The California Memorandum of Understanding (MOU) is an agreement between Southern California Edison Co. (SCE), the California Manufacturers' Association, the California Large Energy Consumers' Association, and the Independent Energy Producers. It tackles three major issues:s recovery of stranded assets
s market power
s market structure.
If the MOU is eventually endorsed, it might be a landmark in electric restructuring \(em and not only in California. But there would still be a long way to go.
By far the most significant item on the agenda of California's investor-owned utilities (IOUs) is the recovery of potentially stranded assets: nuclear power that is not too cheap to meter, expensive contracts with qualifying facilities (QFs) under the Public Utility Regulatory Policies Act (PURPA), and other costs (such as nuclear decommissioning). In the MOU "the parties agree in principle that, as the industry makes the transition to a new competitive market structure, SCE should fully recover its prudently incurred past investments and obligations made to fulfill its historical obligation to serve." This proposition should warm the cockles of IOU management and shareholders throughout the nation.
The parties favor a nonbypassable, Competitive Transition Charge (CTC) as a condition to restructuring. The CTC would be levied on all customers connected to the system, and imposed either on distribution, or on meters, or as a general surcharge (analogous to the nuclear levy in Britain). The CTC would enable SCE to recover the difference between the charges authorized under performance-based ratemaking (PBR) and other arrangements for the cost of the stranded assets and the market price. The CTC would run until 2004 for the generation assets, until 2005 for QF contracts, and until 2013 for the rest. At the end of this period, there would be a final CTC based on the difference between the "market-valued price" and the net book value of the assets. The CTC should enjoy state legislative backing and stand challenge-proof. To further that end, the Federal Energy Regulatory Commission (FERC) would define what qualifies as distribution facilities within California jurisdiction.
Special arrangements are proposed for SCE's share of the nuclear plant at San Onofre units 2 and 3 (1,600 megawatts (Mw)) and at Palo Verde (600 Mw): Depreciation will be accelerated so that they are written off by 2004, and SCE will accept a reduced rate of return. SCE proposes to offer its interest in Palo Verde for sale within five years of the start of the new market. Once sold, the plant owner will be free to market output without regulation. If the sale proceeds are negative, the shortfall will be added to the CTC.
SCE also proposes to develop and implement a PBR mechanism for its fossil plants (12,000 Mw) by 1997. The PBR will promote efficient plant operation and mitigate the exercise of market power during the transition period. At the same time, SCE will be allowed to release tranches of plant into the market \(em 10 percent by the end of the second year, and 100 percent by the end of the fifth. SCE will also develop a PBR mechanism for its hydro facilities (1,000 Mw); any difference from market revenues will credited or debited to the CTC.
The FERC and the U.S. Department of Justice are both concerned \(em if not
obsessed \(em with market power. The Mega NOPR proposes that while new plant will be free to compete, utilities will first have to prove that their existing portfolio of plant cannot exercise market power. The parties to the MOU "understand that the FERC will not consent to market-based pricing if unacceptable market power exists or is unmitigated." SCE suggests that the PBR mechanisms to cap revenue should eliminate or at least mitigate market power.
Although contracts can mitigate short-term market power, the British experience \(em as shown by National Power and PowerGen \(em demonstrates that there are games to be played. In Britain, those two generating companies reached an understanding with the regulator to keep the time-weighted (base load) and system-weighted prices below certain levels for two years. Yet, with increases in the peakiness of the price-duration curve, their profits increased. No doubt, games could be played in California to boost profits for some at the expense of others by profiling the price-distribution curve.
If the PBR cap does not work adequately, then SCE "is committed to working with the FERC and the CPUC to identify and achieve these mitigation measures in the fastest and least disruptive way possible," which may include divestiture. If divestiture of generation is required, the gain or loss on sale compared with the net book value will be netted against the CTC.
(Note: the MOU focuses on lateral market power in generation, but says nothing about the vertical market power from the link between generation and customers.)
While the big short-term dollars in restructuring lie with stranded assets, the noisy (and generally ill-informed) debate has staked out the issue of PoolCo versus bilateral trading.
At first Pacific Gas & Electric Co. (PG&E) supported bilateral trading, joined by power marketers and large customers. By contrast, SCE, San Diego Gas & Electric Co. (SDG&E), and a majority of CPUC commissioners supported PoolCo, which would comprise both a system operator and a framework for a day-ahead market (through a sealed bid, single-price auction).1 PoolCo would act in a nondiscriminatory, pro bono publico manner, with no financial interest in general power trading. It would procure ancillary services, and submit to FERC regulation.
Later on, PG&E agreed to participate in the development of a PoolCo. In July, both SCE and SDG&E proposed a "flexible pool" that would allow bilateral trading outside the pool. This approach appears sensible on political grounds \(em it squares off the large customers and independent power producers (IPPs) \(em and avoids a possible legal challenge to a mandated pool. It also provides a measure of competition to ensure that ancillary services will be priced in a nondiscriminatory and appropriate manner, and brings a modicum of pressure to bear on PoolCo's efficiency of operation.
The large customers, independent power producers, and power marketers were concerned that there might be an internal conflict between PoolCo's roles of providing a market and operating the system. (Namely, it might be tempted to provide lower prices to its market by favoring its transactions when scheduling across constraints compared with bilateral trades.) Although proper governance and a FERC-approved nondiscriminatory code should prevent such bias, they demanded a clear separation between monopoly and market activities, as in the gas market. Rather than one "black box" that was supposed to act pro bono publico, they wanted two black boxes with a transparent interface.
At the behest of the large consumers and power marketers, the MOU proposes splitting the PoolCo into two organizations \(em an independent system operator (ISO) and a power exchange (WEPEX) \(em which would both operate under FERC regulation in a fiduciary manner, with no financial interest in power trading. Power generators, local distribution companies, and large customers (acting independently or by aggregation) would conduct business through WEPEX (using Contracts for Differences to hedge risk), or would contract directly on a bilateral basis. The MOU proposes a four-year schedule for direct access, depending upon customer size:
s 8 megawatts (Mw) or greater in 1998
s 2 Mw in 1999
s 500 kilowatts (Kw) in 2000
s 100 Kw in 2001
s 50 Kw in 2002.
Customers with multiple sites could aggregate internally to qualify for the competitive market.
The WEPEX would conduct an auction in a manner similar to the flexible PoolCo. The ISO would then schedule both the WEPEX trades and the bilateral trades, and would manage constraints based on preferred schedules, reliability factors, real-time load balancing, and other operational requirements. When constraints arise, the ISO will allocate access to the transmission grid, based on nondiscriminatory comparable protocols approved by the FERC to make "the most efficient use of scarce network capacity."
The ISO would price imbalances in bilateral trades at its cost of procuring power, which would be the WEPEX price rather than a penalty (as is done for gas pipelines and was proposed by the FERC in its Mega-NOPR). This arrangement would eliminate one source of distorted price signals and remove one disadvantage for small players in the market. The ISO would offer FERC-approved, nondiscriminatory transmission tariffs for both WEPEX and bilateral transactions.
Theory and Practice
In principle, the proposed split between the ISO and WEPEX could function virtually identically to a single PoolCo; the institutional divide would prove only cosmetic. If WEPEX is designed as an efficient pool, and the transmission pricing and constraint management arrangements are economically and equitably devised, then the WEPEX price will drive short-term contract prices for both contracts for differences and bilateral contracts. There should then be no advantage in the latter, but rather, strong incentives to trade via the exchange. But in practice, the key lies in managing constraint scheduling and transmission pricing. Since constraints are neither precise nor fixed \(em and depend upon what happens in other parts of the system \(em any opportunities to profit from system inefficiency will depend upon how well the ISO can integrate the two sets of schedules. The MOU is an outline only. It does not touch on governance nor on how to incentivize the ISO. In England and Wales, the ISO was initially expected to influence only one percent of system costs. But with cost-plus passthroughs and lack of responsibility for management, that share has increased to 10 percent.
At this point, the philosophical stage of restructuring may be over. Now begins the serious negotiation. But few realize how complex those talks will be. (If we in Britain can construct a PoolCo with a 1,000-page contract, think how many more pages U.S. attorneys can manage.) At the end, the whole thing could be left lying on the floor, as was our restructuring in July 1989, after a failed attempt to develop a PoolCo. The government (with political face at state) and the players (eyeing their stock options) then picked it up and developed a PoolCo that today more or less works.
The only three PoolCos in the world \(em England & Wales, Argentina, and the State of Victoria in
Australia \(em have been created to the agenda of government, with government acting as project manager and arbiter of irreconcilable points of view. Will the CPUC be able to deliver in a more complex plural environment? t
Alex Henney is director of EEE Ltd. in London, and has consulted on electricity restructuring in many countries, including the United States. He is the author of A Study of the Privatisation of the Electricity Supply Industry in England and Wales.1. That is, all successful are paid the price bid by the last generating unit.
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