FERC Filings
SUPPLEMENTAL COMMENTS OF THE ELECTRIC POWER SUPPLY ASSOCIATION re: INVESTIGATION OF TERMS AND CONDITIONS OF PUBLIC UTILITY MARKET-BASED RATE AUTHORIZATIONS
CONCLUSION
Because well-functioning markets are the ultimate consumer protection, EPSA urges the Commission to focus the resources of the agency and the industry on enhancement of existing markets and the creation of RTOs where they do not exist, as well as the development and implementation of a workable standard market design. However, if for a limited and interim period, the Commission needs to implement a proxy for price responsive demand, EPSA would support a $1,000/megawatt bid cap on all electricity sales for a defined period of time, along with taking steps to increase available supply and demand responses.
March 22, 2002
Respectfully submitted,
/S/
Julie Simon, Vice President of Policy
Electric Power Supply Association
1401 New York Avenue, NW
11th Floor
Washington, DC 20005
(202) 628-8200
CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the comments by first class mail, postage prepaid, upon each person designated on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C., March 22, 2002.
/S/_______________
Julie Simon
1401 New York Avenue, NW
11th Floor
Washington, DC 20005
202/628-8200
202/628-8260 fax
www.epsa.org
EPSA Response to Specific Questions in Attachment B of the Notice of Staff Conference Agenda (Revised)
Investigation of Terms and Conditions of Public Utility Market-Based Rate Authorizations, Docket No. EL01-118-000
March 11, 2002
EPSA rejects any generic refund condition under Section 206 as a prudent or lawful way to address possible “market power” in the short- or long-term. However, EPSA supports many aspects of the Chairman’s Strawman as the basis for further discussions on both a short- and long-term approach to market mitigation. EPSA recognizes the need to work with the Commission and others within the industry to develop a workable approach to the monitoring and mitigation of market power. The comments offered in response to the Staff Paper thus address the issue raised in the context of market mitigation generally and not with respect to “fixing” the November 20th Order.
Section A: Modifications to Definitions
- Should the term “full incremental cost” be clarified (e.g., to include opportunity cost)?
Yes. As the Chairman’s Strawman points out: “Marginal costs include not only variable costs but also the marginal opportunity cost of all legitimate opportunities, costs, and risks.” In addition, the Chairman’s Strawman recognizes scarcity value, which must be included when demand approaches available generating capacity. The Commission also needs to be careful not to inadvertently eliminate the power trading industry – such as by casting doubt on the legality of making a margin over acquisition costs. Expert testimony on the definitional question is provided in the filings submitted by Professor Hogan, Scott Harvey, Richard Tabors, Craig Roach, Larry Ruff, Alfred Kahn and others. The Commission's use of this term is particularly critical to hydro resources, as opportunity cost is an integral component of decision-making, bidding and market participation for hydro operators.
- Should the use of the term “market price” be clarified, e.g., as to time (forward vs. spot), product (energy vs. reserves) and geographic market?
Yes. Defining the appropriate product and geographic and temporal markets is a crucial first step in any market power analysis. Definition of a “market” that is too limited or too expansive will produce results that are not meaningful. It is also important to identify which products can substitute for others, since not all megawatts are interchangeable. In addition, the “market price” outside of centralized spot markets is the result of bilateral agreements between sellers and buyers – it is not something that exists independent of these bilateral agreements. Again, expert testimony from several prominent economists was submitted on this issue.
- Should environmental, operational and reliability factors be taken into account for purposes of determining whether physical withholding has occurred? If so, how?
Yes. Generators face a host of choices when deciding whether to operate a particular plant. Units may be limited in the number of hours they can operate under emission caps or water supply and may have greater opportunities at different times. Similarly, start-up costs may make it unprofitable for a generator to operate for a limited number of hours. The need to reserve units to assure physical reliability or hedge risk may also preclude a unit from selling during a particular hour. If market monitors or the Commission are concerned that a unit is withholding capacity, a confidential investigation should be undertaken. The owner of the unit should be given a fair opportunity to explain the situation and the Commission should resolve the dispute in a timely manner. The fact is that all withholding is not necessarily badly motivated, but in fact may be both appropriate and useful—in the event that run-limited units are withheld to be available for true peak demand periods.
As the question suggests, the Commission’s market mitigation plans should explicitly recognize that “withholding” refers to physical action by generation owners and that power marketers should categorically be excluded from any mitigation measures aimed at withholding.
Section B: Limit Applicability to Certain Markets/Market Participants
- Should we exempt sales in markets that are fully competitive with effective market monitoring; exempt all suppliers in an approved RTO market with Commission-approved bid caps?
Yes. As noted above, EPSA rejects a generic refund condition as a prudent or lawful solution to market power problems. The Commission should have sufficient confidence in the Northeast markets to forego further market interventions. All three operating ISOs have several years of experience operating their markets, sophisticated market monitors in place, and $1,000 bid caps that the Commission has seen fit to perpetuate (despite inferences of their interim nature). Report after report validates the competitive nature of these markets. The risks and costs associated with introducing additional intrusions and uncertainties into these markets – such as further delays or reductions in much-needed new generation for New York – clearly outweigh any lingering concerns about market power. In February, the New England ISO, along with the Attorneys General of several New England states released “An Empirical Assessment of the Competitiveness of the New England Electricity Market.” That study concluded that the differences observed between the energy clearing price and a competitive benchmark were attributable to transmission congestion and operating constraints, not the exercise of market power by generators. Moreover, there is no evidence that markets outside of ISOs have been a concern.
In addition, making a distinction between RTO or ISO markets and non-RTO or ISO markets still does not justify imposing the open-ended refund on all sellers in non-ISO/RTO markets. A refund condition would have a negligible effect on integrated utilities with generation in rate-base making bundled retail sales, but would have a devastating effect on merchant generation that relies on market-based sales. In addition, a refund condition would discourage additional unbundling, since unbundling would create new and significant regulatory risk.
- Should we exempt power supply agreements of a specific duration or agreements where parties explicitly waive refund obligations; exempt all bilateral contracts; create safe harbors (rebuttable presumption of legality) for certain transactions, such as, those with markups at a certain level above marginal cost?
As noted above, EPSA rejects a generic refund condition as a prudent or lawful solution to market power. In no event should a refund condition apply to bilateral contracts for wholesale electric transactions, which involve sophisticated buyers in established markets, where numerous counterparties and a variety of hedging mechanisms are available to deal with price volatility. The Chairman’s Strawman highlights the importance of bilateral contracts, pointing out that “market design should never interfere with long-term contracting because such long-term commitments minimize exposure to spot price volatility and mitigate boom and bust cycles.” The Commission should not intervene in these private contracts by providing free regulatory hedges in the form of price caps or mitigation or take action that discourages parties from entering into these contracts.
The term “safe harbor” implies that all other transactions would be unsafe for sellers. EPSA strongly opposes the creation of a class of transactions that would, through a refund condition, invite buyers to renege on their contractual commitments. Well-functioning markets require transactional finality. Ex post regulatory uncertainty undercuts finality and increases costs to consumers. Furthermore, tying prices to marginal cost will undercut the Commission’s policies on market-based rate authority and discounts the need for a variety of non-base load plants. Peaking plants that operate only a few hours of the year need accurate price signals to incent needed investment. The Commission correctly refused to intervene in markets in the Midwest in 1998 and 1999, leading to significant new investment in those areas and consistently lower prices over the last two summers.
The Commission should resist the urge to interfere with the healthy competition that is evolving in power markets. Attempts to establish acceptable “mark-up” or margin levels not only reflects a misguided urge to focus on cost as the only legitimate basis for market prices, but more dangerously would inject the Commission into the wholly untenable position of judging sellers’ own supply acquisition strategies, bidding strategies and risk/reward evaluations.
- Should we limit the condition to the specific market(s) in which a seller has market-power, and tailor mitigation rules to those firms given their particular circumstances, while exempting from the rules those generators that are unable or unlikely to exercise market power, such as net buyers, and small single-plant suppliers?
Yes. As noted above, EPSA rejects a generic refund condition as a prudent or lawful solution market power. However, it is nonetheless important that the Commission adopt a clear standard for defining market power and address only those situations in which market power abuse has occurred. As Gregory Werden, Senior Economic Counsel in the Antitrust Division of the Department of Justice has pointed out, “any firm that can affect the market price by altering its output or bid price is said to possess ‘market power,’ hence, market power is a matter of degree, and the degree of market power – rather than its existence – is what really matters.” Expert testimony in this proceeding point out the need to carefully weigh the costs associated with its mitigation measures against the harm caused by certain behavior.
In tailoring any mitigation mechanism, is it important for the Commission to employ a structural test to show that a party has the potential to abuse market power. While the traditional hub-and-spoke test has been criticized as overly lenient, the Commission should carefully explore other alternatives, such as a showing that a party controls some threshold level—more than 20 percent of the economic capacity, for instance—in an appropriately defined market.
Where market power exists as a result of a load pocket problem, the Commission should consider mitigation measures such as incentives for generation to provide call options at competitively bid prices. In those instances the Commission might require some economic limit for capacity payments as an interim step until adequate transmission or generation is added.
- Should we set an impact threshold for alleged violations?
Yes. The definition of market power should require a sustained and significant effect on markets to be actionable.
Section C: Procedure Modifications/Applicability Based on Timing
- Should we limit the window of refund potential so that transactions would not be subject to refund unless specifically challenged within a particular timeframe; set a sunset date for the refund condition?
Yes. As noted above, EPSA rejects a generic refund condition as a prudent or lawful solution market power. No “limit” on a refund condition could satisfy the investment community that will focus on the fact that all market-based electric generation revenue could become subject to refund and that any “limit” could be modified tomorrow. If the Commission were nonetheless to pursue this unwise and unlawful course, it should try to mitigate the adverse effects on transactional finality. Any party wishing to seek a refund under Section 206 should be required to challenge the transaction within 30 days. Any transaction not challenged in that timeframe should be deemed just and reasonable. Similarly, the Commission should act on any challenges quickly. The refund condition should be in place for the shortest possible time frame.
- Should we clarify the type of opportunity that sellers will be given to respond to allegations and explain the basis for their actions (e.g., a trail-type hearing)?
Sellers should be afforded full due process rights in refuting any allegations of misconduct. Parties challenging transactions should be required to show, with substantial evidence, that transactions are not just and reasonable, and that they have derived from abuse of market power or other improper actions. The Commission must continue to be alert and to differentiate between appropriate scarcity rents which are necessary to attract new investment—such as apparently took place in the Midwest after price spikes in 1998—from abuse of market power. The Commission should quickly dismiss any challenges it deems frivolous.
Section D: Other Suggestions
- Should we impose temporary price caps along with reserve capacity requirements until a competitive market structure emerges?
The efforts of the Commission and the industry should be focused on ensuring workably competitive markets operating under a standard market design as quickly as possible. Outside those markets that are currently operating in a competitive manner (the Northeast) or subject to mitigation (the West) the Commission could implement a $1,000 bid cap as a proxy for demand participation in the current markets. While EPSA supports the development of binding long-term capacity obligation to ensure adequate capacity as part of standard market design, it seems unlikely this issue will be fully resolved in the short-term.
- Should we tailor mitigation measures to be applied to a particular exercise of market power, class of participant, and sector?
As stated above, the efforts of the Commission and the industry should be focused on ensuring workably competitive markets under a standard market design as quickly as possible. Any market mitigation measures should be tailored to solve well-defined problems that defy market-based or structural solutions. Market interventions, particularly retroactive market interventions, should always be a last resort.