Energy Legal Blog

FERC Mostly Affirms Market-Based Rate Program

On April 21, FERC issued an order generally affirming its market-based rate program, promulgated last June in Order No. 697.  FERC left many of its prior determinations in place, including much of the analysis sellers must provide in order to receive or maintain authority to sell electric energy, capacity, and/or ancillary services at market-based rates. 

In particular, FERC affirmed its decision to combine its prior four-pronged analysis into an evaluation of horizontal and vertical market power.  FERC will continue its approach of using "indicative" screens to determine both a seller's wholesale market share and whether the seller is a "pivotal" supplier within the relevant geographic market.  If a seller fails to pass either of these screens, FERC will presume the seller has market power within that market and require the seller to either (a) refute that it has market power or (b) adopt mitigated (i.e., cost-based) rates for that market.  FERC also affirmed its decision to remove questions about the relationship between market-based rate sellers and their affiliated franchised public utilities from the market-based rate review program, and instead to codify those requirements in FERC's regulations as ongoing obligations that sellers must continue to meet.

FERC did offer certain clarifications or revise certain of its prior determinations on rehearing.  One of FERC's major changes was to allow a seller that has been presumed to have market power in the short-term to continue to show that it does not have market power, and thus may continue to charge market-based rates, with respect to its long-term contracts.  To do so, a seller is required to show that the buyer has other viable alternatives to purchasing power under the contract.  Additionally, with respect to FERC's affiliate restrictions, FERC granted rehearing on its adoption of a prohibition on two-way information sharing between market-based rate sellers and affiliated franchised public utilities with captive customers, determining instead that to adopt a one-way prohibition, i.e., the utility may not provide information to the market-based rate seller.  A few FERC's other notable clarifications included:

• FERC clarified that sellers may make use of ISO/RTO mitigation and/or market monitoring in order to show they do not possess market power and that such mitigation and monitoring will be presumed to be sufficient to address market power concerns, although other parties may present evidence otherwise. 

• FERC made certain clarifying changes with respect to the horizontal market power analysis, which examines whether a seller has generation market power in generation.  In particular, FERC clarified the data that it will rely upon in this analysis.  FERC generally affirmed its decision to rely solely on historical data to determine whether a seller has market power.  However, FERC conceded that it will consider, on a case-by-case basis, "clear and compelling evidence" that certain changes in relevant geographic markets should be taken into account.  Additionally, FERC also provided several clarifications to the transmission import studies that sellers must provide to account for uncommitted generation capacity in their relevant markets.

• FERC clarified that sellers are not required to report on firm transmission rights or congestion contracts (collectively, FTRs) as part of their analyses of their vertical market power, which examines whether a seller has market power with respect to transmission or can erect other barriers to entry.

• FERC codified definitions of "affiliate" and "captive customers" in its regulations, and clarified that the affiliate restrictions in its regulations generally supersede prior "codes of conduct."

Bonneville Holding Transmission Open Season to Speed Interconnections

Transmission providers and customers alike are increasingly complaining about the lengthy queues for interconnecting to the transmission grid.  Scores of generator projects sign up for interconnection service, which is then delayed for years while the transmission provider conducts an array of studies.  To clear backlog on its transmission network, the Bonneville Power Administration is conducting a Network Open Season for transmission service that asks customers to commit to the transmission service they are seeking. 

At present BPA’s transmission queue includes requests by 25 customers for approximately 180 applications for transmission service totaling about 8,500 MW of new capacity, but BPA states that many of these service requests are speculative.  Under its new procedure, BPA will give all customers applying for transmission service by May 15, 2008, a precedent service agreement.  If a customer signs the binding agreement and remits the required financial security by June 16, 2008, BPA commits to providing the service, so long as it can provide the service at its rolled-in rate and complete its environmental study obligations.  BPA also will assume the study costs itself and arrange financing for any required transmission facilities, instead of requiring customers to front these costs.  However, if a customer declines the offer, BPA will withdraw its service requests from the transmission request queue, while allowing the customer to participate in future Network Open Seasons.

In December 2007, the Federal Energy Regulatory Commission held a technical conference focusing on transmission queue logjams.  The interconnection queue process is governed by Order No. 2003, which standardized the agreements and procedures related to the interconnection of large generating facilities based on a first-come, first-served process.  However, the surge of new generation projects, including many based on wind and other forms of renewable energy, have led to long interconnection queues that transmission providers are now debating how to expedite. 

ERCOT Identifies Scenarios for Texas Wind Transmission

Texas Senate Bill 20 (2005) directed the Public Utility Commission of Texas (PUCT), in consultation with the Electric Reliability Council of Texas (ERCOT) and the Southwest Power Pool (SPP), to designate Competitive Renewable Energy Zones (CREZ) and develop transmission plans for areas in Texas with significant renewable resource potential and developer commitment to facilitate new electricity generation from renewable resources.  In July 2007 the PUCT designated five CREZs in West Texas and the Texas Panhandle.  In early April ERCOT filed its transmission study, which provides transmission plans and cost estimates for the four scenarios that the PUCT designated.  The study presents optimized transmission plans for developing between 12,000 MW and 24,000 MW of wind generation in the CREZs.

ERCOT applied three overarching criteria to its evaluation of the study scenarios: 1) system reliability, 2) sufficient transfer capability, and 3) benefit and cost-effectiveness for consumers.  ERCOT made a significant effort to evaluate the engineering feasibility of the interconnections and circuits that it proposed.  Consistent with the PUCT's directive, ERCOT also endeavored to design the transmission plans for each scenario to be staged and expandable to bring more wind generation on-line over time.

For Scenario 1, ERCOT designed two transmission proposals for 12,053 MW of wind generation.  Plan A has an estimated cost of $2.95 billion, excluding collection costs, and Plan B, which is a more scalable transmission proposal, has an estimated cost of $3.78 billion.  ERCOT recommended Plan B, since it provides for more cost-effective expansion in the future.

For Scenario 2, ERCOT's estimated cost of the transmission proposal for 18,456 MW of wind generation is $4.93 billion, excluding collection costs.

For Scenario 3, ERCOT's estimated cost of the transmission proposal for 24,859 MW of wind generation is $6.38 billion, excluding collection costs.

For Scenario 4, ERCOT's estimated cost of the transmission proposal for 24,419 MW of wind generation is $5.75 billion, excluding collection costs.
 

Too Much Adieu about Mobile-Sierra?

Did a panel of the US Court of Appeals for the District of Columbia Circuit bid adieu to the half century-old Mobile Sierra doctrine on contract stability when it otherwise affirmed the Federal Energy Regulatory Commission's approval of a multi-party settlement that phases in a Forward Capacity Market in New England?  Notwithstanding alarms to the contrary, it did not.   The panel in Maine Public Utilities Comm'n v. FERC ruled that the challenges of non-settling parties to prices set in the new Forward Capacity Market are to be judged under the statutory just and reasonable standard of review, and not the deferential standard applied under Mobile Sierra when a party to a contract (or its privies) unilaterally seeks to change the terms of its agreement.  That ruling does not show the Supreme Court's Mobile Sierra doctrine the door.

In companion cases, United Gas Pipe Line Co. v. Mobile Gas Serv. Corp and Fed. Power Comm'n v. Sierra Pacific Power Co., the Supreme Court in 1956 held that the terms of a valid, bilaterally negotiated wholesale energy contract are presumptively just and reasonable under the Federal Power and Natural Gas Acts, and that FERC has authority under those statutes to set aside such contracts only in extraordinary circumstances of unequivocal public interest.  Showing only that the contract had become unprofitable to one of the parties was not enough to allow that party unilaterally to change the contract.

Consistent with the Supreme Court's ruling, the Maine PUC panel affirmed a settlement provision that rates set in the Forward Capacity Market could be presumptively just and reasonable as to parties consenting to the settlement agreement, which parties thereafter could not set aside those rates except on a showing of unequivocal public necessity.  FERC erred, however, and the panel reversed when FERC extended that proposition to the eight (of over 150) parties who did not join but rather "vociferously" opposed the settlement.  In other words, the panel ruled that parties to a wholesale energy contract or settlement agreement who become unhappy with their bargain could be made subject to the higher burden of proof imposed by the deferential Mobile Sierra doctrine, but not non-parties.  This is not a rejection of Mobile Sierra.  Rather, the panel's language strongly reaffirms the doctrine's deference to all contracts and forcefully restates the heavy burden imposed on any party seeking to change its contract.

This reaffirmation is significant and timely, since the Supreme Court recently heard argument and will soon decide whether to reverse a ruling of the full US Court of Appeals for the Ninth Circuit that would eviscerate the Mobile Sierra doctrine.  The Ninth Circuit held that the doctrine applies only insofar as the contract was entered into in a market determined to be workably competitive at the time, FERC reviewed and approved the contract, and that the challenge came from a purchaser but not a seller.  The Maine PUC decision now joins the robust body of Mobile Sierra case law that requires reversal of the Ninth Circuit.

FERC Blesses Midwest ISO Plan for Resource Adequacy

The Federal Energy Regulatory Commission has conditionally accepted a Midwest Independent Transmission System Operator (Midwest ISO) plan for ensuring long-term resource adequacy in the RTO’s 15-state territory.  Most other RTOs and ISOs have spent years grappling with how to ensure sufficient capacity is available to meet peak demand, and contentious FERC proceedings have led to different market models in NYISO, PJM, and ISO-NE.  FERC directed MISO to develop its own resource adequacy plan after having operated for years without one.   The first planning year under the resource adequac plan will start June 2009.

MISO’s responsibilities under the new plan will include determining capacity obligations, monitoring compliance, and assessing penalties to deficient load servers.  Unlike the PJM, ISO-NE, and NYISO models, the MISO plan does not entail a centralized capacity market, but does require any load server in the Midwest ISO region to maintain access to sufficient planning resources, whether generation or demand response.  

Standards of Conduct Proposal Retreats from Structural to Functional Separation

A recent FERC Standard of Conduct rulemaking proposal retreats from its Order 2004 expansion of the standards of conduct, expressly finding that expansion too complex and unworkable.  FERC proposes a return to its 1990s vintage functional separation model of Order 497 (natural gas) and Order 889 (electric power), eliminating both Order 2004's concept of "Energy Affiliates" and its emphasis on corporate separation.  FERC concludes that returning to mere functional separation will encourage compliance by making the rules clearer, which the agency indicates is necessary in light of the new penalty regime of the Energy Policy Act of 2005 (EPAct 2005).  Comments on the proposed rule must be filed with FERC by May 12. 

In retreating to functional (from structural) separation, the proposal rulemaking appears to validate vertically integrated utilities by conceding that Order 2004 was hindering the advantages that accrue from vertical integration.  Nevertheless, the agency seems to be adrift between acknowledgment of the planning and integration advantages of the historical utility model and distrust of the  non-competitive characteristics of that model.  

Specifically, the proposed Standard of Conduct reform would implement:  

(1)  An “independent functioning rule” that defines the two groups of employees — “transmission function" and "marketing function" — who must function independently.  This division is based on what the employees do, not where they are employed.  Employees not directly engaged in transmission or marketing -- for example attorneys, accountants, and certain supervisors -- will not have their functions constrained by the proposed rule.   

(2)  A “no-conduit rule” to ensure independent functioning by prohibiting transmission function employees from communicating non-public transmission-related information with marketing function employees.  The no-conduit rule bars both communicating and receiving non-public transmission information, and everyone, regardless of function, is prohibited from being a conduit.   

(3)  A “transparency rule” to help detect, correct, and sanction violations of the independent functioning and no-conduit rules.  Whenever information is communicated in violation of the independent functioning or no-conduit rules, then, as provided in the current rules, the transmission function employee must immediately post that information on OASIS.  In addition, any interaction of transmission and marketing function employees would have to be contemporaneously recorded (handwritten notes may suffice) and made available to FERC on request, so the agency can monitor compliance with the rules.     

Unclear from the transparency rule is whether the damage of an improper disclosure of non-public transmission information can be undone.  Penalties for violations would remain unchanged from those enacted under EPAct 2005.

ERCOT blames inaccurate wind predictions for February emergency event

The Electric Reliability Council of Texas (ERCOT) recently released its Operations Report to explain why it was forced to cut electric supply to interruptible customers on February 26, 2008. The emergency event was caused largely by the convergence of the normal rapid load growth that occurs around 6:00 p.m. and a simultaneous unexpected and sudden drop in wind that decreased the power output from windfarms.

ERCOT was primarily relying on day-ahead schedules to judge wind capacity, which predicted 1294 MW. However, only 335 MW were actually available during the relevant hour. To address this problem, ERCOT stated it would try to adopt in the near term the generation forecasting model it will use when the market transfers to a nodal operating system in 2009, since that model creates more accurate short term planning values for wind generation.

Managing reliable integration of wind generation is a high priority for ERCOT, since Texas is now the state with the largest wind energy production in the United States and has almost 3000 MW of additional wind development with signed interconnection agreements waiting to come online.

DC Circuit Orders Immediate Tightening of Mercury Control Rules

On March 21, a three-judge panel of the US Court of Appeals for the District of Columbia Circuit made clear that its February 8, 2008 order mandating a return to tighter mercury control rules on coal-fired power plants must go into effect immediately.  The court's February order threw out the Bush Administration's Clean Air Mercury Rule (CAMR), which was implemented in 2005 and established a cap-and-trade program for mercury emissions from coal- and oil-fired power plants, and directed a return to the more stringent standards enacted in 2000 under the Clinton Administration.  The court's most recent ruling requires the Environmental Protection Agency (EPA) to begin implementing the tighter rules immediately, instead of allowing time for the EPA and others to request rehearing of the court's February order.

In its February order, the court rejected the EPA's CAMR standards as violating the Clean Air Act.  The CAMR standards required coal- and oil-fired plants to reduce mercury emissions by 70% by 2018, and permitted utilities to trade mercury emissions to allow them to reduce compliance costs.  The CAMR standards also reversed the 2000 mercury standards, which had required mercury emissions to be regulated under a maximum achievable control technology (MACT) standard.  The MACT standard that will now take effect again requires proposed power plants to adopt emissions controls in use at the best controlled similar pollution source, which will likely require power plants to remove an estimated 85% to 90% of the mercury from their emissions. 

The court's ruling will have an immediate impact on coal-fired plants that are currently in the planning and permitting stages, as these plants will have to revise their plans and permit applications in order to remove higher amounts of mercury.  However, the EPA and several utilities that supported it have indicated they plan to seek rehearing of the court's February order, and thus the ruling could be modified or reversed following en banc review.  In the meantime, the court's recent order requires the EPA to begin tightening its controls immediately.

CAISO Says It Will Announce MRTU Start in July

It is still unclear when the California Independent System Operator's long-awaited Market Redesign and Technology Upgrade (MRTU) will take effect, but the CAISO recently suggested it will announce the startup date in July 2008. 

Ever since the California energy crisis, the CAISO has worked on designing and implementing a new wholesale power market with features such as locational marginal pricing, financial transmission rights (called congestion revenue rights), and a day-ahead market energy market.  The CAISO filed the MRTU proposal with FERC in February 2006, and proposed a market startup date of November 2007.  Due to technical issues and ongoing administrative litigation over the details of the market design, the proposed startup date has been delayed several times, first to February 2008, then April 2008, and now again to an unknown time.   The latest delay raised the prospect of MRTU not taking effect until next fall, after the high-demand summer season, which the CAISO's latest announcement appears to confirm. 

FERC Proposes Sundry Changes to Organized Power Market Rules

In a new rulemaking, the Federal Energy Regulatory Commission (FERC) has resisted pressure from various groups to examine the foundations of organized wholesale power markets administered by RTOs and ISOs, and instead proposes various tweaks to the rules in these markets. 

FERC rejected the calls by the American Public Power Association and others who have argued that organized power markets are failing to produce just and reasonable rates and that FERC should engage in fundamental reform of RTOs and ISO.  Instead, FERC focused its proposals on areas where it stated that improvements were supported by the law, facts and economic theory, but which have also been high-profile of late, whether due to advocacy by individual Commissioners (such as demand response) or because of bitter disputes within or about RTOs (such as market monitoring).  The specific proposals fall into four categories.

          Demand Response

o        Require RTOs and ISOs to accept bids from demand response resources in their markets for certain ancillary services comparable to other resources.

o        During a system emergency, require RTOs and ISOs to eliminate a charge to a buyer for taking less energy in the real-time market than it purchased in the day-ahead market.

o        Require RTOs and ISOs to permit an aggregator of retail customers to bid demand response on behalf of retail customers.

o        Modify market rules to allow market-clearing prices, during a period of operating reserve shortage, to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power.

Long-term Power Contracting

o        Require RTOs and ISOs to dedicate a portion of their websites for market participants to post offers to buy or sell power on a long-term basis.

Improved Market Monitoring

o        Require each RTO and ISO to provide its Market Monitoring Unit (MMU) with access to market data, resources and personnel necessary to carry out its duties.

o        Require the MMU to report directly to the RTO or ISO board.

o        Expand the list of recipients who would receive MMU recommendations regarding rule and tariff changes, and broaden the scope of behavior reported to FERC.

o        Remove the MMU from tariff administration, including mitigation, and require each RTO and ISO to include in its tariff ethics standards for MMU employees.

o        Expand dissemination of MMU market information to a broader constituency, with more frequent reports.

Responsiveness to Customers and Stakeholders

o        Adopt principles for RTOs and ISOs to ensure inclusiveness, fairness in balancing diverse interests, representation of minority positions, and ongoing responsiveness.

Comments on the proposed rules are due April 21.  In addition to the proposed reforms, FERC also ordered a technical conference to be held to consider proposals for modifying the design of organized markets, as well as a separate technical conference to discuss barriers to demand response in organized markets.

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

FERC Takes Action to Prevent Cross-Subsidization between Affiliates

FERC continues to tweak its rules regarding mergers and acquisitions under section 203 of the Federal Power Act (FPA), issuing new regulations that impose restrictions on affiliate transactions between certain public utilities and their unregulated affiliates.  FERC explained that it intends to fill a perceived regulatory gap in its current affiliate sales rules, and stated that this final rule, combined with an order issued the same day allowing for grants of blanket authorization for a public utility to dispose of voting securities, marks the completion of the "initial implementation" of the rules governing transactions conducted under section 203. 

Order No. 707 extends the affiliate transaction restrictions already in place for entities with market-based rates and utilities requesting merger approval to franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities.  Under the new rules, wholesale sales of power between such public utilities and power sales affiliates with market-based rate authority will require FERC approval.  In addition, such a public utility that sells non-power goods and services to an affiliate with market-based rate authority or an unregulated affiliate will be required to do so at a price that is the higher of either cost or market price.  Lastly, a public utility subject to the rules will not be permitted to purchase non-power goods or services from an affiliate at a price above market price, except that the public utility cannot receive non-power goods and services from a centralized service company above cost. 

FERC Orders Review of Sellers Using WSPP Agreement Demand Charge in Markets where They Lack Market-Based Rate Authority

Last week, following an investigation under Federal Power Act section 206, FERC issued an order finding it is unjust and unreasonable to allow power sellers to keep using the WSPP-wide "up to" demand charge as a ceiling rate in markets where the seller does not have market-based rate authority, unless the seller can justify that rate based on its own costs.  Under the WSPP Agreement, sellers may charge "up to" a cost-based ceiling rate, which consists of a seller's forecasted incremental cost plus an "up to" demand charge based on the costs of a sub-set of 18 of the original parties to the WSPP Agreement.  In its February 21 order, FERC directed sellers that wish to continue transacting under the WSPP demand charge in markets where they do not have market-based rate authority or where they are presumed to have market power to make a filing by April 21 justifying continued use of the rate.  FERC emphasized that this affects only some, and not all, sellers that use the WSPP Agreement.  In a statement issued along with the order, Chairman Joseph Kelliher stated that allowing sellers to continue to use the WSPP demand charge without justifying the rate based on their own costs would "effectively let those sellers sidestep the more rigorous market-based rate test that we have put in place in recent years."

FERC began its review of the widespread use of "up to" demand charge rates under the WSPP Agreement last year as part of its rulemaking proceeding examining sellers' market-based rate authorizations.  In Order No. 697, FERC explained that it had accepted the use of the WSPP Agreement "up to" rate as a mitigation measure by several different sellers that had failed the indicative screens for market power and were found or presumed to have market power.  FERC expressed concern that use of the WSPP rate was no longer just and reasonable for such sellers because it appeared that many sellers used the rate without showing any relationship to their actual costs.  FERC thus began the investigation into whether WSPP rates can be used by sellers that are found or presumed to have market power or that lack market-based rate authority in certain markets.

Department of Energy Pulls Plug on FutureGen Program

The Department of Energy has cancelled the FutureGen project in which the DOE and a coalition of energy industry companies would have constructed a nearly emissions-free, coal-fired generator.  The futuristic project involved carbon capture and sequestration (CCS) underground as part of an integrated gasification combined cycle 275 MW plant producing both electric power and hydrogen.  The cancellation comes as a particularly hard blow to the people in Mattoon, Illinois who had prevailed in an intense competition with other U.S. locales to host the project.   

FutureGen had been touted as a model plant for devising a way to generate power from coal, while minimizing the release of carbon dioxide into the atmosphere.  This approach to battling climate change is important to countries such as U.S., China, and India that have both vast coal reserves and great energy needs.  But the DOE cited the increased costs of the project ― recent estimates had doubled the costs to $1.8 billion ― as a key reason for pulling the plug on the nascent project.

In lieu of FutureGen, the DOE has opted for what may be a more practical approach.  Rather than sponsor one, very expensive project, the Department explained that it would invest in development and application of CCS technologies that could be applied in numerous power plants that would each be funded by its respective developers.  The DOE has issued a request for information asking for industry input on the costs and feasibility of building clean coal facilities that meet the goals of FutureGen.  Comments are due by March 3.  Following receipt of comments, the DOE plans to issue competitive solicitations for federal funding to equip IGCC plants with CCS technology.  If the technology can be implemented, it could be part of new coal plants coming on-line by approximately 2015. 

FERC Allows Duquesne to Exit PJM, but with Conditions

FERC on January 17 conditionally approved Duquesne Light's request to withdraw from the PJM Interconnection and join the Midwest Independent System Operator.  Last November, Duquesne filed an application with FERC seeking approval to leave PJM over rising capacity costs as a result of PJM's new forward capacity market.  In comments and protests filed in December, PJM and other PJM market participants asked FERC to hold Duquesne be held to its financial commitments to the market and ensure that its withdrawal would not harm other market participants financially.

In the January 17 order, FERC agreed to hold Duquesne responsible for its commitments in the PJM forward capacity market.  FERC conditioned Duquesne's right to exit PJM upon the utility honoring commitments for all forward capacity auctions in which its load had been included.  This means that Duquesne will be liable for forward capacity costs through May 2011.  (Duquesne had asked FERC to make its withdrawal from PJM and termination of its obligations in the capacity markets effective May 31, 2008.)  FERC also directed Duquesne to submit further information on its remaining obligations, including how many and what its continuing obligations to PJM are, what its allocated share of costs for the PJM regional transmission planning process is, and how it will be integrated into the Midwest ISO.