Energy Legal Blog

Reliability v. Health: Neighboring States Battle over Dirty but Needed Generator

A cross-Potomac skirmish over the competing principles of energy reliability and public health has broken out over the fate of Mirant Potomac River's 482-MW, coal-fired power plant in Alexandria, Virginia.  The District of Columbia Public Service Commission’s ("DCPSC") petition to FERC and the Department of Energy ("DOE") to prevent Mirant from shutting down both provoked urgent protests and drew support from regional stakeholders.  

Prompting the DCPSC's petition was Mirant's announcement that, because of a Virginia Department of Environmental Quality ("VDEQ") directive to remedy air quality violations, it would shut down the plant on August 24.  In its petition, the DCPSC argued that the proposed shutdown, which Mirant has implemented, would have a "drastic and potentially immediate effect" on electric reliability in the greater Washington, D.C. area, possibly leading to curtailments of electric service, load shedding and blackouts.  The DCPSC asked the DOE to mandate continued operation of the plant pursuant to its authority under section 202(c) of the FPA, a statutory provision that was put in play during the 2000-2001 California crisis and the August 2003 Northeast blackout, and asked FERC to take complimentary actions under the FPA.

Supporters of the DCPSC petition include PEPCO, the Pennsylvania Public Utility Commission, and the PJM Interconnection.  In its comments, PJM contended that the shutdown was not consistent with its rules for plant deactivation and did not give PJM an opportunity to consider the effect of the shutdown on system reliability.   Not surprisingly, Mirant asked that any order in response to the DCPSC petition requiring it to resume operations should specify that such order preempts the authority of the VDEQ and any other federal and state environmental requirements. 

Anticipating Mirant's request for preemption, the City of Alexandria, which opposes as premature the emergency request made by the DCPSC, pointed out that Mirant’s action to shut down the plant was unilateral, mandated by neither Virginia nor Alexandria.  Alexandria stated that it while it welcomed Mirant’s action as appropriate in light of the environmental concerns, DOE and FERC should consider Mirant’s corporate motives and agenda, and suggested that this was "a wholly manufactured scenario by Mirant to allow it to diminish its public and contractual obligations" by operating in violation of its air permit.

The VDEQ asked that any federal order to resume plant operations should consider the impacts thereof on air quality in Virginia.  The Southern Environmental Law Center, a nonprofit group, argued for rejection of the DCPSC request on the grounds that the plant's shutdown had been expected for years and was in response to "gross violations" of federal and state clean air laws that precluded a finding this was an emergency under section 202(c).

Rhode Island, Wisconsin Investigate Benefits of RPS

Joining the growing number of states embracing Renewable Portfolio Standards ("RPS"), both Rhode Island and Wisconsin have begun to assess the potential benefits of and need for renewables to power their states.

The Rhode Island Public Utilities Commission is reviewing a stakeholder group proposal that recommends the state begin enforcing an RPS in 2007 requiring both utilities and retail marketers to obtain 3% of their power supply from renewables.  Under this proposal, utilities would be allowed rate recovery of all associated costs other than non-compliance penalties.   Renewable power generated outside of the New England Power Pool would only count toward satisfying the requirement if the electricity is used by New England customers.

In Wisconsin, Gov. Jim Doyle has asked the Wisconsin Legislature to pass a bill to boost renewable energy use in the state.  More specifically, he has suggested that it adopt the recommendations of his renewable power task force, which suggested that by 2015, 10% of all electric sales come from renewable resources.  If a utility shows that RPS would increase rates or hurt system reliability, or that transmission constraints exist, however, it could ask for an extension.  This recommendation is a significant increase from the state's current renewable goal, which calls for only 2.2% of all retail electric sales to come from renewable sources by 2011. 

The Governor also has asked the Wisconsin Public Service Commission ("WPSC") and the Department of Natural Resources to work together to investigate the use of integrated-gasification combined-cycle ("IGCC") technology.  In the past, the WPSC rejected the use of IGCC technology, finding that it was too expensive.  However, due to technological advances, IGCC is now viewed as potentially beneficial to ratepayers and the environment.

TVA Considers Open Access Policy As Customers Defect

Hopkinsville Electric System has become the latest Kentucky distribution system to give the Tennessee Valley Authority ("TVA") the five-year notice required to terminate its long-term agreement with federal power company and begin shopping around for other energy suppliers.  In the wake of several recent terminations, TVA has begun to examine the implications of opening up access to its transmission grid.  FERC took up the same issue in an August 3 order [East Kentucky Power Cooperative, Inc., 112 FERC ¶ 61,160 (2005)], directing TVA to allow East Kentucky Power Cooperative to interconnect with the TVA system to transmit power to a co-op inside TVA territory whose contract with TVA would expire in 2008.  As other customers seek to source their energy needs from non-TVA suppliers, pressure on TVA to open its grid to competing suppliers is bound to increase. 

While TVA seems willing to open up its transmission lines, like all integrated generation-transmission utilities, it professes concerns that its native load have priority on its system and that those who benefit from system upgrades be the ones who pay for them.  It is unclear at this time how these concerns will play out, but TVA can be expected to purse so-called "participant" funding as authorized in the new Domenic-Barton Energy Policy Act.  According to TVA President Bill Baxter, the agency is very competitive within its territory, and TVA officials do not expect a huge hit to the agency's bottom line from distribution systems turning elsewhere to obtain their energy needs.  That insouciance seems at odds with projections that the giant power generator may soon have excess power to sell.  [NEW MATTER]

FERC Scurries to Conclude California Refunds Case

With an order issued August 8, FERC has stepped up its efforts to bring to a close the four-year-old refund proceeding that grew out of the 2000-2001 California energy crisis.  The order clarifies how generators and other suppliers should seek to prove the costs they incurred in supplying power to the California ISO ("CAISO") and the California Power Exchange ("CalPX") during the refund period (October 2, 2000 through June 20, 2001) exceeded the mitigated market clearing price established by FERC.  These suppliers now have detailed guidelines as to the types of data they need to provide to support their cost claims.  Once they make showings of the costs incurred to make each sale into the CAISO or CalPX, and the revenues received from all of those sales, any difference between costs and revenues will act as an offset to refunds that California owes to the suppliers.

The California complainants – primarily state government agencies and large investor-owned utilities had argued that FERC should require the sellers to make the cost and revenue calculations for all sales that they made throughout the Western Electricity Coordinating Council.  FERC disagreed and instead endorsed the position of sellers that they need only make these calculations for sales made into the CAISO and CalPX markets.  In addition,  FERC will allow marketers to retain a ten-percent return on their trades.   

To hasten the case's conclusion, FERC convened on August 25 a technical conference to create a uniform template for submitting cost and revenue data. Sellers must submit their cost-based recovery claims by September 10, and FERC intends to issue an order on the filings by November 15.  [San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange Corporation, et al., 112 FERC ¶ 61,176 (2005)] [UPDATE]

California Merchant Generators, IOUs Put Forth Market Reform Plan

Two of California's investor-owned utilities ("IOUs") along with six merchant generators quietly unveiled on August 17 a plan to reform California's struggling power markets at a closed-door meeting in Sacramento.  Pacific Gas & Electric Co., Southern California Edison Co. ("Edison"), AES Corp., Duke, NRG, Mirant, Dynegy, and Reliant secretly developed the plan.  Governor Arnold Schwarzeneggar also encouraged the proposal, in the hopes that the development of a strong energy policy will amount to the decisive action on energy policy that will placate California voters still smarting from the 2000-2001 energy crisis, and the governor's top energy advisor, Joe Desmond, was present at the Sacramento meeting.  Following the announcement, the plan drew cautious praise from some market participants and the California Independent System Operator ("CAISO"), which noted that the plan includes many elements that CAISO President and CEO Yakout Mansour "has been preaching about" for some time, according to a CAISO spokeswoman.

The plan would require all load-servers to procure sufficient power to meet mandated resource adequacy requirements, including peak load and reserve margins, and would penalize load servers who fail to meet these requirements.  The plan also rejects the current resource adequacy requirement of a one-year forward purchase obligation as too short to encourage investment in new resources and infrastructure.  Even though the California Public Utilities Commission ("CPUC") is currently in the process of developing its own resource adequacy requirements, the IOUs' and generators' plan would mandate that the CPUC allow utilities to procure power through long-term purchase agreements that support investment in and construction of new power plants.  The costs of the long-term contracts and any new utility-owned power plants would be recovered "from all customers who benefit from the resulting reliability," including direct-access customers.  The CPUC would also limit contracts to the minimum amount of capacity needed to ensure system-wide reliability, using projections from the California Energy Commission and the CAISO.  Also included in the reform plan are a proposal to develop a capacity market in California, a call to move away from reliance on the must-offer obligation imposed by FERC during the 2000-2001 energy crisis, and a call for the CAISO to raise price caps to the levels of other markets.

Notably missing from the plan's development process was Sempra Energy, parent company of San Diego Gas & Electric, California's other large investor-owned utility.  Sempra was not invited to help develop the plan and was not present at the plan's unveiling in Sacramento.  More than likely, this stems from Sempra's past criticism of an Edison proposal included in the reform plan to spread the costs of proposed power deals for a total of 1500 MW among all customers south of Path 15, a key transmission path in California.  Edison has argued that the contracts are needed to improve reliability in Southern California next summer, while Sempra calls this an "inequitable cost-sharing proposal" and argues it has enough power to meet Southern California's needs for summer 2006.  Many observers also noted similarities in the reform plan to a proposal pushed by Edison last year, which would have guaranteed that utilities recover in their rates all costs of building new generation.  Gov. Schwarzeneggar vetoed that bill.  [NEW MATTER]

Reconsider Exelon-PSEG Merger, NJBPU Urges FERC

Apprehension over the effect of the Exelon-PSEG merger continues, as the New Jersey Board of Public Utilities ("NJBPU"), along with several other regional interests, including New Jersey's Ratepayer Advocate and Pennsylvania's Office of the Consumer Advocate, asked FERC to rehear its July 1 order approving the merger and instead set the merger for hearing.

The NJBPU argues in its request that FERC violated Section 203 of the Federal Power Act ("FPA") by failing to determine affirmatively that the merger is in the public interest in advance of authorizing the transaction.  Instead, complained the NJBPU, FERC's order recognized that the merger's harm to competition may not be adequately mitigated by the Applicants' proposed mitigation plan.  According to the NJBPU, FERC's reliance on the imposition of additional mitigation after the merger closes, if necessary, is in error. Additionally, FERC failed to address significant aspects of PJM's merger analysis as well as the affect of the merger in the natural gas market.  The NJBPU also stated that, to the extent FERC is relying on its ability to revoke the Applicants' market-based rates and impose cost-of-service regulation as a means of addressing market power, this would harm consumers because cost-based rates may be higher than those that existed in pre-merger competitive markets.

Since the NJBPU is independently reviewing the merger, and therefore, may condition its approval on concessions different from those imposed by FERC, the NJBPU contends that administrative efficiency demands a single evidentiary hearing before FERC in which all merger issues can be resolved. [Exelon Corporation and Public Service Enterprise Corporation, Inc., 112 FERC ¶ 61,011 (2005)]

Negotiations Continue on BPA's Role in Pacific Northwest RTO

Following the Transmission Improvements Group's ("TIG") regional transmission proposal, made public earlier this month, BPA solicited public comments on whether it should support and join the opposing Grid West proposal, adopt the TIG alternative, push for a combination of the two, or choose to remain separate from the formation of a Pacific Northwest RTO altogether.  TIG comprises several northwestern electric utilities. In order to be considered, comments are due to BPA by September 9, 2005.

Grid West's proposal focuses on the creation of an independent entity that would manage and control transmission in the region,  acting as the central scheduling entity, and serve as the planning reliability and transmission authority for the entire system.  Although FERC has clarified that participation in an RTO by non-jurisdictional transmission utilities does not subject those utilities to additional FERC oversight, BPA has expressed concern about joining Grid West's proposed RTO because its statutory obligations may conflict with FERC requirements.  BPA's concerns in this regard should be attenuated by provisions of the recently enacted Domenici-Barton Energy Policy Act of 2005 that authorize BPA and other federal power marketing administrations to join regional transmission organizations. 

As an alternative to Grid West, TIG has proposed a restructuring of the transmission system (and improvements to the system) through multilateral long-term contracts while maintaining the autonomy and authority of individual transmission system owners.  This proposal would address regional transmission issues incrementally.  TIG claims that because it is not creating a new institution, FERC's jurisdiction will not come into play.   Critics, however, claim that the TIG's proposal lacks depth and fails to explain how independent power producers will fit into the system, or how Intermountain west issues and dealings with Canada will be handled.

The Regional Representative Group, which includes representatives from regional public and investor-owned utilities, BPA, and independent power producers, is expected to vote September 30, 2005, on whether Grid West's development should move forward.  [NEW MATTER]

Energy Policy Act of 2005 Hands FERC a Long To-Do List

The Domenici-Barton Energy Policy Act of 2005, signed into law on August 8, mandates that FERC issue several new rules and engage in other new initiatives over the next few months.  Milestones of particular significance to the power and natural gas industries are:

• Within 60 days:  Issue regulations on the National Environmental Policy Act pre-filing process for liquefied natural gas (LNG) projects. 
• Within 90 days: 
  • Consult with Departments of Interior, Commerce, and Agriculture, to establish procedures for trial-type expedited proceedings for mandatory conditions and fishways on hydropower licenses.
  • Issue a final rule exempting QFs, EWGs, and foreign utility companies from access requirements that take effect upon PUHCA repeal (PUHCA is repealed effective 6 months after enactment).
• Within 4 months: 
  • Issue rules to exempt from section 1275 any holding company whose public utility operations are confined to a single state and any other class of transactions FERC finds not relevant to jurisdictional public utility rates.
  • Issue any rules necessary to implement new PUHCA provisions.
  • Submit to Congress recommendations and conforming amendments to federal law necessary to carry out the new PUHCA subtitle.
• By Dec. 31, 2005:  Conclude California energy crisis proceedings and submit to Congress a report describing actions taken and timetables, if any, for further action.
• Within 180 days: 
  • Issue final rule implementing new reliability provisions.
  • Issue rule revising criteria for useful thermal output of QFs under PURPA.
  • Sign MOU with Commodity Futures Trading Commission on information under electric and gas market transparency provisions.
  • Report to Congress on progress in licensing and constructing Alaska natural gas pipeline.
  • With DOE, report to Congress on how to make available to all transmission owners and RTOs real-time information on the functional status of transmission lines within Eastern and Western Interconnections.
• Within 1 year:
  • By rule or order, establish how to meet the needs of load-serving entities.
  • Issue rules for incentive-based rate treatments for transmission in interstate commerce.
  • Convene regional joint boards to study security constrained dispatch, report to Congress.
  • Publish annual report assessing regional demand response resources.
  • As a member of a 5-member inter-agency task force, submit report to Congress assessing competition within wholesale and retail electricity markets.
  • Consult with DOE to conduct at least 3 LNG forums.
  • Enter MOU with other federal agencies to coordinate review and permitting of electric transmission facilities.
• Within 18 months:  Consult with DOE to submit report to President and Congress on benefits of cogeneration and small power production
• Within 2 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to identify corridors for pipelines and electricity transmission and distribution facilities on federal land in Western states, perform environmental reviews for those designations, and incorporate corridors into relevant agency land use plans
• Within 4 years:  Consult with Agriculture, Commerce, Defense, Energy, Interior and states to establish procedures to identify corridors for pipelines and electricity facilities for all other (i.e., non-Western) states.
• No deadline is set for these actions:
  • Issue rules governing national transmission corridor permits.
  • Adopt rules providing expedited procedures for processing FPA § 203 applications within 180 days.
  • Conclude MOU with Secretary of Defense to coordinate LNG facilities that may affect active military installations.
  • Consider New England states' objections to proposed locational installed capacity ("LICAP") requirement pending at FERC.
  • By rule or order, require non-regulated transmission entities to provide comparable open access.
  • Issue rules to permit recovery of prudently incurred costs of QF contracts.

Reliant Settles Litigation over Energy Crisis

Houston-based Reliant Energy announced August 15, 2005, that it has entered into a comprehensive settlement agreement with many of the parties to the ongoing litigation over the 2000-2001 California energy crisis, including FERC staff, the states of California, Oregon and Washington, California's three largest investor-owned utilities, and various private class-action plaintiffs.  The settlement will end much of Reliant's liability exposure from sales made during the crisis. 

Pursuant to a Memorandum of Understanding ("MOU") executed by the settling parties, Reliant will make a $150 million cash payment and has agreed to waive all claims to its receivables for electricity sold into California's organized markets from January 1, 2000, to June 21, 2001, plus interest.  To preclude future market manipulation through withholding of resources, Reliant also agreed to allow independent audits of outages for 12 months following FERC approval of the settlement and to continue its "must offer" obligations under an earlier 2003 settlement for two additional years.  According to FERC, the total value of the settlement is estimated to be approximately $460 million, which is in addition to $65 million that Reliant has already paid in earlier settlements.  In exchange, the other parties to the settlement agreed to absolve Reliant from all claims related to the energy crisis, including:  FERC's generic refund proceeding regarding the Western markets; pending appeals of prior FERC orders relating to the crisis; all market price investigations by the Attorneys General ("AGs") of the three settling states; civil litigation filed by the California AG, including a pending Clayton Act antitrust lawsuit; private class action lawsuits filed on behalf of ratepayers in California, Oregon, Washington, Idaho, and Utah; and natural gas price issues raised by any of the settling parties, except the private class action litigants and local governmental entities. 

Once a formal agreement is in place between the parties, it must be approved by FERC, the California Public Utilities Commission, and the courts overseeing the class actions.  The parties indicated that the settlement will be filed at FERC sometime in September, and in a press release, newly minted FERC Chairman Joseph Kelliher applauded the agreement.  Reliant thus becomes the last of the out-of-state generators to settle allegations arising out of the energy crisis.  If approved, Reliant's settlement would bring the total settlements with California to $6.3 billion.  [NEW MATTER]

Xcel Joins Industry Retreat from Market to Cost-Based Pricing of Wholesales

Xcel Energy Services recently became the latest integrated utility to abandon efforts to convince FERC that it lacks generation market power in its control area and thereby surrender its authorization to make control-area power wholesales at market rather than cost-based prices. Entergy made the same decision in July, as did AEP earlier this year. (See Entergy Will Not Renew Market-Based Rate Authority, August 2, 2005). Motivating this retreat is recognition that these large regional utilities are unlikely ever to convince regulators that they have adequately mitigated their generation market power, together with the risk of future refund liability if they are determined to possess market power and the marginal impact that forsaking market pricing will have on bottom lines. Even Southern Company, which is continuing, at least for the moment, its market power proceeding, has indicated that losing its market-based rate authority would not amount to the "death penalty" FERC intended it to be. Similarly, after FERC ordered Duke Power to revert to cost-based sales, the utility pointed out the limited financial effect the switch will have on its business.

Xcel reserved the right to reapply for market-based rates after the Southwest Power Pool ("SPP") becomes the market monitor in Xcel's Southwestern Public Service Co. and Public Service Co. of Colorado service areas. FERC's investigation into Xcel's market power revealed that, once SPP assumes its market monitor duties, the agency might be more inclined to agree that any market power Xcel possesses would be adequately mitigated. But in the meantime, Xcel's acquiescence in cost-based pricing of its wholesales demonstrates that integrated utilities are increasingly unwilling to spend resources to defend market-based rate applications, and are quite comfortable with at least partially returning to the familiar world of cost-based pricing. As a result, any leverage over utilities with market power that FERC sought to gain with the interim market power screens may become elusive and new approaches to market power may be in order.

Court Vacates Erratic FERC Orders on Congestion Pricing

A federal appeals court recently reversed a FERC order on pricing arrangements in a congested area of ISO-NE region because of the agency’s failure to respond to reasonable objections to its mercurial policies on pricing. The opinion demonstrates that the agency’s abrupt policy changes will not withstand appellate scrutiny where FERC fails to resolve reasonable objections by appellants.

FERC's order concerned the ongoing attempts to devise an appropriate mechanism for compensating generators in a congested area of southwest Connecticut in which there is a risk of generator market power. As evidenced by FERC’s recent decision to delay implementation of a contentious locational installed capacity requirement in New England, the agency has yet to settle on a long-term, commonly accepted mechanism. The order on appeal involved two previous attempts to come up with a pricing scheme.

In 2002, FERC addressed NEPOOL’s proposal to create a standard market design in New England, and as part of that market design, approved the use of Reliability-Must-Run ("RMR") agreements that provide for monthly payments of costs and a return to generators that run seldom but are needed for reliability. Not long afterwards, however, when two generators, including an affiliate of PPL, sought approval of RMR agreements with the system operator, FERC reversed course and devised a new compensation scheme, although it signaled that RMR agreements could serve as a last-resort compensation mechanism. The new methodology was termed Peaking Unit Safe Harbor ("PUSH") bidding, and was intended to give a generator that ran seldom a bid price based on the sum of its units’ variable-cost and fixed-cost components.

The PPL affiliate appealed FERC’s order to the D.C. Circuit, where the agency has met with not infrequent reversals in recent years. The gas-fired generator challenged FERC’s assumption that the PUSH methodology would provide it with adequate compensation, as this would occur only if the generator operated as frequently from one year to the next, which was unlikely given rising gas prices and the availability of non-gas generators. The generator further pointed out that FERC relied on an incorrect assumption about whether PUSH-eligible units could set the locational marginal price (LMP). In addition, the generator argued that it met the last-resort standard FERC has established for RMR eligibility. The Court agreed with the PPL affiliate that FERC failed to respond directly to any of these objections. That failure, the court ruled, demonstrated a lack of reasoned decisionmaking and rendered the orders arbitrary and capricious. [PPL Wallingford Energy, LLC v. Federal Energy Regulatory Commission, 419 3d 1194 (D.C. Cir.) (2005)]

California Supreme Court Puts Re-Regulation Proposition Back on the Ballot

Controversial Proposition 80, which seeks to re-regulate California's electricity market, should be put to a vote in the upcoming November 8 elections, according to the Golden State’s highest court. The court's decision overturns a July 22 ruling of a lower court that would have kept Proposition 80 off of the ballot. The lower court ruled that Proposition 80 was unconstitutional on its face because it would expand the authority of the California Public Utilities Commission ("CPUC") to regulate the energy industry, a role that the court found to be reserved for the California Legislature under a constitutional provision giving the Legislature "plenary" authority over the CPUC. Not so, said the state's Supreme Court in a unanimous decision. Instead, the court held that Proposition 80 was not clearly unconstitutional and thus, the issue should be left up to the voters. However, the court managed to hedge its bets somewhat by saying that it could revisit the issue if voters approve the measure.

Drafted and sponsored by consumer group The Utility Reform Network ("TURN"), Proposition 80 would effectively re-regulate the California electricity market. In addition to expanding the CPUC's regulatory authority, the measure would roll back one of the few remaining central provisions of the state's 1996 deregulation law, direct access, and would prohibit large consumers not already doing so from purchasing their electricity from independent power marketers rather than from the state's investor-owned utilities. Proposition 80 would also mandate cost-of-service regulation for all of the state's retail energy-service providers. In the wake of the Supreme Court's decision, TURN has been proclaiming victory. However, the measure's opponents, including the Independent Energy Producers Association and Californians for Reliable Electricity, have pointed out that the Supreme Court could still strike the provision down as unconstitutional if it passes. [Case No. 05-169] [NEW MATTER]

Texas Ups Renewable Energy Requirements

Congress Enacts Energy Bill

One month after the Senate approved its version of a comprehensive energy bill, see Senate Votes in Favor of Energy Bill, Tumultuous Conference Awaits, Congress enacted the Energy Policy Act of 2005.  Although maligned by energy and taxpayer watchdogs as a "piñata of perks and pork" for big oil, big nuclear and other entrenched energy industries, the 2005 Act, as it affects certain aspects of the power and natural gas industries, promises to profoundly change the structure and prospects of new energy business organizations and the viability of new liquefied natural gas and power transmission projects.

For several years the demand for relatively clean-burning natural gas has increasingly outstripped North American production, giving impetus to efforts to import liquefied natural gas ("LNG").  But concerns over the safety of LNG re-gasification facilities in this country, both on- and off-shore, have seen myriad LNG development proposals from coast-to-coast crash in the face of public opposition.  The 2005 Act will override that opposition in part by consolidating many of the needed approvals, including siting, in one agency – FERC.  State and local authorities are effectively stripped of authority to block the siting of LNG importing and processing facilities.

The 2005 Act also promises to effect fundamental changes in the future structure and operation of power markets.  It does so by repealing the Public Utility Holding Company Act of 1935 ("PUHCA") and amending the Public Utility Regulatory Policies Act of 1978 ("PURPA").  At the same time, it gives FERC the authority to certify a new Electric Reliability Organization ("ERO") that (under regulatory supervision from FERC and its Canadian counterpart) will set and enforce standards for the reliable operation of the Eastern and Western Interconnections and the Electric Reliability Council of Texas.  The confluence of these developments will be profound and will likely force further consolidation of the power industry. 

Since its enactment 70 years ago, PUHCA was amended twice to allow limited holding company investment in power generation — in qualifying facilities under PURPA and in exempt wholesale generators under the Energy Policy Act of 1992.  But otherwise PUHCA confined utility holding companies to a single integrated public-utility system and has policed intra-holding company transactions to prevent cross subsidization.  Repeal of the PUHCA will knock down the barriers to consolidation of geographically and operationally diffuse utility systems.  Pending consolidations, such as Duke-Cinergy and MidAmerican-PacifiCorp, which may well have been barred by PUHCA's single integrated public-utility system requirement, now appear to have been prescient in anticipating PUHCA's repeal.  They likely will prove to be harbingers of other consolidations.

The so-called PURPA put also falls victim to the 2005 Act.  The PURPA-imposed obligation of traditional public utilities to buy the output of qualifying cogenerators and small, renewable generators at an avoided-cost price ushered competition in wholesale power markets into the 1980s.  The Energy Policy Act of 1992 later swelled the ranks of competitive generators by creating an additional class of PUHCA-exempt competitive generators with exempt wholesale generators ("EWGs").  Going forward after implementation of the 2005 Act, qualifying facilities and EWGs will no longer exist.  There will simply be power generators selling at wholesale and, where permitted by local law, at retail.  FERC is empowered by the 2005 Act to review and approve utility acquisitions of existing generating facilities in order to prevent (among other things) undue concentrations of generation market power.  Unclear, however, is who will build new generation under the largely deregulated scheme of the 2005 Act.   Arguably, without the price support of the PURPA put and the investment restrictions of PUHCA, only a shrinking universe of highly capitalized investors or existing utilities will build new generation in the future.  Some of these may ally with Indian tribes and construct power plant on tribal lands since the 2005 Act has special provisions for encouraging Indian energy development.  These provisions include the creation of an Office of Indian Energy Policy and Programs within the Interior Department with authority to pre-approve tribal-energy-resource agreements.

The 2005 Act will also tend to consolidate markets through its introduction of an ERO.  While the stated purpose of the ERO is to standardize, and make enforceable for the first time, rules for reliably operating the bulk power systems of North America, the indirect effect of that standardization will be the consolidation of formerly balkanized markets and the facilitation of increased trading in bulk power.

Duke Energy Asks FERC to Approve MISO as ICT for Duke Facilities; Entergy and SPP Come to Terms on ICT Agreement

In a partial concession to FERC's insistence that transmission-owning utilities surrender operational control of their transmission systems to independent operators, on July 22, 2005, North Carolina-based Duke Energy asked FERC to approve amendments to its open-access transmission tariff ("OATT") that would allow the Midwest Independent Transmission System Operator ("MISO") to act as an Independent Coordinator of Transmission ("ICT") for Duke's transmission facilities.  Under Duke's proposal, MISO would oversee and administer – but not operate –Duke's transmission grid.  MISO would not have the authority to control the physical operation of Duke's transmission facilities, but would be responsible for evaluating and approving all of Duke's transmission service requests; administering its OATT; operating and administering its open-access same-time information system ("OASIS"); calculating its available transmission capacity; and coordinating transmission planning for Duke.  Duke selected Potomac Economics to act as the Independent Monitor of its transmission facilities.  As an autonomous transmission monitor, Potomac would be responsible for examining how Duke is dispatching its system, evaluating how it is using its transfer capability, and investigating potentially anticompetitive behavior. 

Transmission owners reluctant to surrender full operational control to an independent operator, including Duke, have been monitoring the progress of a similar plan being pursued by Entergy Services to have an ICT take responsibility for many of its transmission functions.  Duke's recent filing signals its apparent decision that the time was right to file its own plan with FERC, given FERC's conditional approval of the Entergy plan in March 2005 (see UPDATE Mar. 31, 2005) and Duke's own recently announced merger with Cinergy Services.  While Cinergy is a full-fledged member of MISO, Duke has made it clear that it has no intention of joining the MISO or participating in MISO's Day 2 energy markets.  Its ICT proposal, however, seeks to obtain some of the benefits of joining a regional organization without incurring some of the perceived costs.  [FERC Docket No. ER05-1236] [NEW MATTER]  

Entergy's proposal has also recently taken a giant step forward.  FERC had conditionally approved Entergy's plan in March 2005, although the agency withheld final approval pending Entergy's provision of more details.  Following FERC's decision, Entergy has been negotiating a deal with the Southwest Power Pool ("SPP"), pursuant to which SPP would act as Entergy's ICT.    On August 1, 2005, SPP's board of directors gave its ok to the deal, authorizing SPP to negotiate a contract with Entergy pursuant to which it would oversee the utility's transmission system.  Early indications are that the contract would last for two years and that Entergy would pay SPP $12 million per year.  SPP in turn would develop a separate department to carry out its ICT functions.  It proposes to oversee Entergy's transmission system, develop a new process for assigning cost responsibility for transmission upgrades, and implement a new weekly procurement process.  Even though the final contract is not expected to be worked out until Entergy's proposal receives final approval from FERC, expected in early 2006, Entergy and SPP will sign an interim agreement in the meantime, with preliminary work scheduled to begin as early as this month.  [Entergy Services, Inc., 110 FERC ¶ 61,295 2005)] [UPDATE]

Entergy Will Not Renew Market-Based Rate Authority

Entergy Services has notified FERC that it no longer seeks market pricing authority for its wholesale sales of power, and will instead charge cost-based rates for power sales in its home territory.  The move leaves Southern Company, of the three utilities originally cited by FERC for market power concerns in 2001, as the only utility still seeking to maintain its market-based rate authority.

Entergy’s decision to abandon its market-based rate application concludes a protracted dispute that began in 2001, when FERC abandoned its “hub-and-spoke” test for market power and instituted the “supply margin assessment” (SMA) screen on an interim basis.  FERC found that Entergy, along with AEP and Southern Company, failed the SMA screen.  Facing strong opposition to the new interim screen, FERC postponed implementation of SMA, and then abandoned the screen altogether in 2004.  In its place, FERC implemented two interim market power screens, to remain in effect until a broader rulemaking could implement a permanent test.  Applying these interim screens to Entergy, FERC found that the company once was unable to demonstrate that it did not possess  market power in generation.  Faced with the choice of performing a delivered-price test (DPT) to rebut this finding, or agreeing to the default solution of selling power at cost-based rates, Entergy initially chose to submit a DPT.  Entergy has now changed course and opted to join AEP and Duke Energy in agreeing to forego market pricing and engage only in cost-based sales within its own service territory.

The company emphasizes that its decision does not constitute an admission of market power.  Rather, faced with the mounting costs of a long battle with FERC over this issue, Entergy made its decision based on economic considerations.  The switch, combined with the decisions of AEP and Duke Energy to revert to cost-based rates, suggests that FERC's penalty for a finding of market power may not have as much bite as was intended, as utilities are finding that reverting to cost-based sales does not harm their bottom line in the current electric power market.  [Docket Nos. ER91-569, EL04-123] [UPDATE]