Energy Legal Blog

FERC to Electric Utilities and Qualifying Facilities: Presume This!

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.   

Diverse Opposition to Settlement on PJM Capacity Rules

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.

Louisiana Debates Green Pricing Tariff

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.   

National Grid-KeySpan and Babcock & Brown-NorthWestern Mergers Blessed

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.

No More Mr. Nice-Guy on Utilities Favoring Affiliates

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.

Illinois Considers Continuation of Retail Rate Freeze

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.

FERC Approves ITC Acquisition of Michigan Transco

For the first time, FERC has granted approval of one independent transmission company's purchase of another; it authorized ITC Holdings, the parent of ITCTransmission, to acquire Michigan Transco Holdings, the parent of Michigan Electric Transmission.  As a result, ITC will become the largest Transco in the U.S. and one of the ten largest transmission providers in the nation, with more than 20,000 MW of peak load and almost 20 percent of the peak load of the Midwest ISO.   

The same order, the first issued under FERC's new EPAct 2005 merger authority, also authorized an intra-corporate reorganization of Michigan Electric and Trans-Elect NTD Path 15 that will occur before the ITC acquisition.   

FERC to Consider Settlement in PJM Capacity Market Redesign

Thirteen months after the PJM Interconnection proposed to FERC the Reliability Pricing Model (RPM), a redesign of its capacity market, the nation’s largest RTO and many of its members submitted to FERC a proposed settlement agreement to create a new capacity market.  The submitting parties asked FERC to approve the settlement by December 22, 2005, so that it can take effect by June 1, 2007.

The settlement agreement uses many of the concepts included in the proposal PJM had submitted to FERC, but applies them differently, often in a way less favorable to generators.  A sloping demand curve – which combined with generator bids determines capacity prices – continues to be part of the market design, but the pricing points are suppressed.  Instead of procuring capacity four years in advance, as originally proposed, the settlement would require only three-year forward procurement.  The proposed settlement would ultimately create 23 locational deliverability areas (LDAs) reflecting transmission constraints.  Recognition of LDAs then allows capacity prices to vary between regions to reflect constraints on deliverability.  However, all of the LDAs would not take effect until the 2010-2011 delivery year, leaving in place until then awkwardly shaped LDAs with internal constraints, such as the Rest-of-Market LDA that groups together Dominion-Virginia Power and other areas that are separated by significant transmission constraints.  Other modifications include addition of the Fixed Resource Requirement, which allows utilities to opt out of the RPM and instead self-supply capacity, whether from their own resources or through bilateral arrangements. 

The proposed settlement is the result of four months of settlement talks that began a few weeks after FERC’s April 20, 2006 order finding the existing capacity rules to be unjust and unreasonable. 

FERC Addresses Critical Energy Infrastructure Information

Five years after introducing measures that would limit access to information about the nation's energy infrastructure, FERC is again reassessing what protections and procedures are necessary for both protecting and reasonably disseminating this information.  On September 21, FERC issued a final rule and a notice of proposed rulemaking (NOPR), addressing critical energy infrastructure information (CEII), which is protected by FERC's regulations.  The issuances highlight the balancing act FERC has had to play in protecting sensitive information and ensuring the safety of energy facilities, on the one hand, and in recognizing the due process rights of interested persons who want to participate in FERC regulatory proceedings, on the other.  To be considered, public comments on the NOPR must be received by November 2, 2006.

FERC's final rule, Order No. 683, streamlined the requirements interested parties must satisfy in order to obtain CEII, and included the requirement that requesting parties submit a signed non-disclosure agreement along with a request for CEII.  FERC also addressed the problem that companies filing information with FERC tend to "over-designate"  information as CEII.  The agency instructed that CEII is confined to  "specific engineering, vulnerability, or detailed design information" that:  (1) provides details about the production, generation, transportation, transmission, or distribution of energy; (2) could be useful to a person in planning an attack on critical infrastructure; (3) is exempt from mandatory disclosure under the Freedom of Information Act; and (4) does not simply give the general location of the infrastructure.  Descriptions of facilities and processes generally are not CEII unless they describe "specific engineering and design details of critical infrastructure."  Other procedural changes included revisions to the way FERC will issue notices of requests for CEII treatment.  Since Order No. 683 is procedural in nature, its changes will become effective automatically on November 2, 2006.

The NOPR similarly addresses ways to simplify and clarify  FERC's handling of CEII requests.  For example, FERC proposes to certify annually filers who repeatedly seek CEII and waive for them the requirement that they submit a signed non-disclosure agreement with each CEII request. Certified parties would only have to submit information to FERC once a year, to maintain their certification.  The NOPR will also proposes to cut back on CEII protections for information that can be gleaned from a visual inspection of the facility, or that is otherwise easily attainable from other sources, such as the U.S. Geological Survey or commercial mapping firms.  In addition, the NOPR would also allow FERC to impose a fee for processing CEII requests. 

California Enacts More Aggressive RPS Plan

There are growing concerns that due to transmission constraints and cumbersome regulatory procedures, California will struggle to meet the requirements of its renewable portfolio standard (RPS) legislation.  Nevertheless, in a sign of the state's ambition, Gov. Schwarzenegger recently signed into law an even stricter RPS standard.

Under the new law, the state's retail providers (excluding municipal utilities) must obtain 20% of their power from renewable energy by the year 2010, instead of 2017.  However, another aspect of the law may make the utilities' challenge less onerous.  Until now, California regulators have not authorized the use of renewable energy credits (RECs) to meet RPS requirements, but the new law allows the state's Public Utilities Commission and Energy Commission to develop such a system of credits.  In addition, renewable energy from outside the state may now become eligible to help meet RPS requirements.  These provisions are likely to help integrate western renewable energy markets.

Xcel Announces Nation's Largest Solar Plant

Xcel Energy announced last week its plan to build, own, and operate an 8 MW solar plant in the San Luis Valley, in south central Colorado.  The plant, which would be constructed in conjunction with Sun Edison LLC, would use two types of solar panel technologies, producing 6.8 MW from advanced flat-plate solar panels and the remaining 1.2 MW from concentrating photovoltaic technology.  This latter type of solar technology uses optical lenses or mirrors to concentrate sunlight onto a small group of photovoltaic cells, which then convert sunlight into energy.  Once completed, both the flat-plate solar panel and concentrating photovoltaic segments would be the largest of their type in the U.S. 

Xcel expects the plant to come on-line at the end of 2007.  Xcel plans to sell the plant's output, and the renewable energy credits that go along with it, to Public Service Company of Colorado, to help the utility meet the state's renewable portfolio standard (RPS).  The Colorado RPS, enacted by voters in a 2004 referendum, requires public utilities to generate 3% of their power from renewable energy sources in 2007 (increasing gradually to 10% by 2015).  Uniquely, the Colorado RPS requires that at least 4% of renewable energy come from solar technology.

New PJM Market Efficiency Analysis Synthesizes Economic and Reliability Planning

Expanding on changes made to its regional transmission expansion plan (RTEP) process last June, the PJM interconnection has asked FERC to approve further RTEP adjustments intended to coordinate economic planning with reliability planning in a "forward-looking market efficiency analysis."  

The June changes projected RTEP's planning horizon fifteen years into the future, and developed more fully the shorter-term outlooks.  With the current redo, PJM will apply a revamped market efficiency analysis to the fifteen-year horizon.  The intended  result is a forward-looking assessment in lieu of PJM's current economic planning, which focuses only on mitigating historical congestion.   

The new efficiency analysis considers the economic benefits associated with three types of reliability upgrades.  The first type provides economic benefits simply by accelerating the in-service date.  The second type relieves economic constraints.  The third type achieves cost savings even when no reliability violations are at issue.  These evaluations will consider a wide array of economic metrics, from fuel costs to generation retirement scenarios.  Based on this evaluation process, PJM planning officials will recommend needed upgrades to PJM's board.  The recommendation will designate who would construct, own or finance the upgrade; the estimated cost; and the market participants who should bear the cost.  Once included in RTEP an upgrade would continue to be evaluated and compared to alternatives, such as demand response or new generation.  PJM cautioned that it would consider removing an upgrade from RTEP only when other market solutions are implemented that obviate the reliability or economic need for the upgrade. 

In another change, PJM has eliminated the one-year window for economic upgrades, under which PJM – once it identified an area of historically unhedgeable congestion – waited one year during which a market participant could propose a solution before PJM itself initiated upgrades as part of the RTEP process.  The one-year lagtime is no longer needed, PJM reasoned, due to the increased depth of economic as well as reliability information that the revised RTEP will provide concerning areas where the system will experience future needs.