Energy Legal Blog

To address the energy shortages of the 1970s, the Public Utility Regulatory Policies Act was enacted to empower qualifying cogenerators or small power producers (from renewables) ― qualifying facilities or QFs ― to “put” their electric generation to an interconnected electric utility and charge the utility an avoided-cost rate, and also demand backup power from the utility.  Because the avoided-cost rate was often locked in at relatively high prices, utilities for years sough repeal or amendment of the “put.”  In the Energy Policy Act of  2005, Congress agreed and directed FERC to end prospectively the “put” for post-October 8, 2005, power sales by QFs that are found to enjoy nondiscriminatory market access.

Responding to this directive, FERC originally proposed to end generically the “put” for all electric utilities participating in independent transmission system operations that offer auction-based day-ahead and real-time energy markets ― the so-called Day 2 markets of ISO New England, the Midwest ISO, the New York ISO and the PJM Interconnection.  But in an October 20 ruling, the agency retreated to a more nuanced approach that creates rebuttable presumptions as to when a QF enjoys nondiscriminatory market access and when it doesn't.

One presumption is that QFs of 20 megawatts or less do not have nondiscriminatory market access.  But for a QF larger than 20 megawatts the “put” presumptively ends if, on a utility purchaser's application, FERC finds the QF is connected to an open-access transmission system that can access a Day 2 market, a Day 1 (an auction-based real-time market only) RTO that also includes sufficiently competitive markets, or the functional equivalent of these.  New England, the Midwest, New York and PJM qualify as Day 2; pending implementation of scheduled new market redesigns, SPP and the California ISO will remain Day 1 (leaving to case-by-case determinations the question whether the markets are sufficiently competitive); and FERC deemed ERCOT a functional equivalent.  The larger QFs can rebut the presumption of nondiscriminatory access by showing that characteristics of how they operate ― for example erratic cogeneration available for sale or non-dispatchability, or where they operate ― for examples in proximity to a binding transmission constraint ― preclude market access.

The new rule provides not only for termination of the “put” in circumstances where a QF fails to rebut the presumption of nondiscriminatory market access, but also for its reinstatement where a QF later shows that the nondiscriminatory market access it once enjoyed is no longer accessible.   

A wide range of stakeholders has gone on record opposing a proposed settlement to restructure the capacity market in the PJM Interconnection.  The settlement was submitted to FERC 13 months after the PJM Interconnection proposed to FERC its Reliability Pricing Model (RPM), and five months after FERC issued an order finding the existing capacity unlawful. 

Parties opposing the settlement – although for divergent reasons – included utilities, generators, marketers, state agencies, and a municipal utility.  Various parties contend the settlement is too complex and will not increase competition, induce new infrastructure investment, or lower prices for consumers.  Among the objections by generators and marketers are the delayed  implementation of locational deliverability areas, a suppressed demand curve for use in the capacity auction, opportunities for buyers to exercise market power, low cost-of-new-entry calculations that would suppress auction prices, and a failure to provide continuity in the prices received by new entrants in the auction.  State agencies, on the other hand, argued the prices received by new entrants in the auction were being maintained too long at higher levels, and also took issue with other features of the settlement.

After receiving another round of comments, FERC will issue an order on the proposed settlement, which could consist of rejecting the settlement, accepting it unchanged and applying it to all market participants, modifying parts of it and applying it to everyone, or accepting it for some parties and severing contesting parties to enable them to litigate their issues of concern.

The Louisiana Public Service Commission (PSC) is currently developing a green pricing tariff that would allow electric power customers to choose to receive power from renewable resources.  The proposed tariff would require that regulated utilities, including cooperatives, offer a minimum amount of renewable energy to their consumers, but would exempt utilities for whom the available renewable options are too expensive or unreliable.  The PSC has asked for comment on whether only Louisiana-generated power should qualify for the tariff's requirements, and whether utilities should be allowed to purchase renewable credits to meet their obligations under the tariff.   

While Louisiana's three investor-owned utilities offered general support for the green pricing tariff, they encouraged the PSC to allow them to use renewable energy credits to satisfy their obligations under the tariff.  Several industrial entities and the state farm bureau would support the green pricing tariff, though they would prefer that the PSC develop an RPS, since an RPS would provide a more secure market for the co-generated electricity that these entities produce.  Should the PSC implement the green pricing tariff, these entities have asked the PSC to validate state-produced biomass as a renewable resource qualified to meet any standards imposed under such a tariff.   

Once the tariff is finalized, Louisiana will become the tenth state to implement a mandatory green pricing tariff, joining Connecticut, Iowa, Minnesota, Montana, New Jersey, New Mexico, Oregon, Vermont and Washington in doing so.  Since a green pricing tariff can provide the cornerstone for later implementation of an RPS, without immediately imposing the added costs that RPSs can entail, more states are likely to follow this route.

FERC announced its unconditional approval for two large mergers October 19:  one between National Grid and KeySpan Corp., the other between Babcock & Brown Infrastructure Ltd. and NorthWestern Energy Corp. 

Under the $11.8 billion National Grid-KeySpan deal, announced in March 2006, KeySpan - currently one of the largest natural gas distributors in the northeast United States - would become a wholly-owned subsidiary of National Grid, a United Kingdom-based company.  National Grid, which is already active in electric transmission in the Northeast, has been looking to increase its presence in the U.S., particularly in natural gas markets.  Of primary importance to FERC in approving the acquisition was the fact that both companies' electric generation output was already committed well into the future, and thus, the proposed transaction would not increase the merged company's market power in wholesale markets.  The merger must now win the approval of New York and New Hampshire state regulators.  National Grid and KeySpan have already obtained the blessings of the Federal Trade Commission and foreign investment regulators.

FERC also approved Babcock & Brown's bid to acquire NorthWestern Energy, the Montana-based electric utility.  FERC found no problems with the merger, particularly since the combination would not join generating assets that would compete in the same geographic markets.  Moreover, NorthWestern offered to protect wholesale sales and transmission customers by holding them harmless from rate increases for five years, and by not passing through any of its acquisition costs to them.  The South Dakota PUC, one of the states with jurisdiction over the acquisition, announced last week that it had conducted extensive discussions with both parties and would approve the merger pending FERC's approval.  Regulators in Montana and Nebraska will also have to approve the deal.

In an October 5, 2006 decision, a chastened FERC ruled that it would no longer tolerate Southern Company – the sine qua non of traditional holding companies – providing its in-house “independent” generator with “inside” information on its transmission systems.   The decision is noteworthy in its apparent validation of whistle-blower allegations that certain authorities tried to prevent a thorough investigation into allegations that Southern favored its “independent” generation to the detriment of competitive generators and other power suppliers.

The case illustrates the shifting sands of how FERC has regulated relations between traditional utilities and their merchant generation divisions.  In 2000, under Chair James Hoecker, FERC approved treating Southern's power marketing affiliate as a member of the Southern power pool.  That decision ensured the affiliate would have access to utility information and services not available to other competitive generators and power marketers.  Then, responding to complaints from competitive power suppliers in 2005, FERC under Chair Pat Wood undertook an investigation into whether the 2000 arrangement remained just and reasonable.  One year later, current Chair Joe Kelliher's chief of staff negotiated a controversial settlement with Southern, under which Southern agreed to limited restrictions on its marketing affiliate's access to utility information.  Consternation greeted this negotiated outcome.  One FERC investigator publicly accused Kelliher and his chief of staff of obstructing the investigation into Southern and of packaging a sweet-heart deal with the holding company.  Taking up the disheartened investigator's cause, Representative Henry Waxman called Kelliher on the carpet.  Later, the FERC judge assigned to the case publicly described the circumstances surrounding the negotiated settlement as “most unusual” and “maybe even dangerous.”  And in an opinion concurring in the October 5 decision, Commissioner Suedeen Kelly described the negotiation as “questionable.”

The October 5 decision, supported by three newly seated commissioners, unanimously rejects the controversial settlement that Chair Kelliher's chief of staff negotiated.  The decision finds the settlement restrictions “severely deficient” and orders that they be replaced with a clear separation between Southern and the affiliate and restrictions on the affiliate's preferential access to information and services.  Moreover, it keeps open an investigation into how Southern interacts with its marketing affiliate and directs the agency's Office of Enforcement to audit Southern and all of its affiliates.  At a higher level the decision also indicates a sea change that will bring greater scrutiny to commerce between transmission utilities and their merchant generation and power marketing affiliates.

The Illinois House of Representatives' Electric Utility Oversight Committee on October 10 voted 9-4 to approve a measure, H.B. 5766, that would extend the state's currently effective retail rate freeze for three more years, through 2009.  The measure will now come for a vote before the full House of Representatives, which is currently out of session until mid-November, but whose members could address it in a special session, if one is convened by Governor Rod Blagojevich. 

In the past, Blagojevich has been a vocal opponent of retail competition and has indicated he would convene a special session in order to extend the rate freeze, which is currently set to expire in January 2007.  Illinois utilities Commonwealth Edison and Ameren, on the other hand, have publicly opposed the rate freeze, stating recently that its continuation could force them into bankruptcy.

Pressure for an extension of the rate freeze has been mounting since last month, when Com Ed and Ameren held a controversial reverse power auction.  Based on the auction results, both Com Ed and Ameren have proposed significant retail rate increases, to go into effect in 2007.