Perspective
FERC and the Balance Of Market Power
Commission policies need to recognize customer obligations and state commission decisions.
July 2004
By Michael McGrath
Even the best of intentions can create unintended consequences. The Federal Energy Regulatory Commission (FERC) has acted aggressively and appropriately during the past few years to stimulate competitive wholesale electricity markets.
Now the commission is beginning a comprehensive reassessment of its four-part analysis to determine whether applicants for market-based rate authority have market power-the ability to profitably raise prices in these competitive markets.
As FERC examines its policies to address the potential for the exercise of market power, it must recognize the potential impact the policies could have, as a side effect, on the ability of electric utilities and state public utility commissions to serve their regulated customers. FERC's actions here could take away many of the options both groups need to make the best decisions to provide their customers with a reliable and affordable supply of electricity.
Conflicts Arise
This past April the commission substantially revised its interim generation market power test for market-based rate applications. FERC also announced that in June it would begin holding hearings and technical conferences to examine the generation market power issue and three other aspects of the market power question-limiting transmission access, building barriers to entering a market, and the potential for creating preferential deals with affiliates.
This comprehensive look at market power comes as conditions in the wholesale electricity market have produced an abundance of low-priced power plants for sale. State regulators have authorized utilities to pursue some of these assets as the best-cost option to serve their customers. These actions have included:
- Authorizing utilities to purchase financially distressed merchant generation plants to serve their regulated customers;
- Enabling energy companies with utilities to reclassify power plants from merchant to regulated load serving;
- Allowing utilities to enter into power purchase agreements with affiliated generation units; and
- In open retail states, setting up state-approved competitive procurement practices.
FERC, however, out of its desire to stimulate wholesale competition, has placed a number of these resource procurement actions under scrutiny. For example, FERC is now conducting a technical conference that could lead to FERC oversight of state competitive procurement.
In some cases, the commission has even overruled a procurement action-and with it a decision of the regulating state public utility commission-on the basis of the action's potential for enhancing the market power position of the applicant. For example, in mid-December FERC reviewed a proposal by Oklahoma Gas and Electric (OG&E) to purchase a local merchant power plant and set it for a rehearing. The Oklahoma Corporation Commission, the state regulatory agency, had approved a plan for OG&E to add not less than 400 MW of new generation capacity to meet the growing needs of its retail customers. OG&E made the decision to buy the plant based on its analysis that it would save money for its retail customers compared with building or contracting for the needed power. In late April, the Oklahoma Corporation Commission issued an order acknowledging that OG&E's customers are indeed receiving savings as contemplated in the company's 2002 rate settlement agreement. In that agreement, OG&E guaranteed $75 million in savings during a three-year period, starting this past January.
FERC in its ruling said that this new capacity would increase OG&E's incentive to use control of its transmission facilities to the disadvantage of its competitors in wholesale power markets, and therefore must be mitigated. OG&E offered several mitigation steps, including making transmission upgrades and using a market monitor to oversee its calculation of available and total transmission capacity. These were acceptable to commission staff, but a FERC administrative law judge has stated that the proposal needs more time to be vetted.
The commission also is considering taking action in a case involving supply procurement transactions between Ameren Corp., a holding company, and its regulated and unregulated subsidiaries. Ameren wanted to transfer control of two power plants from its unregulated affiliate, AmerenEnergy Generating, to one of its regulated electric utilities, AmerenUE. AmerenUE, as with OG&E, was acting with the consent of the Missouri Public Service Commission to expand its capacity base.
The commission is reviewing the asset transfers to see if the utility should be required to demonstrate that its purchase price at net book value is consistent with the results that would be obtained through a competitive procurement process. A FERC administrative law judge had found no evidence of affiliate abuse in this case. Despite this, the commission still has not acted.
In another affiliate relationship issue, this one involving Southern California Edison Co. (SCE), the commission approved a 30-year, cost-based power purchase agreement between SCE and its wholly owned subsidiary, Mountainview Power Co. LLC. Mountainview owns a not-yet-completed 1,054-MW generating plant in SCE's service area. SCE planned to exercise an option to purchase the project by buying Mountainview from its current owner, Sequoia Generating LLC, but sought FERC approval of the purchased power agreement before exercising the option.
Although it approved the purchase, the commission conditioned its approval on the termination of Mountainview's eligibility to make market-based sales and the company's agreement not to sell power to anyone but SCE, with no possibility for revisiting the decision in the future. FERC put others on notice that future reviews of affiliate deals would be subject to the standards raised in its Edgar Electric Energy case.
In Edgar, the commission ruled that an affiliate's market-based sales of power to a franchised utility must be shown to be "reasonably priced" compared with competitive alternatives. Traditionally, a purchased-power agreement with a cost-based rate has not triggered application of the standard set forth in Edgar. FERC noted that market prices are now below cost-based rates in many regions of the country, and the application of Edgar to all long-term contracts will guard against potential self-dealing in those markets. The policy will be applied prospectively, however, to avoid regulatory impacts on transactions already filed for FERC approval as of its February 2004 order.
The net effect is that FERC will look at whether an affiliate deal results in the lower of cost or market price. In applying Edgar to a cost-based affiliate transaction, the commission apparently believes it has the right to reject a cost-based rate, if a lower-cost market rate is available. Moreover, Edgar makes no reference to state commission actions that address transactions affecting state-regulated customers. It thus remains to be seen whether the commission will consider-and the importance it will give to-state commission decisions affecting choices to obtain electricity from affiliates to serve regulated customers.
It is noteworthy that SCE chose to structure the deal through a subsidiary rather than as a direct-ownership of rate-base plant because of the greater assurance of cost-recovery. SCE was concerned that it otherwise would be unable to recover its investment under traditional California Public Utilities Commission (PUC) jurisdictional ratemaking. The California PUC approved the proposal. Specifically, the state PUC found that "that ratepayers will be better off with Mountainview than without it."
More, Not Fewer Options
As these cases illustrate, commission action in the name of addressing the potential for market power can contradict or greatly restrict the best efforts of state PUCs and electric utilities to serve their regulated customers. The regulated customers benefit when more-not fewer-procurement options are available. In some cases, the acquisition option, or a power agreement with an affiliate, may be the most cost-effective and least-risky approach, and should be permitted.
Allowing regulated utilities to make these decisions will further the commission's efforts to revitalize the wholesale markets as well. It gives merchant generators who wish to sell surplus generation more potential buyers. This is particularly important now when many generators face financial difficulties, and integrated utilities have both the resources and the need to secure additional capacity. The sale of financially distressed merchant assets is also a critical part of the industry's restructuring efforts. Generally, these sales can help restore stability to the electric sector. They strengthen balance sheets and improve credit ratings for sellers as well as buyers, leading to greater financial stability for both.
Balancing Needs
America's electric companies support the development of competitive energy markets and protection against market power abuse. As FERC now prepares to begin a comprehensive analysis of the entire market power issue, it must give great weight to the views of state regulators on the best ways to serve the regulated customer.
This past April, the commission did state that its substantially revised interim screens to test for generation market power would recognize the need to account for the capacity a utility needs to serve its regulated customers. When such commitments of capacity to serve native load are ignored, the analysis will consistently overstate a utility's capacity to sell electricity in wholesale markets and its ability to influence market prices.
This approach is a start. However, the commission's order does not consistently apply this change in approach.
In fact, one aspect of the commission's approach continues to ignore commitments to serve regulated customers, despite the commission's understanding of the importance of these commitments. EEI has filed for a rehearing of FERC's recent market power order, asking the commission to address this and other concerns related to the new interim screens.
Furthermore, FERC needs to recognize a utility's need to serve regulated customers in all of its market power investigations. By not doing so, FERC discourages utilities from purchasing existing plants instead of building plants or signing long-term contracts. This encourages utilities to pursue options that may not be the lowest-cost options for their regulated customers. The effect is that customers that purchase or would have purchased power from the utility can be harmed by inappropriate constraints imposed by FERC.
As the commission continues to address its policies for determining market power, it must strive not to unreasonably limit the energy procurement options of vertically integrated utilities and their state regulators. More options are in the best interests of customers, because they lead to more affordable and reliable power. And having more options, rather than fewer, is in the best interests of the evolving wholesale markets, because that will lead to a faster evolution to robustly competitive markets.
The commission has the capability to build its market power policies on this principal. EEI urges it to do so.
Michael McGrath is executive director of the Retail Energy Services Group at Edison Electric Institute. Contact him at mmcgrath@eei.org.
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