FERC Filings

REQUEST OF THE ELECTRIC POWER SUPPLY ASSOCIATION FOR REHEARING OF THE COMMISSION’S MARCH 9, 2001 ORDER DIRECTING SELLERS TO PROVIDE REFUNDS OF EXCESS AMOUNTS CHARGED FOR CERTAIN ELECTRIC ENERGY SALES DURING JANUARY 2001 OR, ALTERNATELY, TO PROVIDE FURTHER

REHEARING

A. The Commission Should Not Have Ordered Refunds, Retroactively, Based Upon Its “Rate Screen” Or “Proxy Market Clearing Price,” In The Absence Of Any Finding That An Affected Seller Exercised Market Power

The Commission exceeded its authority by ordering refunds pursuant to its December 15 Order in the absence of any finding that an affected seller exercised market power or engaged in anti-competitive practices. Rather, the Commission should have ordered retroactive refunds only after a finding that a seller, during the applicable period, ceased to meet the requirements of market based pricing under longstanding Commission precedent.

The Commission granted each Seller listed in Attachment A market-based rate authority upon findings that the Seller (and each of its affiliates) did not have or had adequately mitigated, market power in generation and transmission and could not erect other barriers to entry As such, in proposing mitigation for the market-based pricing previously granted via the $150/MWh breakpoint, the Commission’s clear focus was ensuring that market power was not now being exercised. The Commission said:

In implementing our monitoring, we will rely on several indicators of potential market power, including: the outage rates of the seller's resources, the failure to bid unsold MW's into the ISO's real-time market, and variations in bidding patterns for the same or similar resources (e.g.,bidding large blocks of capacity at a low price and a small amount of capacity at a high power price for the purpose of setting the market clearing price for the entire amount)

Indeed, the Commission characterized the required weekly reports, which included detailed outage reports, as enabling it to assess the possibility for the exercise of market power through means such as withholding of energy, any failures to bid, or variations in bidding patterns for the same or similar resources. Accordingly, any retroactive refunds ordered under the December 15 Order should be premised upon requisite findings that a seller has exercised or abused market power or engaged in anti-competitive practices that are inconsistent with the Commission’s prior grant of market-based rate authority.

Applying these standards to the California market, the March 9 Order found no evidence of “any improper exercise of market power caused the high prices.” Instead, the Commission’s March 9 order simply adopted its “proxy market clearing price” as the measure for just and reasonable prices, a departure from the standard in the December 15 Order for how the Commission would effectively monitor and mitigate market prices using the $150/MWh breakpoint.

Such a departure from the standard for market mitigation should not have been instituted through the March 9 retroactive refund order, when Sellers had no opportunity to respond. EPSA recognizes that the Commission is faced with the difficult situation of determining what makes a market-based rate unjust and unreasonable.” Moreover, “[t]here is no precise legal formulation for setting a just and reasonable rate and no precise bright line for when a rate becomes unjust and unreasonable.” At the same time, courts have cautioned against the retroactive application of new standards, for old standards that were reasonably clear, in order to protect the settled expectations of those that relied on the old standard. In addition, the Commission has repeatedly emphasized that market participants in competitive markets must be given an opportunity to adjust their behavior in response to Commission imposed rules. For example, the Commission denied a request by the California Independent System Operator Corporation to limit, on a retroactive basis, the broad waiver of penalties in its tariff saying:

Market participants cannot retroactively change their behavior in response to penalties they now understand to apply.

In this case, the old standard was clear, i.e. absent a finding that a Seller (and each of its affiliates) had market power in generation and transmission or could not erect other barriers to entry, market based rates were appropriate. Nowhere in the December 15 Order did the Commission specifically state that was no longer the standard. Moreover, market participants had no opportunity to adjust their bidding behavior during Stage 3 emergencies in order to avoid the potential for refunds based upon the new proxy market clearing price standard. By deviating from the standard for price mitigation that market participants relied upon in making their bids, and by failing to provide market participants with notice of the proxy market clearing price standard for price mitigation that the March 9 Order applies retroactively, the Commission erred.

B. Mitigation of market prices using post-hoc approximations of expected market behavior is arbitrary and capricious

Even if the Commission’s switch from a setting-based to a “proxy market-based” rate is not an instance of retroactive rate setting, the proxy market clearing price formula adopted by the Commission is arbitrary and capricious. The “arbitrary and capricious standard” demands than an agency must give a reasoned justification for its decision to alter an existing regulatory scheme. An agency determination is arbitrary and capricious “if the agency has … entirely failed to consider an important aspect of the problem, offered an explanation for its decision that runs counter to the evidence before the agency, or is so implausible that it could not be ascribed to a difference in view or the product of agency expertise.”

The Commission’s “proxy market-based” rate is arbitrary and capricious and thus on rehearing should be revised because it attempts to replicate the California wholesale markets under “optimum conditions, whereby every unit bids its variable cost.” First and foremost, the conditions in California are not “optimum,” during a period of a reserve deficiency and, therefore, the Commission’s decision to assume units would bid their variable costs during such reserve shortages is not supported by the record. During Stage 3 conditions energy is scarce. The Commission’s December 15 Order expressly acknowledged that “sellers may bid above their marginal cost in times of scarcity.” Yet the Commission’s “rate screen” and “proxy market clearing price” do not account for scarcity rents. During a time of acute shortages, competitive prices must derive from the customer’s value, not the supplier’s costs, if the supplier is going to be available to provide the necessary service.

Second, the Commission’s “rate screen” and “proxy market clearing price” do not account for credit premiums. As of January 2001, the IOUs no longer met the creditworthiness provisions of the ISO and PX Tariffs and could not pay for energy purchased for them by the ISO and PX. The Commission acknowledged in its February 14 Order that “lowering of the financial creditworthiness standard, without some assurance of payment for third party sales, would … increase the risk premium added to the price of power due to the exposure of non-payment.” That risk premium should have been included in the proxy price.

Third, the Commission should have used daily natural gas prices rather than a monthly average of the midpoint prices. Given the highly volatile gas prices during the refund period, and the fact that the Commission, itself, has acknowledged the daily nature of the natural gas market , the Commission should have used daily gas prices in the March 9 Order rather than the monthly average gas price, which do not capture gas prices during Stage 3 conditions.
Fourth, the proxy price needs to incorporate the cost of purchasing NOx credits on the days that the Stage 3 conditions were in effect. Like natural gas prices, prices for purchasing such credits are extremely volatile and can be very expensive on a daily basis. As such, the Commission should factor such costs into the proxy price.

Finally, the proxy price must incorporate some aspect of a return on the fixed costs of operation if such costs are to be recovered.

In sum, the proxy price in the March 9 Order needs to incorporate a methodology that reflects the true value of the service provided, such as a capacity value, opportunity cost, scarcity value, and a credit premium consistent with the prevailing conditions in California. All of these values are inherent in market-based rates and, if not included, underestimate the true cost of the service provided. With respect to capacity value, it is essential that such a value be reflected in the price so that new investment in generation is sufficient to ensure system reliability by meeting future demand. Marginal capacity value, which varies as generating capacity and load get out of balance, must be included if a marginal cost analysis is used. Opportunity costs should also be taken into account when a generator facing limitations on operating hours would find it better to wait to produce at another, more critical period. Scarcity value reflects the point at which market prices must rise sufficiently to curtail load in an environment where demand exceeds capacity.

C. Mitigation of market prices, absent anti-competitive behavior, will adversely effect the development of additional western generation

The refunds ordered in the March 9 Order are based upon a policy concern about the price produced by California’s market design, rather than abuse of market power. EPSA believes and has documented in prior filings and reports, that this type of price intervention is likely to harm the development of competitive markets in California and act as a disincentive to increased investment in more generation. It is well-established that “just and reasonable” prices may include incentives to stimulate additional supply. The very premise underlying market-based rates is the assumption that wholesale sellers of energy will respond to increased demand, and higher prices, by constructing additional generation. Indeed, the California State Auditor recently recognized that very point when he said that “without [a finding that markets are noncompetitive and supply is being withheld to force prices higher] regulators should let the markets work to increase supply.”

In fact, Seller’s now being charged with retroactive refund liability are in various stages of designing and constructing additional generation to meet western demand. There is a very real risk that the Commission’s precedent-making decision to impose retroactive refunds in the absence of anti-competitive behavior, particularly in combination with increased specter of increased State intervention in the marketplace, will chill such investment, a point the Chairman of FERC recently made:

Retroactive price changes (and I would add commandeering bids) create uncertainty in the market. As we have seen in many parts the world, uncertainty drives suppliers from the market, on the theory “fooled twice, shame on me.” This kind of conduct undermines competition, to the detriment of consumers.

Accordingly, the Commission should not order refunds under these circumstances.