Energy Legal Blog

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).

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.

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]

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]

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]

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)]