Energy Legal Blog

FERC on May 25 issued a stern warning to over 200 companies possessing market-pricing authority, but who had become delinquent in filing their triennial updated or revised market power analysis.  File the update within 60 days, FERC admonished, or risk losing market-pricing authority.  All power sellers dependent on market-pricing authority need to heed this warning with care. 

FERC also instituted a section 206 investigation to determine whether the rates charged by these companies remain just and reasonable.  By cracking down on late filers, FERC hopes to see more companies file the triennial update on time and thereby avert fruther judicial criticism in the wake of the California Attorney General's recent, partially successful challenge to the adquacy of filing requirements in connection with FERC' market-based rates program.  See UPDATE (05/04/05).    [South Point Energy Center, 11 FERC ¶ 61,239 (2005);    Carthage Energy, LLC, 111 FERC ¶ 61,240 (2005);   Backbone Mountain Windpower, LLC, 111 FERC ¶ 61,242 (2005);    Virginia Electric and Power Company, 111 FERC ¶ 61,241 (2005) and Western New York Wind Corporation, 111 FERC ¶ 61,295 (2005)] [UPDATE]

 Amid a flurry of rulemaking activity at the end of May, FERC issued a Notice of Proposed Rulemaking (NOPR) on May 27, 2005, seeking comments on whether it should provide for the electronic filing of required information on interlocking positions (FERC Form 520 and Form 561) and a public utility's annual report of its twenty largest energy purchasers (FERC Form 566).  Without advance FERC approval, Federal Power Act (FPA) § 305(b) prohibits individuals from holding positions as an officer or director at more than one public utility, or from holding officer or director positions simultaneously at a public utility and either an entity authorized to underwrite or market public utility securities or an entity supplying electrical equipment.  FERC approval is initially obtained by filing Form 520.  Once FERC approves the holding of interlocking positions, the officer or director must file Form 561 annually by April 30 of each year.  In addition, FPA § 305(c) requires a public utility to file a report identifying its twenty largest utility customers each year by January 31, which helps FERC identify possible conflicts of interest.  If adopted, the proposed rule would allow the filing of these forms electronically, as suggested by the FERC's Information Assessment Team (FIAT).  Comments on the NOPR are due 60 days following the publication of notice in the Federal Register.  [Electronic Filing of Interlocking Positions and Twenty Largest Purchase Information, 111 FERC ¶ 61,278 (2005)] [NEW MATTER]

            FERC issued a series of proposals and rules May 25 that will streamline and assist FERC in collecting various kinds of information, as well as a change to the calculation of that essential metric: available transfer capacity (“ATC”) on the transmission grid.  FERC Chair Pat Wood expressed his belief that these orders would benefit both customers, by improving market transparency, and the electric industry, by ensuring that FERC's reporting requirements are “useful and necessary.” 

Two of the issuances included two Notices of Inquiry (“NOI”).  In Docket No. RM05-16, FERC issued a NOI seeking comments on the collection or retention of generator run-status information from all public utilities.  The information, which would include data on operating performance, capability of units, and commitment of generation, would be confidential, but FERC would use it to protect the market against withholding of generation or misrepresentation of capacity, by monitoring markets, investigating market abuses, and evaluating complaints.  The second NOI, issued in Docket No. RM05-17, sought comments on a revision to the calculation of ATC.  In it, FERC responded to a chorus of concerns that transmission providers generally are inconsistent and self-serving in current ATC calculations.  FERC referenced the North American Electric Reliability Council's (“NERC's”) Long Term AFC/ATC Task Force Report and requested comments on the Report.  To be considered by the agency, public comments on both NOIs are due 60 days after each is published in the Federal Register.  [NEW MATTER]

 On May 1, 2005, at 12:01 a.m., Dominion, the largest utility in Virginia, successfully transferred operational control of its 6,000-plus miles of high-voltage transmission lines to PJM Interconnection, LLC (PJM).  Dominion's transfer follows the integration of  the Duquesne Light transmission system earlier this year, as well as the Commonwealth Edison, American Electric Power, and Dayton Power & Light transmission systems, which occurred in 2004, making PJM the nation's largest regional transmission organization.   

As a result of the transfer, PJM now manages the dispatch of generation and the flow of wholesale electricity over Dominion's transmission lines, making available to Dominion's customers over 160,000 MWs of installed capacity.  This integration is expected to improve market liquidity and price transparency, thereby increasing reliability, economic benefits and market efficiency for the Dominion region. 

Dominion was granted the approval for its integration by the North Carolina Utilities Commission on April 19, 2005.  The Virginia State Corporation Commission and FERC had earlier granted Dominion approval to integrate into PJM on November 10, 2004 and October 5, 2004, respectively.  See UPDATE (10/29/04).   [UPDATE]

Responding to a judicial demand that FERC explain an apparent change in policy, FERC decreed on May 6 that its 2002 order providing GenWest LLC (GenWest) transmission credits for network upgrades built to interconnect with Nevada Power Company’s (Nevada Power) grid was no change at all. 

Beginning with  FERC’s mid-1990s orders mandating that transmission-owning utilities open their systems to third parties, FERC has generally required that the costs of constructing upgrades to interconnect a customer be spread across all network customers, provided the upgrades are beneficial to the transmission system as a whole.  This is typically done by requiring the customer to advance initial funding for the construction costs and later receive a credit for those costs against future transmission charges.  By contrast, if FERC deems a particular upgrade to benefit only the interconnecting customer, the generator is not entitled to any reimbursement.  The key issue is how to determine who benefits from a particular upgrade ― just the interconnecting customer or all users of the transmission grid. 

In this case, FERC found that the one-line terminal GenWest LLC funded was a network upgrade that benefited all system users because it was located “at or beyond” the point at which the customer interconnected with Nevada Power’s grid.  Nevada Power, joined by Southern Company Services, Inc., and Entergy Services, Inc., challenged FERC’s use of the “at or beyond” language as an unexplained change from how FERC previously determined who benefits from a particular upgrade.  Apparently concerned about how the “at or beyond” language conforms to FERC’s earlier rulings, an appeals court instructed FERC to explain itself.  See UPDATE (12/29/04).  

            FERC’s response was a simple, and predictable:  “Change?  What change?”  FERC rationalized its decision to use the phrase “at or beyond” as a way to clear the fog surrounding some of its ealier descriptions of network upgrades.  According to FERC, the court misunderstood FERC’s distinction between interconnection facilities (which benefit, and hence are paid for by, only the interconnection customer) and network upgrades (which benefit, and hence are paid for by, all grid customers).  Because interconnection facilities are almost never “at or beyond” the point at which the customer interconnects to the grid, they are almost always located on the generator’s side of that point.  The costs at issue in the earlier Consumers Energy case that concerned the court, FERC said, were for run-of-the-mill interconnection facilities that were not “at or beyond” the point of interconnection.  Hence, requiring the customer alone to bear their costs was appropriate under FERC’s cost allocation policy, regardless of the language FERC used to describe them.  [Nevada Power Company, 111 FERC ¶ 61,161 (2005)] [UPDATE]

Reducing power plant emissions seems to be the priority du jour, as several state regulatory agencies consider plans to comply with the EPA's new clean air interstate rule (“CAIR”).  Passed in March of this year, CAIR permanently caps sulfur dioxide (“SO2″) and nitrogen oxide (“NOx”) emissions in the eastern United States, by providing for SO2 rductions of 70 percent and NOx  reductions of 60 percent by 2015.  This past April, the Ozone Transport Commission (“OTC”), a multi-state organization created under the Clean Air Act encompassing the Northeast and the Mid-Atlantic states and the District of Columbia, held a meeting to gather ideas and comments from the industry regarding proposals to direct reductions of emissions at state-levels lower than that of CAIR.  Trying to build upon a position statement it passed last year that petitioned for nationwide targets for SO2 and NOx emissions caps for the years 2008 and 2012, as well as stricter limits on the EPA's mercury emissions standards, OTC would like to see states recommend “CAIR-plus” programs in their implementation plans for meeting EPA standards, due in late 2006.  OTC also urged other regions to participate in emissions reductions, possibly through a regional cap-and-trade program that would cover the entire eastern United States. 

While they did not participate in the April OTC meeting, Midwestern and Southern officials also now appear to be focused on reducing SO2 and NOx emissions. An interim white paper released by the Midwest Regional Planning Organization in January of this year examined options for reductions in power plant emissions, but didn't commit to any actual approach.  Reductions would apply to Illinois, Indiana, Michigan, Ohio and Wisconsin. 

Not surprisingly, the electric industry expressed concerns over these proposals.  Segments of the industry contend that reducing emissions below the CAIR targets could very well ruin many small- and medium-sized coal-fired plants by requiring the installation of emissions control technology such as selective catalytic reduction and flue gas desulphurization wet scrubbers at a cost of millions of dollars over the next decade. [NEW MATTER]