FERC Restricts Power Plant Sales to Utilities
By Robert F. Shapiro
The Federal Energy Regulatory Commission is making it hard for franchised utilities in the United States to buy power plants from distressed independent power companies.
Two recent FERC orders show the difficulty that utilities are having getting approval for such transactions. The effect is to reduce the number of potential buyers for distressed assets. It is also a sign that FERC intends to keep fighting for a more robust competitive wholesale market in the face of an increasing trend toward reintegration of generation by franchised utilities.
Ever since Enron’s demise and the virtual collapse of spot market trading in many markets, merchant generating plants have become uneconomic. Seizing upon the opportunity to acquire independent generation at a bargain price or to salvage a bad investment in generation from their own unregulated affiliates, franchised utilities have sought to acquire new capacity from the market in order to add to their regulated rate bases.
FERC must approve acquisitions of certain power plants, distribution lines and other utility assets. Until a couple of months ago, utilities had successfully convinced FERC that their acquisitions were in the public interest. An example was FERC’s decision in 2003 to let PSI Energy, a regulated utility in Indiana, acquire two existing power plants in Ohio and Indiana from its unregulated affiliates. This trend appeared to dovetail with a national energy plan that narrowly failed to pass Congress in late November. The bill would have given franchised utilities the upper hand to place the needs of their captive customers over the needs of independent generators in the wholesale markets. Among other things, the bill offered vertically-integrated utilities the potential to manage their transmission systems to the detriment of their competitors.
Perhaps sensing that the bill’s failure to pass offered an opportunity to reinvigorate the effort to create workably competitive wholesale markets, FERC issued an order in late December that put franchised utilities on notice that it would view skeptically their efforts to acquire generating plants from their competitors. Most remarkable was a FERC decision to question an acquisition of a failing enterprise where the to-be-acquired power project was owned by a bankrupt independent power company. Even the US antitrust laws make an exception and let a strong player in the market acquire a competitor where the competitor is a “failing company.” The “failing company” doctrine is included in the Department of Justice/Federal Trade Commission 1992 horizontal merger guidelines that the commission adopted in its “merger policy statement” as the basic framework for evaluating the competitive effects of proposed mergers.
Oklahoma Gas & Electric
Oklahoma Gas & Electric, or “OG&E” sought to acquire the generating assets owned by an NRG Energy subsidiary called NRG McClain in Oklahoma. NRG McClain, like the NRG parent, had filed for bankruptcy, and OG&E was the winning bidder of a bankruptcy auction for the assets. As a vertically integrated utility, OG&E had captive customers and needed additional capacity to provide service to those customers. OG&E also had made a commitment in a settlement agreement with its state regulatory commission to acquire this amount of capacity within a specified time period or pay a penalty to its retail customers. The filing was opposed by several independent power producers.
FERC does a “competitive screen analysis” when asked to approve such transactions. This is a test to measure the effect of the proposed transaction on competition for wholesale electricity supply in the region where the power plant is located. This “competitive screen analysis” does not recognize that any portion of a utility’s generation must be used to serve its native load customers. OG&E’s study showed that the acquisition would lead to too much horizontal market concentration in certain time periods in certain markets. However, OG&E also presented evidence that there would be no impermissible market concentration if OG&E’s native load requirements were considered. OG&E proposed mitigation measures to increase transmission import capability that would take 18 months to complete.
In a December 18, 2003 order, FERC found that the analysis showed excessive horizontal market concentration and vertical market concentration. It ignored the impact of OG&E’s native load in examining horizontal concentration. With respect to vertical market concentration, FERC found that OG&E already had the ability to use its transmission system to frustrate competition, and that adding 400 megawatts of additional generating capacity would increase its incentive to do so, despite the fact that OG&E has an “open access transmission tariff” that is supposed to allow everyone equal access to the OG&E transmission grid. FERC set the matter for hearing to determine what interim and permanent mitigation measures would be required before the acquisition could be approved. Hearings have been scheduled for August, and a final decision would not be expected until mid-2005. However, OG&E has asked FERC to reconsider whether a hearing is necessary and has also made a unilateral offer of settlement with the presiding judge, offering additional transmission enhancements as mitigation measures.
The OG&E decision signaled strong FERC opposition to the acquisition by vertically-integrated utilities of independent power plants in the utilities’ own service areas and has had a chilling effect on the industry.
Several major owners of merchant generating plants that are losing money have said publicly that they will not offer to sell those plants to franchised utilities in light of the current FERC position. The FERC’s order showed a preference for utilities to purchase power from competitors rather than acquire them, particularly in areas where no regional transmission organization, or “RTO,” has been established.
FERC also put franchised utilities on notice that purchases of power plants from their own affiliated companies would be subject to stricter scrutiny in the future.
In a case involving the Southern California Edison Company in late February, FERC approved a proposed power purchase agreement between Edison and an affiliate of Edison that had an option to purchase an unfinished power plant in the Edison service territory. The Mountainview project was owned by an independent power developer that ran into financial difficulty due to its inability to obtain a power contract for its output. The pricing under the power purchase agreement was on a cost of-service basis. Numerous independent power producers, who had also been unable to obtain contracts to supply power to Edison, challenged the proposed agreement between Edison and its affiliate, claiming that they could meet or beat the Mountainview deal and asking FERC to apply the so-called Edgar standard to the proposed agreement. The “Edgar standard” is a FERC policy that a utility applying to buy power using market-based rates from an affiliate must show that the electricity is reasonably priced compared to alternatives in the market. It came out of an order FERC issued more than 10 years ago in a case involving Boston Edison and its affiliate, Edgar Electric Company.
Edison argued that the Edgar test was inapplicable since the prices it proposed to pay for electricity from its affiliate, Mountainview Power, were cost-based, not market-based.
FERC said that it was concerned about granting undue preference to affiliates, but it nonetheless approved the proposed deal on the stated ground that a cost-based formula did not require an Edgar analysis under current policy. Perhaps a more forthcoming response would have been that FERC knew that the California Public Utilities Commission had approved the deal and did not want to make waves. FERC certainly was not legally barred from applying a new standard to a contested case; only rulemakings must be applied prospectively.
However, FERC announced that future affiliate transactions with franchised utilities, even those using cost-based rates, will be subject to an Edgar test. The order was another sign that FERC has a strong predilection for power purchases from non-affiliated entities to promote wholesale competition.
What Could Happen
FERC’s policy cuts both ways for the independent power industry. It helps in the longer term to have an agency strongly interested in promoting competition in the wholesale market. However, the short-run effect is to exacerbate the financial straits of merchant generators who find themselves in a severely-depressed wholesale market by removing likely buyers of troubled assets. The fewer buyers there are, the lower the prices for assets become. The two FERC orders could also have the unintended effect of promoting traditional, rate-based utility construction, since FERC has no jurisdiction over the construction of generating plants. That would lead to the very sort of non-competitive market concentration and reintegration that FERC has sought mightily to avoid.