Energy Legal Blog

In an order issued at its April 19 meeting, FERC dismissed two of several pending complaints by the CAlifornians for Renewable Energy (CARE) that urged FERC to abrogate two contracts:  one between Southern California Edison (SCE) and Long Beach Generation, and the other between Pacific Gas & Electric (PG&E), Metcalf Energy Center, and Los Medanos Energy Center.  The California Public Utilities Commission (CPUC) approved both of the contracts as part of its resource adequacy program.  CARE argued that, based on the Ninth Circuit’s 2004 decision in State of California ex rel. Lockyer v. FERC and its recent “Long-Term Contracts” decisions (Snohomish PUD v. FERC and CPUC v. FERC), the PG&E and SCE contracts at issue were not just and reasonable and had not been pre-filed with FERC for approval, and thus were not entitled to protections of the long-standing Mobile-Sierra doctrine.  While FERC could have dismissed CARE’s complains based on their lack of real factual support or development, the Commission took the opportunity to address the merits of CARE’s assertions regarding the meaning of the Ninth Circuit decisions.

FERC defended its market-based rate program on several grounds:  First, FERC emphasized that the court in Lockyer had actually upheld FERC’s market-based rate regime.  According to FERC, Lockyer’s holding was that the Commission had failed to properly oversee the dysfunctional California energy markets during the 2000-2001 crisis by ensuring adequate compliance with its reporting requirements, meaning that sellers could be subject to retroactive refunds for those sales.  Addressing the Long-Term Contract cases, it appears that FERC’s view is a narrow one, i.e., that the court held that the Mobile-Sierra protection will apply when certain factors have been met, including whether FERC provided adequate oversight of the markets in which contracts were negotiated and whether it considered changed market circumstances in deciding whether contracts negotiated in those markets remained just and reasonable. 

FERC also defended its efforts to improve the markets, emphasizing its approval of a significant overhaul of the California market (the MRTU market design);  FERC’s enhanced reporting requirements, market oversight, and increased enforcement authority to address manipulation; FERC’s guidance regarding reporting to the various price indices; and the Commission’s ongoing effort to strengthen its market-based rate program.  FERC made clear that it considered the California crisis to be a “perfect storm” of events that are unlikely to reoccur in the future.  FERC thus determined that the contracts here did not need to be submitted for prior review, testing whether the Ninth Circuit meant what it said when it held that the market-based rate program is still valid as long as certain protections are in place.  Of course, the court has yet to bless many of these reforms, so it remains to be seen whether FERC’s efforts will be sufficient.

ColumbiaGrid, a non-profit membership corporation formed in 2006 to improve the planning and operation of the Northwest transmission grid, has received FERC acceptance of  its Planning and Expansion Function Agreement (Agreement) with its members and with Snohomish County PUD, a non-member party to the agreement.  ColumbiaGrid's current members are Avista Corp. (Avista), Bonneville Power Authority (BPA), Chelan County PUD, Grant County PUD, Puget Sound Energy (Puget Sound), Seattle City Light and Tacoma Power.  Completion of the Agreement comes as good news to parties that have weathered several stymied efforts to create such an organization in the northwest region.  

The Agreement took effect April 4 and requires ColumbiaGrid to prepare a 10-year transmission plan for its footprint within 30 months and to update that plan biennially.  Based on evaluations of its members' transmission systems, the plan will recommend capacity increases, single-system projects, expanded scope projects and non-transmission alternatives (e.g., generation additions or demand management) to the region's interconnected transmission systems.  In addition, ColumbiaGrid will coordinate multi-system project planning and stakeholder participation in the planning process.  Finally, ColumbiaGrid will assume BPA's planning obligations to the Western Reliability Coordinating Council. 

Rejecting protests opposing the agreement, FERC noted its support for a planning process that includes both public and governmental transmission providers.  As suggested by the concurrences of Commissioners Moeller and Wellinghoff, who would have conditioned acceptance of the Agreement on acceptance of each member's Order No. 890 compliance filing, Columbia Grid’s planning process may raise unforeseen transmission planning issues as FERC implements its transmission planning authority and begins evaluating compliance filings.

At a FERC conference on the role of market monitors in the power industry, a simmering dispute between PJM Market Monitor Joe Bowring and PJM management surfaced when Mr. Bowring accused PJM management of interfering with its independence.  The role of market monitors, including their chain of command, was the key issue in the conference.  Moving past more academic concerns, Mr. Bowring aired his dispute with management.

In oral and written comments delivered to the Commissioners, Mr. Bowring said that while PJM is independent from market participants, PJM, as an organization, has specific interests, which may differ at times from the Market Monitoring Unit's (MMU) goal of providing objective, critical evaluations of markets, of market participants, and of PJM itself.  He said PJM management had ordered changes to the State of the Market Report that is filed with FERC, and also prevented him from presenting to PJM members analyses with which management disagreed.  He also charged PJM management with delaying the release of an MMU report that management opposed.

Mr. Bowring recommended that to ensure the MMU's independence, its employees not be part of the “chain of command” from PJM management.  He stated, however, that PJM appeared to be more interested in hiring outside consultants to perform the market monitoring function.  FERC Chair Joe Kelliher ― who stated he had not previously been aware of this dispute ― asked Bowring to whom the market monitor should report, and suggested that regarding this dispute PJM's side of the story should also be heard.

In response to the allegations on inappropriate interference with the market monitor's work, the PJM Board announced it was hiring an outside party to investigate Mr. Bowring's assertions.

On April 4, the Virginia General Assembly voted overwhelmingly to approve amendments to a measure that would “re-regulate” the state's (never de-regulated) retail electric industry, ending the prospect of customer choice for all but very large customers and lifting existing retail price caps two years earlier than scheduled.   The re-regulation bill originated in the General Assembly, but was later amended by Governor Tim Kaine (D), who revised the legislation's rate-setting provisions and doubled the state's voluntary renewable energy use and demand reduction (below 2006 consumption) objectives from 5% to 10% by the year 2022.  The legislation will take effect automatically, without Governor Kaine's signature, on July 1, 2007.

Under the version of the legislation adopted, the Virginia State Corporation Commission will review utility rates every two years and will set a utility's basic rate of return at levels equal to the average rates of return for similar utilities in the Southeast, irrespective of the relative risks it confronts or the quality of electric service the utility provides.  On top of that, the utilities will still be permitted to earn a bonus rate-of-return for developing new baseload generating capacity, but in an attempt to placate environmentalists who had decried the original legislation as not doing enough to encourage the development of renewable resources, the law will give priority to nuclear, “clean coal” plants (i.e., those with carbon capture technology), and renewable projects.  In addition, the existing retail price caps, set to expire on December 31, 2010, will now expire at the end of 2008.  The bill has been called a “hybrid” form of rate regulation, because it allows a few of the largest industrial customers to retain the “choice” option, but would end that opportunity for the majority of retail customers.

With the passage of this legislation, Virginia became the first state to re-regulate its electric industry before any real de-regulation was implemented.  Debate has been ongoing in several other states, with critics calling for the rejection of competition in electric markets.  Illinois, Maryland, and Michigan, to name a few, have also faced growing dissatisfaction in their states with the results of competitive electric markets.

In contrast to the legislation’s weak provision asking utilities to volunteer 10% demand reductions, Governor Kaine more recently issued Executive Order 48 that directs the Commonwealth’s executive branch to reduce the annual cost of energy purchases from non-renewable sources by at least 20% by fiscal year 2010.  Given that Virginia utilities have among the nation’s least developed demand reduction programs and funding, this directive could engender considerable business opportunities for independent vendors of demand-reduction programs and technologies.

State governments have been busy of late seeking to increase renewable energy development and sales within their borders, mostly through the increasingly popular renewable portfolio standards that require utilities to include a certain percentage of renewable energy in the electric power sold to consumers.

Most recently, the Oregon State Senate approved SB 838 that would introduce a renewable portfolio standard to the state.  Oregon is today the most populous Western state without a renewable portfolio standard.   If enacted into law, the bill would require utilities to gradually increase their procurement of renewable energy up to the level of 25 percent of the energy they provide to consumers by the year 2025.  To stimulate development of other resources, the bill would limit the amount of the requirement that can be satisfied by hydroelectric generation, on which the Pacific Northwest already heavily relies.  To reduce the cost of the standard, the bill would cap the added cost of renewables at 4 percent on a utility’s annual revenue requirement.  The bill now goes to the Oregon House of Representatives for hearings.

In Colorado, Governor Bill Ritter signed a bill doubling the state’s renewable energy standard, which had been adopted through a voter ballot in 2004.  The new law increases the renewable energy procurement for utilities from 10% to 20% by the year 2020 and also establishes a 10% procurement requirement by 2020 for municipal utilities serving more than 40,000 customers and electric cooperatives.  The Governor also signed legislation compelling the state’s utilities to identify high-potential wind-energy locations by undertaking biennial reviews to designate “Energy Resource Zones” where transmission constraints hinder the delivery of electricity.  This requirement is intended to spur subsequent development of the transmission needed to bring renewable energy to load centers.

Wisconsin likewise moved to increase renewable energy development as Governor Jim Doyle signed several executive orders intended to boost renewable energy development and fight global warming.  The Governor previously announced a goal of Wisconsin obtaining 25 percent of its electricity and 25 percent of its transportation fuel from renewable fuels by 2025, although the state’s renewable portfolio standard calls for a more modest 10% procurement of renewable energy by 2015.  The executive orders create a new Office of Energy Independence whose objectives will include working with the state’s Public Service Commission on a potential multi-utility effort to build a integrated gasification combined cycle “clean coal” generator.  Another executive order created a Task Force on Global Warming to include a wide range of business, industry, government, energy and environment leaders to examine the effects of, and solutions to, global warming in Wisconsin. 

Finding that two proposed transmission lines did not jeopardize the jurisdictional arrangement that keeps ERCOT outside of FERC regulation, on March 15, the Commission approved new transmission lines proposed by Cottonwood Energy Co. and Brazos Electric Power Cooperative.  Cottonwood plans to build an approximately 100-mile high voltage transmission line from a 1200 MW natural gas-fired generating facility in Deweyville, Texas (on the Texas-Louisiana border), which Cottonwood will interconnect with CenterPoint Energy Houston.  FERC’s order disclaimed jurisdiction of the new line, because it would not interconnect with any non-ERCOT utilities and would not intermingle any ERCOT electricity with electricity from the Eastern Interconnection.

In a separate order issued the same day, FERC also approved Brazos’s proposed transmission project.  Late last year, Brazos had proposed to construct a 345 kV, 70-mile alternating current transmission line from a planned new 750 MW coal-fired generating unit in Hugo, Oklahoma (which it originally planned to co-own with the Western Farmers Electric Coop (“WFEC”)).  Brazos also planned to build a 375 MW high voltage direct current line to provide a connection between the Hugo generating unit and the Southwest Power Pool.  FERC’s March 15 order approved the new intertie, directed interconnection of the Brazos line with local utility TXU, and directed TXU and CenterPoint Energy to provide transmission services to Brazos.  FERC made clear that its order would not make TXU, CenterPoint, or ERCOT a FERC-jurisdictional “public utility.”  Interestingly enough, Brazos filed just a few days later asking FERC essentially to rescind these authorizations and terminate the proceeding.  Brazos explained that after continued negotiations with WFEC, the parties determined that Brazos will no longer own any part of the Hugo generating unit, and thus, Brazos no longer plans to build the approved transmission line.

Meanwhile, Texas Congressman Joe Barton (R), former chairman and current ranking member of the House Committee on Energy and Commerce, continued on his warpath that FERC should have jurisdiction over ERCOT.  Congressman Barton’s concerns about ERCOT’s independence arose in the wake of a proposed buyout of TXU.  Barton had posed several questions to FERC Chairman Joseph Kelliher (a former Barton Capitol Hill staffer) regarding the TXU buyout, many of which Kelliher stated he was unable to answer because no information has been filed with FERC regarding the proposed transaction.  Kelliher stated that FERC currently has only limited jurisdiction over utilities like TXU whose operations are confined to ERCOT, but made clear that he does not believe any expansion of FERC’s jurisdiction is needed.  If Congress did grant FERC authority to regulate ERCOT utilities, Kelliher stated he envisioned that FERC would have much the same jurisdiction over those utilities as it currently exercises over utilities that transmit and sell power across state lines — namely, regulating all rates, terms, and conditions of transmission and wholesale rates by investor-owned utilities, and overseeing certain corporate transactions, including mergers and acquisitions of jurisdictional facilities.  Whether Barton will continue to demand FERC jurisdiction over ERCOT remains to be seen.