electricity. They further recognized that after the crises were over, the contracts
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However some of the contracts seem to not be based on identifiable generating assets, but rather liquidated damage contracts. Liquidated damages will protect the utility but will not necessarily assure adequate supplies of electricity. Regulatory rule making in this area is continuing.
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At the time of this writing, natural gas prices at Henry Hub have increased to $14/mcf, up from $6.50 one year ago. This will increase the electricity generation costs and therefore can be expected to increase retail rates.
would become obligations of the utilities to purchase the bulk power. In order to protect the State and the utilities from risks that the contractual power would either be a greater quantity than needed by the utilities or at an uncompetitively high price, the legislature passed a law suspending the right for electricity users to enter new direct access contracts. This suspension of all retail competition would last as long as the state contracts were still operational, until roughly 2015. As originally envisioned, this law would preclude companies and individuals from
entering contracts to purchase electricity, except from their local utilities or from municipalities. Subsequently, the CPUC established some limited opportunity for firms to enter direct-access contracts, bypassing the utilities, if those firms paid an “exit fee”, designed to cover that firm’s share of the historical costs. This law and the CPUC implementing rules assure that the costs of the DWR long-term contracts would be recovered from ratepayers.
Governor Schwarzenegger has supported the reopening of direct access to acquire electricity, through a “core/non-core” structure in which large users of electricity would be able to enter direct access contracts, but smaller “core” customers would rely on the utility to supply
electricity69. Such a regulatory change is still under debate. In the meanwhile, there now is no
effective retail competition.
Electricity Demand Measures
The CPUC, the CEC, and utilities, are developing and implementing systems to improve electricity consumption response to changing conditions. Demand management contracts have been entered with large commercial and industrial users of electricity. Some contractually require those users to curtail use of electricity when conditions are tight; others give the utility the ability to remotely curtail that use. Additional demand response mechanisms are under debate or experimentation. However, much more research and policy analysis is needed to increase the short-run and the longer-run demand response to wholesale prices. This is particularly important because the current market structure so severely blunts the connection between hourly wholesale prices and the retail prices that most consumers face.
A second approach is tighten the connection between hourly wholesale prices and the retail prices, possibly through real-time pricing, or some variant of real time pricing, such as critical peak pricing. Experiments are underway to test real-time pricing. Interval meters have been installed in facilities of the largest industrial users, allowing the possibility of real time pricing. Tariffs that include variants of real time pricing for electricity have been developed and tested, but have not been broadly implemented. PG&E and SDG&E have proposed to deployed advanced meters to all customers over the coming years.
The significance of demand response can be seen in Figure 19, developed by the CEC, which estimates peak demands for electricity in California for the various usage categories. Almost 30% of the peak demand is for residential or commercial air conditioning. This use, in principle, can be shifted significantly over time within the course of a day. However, absent incentives or controls to do so, there is no reason to expect that a large fraction of this load will shift away from the times of the greatest demands on the system. With appropriate incentives, and with appropriate information technology, such uses can be shifted in time so as to optimize the overall
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system, reducing the costs at the highest peak loads, and reducing the need for new peaker power plants.
California is continuing and expanding its emphasis on longer-term energy efficiency measures. Energy efficiency programs organized through the IOUs have been expanded through a CPUC rulemaking process. The State of California continues its “Flex Your Power” publicity
campaign, providing information about and encouragement for energy efficiency. The Governor has ordered all State-owned building to be managed so as to meet minimum energy efficiency standards. New appliance efficiency standards have been established; others are under consideration. Energy efficiency in incorporated into California building standards and
additional rulemaking can be expected. These actions collectively can be expected to continue the trend of per-capita electricity use in California growing significantly less rapidly than in the rest of the United States.
IOU Wholesale Electricity Procurement
CPUC has recently established rules that now require IOUs to acquire new electricity supplies through a competitive process, intended to level the playing field across different potential suppliers of electricity, in particular between IOU self-supply of electricity and IPP generation. Such a competitive procurement process increases the probability that the utility portfolio will be based on minimum cost, for the given risk, reliability, and environmental performance. But such
rules do not eliminate the incentive70 for utilities to purchase from themselves in preference to
IPPs; the rules simply make it more difficult for the utilities to act in accordance with that
incentive. Moreover, the rules can be applied to allow the utilities to exercise market power over
existing generators that do not yet have long-term contracts to sell their power71. However, the
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IOUs are not compensated for the credit risk they take on when they enter long-term contracts, although they are compensated for risks when they build their own plants. This provides an incentive to avoid long-term contracts in favor of self-generation. Most of the IPPs are in difficult financial situation, so that there is risk of long-term contracts with these entities. Regulatory uncertainty makes long-term commitments risky, but whether long-term contracts with IPPs are more risky than construction of utility-owned generation is unclear. Finally, though, utilities earn a regulated rate of return on own-generation; they do not earn a return on contracts.
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For example, the ongoing PG&E procurement process excludes already completed IPP plants, such as the Calpine Metcalf plant, from bidding to supply electricity. This restriction is being negotiated at the time of the Figure 19. California Peak Demands by Usage Category
alternatives – simply ban the utilities from any self-generation or any new self-generation – would create important dysfunctional incentives and would preclude utility self-generation when such an option was truly the best for consumers.
In addition, competition among wholesale buyers of electricity is currently very limited in California. Because California no longer has any meaningful retail competition in electricity markets, the IOUs are virtually the only wholesale electricity buyers in California. This market domination allows the IOUs to exercise market power over the IPPs. IPPs, understanding the dominance of the IOUs as buyers, are unlikely to start construction of new power plants, absent long-term contracts with the IOUs. Moreover, IOUs seem unwilling to enter long-term contracts with IPPs to purchase electricity. Thus while in principle wholesale procurement rules promote a level playing field, whether the field will turn out in practice to be truly level is not clear.
ISO Market Redesign
The CAISO is developing a new market design in order to correct flaws in California wholesale electricity markets. The current design includes nodal pricing for electricity, rather than the original zonal pricing, and firm marketable transmission rights. Market software to support the new market design is under development. But the process is very slow and costly. Originally entitled MD 02, for “Market Design 2002”, the process has been renamed, reflecting the reality of the process speed.
Capacity Incentives
It is generally realized that absent payment for providing unused generation capacity, electricity suppliers are unlikely to have economic incentives to invest in enough new capacity to assure that there will always be an adequate reserve margin of unused generation capacity. In order for generators to provide sufficient capacity to assure that they can cover very uncertain peak loads, they need incentives to do so.
One option is for generators to enter long-term contracts to sell a bundled combination of electricity and generation capacity, with the generation capacity some agreed-upon fraction greater than the expected electricity generation. But such a bundled combination would be more costly than an electricity-only contract. Thus, absent regulatory rules that require utilities to enter such bundled combinations, it is unlikely that such combinations could compete with electricity-only contracts.
even when it is not used. In periods of adequate electricity supply, the short-term prices for bulk power tend to be too low to repay the capital costs. In periods of short supply, in theory, prices might increase enough that these limited time periods could allow enough profits to cover the long-term capital costs. In practice, however, the electricity crisis has made it clear that
wholesale price mitigation can be expected. Such price mitigation measures virtually assure that generators could not repay the long-term capital costs through such short-time periods of short supply. In addition, generators can only wait a limited time to recover capital costs. The need to writing. But it does illustrate the ability of the IOU to adopt procurement rules that do not truly level the playing field, since PG&E does not exclude itself from acquiring electricity from its existing generation assets.
obtain financing through normal financial markets implies that waiting too long to recover capital costs may be a route to bankruptcy.
In response to this recognized problem, the State is examining how to create an electricity generation capacity market that would allow utilities and generators flexibility in meeting resource adequacy requirements. The market could include tradable capacity rights or
obligations. However, design is far from complete. Thus it is not clear when and whether such a market will be created.