Energy Legal Blog

Harsh Admonition for Over 200 Late Filers of Market Power Updates

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]

Proposed Rule Would Allow e-Filing of Interlocking Directorates, 20 Largest Utility Purchasers Information

 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 Pushes Ahead on Prevention of Market Abuse and Works to Increase Transparency in Energy Markets

            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]

Dominion Successfully Integrates into PJM

 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]

FERC Says the Court Was Confused in Affirming Generator Interconnection Decision on Remand

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]

Reductions of Power Plant Emissions on the Minds of State Regulators

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]

FERC Issues Small Generator Interconnection Rule

In its Order No. 2006, issued May 12, FERC established standard procedures for interconnecting generators no larger than 20 MW.  This order continues the process begun in Order No. 2003 of standardizing the terms and conditions of open-access interconnection service.  The new procedures apply to small generators seeking to interconnect with transmission systems that are subject to an open-access tariff at the time the generator's request is made.  Order No. 2006 requires public utilities to amend their open-access transmission tariffs ("OATTs") to include a Small Generator Interconnection Procedures ("SGIP") document and a Small Generator Interconnection Agreement ("SGIA"). 

The SGIP, like the large generator interconnection procedure ("LGIP") set forth in Order No. 2003, includes the technical procedures that a transmission providers is to follow when it receives an interconnection request.  The SGIP differs from the LGIP, however, in that the procedure under the SGIP is simpler and includes an accelerated trajectory.  The SGIP provides three methods for addressing interconnection requests.  One approach, called the "Study Process," is a default process available to any small generating facility.  This approach, identical in concept to the process for large generators under Order No. 2003, relies on a scoping meeting and studies addressing standard feasibility, system impact, and facilities.  The other two approaches involve special procedures designed specifically for two subgroups of small generating facilities and use technical screens to evaluate the proposed interconnection.  One of these approaches, the "Fast Track Process," is available to certified small generating facilities no larger than 2 MW, while the other, the "10 kW Inverter Process," applies to certified inverter-based small generating facilities no larger than 10 kW.   

The SGIA prescribes contractual provisions applicable to the interconnection of small generating facilities and describes the legal relationships of the interconnection customer and the transmission provider.  For example, the SGIA includes provisions for payment for modifications to the transmission provider's system made to accommodate the interconnection.  These provisions utilize the same pricing policy as was applied in Order No. 2003.  The parties are to sign the SGIA after completing the SGIP Study Process or one of the approaches for very small generating facilities.  [Standardization of Small Generator Interconnection Agreements and Procedures, 111 FERC 61,220 (2005)] [NEW MATTER]

FERC Revises Business Practices Standards for Pipelines and Proposes New Standards for Electric Utilities

            On May 9, 2005, FERC issued complementary orders adopting revised business practices for natural gas pipelines and proposing similar standards for electric utilities.  The orders largely adopt standards proposed by the North American Energy Standards Board (NAESB). 

The Final Rule for gas pipelines adopts several standards developed by the Whole Gas Quadrant (WGQ) of NAESB, including WGQ's recommended practices for creditworthiness and gas quality reporting.  The creditworthiness standards provide procedural rules by which pipelines should deal with their customers with respect to credit issues, and these standards received broad support from shippers and pipelines.  They would provide standardized procedures for obtaining credit information; acknowledging and responding to requests for and receipt of information; notifying shippers regarding creditworthiness issues and contract termination;  reevaluating of determinations that a service requester is not creditworthy; and monitoring releases of capacity only to shippers  found to be creditworthy.   

FERC's Final Rule also adopts WGQ's proposed standards for gas quality reporting.  These standards include requirements that a pipeline include on its Informational Posting Web Site a link or reference guide to its gas quality tariff provisions and information on its daily average gas quality for preceding days to the extent quality information is available for locations that are representative of mainline gas flow for the most recent three-month period.  The Final Rule will become effective June 16, 2005, and pipelines are required to file with FERC conforming tariff provisions by July 1, 2005, to be effective September 1, 2005.  

In an attempt to similarly streamline reporting requirements and business practices for electric utilities, FERC also issued a Notice of Proposed Rulemaking (NOPR) proposing business practices standards that seek to incorporate standards developed by NAESB's Whole Electric Quadrant (WEQ).  The NOPR proposes to adopt: (1) Open Access Same-Time Information Systems (OASIS) Business Practices Standards; (2) OASIS Communications Protocols; and (3) an OASIS Data Dictionary.  The NOPR also proposes procedures for  redirecting transmission service, queuing multiple submissions of identical transmission requests, adopting the OASIS requirements of FERC's Large Generator Interconnection Rule (Order No. 2003), and for reviewing and updating OASIS standards.  Finally, the NOPR proposes to incorporate WEQ business practices standards, which complement the Version 0 Reliability Standards developed by the North American Electric Reliability Council (NERC).  To be considered by the agency, public comments on the NOPR must be submitted by July 1, 2005.   [Standards for Business Practices of Interstate Natural Gas Pipelines, 111 FERC ¶ 61,203 (2005) and Standards for Business Practices and Communication Protocols for Public Utilities, 111 FERC ¶ 61,204 (2005)] [NEW MATTER]

Court Rejects Industrial Consumers Challenge to New York ISO's Design for Pricing Capacity Reserves

            Over the spirited and multifaceted objections of industrial power consumers ― represented by the Electricity Consumers Resource Council ("ELCON") ― a US appeals court upheld FERC orders allowing the New York ISO ("NY ISO") to replace a flat-rate price for installed capacity with a price set equal to a downward-sloping demand curve.  The sum of ELCON's arguments boiled down to a complaint that the new prices were simply too high and would unduly burden New York consumers.  But the court agreed with FERC that the downward-sloping demand curve price would induce needed investment in generating capacity by providing more stable and predictable pricing of capacity than resulted from the flat-rate price.  

Similar to other regulators and operators of organized power markets, NY ISO requires that all providers of retail power service maintain a reserve of installed capacity or "ICAP" in excess of peak demand ― 118 percent of peak demand in the case of NY ISO.  Formerly, a retail service provider within NY ISO who was ICAP deficient was required to make up the deficiency in monthly ICAP auctions in which the price of  ICAP was a deficiency charge equal to $255 per kilowatt/year or three times the annualized cost of installing new peaking capacity.  This produced a vertical demand curve:  All demand for ICAP up to 118 percent of peak demand was flat at the deficiency charge, beyond which the price fell to zero.  NY ISO found that this scheme resulted in extreme price volatility that deterred investment in new capacity.  Accordingly, NY ISO proposed, and FERC agreed, to replace the flat-rate prices with a structure that priced ICAP on a downward-sloping demand curve under which price declines as quantity demanded increases.  Specifically, for ICAP equal to 118 percent of peak demand the price would be the annualized cost of new peaking capacity; the price for demand beyond 118 percent gradually would to zero at 132 percent of peak demand, and for demand less than 118 percent the price gradually would increase to the 200 percent of the cost of new peaking capacity.  

FERC found that the sloping continuum of prices was likely to eliminate the extreme volatility of pricing under the old scheme and, as a consequence, would likely induce new investment in ICAP at not too high of a cost to consumers.  The court agreed and rejected ELCON's contention that FERC could approve a system of what ELCON characterized as "incentive rates" only if FERC determined that the increased price of ICAP was no more than absolutely necessary to achieve the objective or encouraging new investment.  FERC need only demonstrate that the new pricing is supported by the available evidence.  The court also took comfort in FERC's insistence that NY ISO monitor and report on the new pricing system's performance during the first two years of its operation.  (D.C. Circuit No. 03-1449) [NEW MATTER]

Illinois Commerce Commission Conference on Sustainable Energy

            The Electric Policy Committee of the Illinois Commerce Commission met May 11 to hear electric utility proposals for implementing a sustainable energy plan in the Land of Lincoln.  The proposals were developed in response to Governor Rod Blagojevich's "Sustainable Energy Plan," a proposal submitted last February to the Commission.  The Governor asked the Commission to find a way to implement the Plan, which includes a set of goals and recommendations.  Commissioner Robert Lieberman leads the initiative to develop the plan, which is expected to be issued in final form in June.  

The Governor's Sustainable Energy Plan drew on the recommendations of various stakeholders, including electric utility companies, environmental organizations, and consumer groups.  It also incorporated some of the recommendations from the Illinois Energy Task Force I appointed following the August 2003 blackout that crippled much of the rust belt extending to New York.  The Plan included a Renewable Portfolio Standard involving procurement requirements for electric utilities, eligibility criteria for resources that can be used to meet those requirements, cost recovery provisions, energy trading options and compliance measures.  The Plan also included an Energy Efficiency Portfolio Standard with similar features.  To facilitate discussions on the Plan's goals, Lieberman divided the issues among two working groups, the Renewable Portfolio Standard ("RPS") Working Group and the Demand Response/Energy Efficiency ("DR/EE") Working Group.  

At the May 11 meeting, the Commission heard Utility Implementation Plans from Commonwealth Edison and Ameren, presentations on regional transmission issues from the PJM Interconnection and Midwest ISO, and presentations on renewable energy credit trading.  The Commission staff will report to the full Commission on the Plan and implementation options by June 7.  Further developments may be expected soon, as Illinois moves to join the growing number of states that have established renewable energy requirements.   [NEW MATTER]

New Hampshire Representative Seeks Delay of MTBE Liability Waiver to Grandfather N.H. Groundwater Contamination Lawsuit

Even though he voted for the controversial provision in the US House of Representatives' latest energy bill that would relieve manufacturers of gasoline-additive methyl tertiary butyl ether (MTBE) from liability, Representative Charles Bass (R-NH) is reportedly currently drafting an amendment that would delay the waiver's effective date.  Bass faces pressure from his home state to delay the liability waiver in order to preserve groundwater contamination lawsuits filed by the State of New Hampshire and local officials against MTBE manufacturers.  By saving his home state's lawsuits, Bass's amendment could help secure the crucial support of New Hampshire Senators Judd Gregg (R) and John Sununu (R).  In last year's Congressional fight over the MTBE liability waiver, Bass, Gregg, and Sununu all voted against the House's energy bill containing a similar waiver provision.  

H.R. 6, the House's current version of the long-awaited energy bill, contains language that would retroactively bar lawsuits against MTBE manufacturers and distributors that were filed after the waiver's effective date, which is September 5, 2003 in H.R. 6.  Numerous suits have been filed by states, counties, and drinking water suppliers, alleging that MTBE has contaminated their drinking water and seeking compensation from manufacturers and distributors.  Bass's amendment, if passed, would push the effective date of the waiver back to October 1, 2003, which environmental groups point out would save only a handful of the 155 MTBE lawsuits currently pending.  Industry groups oppose any amendment that would delay the effective date of the waiver, since they say that no one date will satisfy everyone.  In a tradeoff for his vote in favor of the liability waiver, Bass has also indicated support for establishing a fund, possibly entirely industry-financed, that would help states and counties address contamination cleanup.   [UPDATE]

We Energies of Wisconsin Awaits Key Court Ruling on Air and Water Permits

We Energies, a utility serving Wisconsin and Michigan's Upper Peninsula, is facing legal challenges on numerous fronts to its proposed "Power the Future" project, a $2.15 billion proposal to develop Wisconsin's first coal power plant to be built in decades.  We Energies is battling state agencies over air and water permits, as a docket of lawsuits have been filed attempting to overturn the permits and derail the project.  The company's battles have attracted nationwide attention and have implications for the development of similar coal-fired projects in other states.  

In 2004, Wisconsin state utility regulators approved We Energies' plan to build two 615 megawatt coal base load plants at its Oak Creek generating plant, as part of its plan to add 2,300 megawatt of fuel-diverse power to its service territory.  The project development hinges on the construction permit decision expected soon by Wisconsin's Supreme Court.  The court is reviewing a decision by the Dane County Circuit Court, which vacated the construction approval issued by the Wisconsin Public Service Commission.  The Circuit Court Judge agreed with the plaintiffs' argument that regulators failed to follow state statues that require thorough accounting of other energy alternatives, specifically renewable projects, before approving any more coal power supply.  Sources within We Energies say that a decision against the company will effectively kill the project.  In order to meet contract deadlines, We Energies needs a ruling from the Supreme Court by mid-May.  

In addition, We Energies is also defending air permits awarded to it by the Wisconsin Department of Natural Resources (DNR).  In that lawsuit, challengers argue that We Energies should be required by the Clean Air Act's lowest achievable emission rate and best available control technology requirements to evaluate the use of Integrated Gasification Combined Cycle (IGCC), a state-of-the-art technology that produces electricity from gasified coal and can significantly reduce air emissions.  DNR officials argue that federal technology requirements are not relevant because IGCC is a fundamentally different type of energy production process, rather than emissions control.  We Energies is also facing a lawsuit filed on April 25 in Dane County Circuit Court by the environmental watchdog group Clean Wisconsin and consumer-products giant S.C. Johnson that seeks to overturn a water discharge permit issued by the Wisconsin DNR.  Plaintiffs argue that the intake system, using 2.2 billion gallons of water from Lake Michigan, will kill billions of fish and disrupt the aquatic ecosystem in the lake.  These groups say DNR erroneously classified the cooling system as an existing facility, thereby subjecting it to less stringent regulations.   [NEW MATTER]

FERC to Begin Revising Order 888 this Summer

FERC will formally begin revising its landmark order requiring open-access transmission by issuing a notice of inquiry within the next few weeks.  Chairman Pat Wood has indicated that the notice will issue before his June 30 departure.  The impetus for change began last summer, when then-newly appointed Commissioner Joseph Kelliher suggested that the agency needed to evaluate whether Order 888 should be broadened to protect against transmission market power.  Kelliher began an informal process to determine whether the open-access transmission tariffs of jurisdictional utilities' were sufficient to ensure open access to the transmission grid.  At a technical conference on transmission market power in December 2004, both Wood and Kelliher indicated the agency was considering an update to the nearly ten-year-old open-access rules.  A notice of inquiry, if issued, would institute a broad stakeholder process inviting comments on the issue, and may result in a formal rulemaking.  [NEW MATTER]

California Assembly Considers Reductions in Greenhouse Gas Emissions Despite Concerns by Industry Groups

The Golden State is currently considering a bill (AB 1365) that will set greenhouse gas ("GHG") emission reduction targets of seven percent by 2010 and ten percent by 2020, in relation to the state's 1990 GHG emission levels.  The Assembly Natural Resources Committee passed the bill on April 25, in the face of public opposition by industry groups.  These groups expressed concerns over emissions targets and indicated their preference for a more wide-ranging effort on the part of the state's EPA to pursue GHG emission reduction standards.  The industry groups primarily opposed the deadlines, which they would extend, and complained of perceived adverse impacts on business within the Golden State.  (AB 1365) [NEW MATTER]

Seeking the Best of Old and New, FERC Solicits Ideas on How to Create Long-term Transmission Rights in Markets With Locational Pricing

Taking another look at a controversial feature of restructured electricity markets, the Federal Energy Regulatory Commission ("FERC") recently invited the public to comment on how long-term transmission rights could exist in markets that manage congestion with  locational pricing.  While market participants in restructured markets can purchase Financial Transmission Rights ("FTR") to hedge against congestion costs, FTRs have a term of only one year.  In contrast, the life of a generating stations and the term of a typical power purchase agreements extend over many years, possibly decades.  This temporal asymmetry, according to FERC, is what is driving the interest in creating longer-term transmission rights.  To be considered by the agency, public comments must be submitted to FERC by June 27, 2005.  

In power markets based on the open-access principles of FERC's Order No. 888, grid users can purchase network integration transmission service or firm point-to-point transmission service, both of which are available on a long-term basis.  These transmission services offer their own protection against transmission congestion.  In restructured electric power markets that use locational pricing, where congestion can increase energy prices, entities can hedge against congestion costs by purchasing FTRs and thereby receiving congestion revenues that, at least in part, offset congestion charges.  However, FTRs are relatively short-term instruments, as no organized power market in the U.S. offers FTRs for more than a one-year.  In addition, there may not be enough FTRs available at any given time to satisfy demand for them. 

Among the obstacles FERC identified to the use of long-term FTRs are that FTRs must be allocated the transmission system capabilities expected to exist in a given year.  Long-term capability scenarios, however, are hard to forecast.  Consequently, there are valuation problems based on the difficulties of predicting system congestions for future years; liquidity concerns since the market for FTRs of a specific duration could be thin; as well as other complications.  FERC is interested in hearing about the need for long-term transmission rights and the problems caused by the lack of them; what entities or markets are most affected by their absence; whether regional transmission organizations or independent system operators have plans to address this; and, perhaps most importantly, what are FERC’s options for creating markets in long-term transmission rights.  

For assistance in preparing or submitting comments to FERC on this important initiative, please contact the Energy Markets & Regulation practice group in the Washington, DC office of Bracewell & Giuliani.  (FERC Docket No. AD05-7-000) [NEW MATTER]

Kansas Creates Electric Transmission Authority to Ensure that the Lights Stay on in the Sunflower State

Early in April, the Sunflower State followed Wyoming's lead in the creation of a state electricity infrastructure authority by passing the Kansas Electric Transmission Authority Act ("Act") and creating the Kansas Electric Transmission Authority ("Authority").  According to the Act, the Authority is responsible for ensuring the reliable operation of the state's integrated electrical transmission system and facilitating the consumption of the state's energy through improvements in Kansas' electric infrastructure.   

The Act permits the Authority to accept federal agency grants for operation, and to borrow funds and make loans to finance construction of or make upgrades or repairs to third-party transmission facilities.  It is intended that the Authority will recover its costs through tariffs of the Southwest Power Pool ("SPP"), or through assessments against any utility that benefits from Authority projects that have customers in Kansas.  The Authority is not permitted to directly maintain or operate transmission facilities. 

One important caveat, however, is that the Authority is only permitted to exercise its powers where private entities fail to do the job.  Specifically, SPP will continue to solicit support from utilities to build transmission projects in Kansas; only where the utilities are unwilling to fund and build new infrastructure is the Authority permitted to act.   (H.B. 2263) [NEW MATTER]

California Assembly Again Considers Retail Choice for Large Customers

The California State Assembly is considering the possibility of returning retail choice to the state, after its suspension during the 2000-2001 energy crisis.  Assembly Bill 1704 ("AB 1704"), introduced by Assemblyman Keith Richman (R-Granada Hills), would establish a core/non-core retail market in California.  Under the proposal, utility customers who use more than 200 KW ("non-core" customers) could choose either to take service from direct-access providers or remain with their investor-owned utility, while individual and small commercial customers would continue receiving service from the IOUs.  Non-core customers that do not choose between direct access and remaining with their IOU would be placed on a temporary default service tariff from their utility.  The length of time customers would be on default service is currently being debated, ranging anywhere from no default period to five years, with the utilities pushing for a longer amount of time in order to ease generation procurement concerns.  Current language in the bill would also encourage aggregation, which would allow cities or towns to aggregate their loads and would allow customers with any facility that uses more than 200 KW to aggregate load at all facilities. 

Assemblyman Richman explained: "I believe large customers should have the ability to choose, and I think this bill accomplishes that."  However, Richman does expect changes to AB 1704 as it goes through the legislative process, including the possible addition of a phased-in implementation schedule.  A phased-in timeline would allay fears, even among some supporters of the proposal, that the bill would open the market up to retail choice too quickly.  Other changes may include working out the details on mitigation between core and non-core service and the CPUC's role in oversight of utility procurement.  The proposal's earliest possible effective date is January 1, 2007. 

AB 1704 was approved by the Committee on Utilities and Commerce on April 18, 2005 and was referred to the Appropriations Committee.  If the bill passes the entire Assembly, it must also gain support in the California State Senate, which has rejected similar efforts in the last few years.  The bill already has the public support of Governor Arnold Schwarzenegger, who made retail choice a part of his proposed energy plan, as well as the head of the CPUC.  Sempra Energy, Pacific Gas & Electric, the Alliance for Retail Energy Markets, and the Independent Energy Producers Association have also expressed support for retail choice.  However, Southern California Edison opposes the bill, complaining that the proposed rules on aggregation are so loose that its entire customer base would become uncertain.  Other opponents include the Utility Reform Network and the Coalition of California Utility Employees.  Many Democrats have also opposed AB 1704, arguing that it will result in the kind of chaos that occurred the last time the state attempted to deregulate its electricity markets.  Richman rejected these claims, stating, "This is a fully regulated market structure.  To describe it as deregulation is just incorrect."    (A.B. 1704) [NEW MATTER]

FERC Audits Two Market-Based Rate Sellers – Reaction to Ninth Circuit Lockyer Decision Concerning Reporting Requirements for Market-Based Rate Sellers?

FERC announced in April that it would begin auditing power sellers with market-pricing authority for compliance with demanding quarterly reporting requirements.  The audits plainly come in response to the dubious court decision in Lockyer v. FERC and signal to all market-price sellers the need to heighten their attention to accurate quarterly reporting both in the past and going forward.  

Last September, the Ninth Circuit US Court of Appeals ruled that wholesale power sales under a market-based tariff, if not individually detailed in quarterly filings with FERC, were "pragmatically" sales with "no filed tariff in place at all," implying that such sales would not enjoy the protections accorded to transactions undertaken pursuant to filed tariffs and could be subject to retroactive refunds stretching back indefinitely.  See UPDATE (9/30/04).  The court was plainly imposing more stringent requirements than had FERC for most of the market-pricing program, which began in the early 1990s.  Not until May 8, 2002, did FERC make it clear in its Order No. 2001 that it expected all short- and long-term sales under authority of a market-based tariff to be individually recounted in quarterly reports, without aggregation. 

What the Court did was wrongly caveat its approval of FERC's market-based rate program with a finding that sales made pursuant to the program, if not individually detailed in quarterly published reports, were not sales made under a filed tariff.  The Court determined that those sales that were not authorized by a filed tariff would not be eligible for filed rate protection, and thus, could be the subject of refunds.  As we observed last September, the potential impact of the Court's erroneous ruling is not necessarily confined to the Attorney General's complaint, which assailed only short-term sales made to the ISO, PX and CERS.  See UPDATE (09/30/2004).    (Docket Nos. FA05-1-000 and FA05-2-000) [NEW MATTER]

U.S. District Court Finds Filed Rate Doctrine also Applies to Market-Based Rates in Natural Gas Markets

On April 8, 2005, the U.S. District Court for the District of Nevada found that the filed rate doctrine prohibited federal and state antitrust and unfair competition claims against sellers of natural gas.  In In Re W. States Wholesale Natural Gas Antitrust Litig., the Court affirmed FERC's exclusive authority to determine the reasonableness of wholesale natural gas prices under the Natural Gas Act, even in the context of a price-deregulated natural gas market.  The court's decision joins other recent legal decisions protecting the price expectations of market-based sellers of both natural gas and electricity.  

As a result of the California energy crisis of 2000-2001, Texas-Ohio, Inc. sued several sellers of natural gas, claiming that they violated federal and state antitrust laws and unfair competition laws by engaging in false reporting of natural gas prices, facilitating wash trades, entering into illegal netting agreements, and conspiring not to compete in the natural gas markets. The natural gas sellers asked the court to dismiss the complaint on the ground (among others) that the court was barred by the filed rate doctrine from calculating hypothetical rates for what would have been charged in the natural gas markets absent the defendants' alleged misconduct.  The court agreed, explaining that Congress gave FERC the exclusive authority over wholesale natural gas prices under the Natural Gas Act, and that the filed rate doctrine applied "even though FERC, in exercising its authority, chose to move toward a market-based system."  The Court also found that the natural gas market should be treated no differently than electricity markets, noting the Ninth Circuit's finding in Public Utility District No. 1 of Grays Harbor County Wash. v. Idacorp, 379 F.3d 641 (9^th Cir. 2004) that FERC retains statutory authority over wholesale power sales under the Federal Power Act, and that the filed rate doctrine protection applies even in the context of market-based rates.  (D. Nev., J.P.M.L. Docket No. MDL 1566) [NEW MATTER]

U.S. Supreme Court Will Not Review Decision Prohibiting Courts from Ruling on Wholesale Power Prices

Fallout from the 2000-2001 western energy crisis persisted in April.  In a case involving one of the relatively smaller claims to arise out of the crisis, on April 18, 2005, the US Supreme Court denied the petition of the State of California for review of a lower court ruling that only FERC can decide whether the state was unlawfully double-billed for wholesale power.  

In a claim filed in state court in 2002, California alleged that certain generators violated the state's unfair business competition laws by double-billing the California Independent System Operator ("CAISO") over $100 million during the crisis.  The double-billing occurred, according to California, when the generators charged the CAISO for energy reserves and then later sold the same electricity used to back up these reserves into the spot market at "exorbitant" prices.  The generators, on the other hand, claimed they did nothing wrong and argued that the electricity was always available when the reserves were called upon. 

In July 2004, the Ninth Circuit denied California's claims, ruling they were not appropriately heard by the courts, but instead could only be decided by FERC since the Federal Power Act conferred on FERC exclusive jurisdiction to establish lawful prices in public utility wholesale power sales.  By denying California's petition, the Supreme Court allowed this ruling to stand.  Spokesmen for the State have promised to continue pursuing these claims at FERC.  (U.S. Supreme Court, Case No. 04-1028) [UPDATE]

New England Set to Implement Day-Ahead Demand-Response Market Beginning June 1

The New England Power Pool and the ISO New England finally won FERC approval in April to expand their demand-response bidding beyond real-time to the day-ahead market ¾ the Day-Ahead Load-Response Program or DALRP.  This approval joins other recent regulatory recognitions that conservation can often prove the least-cost answer to perceived supply shortages.

When the new program goes into effect June 1, a firm-demand New England customer can elect to become a demand resource by registering in one of ISO-NE's load-response programs and then be able to offer demand reduction in the day-ahead market to reduce its demand for payment.  If not accepted day-ahead, then the customer can still offer its demand reduction in the existing real-time response program.

DALRP offers must be in increments of 100 kilowatts, for a minimum interruption between one and four hours, at prices between a minimum of $50 and a maximum $1,000 of per megawatt hour.  DALRP offers that clear the market will be paid the day-ahead locational marginal price multiplied by the offered amount of demand reduction and the number of hours that are cleared.  Differences between DALRP offers and real-time performance will be settled at real-time locational marginal prices.

Who pays the cost of the DALRP program was controversial.  Once the program goes into effect on June 1, the cost of all load response ¾ both the new day-ahead and the existing real-time program ¾ ceases to be the responsibility of only real-time load response customers and becomes the responsibility of all network demand based on the theory that the downward pressure on prices of reduced day-ahead demand will benefit equally all customers.  Certain municipal network customers balked at this because they are fully scheduled day-ahead and are locked into day-ahead prices.  Under the first phase of DALRP implementation, however, the DALRP offers will only reduce clearing energy prices in real-time, sequentially after the supply offers have been processed.  Despite this complaint, FERC authorized the program because, it reasoned, downward-price pressure in the real-time dispatch, over time, will push down day-ahead prices as well.

In a later phase of implementation, the DALRP program will be integrated into the day-ahead dispatch and will no longer be a sequential add-on to the processing of supply-side offers.  Once integrated and no longer sequential, DALRP should cease to be controversial. [New England Power Pool, 111 FERC ¶ 61,064 (2005)] [NEW MATTER]

Benefits of ISOs and RTOs – ISO-NE Results Show Lower Prices, Increased Investment and Improved Efficiency, Reliability and Environmental Action

In its recently published "Progress of New England's Restructured Electric Industry and Competitive Markets: The Benefits of ISOs and RTOs," ISO-New England ("ISO-NE") lauds the long-term performance of its power market.  Since the market's inception in 1999, New England wholesale electricity prices have declined by 5.7 percent, after adjustments for fuel costs, and the fuel-adjusted price decline experienced from 2001-2004 was 11 percent.  Also during this time, ISO-NE estimates that more than $9 billion was invested in new power plants, and up to $4 billion was invested in transmission facilities.  These improvements have significantly increased the region's reliability and competition, according to the report. 

The report notes significant environmental improvements as well, including the use of more efficient gas-fired generators, which has reduced annual carbon dioxide emissions by up to 6%, nitrogen oxide emissions by approximately 32%, and sulfur dioxide emissions by up to 48% from 2000 to 2004.  ISO-NE estimates that the additional generation, along with the competitive market incentives to improve generator availability, enhance operations, and make infrastructure investment more efficient, has led to a wholesale market cost reduction of approximately $700 million annually (after adjusting for fuel costs), demonstrating that these markets bring significant benefits to consumers.  [NEW MATTER]

FERC Asks for Comments on the Roles of RTOs and ISOs in Establishing Reference Prices for Mitigation

On April 1, 2005, FERC invited comments on the roles of Regional Transmission Organizations ("RTO"), Independent System Operators ("ISO"), or their market monitors in establishing reference prices to be used to lower or "mitigate" wholesale power prices deemed to be non-competitive.  Public comments were due to FERC by May 2, 2005. 

Several RTOs and ISOs ― including the New York ISO, ISO-New England, California ISO, and the Midwest ISO ― use "conduct and impact" tests in their wholesale day-ahead and real-time electricity markets to determine whether to apply mitigation to assure just and reasonable rates.  The conduct test seeks to identify excessive bidding or economic withholding.  A unit's bids are compared to the reference price for that unit, which is an approximation of the unit's marginal costs.  If a bid exceeds the reference price by more than the set percentage or dollar amount stated in the tariff, then the bid has exceeded the conduct threshold, and therefore failed the conduct test.  If a bid fails the conduct test, then the impact test is also applied to determine whether the bid has changed the market prices by more than a level stated in the RTO or ISO's FERC-approved tariff.  If the impact exceeds this level, then the bid is mitigated ― it is replaced by a default bid  The unit's reference price serves as its default bid when the unit's bid fails both the conduct and impact tests. 

RTOs and ISOs or their market monitors use a variety of methods to determine the reference price for a particular unit at a particular output level.  Reference prices are set in advance of application of conduct and impact tests.  The methods of determining the reference price, and the order in which these methods are used, are specified in the RTO's or ISO's FERC-approved tariff.  The level at which reference prices are set for individual units may affect the market prices both by determining the point at which a unit's bid fails the conduct test (and thus may be subject to mitigation) and by the use of the reference price as a default bid.

FERC is particularly interested in understanding who develops reference prices; when reference prices are used and what effect they have on the wholesale market-clearing price; how reference prices in the wholesale market function like bid caps as opposed to how they function like formula rates; circumstances under which reference prices, once set, may require quick adjustment; how often the various methods of determining references prices are used; and whether a better system for determining reference prices exists, what such a system would look like, and whether that system may involve the market monitor developing the reference prices and submitting them to FERC for approval.  Finally, FERC is interested in the degree to which RTOs, ISOs and their market monitors employ discretion in setting reference prices, and in whether that discretion is appropriate under the RTOs' and ISOs' tariffs and is a proper delegation of FERC's authority. [NEW MATTER]

FERC Seeks to Rectify Imbalance in OATT with New Rule Giving Lift to Wind

To integrate wind and other intermittent resources energy more completely into wholesale power markets, FERC has proposed a new rule that would relax the imbalance penalties that generators pay under the pro forma open-access transmission tariff ("OATT").  The proposed new generator imbalance service schedule is intended to address the unique characteristics and constraints of intermittent resources such as wind, solar and run-of-river hydro facilities that rely on the weather, and therefore have a limited ability to predict or control their output.  Comments on the proposed imbalance rule are due to FERC by May 26, 2005.

When FERC first adopted the OATT, wind energy played a smaller role in power generation, and was not forecast to grow as it is today.  Instead, the OATT was designed around the characteristics of generators with controlled fuel input and more precise scheduling ability, and, among other objectives, was intended to help promote predictable scheduling by generators.  At present, most intermittent resources are held to the same exacting scheduling requirements as dispatchable generators, but the inability of intermittent resources to correlate their scheduled and actual output can cause them to pay high penalties, compromising their economics. 

FERC's proposal would establish for intermittent resources a safe-harbor bandwidth of plus or minus 10 percent.  Deviations within the bandwidth would be priced at the transmission provider's incremental/decremental cost at the time of the deviation.  Deviations outside the bandwidth would be priced at the transmission provider's system incremental/decremental cost plus or minus 10 percent.  The proposed rule would apply even more relaxed standards to intermittent generators of less than 20 MW in size.

For those transmission provider tariffs that already contain more lenient imbalance charge provisions, FERC proposes that the lesser charge continue to apply to intermittent resources.  The proposal adheres to the existing tariff standard of allowing modification of generation schedules up to 20 minutes before the hour to minimize exposure to the costs associated with imbalances. 

FERC is seeking comments on a wide range of issues related to the proposed rule and generator imbalances generally, including whether generator imbalance provisions in future interconnection agreements should conform to what is proposed in the rulemaking, and what effect the proposed rule would have on transmission system operations and reliability.  FERC also noted that system reliability should not be compromised by the proposal since the impact of the intermittent resources for most transmission systems will be relatively small in comparison to total generation and transmission on any system. 

The proposed rulemaking stems from the increased attention FERC has given to wind energy issues in the past year.  In December, the agency's technical staff issued a white paper on the status of wind energy in wholesale markets, followed by a technical conference and public comments in January.  FERC also proposed in January regulations addressing the interconnection of wind energy plants to the grid.  See UPDATE (1/31/05).  [Imbalance Provisions for Intermittent Resources Accessing the State of Wind Energy in Wholesale Electricity Markets, 111 FERC ¶ 61,026 (2005)] [UPDATE]

Mexican High Court Rejects Congressional Auditors' Challenge to Private Generation and Sales of Power

Private power south of the border narrowly escaped in April a congressional audit committee invalidating as unconstitutional their generation and sale of power to the national electricity monopoly, the Comisión Federal de Electricidad ("CFE").  At the request of Mexican President Vicente Fox, the Mexican Supreme Court by a 6-to-5 vote ruled that the audit committee of the opposition-dominated Congress did not have authority to rule on the constitutionality of the power purchase contracts between CFE and private generators.  Had the high court affirmed the audit committee and ruled against President Fox, approximately 7,300 megawatts of privately owned generation capacity in Mexico would no longer have been able to make sales to CFE ― the only private sales permitted under Mexican law ― thereby setting up a scenario in which CFE would be forced to buy out the private owners at fire-sale prices.  While the decision on the authority of congressional auditors falls short of an affirmative endorsement of the constitutionality of private power sales to CFE, it was nevertheless sufficiently reassuring that an audible sigh of relief arose from private power developers following the court's April 16 decision.

Ever since the late 1930's nationalization of Mexico's energy industry, CFE and its predecessor alone were permitted to generate and sell electric power in Mexico.  The law was changed in 1992 to permit private companies to generate or cogenerate power for their own use or for sale to CFE, but not directly to the public.  Since then, private capacity has grown to the point that today it accounts for approximately 20 percent of the capacity available to CFE.

Development of private generation accelerated under the policies of President Fox, until the congressional auditors raised their challenge to the private sales to CFE in early 2004.  Recognizing the chilling effect that the auditors' challenge would have on sorely needed investments in the Mexican economy, President Fox moved quickly to challenge the auditors, resulting in the high court's ruling against the auditors on April 16.    In the near term, the court's decision is not expected to increase new private investments in the Mexican power sector since CFE currently has a 40 percent capacity reserve due to a surge in private investment soon after President Fox's reelection in 2004 and a floundering economy.  [NEW MATTER]