ORACIONES COMPUESTAS SUBORDINADAS

State policy and Federal policy sharply conflicted during the crisis, making any solution even more difficult.

California political leaders emphasized direct government intervention in the market place, reliance on retail and wholesale price controls, plus strong regulatory intervention. The CPUC, by then with changed leadership, stopped trying to improve markets, strongly enforced retail price controls (which the State could control), and lobbied for wholesale price controls (which the State could not control.) The California Governor relied on a public relations campaign of blaming California’s electricity problems on the Federal government, including Federal

regulators, on electricity generators, on “deregulation”, all but on his own policy inaction. When the Governor and Legislature did respond to the financial crisis, their response relied on direct governmental wholesale purchases of electricity and negotiations to acquire assets of the utilities, increasing State participation in electricity markets.

Federal action, through FERC, though slow, sometimes misdirected, and inconsistent over time, seemed designed to address the underlying flaws in the market design and implementation and to strengthen the role of markets. FERC operated to reduce reliance on direct control of market transactions and market pricing.

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The bankruptcy of the PX had no impact on the market because all purchases, other than through the CAISO were through bilateral trades. The PX was no longer being used.

The State and FERC each had jurisdiction over important parts of the restructured system so neither could fully impose its views on the other and each needed actions of the other to be fully effective. The fundamental ideological differences were never fully resolved. However,

ultimately the FERC did develop a set of market-mitigation measures, including limits on wholesale prices.

Federal Responses: FERC Rule Making

November 1 and December 15, 2000 Orders

In the first major rulemaking, on November 1, 2000, FERC issued a market Order proposing remedies for California’s wholesale electricity markets and on December 15, with an Order directing the remedies. FERC reiterated its earlier conclusion that the wholesale prices were not

“just and reasonable” and identified problems of market design as fundamental to the problem60.

A first goal of the Orders was to reduce the reliance in California on spot markets for wholesale electricity. FERC eliminated the requirement that the investor-owned utilities buy and sell all power on the PX or CAISO, thereby in theory permitting utilities to enter bilateral forward contracts. Utilities could use their self-generated electricity directly. Although an important long-term change, given the financial crisis, its short-term impact was limited to allowing the utilities to use directly self-generated electricity. And that change probably had little or no impact on either the energy crisis or the financial crisis.

FERC did impose strong incentives on utilities and generators to complete almost all scheduling of load and generation with CAISO ahead of time, rather than in real time transactions. FERC announced a large penalty on all real time energy transactions greater than 5 percent of the prescheduled amount.

CAISO ancillary service market rules were modified so that a supplier bidding into this market would receive only the energy payment if it were called upon to deliver energy, not the capacity payment in addition. These modifications were designed to make market scheduling more rational, the acquisition process more deliberate, and energy emergencies less frequent. The FERC Orders rejected California’s proposal to give the PX authority to impose wholesale price caps. It denied the CAISO request to continue managing price caps, but ordered the CAISO to impose a $250 price cap on its purchases, without modifying the $100 price cap it had imposed for replacement reserves, until the end of December.

FERC ordered that all single-price auctions run by the CAISO or the PX be temporarily modified to a hybrid system, often described as a “soft price cap”. A single market clearing price would be used if it were no greater than $150/MWh. If the market did not clear at $150/MWh or below, suppliers bidding less than $150/MWh would be paid $150/MWh and those bidding above would be paid their actual bid.

This rule changed optimal bidding strategies for those times participants expected that the market would not clear at a price at or below $150/MWh. In those cases optimal bidding strategies

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would be the same as in any as-bid auction system, not like those in the previous single-price system.

The PX and CAISO were required to report confidentially to FERC all bids in excess of $150 and each seller was required to file bid price, electricity quantity, and marginal generation cost of each such transaction. Bidders above $150/WHh would be required to justify their bids. Lack of valid justification could result in the supplier refunding the higher price.

Such a requirement for bid justification could provide strong motivation if generators believed that price bids above costs would be detected and that refunds would include a penalty in

addition to the difference between price and marginal cost. However, if generators believed that bids well above costs were unlikely to be detected and that, if detected, the only penalty would be a requirement to refund the difference, then this requirement would provide little or no motivation for limiting bids.

Wholesale prices increased after these Orders were issued.

April 26, 2001 FERC Price Mitigation Order

By Spring of 2001, FERC agreed to impose more rigid wholesale controls in California, but not in the other Western States. The April 26 Order established a “mitigation and monitoring” plan for the California wholesale electric markets, to become effective May 29, 2001.

The plan required that all planned outages by units with Participating Generator Agreements61

(PGAs) with CAISO be coordinated with, and approved by, CAISO. Such a requirement would presumably make it easier to judge whether outages of generating units were for non-

manipulative reasons.

The price mitigation plan retreated from the hybrid auctions, moving back toward single-price auctions for the CAISO (the PX was no longer in operation.) All price caps would be eliminated and replaced with “bid caps”, limitations on maximum seller bid prices. Bids could be no higher than an administratively determined estimate of the marginal cost of operating the plant, based on the unit’s heat rate and emissions rate, prices of natural gas and emissions credits, and a $2/MWh fee for operation and maintenance costs. Bids would determine market price through a single-price auction. Bid caps would be imposed only when an energy emergency had been declared. No caps would be imposed in the absence of an energy emergency, in the theory that competitive forces would be sufficient in those times.

Exceptions to bid caps were allowed if a firm could establish that its cost was greater than the cap. Such bids would not help determine market clearing prices. Firms would be required to justify their costs or pay refunds. Similarly, resources located outside California could bid, but their bids would not determine market-clearing price during mitigated periods.

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A Participating Generator Agreement is a legal agreement between a generator and the ISO that establishes “the terms and conditions on which the ISO and the Participating Generator will discharge their respective duties and responsibilities under the ISO Tariff”. The agreement allows the Participating Generator to schedule energy and submit bids to ISO through a Scheduling Coordinator.

The plan imposed a “must offer” requirement on fossil-fuel plants62, a requirement that all sellers with PGAs offer all their available power to the CAISO in real time if not already scheduled. This rule was designed to stop generators from exercising market power by not bidding at all. The Order prohibited other bidding practices if they were seen as potentially allowing anti- competitive market gaming, for example, bids that vary with unit output in a manner not related to its cost characteristics.

Finally, the Order made it clear that demand response should be part of the market response. Load- serving entities were required to establish demand response mechanisms in which they identified the price at which load should be curtailed.

FERC June 19 Order Broadening Scope of Price Mitigation

The April 26 Order applied only in California, ignoring the fundamental linkages between all of the Western markets. This problem was corrected in the June 19 Order. That Order extended the price mitigation plan to all western states and to all times and expanded its scope. The new Order was scheduled to remain in effect until September 30, 2002.

The June 19 Order set rules to be implemented in a common manner63 across all of the markets

in the Western region. The bid caps and the must-offer requirement would remain during energy

emergencies.64 But the bid cap would no longer allow costs of emissions credits or other

emissions costs65. These costs and start-up fuel costs could be directly billed to CAISO and thus

would have no impact on CAISO market-clearing prices.

It also imposed price caps on bilateral sales. The market-clearing price in the single price auction would set an upper limit on the allowable prices for these transactions.

Generators and marketers would be treated differently. Generators could justify costs higher than the administratively determined bid caps, but these higher costs would not be used in setting the market-clearing price. Marketers would not be allowed to a price higher than the market- clearing price. That is, they would be required to act as price takers.

For non-energy-emergency times the price for spot market sales could be no greater than 85% of the highest CAISO hourly market clearing price established while the last Stage 1 emergency (not Stage 2 or 3) was in effect.

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The requirement would not be imposed on hydroelectric plants.

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In price control times a 10% price premium was allowed for sales to California, to compensate for market risk.

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FERC: “Order On Rehearing Of Monitoring And Mitigation Plan For The California Wholesale Electric Markets, Establishing West-Wide Mitigation, And Establishing Settlement Conference” (Issued June 19, 2001)

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Such a system would no longer assure that the lowest cost units would have their bids accepted. In particular, emissions and start-up costs would not count in determining which plants would be dispatched. Unfortunately, this would create a bias toward selecting the plants with less good environmental performance if their costs otherwise were low.