FERC Adopts New Western Market Mitigation Tools and Orders Changes to California’s Revamped Market Design

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Foster Electric Report

Citing the lack of sufficient infrastructure and proven rules needed to make Western wholesale power markets sufficiently competitive, FERC on 7/17/02 adopted a new market mitigation strategy that will go into effect October 1 for those markets and remain in place indefinitely, and ordered the California Independent System Operator, Inc. (Cal-ISO) to accelerate the revamping of its market structure.

Despite these ordered modifications, FERC liked much of the rest of the Cal-ISO’s market redesign proposal (ER02-1656;EL01-68), tinkering with certain provisions but not requiring major changes. In fact, even the newly adopted market mitigation strategy is not that much different from what was proposed by the Cal-ISO. The Commission mostly accepted the ISO’s proposal to use an
automated mitigation procedure (AMP) patterned after what is being used in New York state, but tweaked the proposal to include the establishment of a $ 250/MWh hard cap on spot market bids — instead of the $ 108/MWh “damage control cap” proposed by the Cal-ISO — and different thresholds for triggering price mitigation at prices below that hard cap level.

In related action (See adjacent story, this FER), FERC also demanded that the Cal-ISO’s politically appointed governing board be replaced with an independent one. The current board’s lack of independence is hurting efforts to create competitive markets in California because market participants are worried that the state is using the board to game the market to protect its own interests,
FERC explained.

FERC Chairman Pat Wood III called the AMP the “heart” of the price control order, but added that the $ 250/MWh hard cap “is needed at this time to mitigate against the potential for market power abuse.” Add to this mitigation mix the extension of a requirement originally adopted in 2001 that power suppliers “must offer” their resources to the Cal-ISO and Wood maintained that the order effectively deals with the two most typical abuses of market power — economic and physical withholding.

Despite FERC’s doing all it can to make competitive power markets in the West work, FERC added, “I don’t think we’re out of the woods yet,” referring to a staff study showing the lack of needed market infrastructure in California. “The long-term fixes are not there” yet, Wood explained, and “infrastructure is outside of our realm” and the responsibility of state regulators.

“Unless California builds new generation and transmission, increases the physical and contractual security of its natural gas supply, helps its customers see and respond to high electric prices, and continues and increases its conservation efforts, no set of market rules and market power mitigation measures can make its markets fully competitive, or protect the state’s customers from the inevitable reliability failures that will result,” the order added. “This Commission can encourage and facilitate new infrastructure construction, but only California can make it happen.”

Commissioner William Massey was pleased that the adopted AMP will handle potential market abuses “on the front end” instead of in refund proceedings that drag on for years — “the worst way to handle these problems,” in Massey’s opinion. And correctly anticipating that California’s politicians may fret over the raising of the existing price cap, Massey countered that “the AMP can work
very effectively as a mitigation tool. I would urge anyone concerned with the caps being lifted to look at the AMP.”

Reactions to the orders by California interests were mixed. California Gov. Gray Davis (D) described the move to a $ 250/MWh cap from the current $91.87/MWh cap as “tripling the amount of money energy generators can siphon out of the pockets of California consumers. California has been buying all the power it needs this year in the $ 20 to $ 50 range on the spot market. The price caps make no sense and this order just invites more mischief by energy generators.” He did see the order’s continuation of the must-offer obligation as a “silver lining,” however.

Equally miffed was Doug Heller, director of the Foundation for Taxpayer and Consumer Rights. FERC has “reloaded the energy companies’ guns,” Heller alleged, and “when this order takes effect in October, it will once again be open season on California consumers.”

While Senator Dianne Feinstein (D-Calif.) would have preferred that the $91.87/MWh cap FERC imposed recently stay in place, she said that the order was a “workable solution, and it should prevent what happened in 2000 from happening again. . . . I believe the combination of these caps and a must-bid requirement will help ensure that the markets remain stable, that California has an adequate supply of energy, and that prices remain low.”


After California’s wholesale power markets became wildly dysfunctional in 2000-01, the Commission issued a series of orders requiring a series of immediate short-term fixes and imposing various price mitigation measures. While these measures have helped rein in prices and have brought stability to these markets, FERC recognized that the ultimate fix to California’s market troubles was for the Cal-ISO to revamp its market design. With stakeholder input, the Cal-ISO developed several comprehensive proposals, with the latest (MD02) filed on 5/1/02.

MD02 looks a lot like the market structure that FERC is developing in its standard market design rulemaking (RM01-12) — an integrated day-ahead and real-time congestion management, energy and ancillary services market based on locational marginal pricing. However, the MD02 plan was filed at FERC under duress, with the Cal-ISO complaining that many of the proposal’s provisions will need to be modified to reflect the outcome of related matters that have yet to be resolved.

Given this uncertainty, the Cal-ISO asked FERC to extend existing price controls beyond a 9/30/02 expiration date even though the Commission had hoped that a comprehensive proposal by the Cal-ISO would make those controls no longer necessary. If the Commission refuses, the Cal-ISO proposed two alternative
measures: (1) a “damage control” bid cap that would initially be set at $108/MWh, but could rise if natural gas prices climb above $5.95/million British thermal units, and (2) a companion AMP similar to what is being used in New York in that it would apply to bids that substantially exceed historical levels and materially threaten to impact market clearing prices.

In addition, the Cal-ISO planned to implement the new design in three phases. Phase 1 features, to be implemented by 10/1/02, are intended to prevent economic and physical withholding of power from the market over both the short and long term, and reflect some elements of the New York and PJM markets, including a capacity market and location marginal pricing. The Cal-ISO will try to implement the Phase 2 elements of its proposal — the remaining design features except nodal energy pricing and a new fixed transmission right design — by Spring 2003. The remaining features would be implemented during Phase 3, with a target date of Fall 2003/Winter 2004. (See FER No. 255, p. 8)

The July 17 Order

West-Wide Mitigation Procedures — FERC used the current order to establish new market power mitigation procedures for 11 Western states, to be used when the current procedures expire at the end of September.

Commenting on the need to continue market power mitigation procedures in general, the Commission noted that while the Cal-ISO is planning on implementing needed market reforms, many of those measures won’t go into effect until long after October 1. The Commission “cannot allow unfettered activity in California markets without the protection afforded by such market design elements and market rules being in place,” the instant order stated.

Moreover, FERC lamented that despite expedited state siting procedures and accelerated construction of new generating plants, many proposed power plants have been cancelled and consumer interest in interruptible rate programs has diminished. In addition, California has significant electric and natural gas
transmission constraints, and is continuing to rely on imports to meet its power needs, even when the surrounding states of Arizona, Nevada and New Mexico are facing very low reserve margins themselves. In these types of circumstances, the Commission insisted that even the best market rules will not work and therefore it reluctantly chose to extend market protections.

A key feature of the previous measures was a must-offer requirement for Western power suppliers, and the Commission agreed with the Cal-ISO that this requirement should be extended, praising the mechanism for helping to stabilize the previously turbulent Western power markets. Until “we determine that adequate infrastructure and market design improvements have been made and Western market prices reflect competitive outcomes on a more consistent basis,” the Commission said the must-offer requirement will remain effective.

Under the Cal-ISO’s MD02 proposal, a bid cap for its energy and ancillary service capacity markets would be initially set at $108/MWh, but could fluctuate thereafter to reflect natural gas price increases and competitive market improvements. The Cal-ISO’s own market surveillance committee (MSC) opposed this bid cap proposal, predicting that average costs would actually be higher using this approach than under a $ 250/MWh bid cap. Because system shortages will force the Cal-ISO to make a significant amount of out-of-market (OOM) purchases to maintain system reliability, the MSC reasoned that the “high risk strategy” of establishing a hard cap of $ 108/MWh would prove to be “no cap at all.”

FERC agreed with the MSC’s predictions. Market power mitigation measures must be flexible enough to constrain market power when it exists, but allow the market to function whenever market power is not present, the Commission explained. “If the spot market is the sole backstop for resource adequacy, then market power mitigation rules must be relaxed to allow for prices that properly signal scarcity and allow greater opportunity for generators to recover their total costs,” FERC stated. Morever, “a market with a relatively low bid cap provides incentives for significant amounts of OOM purchases that will take the form of a non-transparent, pay-as-bid market, thus negating the effectiveness of market forces to limit prices.”

Thus, the Commission rejected the Cal-ISO’s proposal and adopted the MSC’s proposal to establish a hard bid cap of $ 250/MWh that will apply to California real-time energy and ancillary services markets beginning October 1, and the Cal-ISO’s day-ahead markets once they are established. A $ 250/MWh hard cap will also go into effect on Oct. 1 for all wholesale power sales in the Western Electricity Coordinating Council. FERC will only consider rasing the caps “to reflect market conditions” once Western energy markets improve significantly and the Cal-ISO’s market redesign is implemented successfully. In the organized
wholesale power markets in the eastern part of the country, the Commission has adopted a $ 1,000/MWh bid cap.

California-Specific Mitigation Procedures — While mostly accepting the Cal-ISO’s AMP proposal, FERC ordered several modifications. Under the version mandated by FERC, essentially three screens will determine whether the AMP would be activated for a given resource’s bid.

The first screen is overcome once market clearing prices in all Cal-ISO zones rise above $ 91.87/MWh. If this is the case, each supplier will be subjected to a “conduct” screen to compare its current bid with a reference price. For generators, the reference price will be based on a 90-day rolling average of their accepted bids. For other suppliers, the reference price will reflect the 12-month rolling average price of energy they provided at each scheduling point across an intertie. Any bid by a supplier that exceeds its reference price by either 200 percent or $ 100/MWh will fail the test and be subjected to the third screen, a market-impact test. Under this screen, if a bid would cause market clearing prices to increase by 200 percent or $ 50/MWh, that supplier’s bid will automatically be reduced to its reference price and placed back in the bid stack.

FERC established slightly different mitigation procedures for situations where intrazonal congestion prevents the running of reliability must-run units. In such instances, a bid greater than $91.87/MWh and taken out of merit order is instantly assumed to have failed the conduct test, and if it is $50/MWh or 200 percent higher than the market-clearing price, the bid will be mitigated and
will not be used to set the clearing price. Instead, the generator would be paid the higher of its reference price or the market clearing price (MCP).

The Cal-ISO had proposed an AMP process with lower thresholds than those used by the New York ISO, reasoning that its markets were less competitive than New York’s. Worried that the proposed lower thresholds might result in the mitigation of bids unnecessarily, FERC ordered them raised.

The Commission agreed to reexamine California’s mandated thresholds “as appropriate,” and ordered the Cal-ISO to file quarterly reports detailing the impact of the AMP measures. FERC also determined that an independent entity and not the Cal-ISO should calculate the reference prices for individual sellers, and ordered the Cal-ISO to complete the process for selecting such an entity by September 15, 2002.

In another deviation from the NY-ISO AMP, FERC agreed to allow the Cal-ISO to subject hydroelectric resources and imports to the AMP since they provide such a significant portion of California’s energy supply and the fact that excluding the resources may lead to megawatt laundering. In other changes to the Cal-ISO proposal, the Commission ordered that small portfolios and bids below $25/MWh should be exempted from the AMP. Finally, the Commission rejected the Cal-ISO’s proposal to not apply the AMP when its day-ahead forecasted load exceeds 40,000 MW. “While it is important to allow the price signals scarcity creates, we also
believe it is important to protect customers from market power,” FERC declared.

FERC Action on Other MD02 Provisions — While FERC generally approved the Cal-ISO’s proposed market improvements, it directed the Cal-ISO to expedite the creation of the planned integrated day-ahead market, and reforms to its ancillary services, hour-ahead and real-time markets. “Because we are not authorizing the development of certain interim elements proposed by the Cal-ISO, we direct the Cal-ISO to devote the resources that would have been allocated to those interim elements to the development of the expedited items,” the order explained. The Cal-ISO is to file an “integrated” proposal for speeding these
changes by Oct. 21, and implementation is to take place by the end of the year.

The Commission also expressed concern that the Cal-ISO does not plan on establishing an available capacity requirement until 2004. “A requirement to assure long-term adequate resources is needed because most resources take years to develop and spot market prices alone will not signal the need to begin development of new resources in time to avert a shortage,” the order said. Without a requirement for long-term generation adequacy, “this mitigation program will not encourage sufficient investment,” FERC concluded. Thus, the Commission ordered a technical conference to consider these matters, as well as certain other MD02 elements including congestion revenue rights, locational marginal pricing and the use of a 10-minute market.

On other proposed market redesign provisions, the Commission agreed to place a negative $ 30/MWh cap on so-called decremental bids for reducing generation. However, the Commission asked the Cal-ISO to file a tariff amendment giving suppliers the opportunity to justify costs above the cap.

Among other things, FERC also (1) approved expenditures for the introduction of locational marginal pricing; (2) rejected a proposed 12-month market competitive index for triggering price mitigation; (3) directed the Cal-ISO to change the rules of its spinning reserve market and explore other ways to incorporate demand response into its market design; (4) rejected the proposed “interim residual unit commitment” process; (5) accepted a proposal requiring
bidders into the day-ahead and hour-ahead markets to submit the same energy bid (i.e., a single energy bid curve) for all services offered by a single resource; and (6) approved proposed penalties for uninstructed scheduling deviations subject to certain software improvements.

The order concluded that three elements are needed for successful competitive electricity markets: adequate infrastructure, including generation, imports and transmission; balanced market rules that lead to fairly operated markets; and a combination of market oversight and market power mitigation.

Thus, despite the needed market reforms approved here, “this Commission has no authority to fix the most fundamental of California’s problems — the relative inadequacy of the state’s energy infrastructure. This inadequacy of generation, transmission and demand response, combined with diminished import availability, in the face of growing electricity demand is a cause of
California’s dysfunctional electricity market. Until it is fixed, California will not have a sound, robust, competitive wholesale electricity market.

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