Energy Legal Blog

Hoping to encourage the formation of independent transmission companies (“ITC”), FERC adopted in June a new Policy Statement on the ownership of ITCs.  The Policy Statement addresses the types of ownership structures that are eligible for ITC status.  The Policy Statement clarifies that FERC will consider ITC proposals from applicants in which market participants have passive minority equity interests, based on FERC's evaluation of certain criteria.  

Under the Policy Statement, FERC will consider proposals involving passive participation of up to 49 percent ownership by a single market participant, as well as proposals involving multiple market participants owning greater than 49 percent of an ITC applicant's equity.  In evaluating ITC rate proposals, FERC will also consider various issues that could affect the independent operation, planning and construction of their transmission systems, including the composition of the applicant's board of directors and their responsibilities; the corporate governance structure of the applicant; and the nature of the applicant's capital investment policies and any relationship between those policies and policies governing capital contributions or dividend reinvestment by passive equity holders.  Ultimately, FERC will focus on the applicant's ability to operate free of market participant control or influence.

The new policy goes into effect immediately.  FERC views it as a complement to the transmission incentives contained in the Jobs Creation Act that Congress enacted last year, which allows companies that sell transmission assets to an ITC to realize their taxable gains over an eight-year period.  The policy comes on the heels of FERC's hitherto-unsuccessful attempts at implementing a transmission pricing policy by granting certain return on equity incentives.  Notably, the currently-pending Senate energy bill would require FERC to initiate a formal rulemaking to establish rate incentives for various investments in transmission systems.  With the departure of Pat Wood from the FERC Chairman's post, development of transmission rate incentives may be one of the key tasks for the incoming Chair.  [Policy Statement Regarding Evaluation of Independent Ownership and Operation of Transmission, 111 FERC ¶ 61,473 (2005)  [UPDATE]

Responding to the increasingly controversial issue of escalating RTO and ISO operating costs, FERC has proposed a new rule that would change its accounting and financial reporting requirements for public utilities, including independent system operators and regional transmission organizations (collectively “RTOs”) that file financial reports with FERC.  Specifically, FERC is seeking more detailed information about regional transmission and RTO market operation assets, RTO revenues, and other market-related expenses.

FERC states it is proposing the rulemaking to accommodate the industry restructuring that has resulted from introduction of open-access transmission service and increased competition in wholesale bulk power markets.  Currently, financial reporting requirements cover only traditional functional utility plant classifications – generation, transmission and distribution of electric energy, but do not cover RTO-related costs.  According to the proposed rule, this is because many of the current asset and associated expense accounts are not applicable to RTOs.

FERC intends for the new regulations to provide information regarding activities specifically reserved to RTOs, such as overseeing markets and conducting long-term system planning.  The proposed rule would also create accounting and financial reporting requirements that will illuminate expenses incurred in providing service and the revenues collected from RTO members.  In addition, a unified reporting format for RTOs will provide FERC and the market with a better understanding of RTO expenses and whether they are legitimate and reasonable.  [Accounting and Financial Reporting for Public Utilities Including RTOs, 111 FERC ¶ 61,352 (2005)] [NEW MATTER]

The contentious battle over capacity markets in New England moved a step closer to conclusion when a FERC judge recently upheld for the most part the details of ISO-New England’s locational ICAP (“LICAP”) proposal.  See UPDATE (09/30/2002).  LICAP would replace the simpler ICAP regime that allowed load-servers to satisfy their ICAP obligations without regard to whether the capacity was actually deliverable where needed.

The judge found that use of LICAP and demand curves for capacity pricing was the only proposed methodology that would appropriately compensate generators needed for reliability and ensure there was adequate infrastructure while balancing the interests of generators and load.  The judge also recommended that the New England capacity market include Capacity Transfer Rights (“CTRs”) to allocate constrained interfaces among competing uses.  CTRs would be allocated to those who pay for the transmission system, including those that funded specific upgrades that increase transfer capacity, and would not be given to load-servers outside of import constrained regions.  There would ultimately be five LICAP regions with separate capacity requirements and prices:  Maine, Connecticut, Southwest Connecticut, Northeast Massachusetts/Boston, and the remainder of New England.  

The transition from ICAP to LICAP in New England began with the submission to FERC of four reliability-must-run agreements in 2003.  FERC rejected the agreements, and directed the ISO to propose a mechanism that would implement location or deliverability requirements so that capacity within constrained area would be appropriately compensated for reliability.  Underlying this directive was the recognition that transmission constraints caused generation within congested areas to be of greater value than generation capacity located elsewhere.  In March 2004, ISO-NE proposed a LICAP model, supported by a coalition of generators, but opposed by most load servers who thought it would generate a windfall of revenue to generators.  Those opponents can be expected to appeal the judge's ruling.   [Devon Power LLC, et al., 111 FERC ¶ 63,063 (2005)] [UPDATE]

On June 22, 2005, Sempra Energy and its utility subsidiaries, Southern California Gas Company and San Diego Gas & Electric Company (collectively “Sempra”), petitioned FERC for an order declaring that the claims made in an antitrust lawsuit pending in state court in San Diego impermissibly intrude upon FERC’s jurisdiction.  A FERC decision due on the petition is anticipated on the eve of trial and as a consequence may undercut the claims in the massive litigation stemming from the western power crisis of 2000-2001.

The litigation under California state antitrust and unfair competition laws commenced in September 2000 and now includes as plaintiffs classes representing most of the natural gas consumers served by the Golden State’s regulated utilities between July 2000 and July 2001, most of the electricity customers served by the state’s regulated utilities between July 2000 and August 2003, and a number of individual companies, counties and municipalities (“Plaintiffs”).  The core allegation is that Sempra and El Paso Corporation (“El Paso”) in 1996 agreed to, and thereafter undertook a variety of acts in furtherance of, a conspiracy enabling them to restrict supply of natural gas in California, and, ultimately, to raise the commodity price.  (El Paso eventually settled the case, leaving Sempra to defend itself alone.)  Restricted natural gas supply, the Plaintiffs contend, caused (or least exacerbated) the western energy crisis and resulted in charges that were much higher than they would have been absent the alleged Sempra-El Paso conspiracy.

The Plaintiffs have successfully navigated numerous obstacles throughout the course of this litigation and are now poised to begin presenting their case to a jury starting in early September of this year.  Sempra’s petition seeks to pull the rug out from under the Plaintiffs’ claims.  Sempra seeks a FERC declaration that the task for the antitrust jury – deciding the proper level of wholesale electric and gas rates during the California energy crisis – would invade matters subject to FERC’s exclusive jurisdiction, and hence, are preempted.  Congress’ decision to deregulate most natural gas prices, the petition claims, does not mean that states can step in to regulate those same prices by means of state antitrust laws.

Sempra asked FERC to rule on its petition by August 1^st.  (FERC Docket No. EL05-130) [UPDATE]

Storms of re-regulation in the Buckeye state appear to be building as Ohio Governor Bob Taft (R) hinted in a speech delivered at the NAE Regional Conference held on June 3 in Cleveland that unless competition in the electric industry registers a pulse, re-regulation could be in the state's future.  De-regulation in Ohio began in 1999 when S.B. 3, the Electric Restructuring Bill was passed providing customer choice effective January 1, 2001.  The results of de-regulation have been mixed; local government aggregation programs, primarily in Northern Ohio where FirstEnergy operates, have won some gains and many large customers have switched suppliers, but small customers have been slow to take advantage of competition, specifically in areas supplied by Ohio Power, Columbus Southern Power, Cincinnati Gas & Electric and Dayton Power & Light.  

A decision on potential new energy regulation legislation could follow from a series of hearings investigating the effectiveness of S.B. 3.  Ohio State Senator Robert Schuler (R) will chair the hearings, which are expected to conclude before the end of the year.  [NEW MATTER]

Wind energy developers may obtain greater access to many promising wind energy sites on federal lands in the Western U.S. based on the proposals of the U.S. Department of the Interior, Bureau of Land Management (“BLM”).  BLM has released a final programmatic environmental impact statement (“EIS”) addressing the environmental, social and economic impacts associated with developing wind energy on public lands in Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming.  Cumulatively, these western states have great wind power potential.  The EIS recommends adopting a Wind Energy Development Program, instituting policies and best-management procedures for wind energy right-of-way authorizations on BLM-administered land, and amending 52 BLM land-use plans to facilitate wind energy development.  BLM lands presently are host to approximately 500 MW of installed wind capacity.  But these lands could produce thousands of additional megawatts.  Not all BLM lands would be open to wind energy developers, however, as the study identified various scenic or sensitive areas that would be off-limits.  The study also considered the possibility of more limited wind energy development throughout BLM land, but proposed the pro-growth policy instead of continuing the current, more restrictive BLM Interim Wind Energy Development Policy or adopting another limited wind-energy-development alternative.  The study leaves for future consideration site-specific issues associated with individual wind energy development projects.  BLM undertook the study partly in response to the National Energy Policy issued by the White House in 2001, which asked federal agencies to take action to expedite projects to increase the production, transmission, or conservation of energy.  [UPDATE]