Energy Legal Blog

Following the Transmission Improvements Group's (“TIG”) regional transmission proposal, made public earlier this month, BPA solicited public comments on whether it should support and join the opposing Grid West proposal, adopt the TIG alternative, push for a combination of the two, or choose to remain separate from the formation of a Pacific Northwest RTO altogether.  TIG comprises several northwestern electric utilities. In order to be considered, comments are due to BPA by September 9, 2005.

Grid West's proposal focuses on the creation of an independent entity that would manage and control transmission in the region,  acting as the central scheduling entity, and serve as the planning reliability and transmission authority for the entire system.  Although FERC has clarified that participation in an RTO by non-jurisdictional transmission utilities does not subject those utilities to additional FERC oversight, BPA has expressed concern about joining Grid West's proposed RTO because its statutory obligations may conflict with FERC requirements.  BPA's concerns in this regard should be attenuated by provisions of the recently enacted Domenici-Barton Energy Policy Act of 2005 that authorize BPA and other federal power marketing administrations to join regional transmission organizations. 

As an alternative to Grid West, TIG has proposed a restructuring of the transmission system (and improvements to the system) through multilateral long-term contracts while maintaining the autonomy and authority of individual transmission system owners.  This proposal would address regional transmission issues incrementally.  TIG claims that because it is not creating a new institution, FERC's jurisdiction will not come into play.   Critics, however, claim that the TIG's proposal lacks depth and fails to explain how independent power producers will fit into the system, or how Intermountain west issues and dealings with Canada will be handled.

The Regional Representative Group, which includes representatives from regional public and investor-owned utilities, BPA, and independent power producers, is expected to vote September 30, 2005, on whether Grid West's development should move forward.  [NEW MATTER]

The Domenici-Barton Energy Policy Act of 2005, signed into law on August 8, mandates that FERC issue several new rules and engage in other new initiatives over the next few months.  Milestones of particular significance to the power and natural gas industries are:

• Within 60 days:  Issue regulations on the National Environmental Policy Act pre-filing process for liquefied natural gas (LNG) projects. 
• Within 90 days: 
  • Consult with Departments of Interior, Commerce, and Agriculture, to establish procedures for trial-type expedited proceedings for mandatory conditions and fishways on hydropower licenses.
  • Issue a final rule exempting QFs, EWGs, and foreign utility companies from access requirements that take effect upon PUHCA repeal (PUHCA is repealed effective 6 months after enactment).
• Within 4 months: 
  • Issue rules to exempt from section 1275 any holding company whose public utility operations are confined to a single state and any other class of transactions FERC finds not relevant to jurisdictional public utility rates.
  • Issue any rules necessary to implement new PUHCA provisions.
  • Submit to Congress recommendations and conforming amendments to federal law necessary to carry out the new PUHCA subtitle.
• By Dec. 31, 2005:  Conclude California energy crisis proceedings and submit to Congress a report describing actions taken and timetables, if any, for further action.
• Within 180 days: 
  • Issue final rule implementing new reliability provisions.
  • Issue rule revising criteria for useful thermal output of QFs under PURPA.
  • Sign MOU with Commodity Futures Trading Commission on information under electric and gas market transparency provisions.
  • Report to Congress on progress in licensing and constructing Alaska natural gas pipeline.
  • With DOE, report to Congress on how to make available to all transmission owners and RTOs real-time information on the functional status of transmission lines within Eastern and Western Interconnections.
• Within 1 year:
  • By rule or order, establish how to meet the needs of load-serving entities.
  • Issue rules for incentive-based rate treatments for transmission in interstate commerce.
  • Convene regional joint boards to study security constrained dispatch, report to Congress.
  • Publish annual report assessing regional demand response resources.
  • As a member of a 5-member inter-agency task force, submit report to Congress assessing competition within wholesale and retail electricity markets.
  • Consult with DOE to conduct at least 3 LNG forums.
  • Enter MOU with other federal agencies to coordinate review and permitting of electric transmission facilities.
• Within 18 months:  Consult with DOE to submit report to President and Congress on benefits of cogeneration and small power production
• Within 2 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to identify corridors for pipelines and electricity transmission and distribution facilities on federal land in Western states, perform environmental reviews for those designations, and incorporate corridors into relevant agency land use plans
• Within 4 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to establish procedures to identify corridors for pipelines and electricity facilities for all other (i.e., non-Western) states.
• No deadline is set for these actions:
  • Issue rules governing national transmission corridor permits.
  • Adopt rules providing expedited procedures for processing FPA § 203 applications within 180 days.
  • Conclude MOU with Secretary of Defense to coordinate LNG facilities that may affect active military installations.
  • Consider New England states’ objections to proposed locational installed capacity (“LICAP”) requirement pending at FERC.
  • By rule or order, require non-regulated transmission entities to provide comparable open access.
  • Issue rules to permit recovery of prudently incurred costs of QF contracts.

Houston-based Reliant Energy announced August 15, 2005, that it has entered into a comprehensive settlement agreement with many of the parties to the ongoing litigation over the 2000-2001 California energy crisis, including FERC staff, the states of California, Oregon and Washington, California’s three largest investor-owned utilities, and various private class-action plaintiffs.  The settlement will end much of Reliant’s liability exposure from sales made during the crisis. 

Pursuant to a Memorandum of Understanding (“MOU”) executed by the settling parties, Reliant will make a $150 million cash payment and has agreed to waive all claims to its receivables for electricity sold into California’s organized markets from January 1, 2000, to June 21, 2001, plus interest.  To preclude future market manipulation through withholding of resources, Reliant also agreed to allow independent audits of outages for 12 months following FERC approval of the settlement and to continue its “must offer” obligations under an earlier 2003 settlement for two additional years.  According to FERC, the total value of the settlement is estimated to be approximately $460 million, which is in addition to $65 million that Reliant has already paid in earlier settlements.  In exchange, the other parties to the settlement agreed to absolve Reliant from all claims related to the energy crisis, including:  FERC’s generic refund proceeding regarding the Western markets; pending appeals of prior FERC orders relating to the crisis; all market price investigations by the Attorneys General (“AGs”) of the three settling states; civil litigation filed by the California AG, including a pending Clayton Act antitrust lawsuit; private class action lawsuits filed on behalf of ratepayers in California, Oregon, Washington, Idaho, and Utah; and natural gas price issues raised by any of the settling parties, except the private class action litigants and local governmental entities. 

Once a formal agreement is in place between the parties, it must be approved by FERC, the California Public Utilities Commission, and the courts overseeing the class actions.  The parties indicated that the settlement will be filed at FERC sometime in September, and in a press release, newly minted FERC Chairman Joseph Kelliher applauded the agreement.  Reliant thus becomes the last of the out-of-state generators to settle allegations arising out of the energy crisis.  If approved, Reliant’s settlement would bring the total settlements with California to $6.3 billion.  [NEW MATTER]

Xcel Energy Services recently became the latest integrated utility to abandon efforts to convince FERC that it lacks generation market power in its control area and thereby surrender its authorization to make control-area power wholesales at market rather than cost-based prices. Entergy made the same decision in July, as did AEP earlier this year. (See Entergy Will Not Renew Market-Based Rate Authority, August 2, 2005). Motivating this retreat is recognition that these large regional utilities are unlikely ever to convince regulators that they have adequately mitigated their generation market power, together with the risk of future refund liability if they are determined to possess market power and the marginal impact that forsaking market pricing will have on bottom lines. Even Southern Company, which is continuing, at least for the moment, its market power proceeding, has indicated that losing its market-based rate authority would not amount to the “death penalty” FERC intended it to be. Similarly, after FERC ordered Duke Power to revert to cost-based sales, the utility pointed out the limited financial effect the switch will have on its business.

Xcel reserved the right to reapply for market-based rates after the Southwest Power Pool (“SPP”) becomes the market monitor in Xcel's Southwestern Public Service Co. and Public Service Co. of Colorado service areas. FERC's investigation into Xcel's market power revealed that, once SPP assumes its market monitor duties, the agency might be more inclined to agree that any market power Xcel possesses would be adequately mitigated. But in the meantime, Xcel's acquiescence in cost-based pricing of its wholesales demonstrates that integrated utilities are increasingly unwilling to spend resources to defend market-based rate applications, and are quite comfortable with at least partially returning to the familiar world of cost-based pricing. As a result, any leverage over utilities with market power that FERC sought to gain with the interim market power screens may become elusive and new approaches to market power may be in order.

A federal appeals court recently reversed a FERC order on pricing arrangements in a congested area of ISO-NE region because of the agency’s failure to respond to reasonable objections to its mercurial policies on pricing. The opinion demonstrates that the agency’s abrupt policy changes will not withstand appellate scrutiny where FERC fails to resolve reasonable objections by appellants.

FERC's order concerned the ongoing attempts to devise an appropriate mechanism for compensating generators in a congested area of southwest Connecticut in which there is a risk of generator market power. As evidenced by FERC’s recent decision to delay implementation of a contentious locational installed capacity requirement in New England, the agency has yet to settle on a long-term, commonly accepted mechanism. The order on appeal involved two previous attempts to come up with a pricing scheme.

In 2002, FERC addressed NEPOOL’s proposal to create a standard market design in New England, and as part of that market design, approved the use of Reliability-Must-Run (“RMR”) agreements that provide for monthly payments of costs and a return to generators that run seldom but are needed for reliability. Not long afterwards, however, when two generators, including an affiliate of PPL, sought approval of RMR agreements with the system operator, FERC reversed course and devised a new compensation scheme, although it signaled that RMR agreements could serve as a last-resort compensation mechanism. The new methodology was termed Peaking Unit Safe Harbor (“PUSH”) bidding, and was intended to give a generator that ran seldom a bid price based on the sum of its units’ variable-cost and fixed-cost components.

The PPL affiliate appealed FERC’s order to the D.C. Circuit, where the agency has met with not infrequent reversals in recent years. The gas-fired generator challenged FERC’s assumption that the PUSH methodology would provide it with adequate compensation, as this would occur only if the generator operated as frequently from one year to the next, which was unlikely given rising gas prices and the availability of non-gas generators. The generator further pointed out that FERC relied on an incorrect assumption about whether PUSH-eligible units could set the locational marginal price (LMP). In addition, the generator argued that it met the last-resort standard FERC has established for RMR eligibility. The Court agreed with the PPL affiliate that FERC failed to respond directly to any of these objections. That failure, the court ruled, demonstrated a lack of reasoned decisionmaking and rendered the orders arbitrary and capricious. [PPL Wallingford Energy, LLC v. Federal Energy Regulatory Commission, 419 3d 1194 (D.C. Cir.) (2005)]

Controversial Proposition 80, which seeks to re-regulate California’s electricity market, should be put to a vote in the upcoming November 8 elections, according to the Golden State’s highest court. The court’s decision overturns a July 22 ruling of a lower court that would have kept Proposition 80 off of the ballot. The lower court ruled that Proposition 80 was unconstitutional on its face because it would expand the authority of the California Public Utilities Commission (“CPUC”) to regulate the energy industry, a role that the court found to be reserved for the California Legislature under a constitutional provision giving the Legislature “plenary” authority over the CPUC. Not so, said the state’s Supreme Court in a unanimous decision. Instead, the court held that Proposition 80 was not clearly unconstitutional and thus, the issue should be left up to the voters. However, the court managed to hedge its bets somewhat by saying that it could revisit the issue if voters approve the measure.

Drafted and sponsored by consumer group The Utility Reform Network (“TURN”), Proposition 80 would effectively re-regulate the California electricity market. In addition to expanding the CPUC’s regulatory authority, the measure would roll back one of the few remaining central provisions of the state’s 1996 deregulation law, direct access, and would prohibit large consumers not already doing so from purchasing their electricity from independent power marketers rather than from the state’s investor-owned utilities. Proposition 80 would also mandate cost-of-service regulation for all of the state’s retail energy-service providers. In the wake of the Supreme Court’s decision, TURN has been proclaiming victory. However, the measure’s opponents, including the Independent Energy Producers Association and Californians for Reliable Electricity, have pointed out that the Supreme Court could still strike the provision down as unconstitutional if it passes. [Case No. 05-169]