Energy Legal Blog

In a September 21 order, a full panel of five FERC commissioners unanimously accepted the California Independent System Operator’s (CAISO) long awaited Market Redesign and Technology Upgrade (MRTU) tariff.  While directing the CAISO to make some changes around the edges, FERC approved the core of MRTU proposal.  It includes a day-ahead energy market, revised hour-ahead scheduling timelines, a form of locational marginal pricing (LMP), a new congestion management system with long-term firm transmission rights, redesigned market power mitigation measures, and resource adequacy backstop provisions that would allow the CAISO to procure power to meet forecasted load.  The MRTU tariff would also provide for gradual increases of the energy bid cap.  The CAISO proposes to implement MRTU in November 2007.

But several issues need more work, according to FERC.  It directed the parties to convene technical conferences on “seams” issues (how CAISO interacts with neighboring western markets), the allocation of transmission capacity available for imports, and the CAISO’s Business Practices Manuals.  FERC also complained that the CAISO’s proposal for offering long-term firm transmission rights ─ something that FERC mandated ─ remains mired in stakeholder negotiations.  In addition, FERC directed the CAISO to implement “convergence bidding” within 12 months and to develop measures to counteract incentives for load-serving entities to underschedule, and invited interested parties to file demand response proposals within 60 days.  Responding to commenters that expressed concerns that the necessary software would not be ready and operational by the CAISO’s proposed November 2007 implementation date, FERC directed the CAISO to certify at least 60 days in advance of implementation that software and markets will work as expected.

FERC’s approval of MRTU comes after a long summer of intensive lobbying by public power groups and public officials in the west who oppose California’s market revisions.  Opponents argued that features of the market structure proposed by the CAISO, particularly LMP, were not well suited to western energy markets, and that the changes in California would drive up prices across the west.  In light of the size and importance of the California marekt in relation to the rest of the west, opponents also fear that wherever California goes the rest of the western states will have no choice but to follow.  The FERC commissioners disagreed, and several expressed their views that MRTU would not have adverse impacts on the rest of the west.

In a September 7 order, the Canadian National Energy Board (NEB) approved Sea Breeze Victoria Converter Corp.'s proposal to construct and operate a 30-mile, 574 MW high-voltage direct current transmission line from Victoria, British Columbia to Port Angeles, Washington.  Expected to begin construction in 2007, Sea Breeze will build the transmission line under the Juan de Fuca Strait, interconnecting with the Bonneville Power Administration's (BPA) system via a 150 kV tie line.  The NEB's approval was one of the remaining regulatory hurdles to the project's construction; FERC approved Sea Breeze's proposal in September 2005, including its application to charge negotiated rates for transmission service.

According to Sea Breeze's filings, the transmission line will enable enhanced trade between British Columbia and United States wholesale markets and will improve reliability in the Pacific Northwest.  The NEB noted the need for enhanced energy on Vancouver Island, which faces potential reliability and stability concerns resulting from a growing population and a lack of new on-island generation.  Moreover, substantial congestion on the intertie between Canada and the U.S. and on BPA's transmission system threatens to prevent BPA from fulfilling its obligation to return power to Canada pursuant to the Columbia River Treaty.  While the Sea Breeze transmission line will not be used to return Columbia River Treaty power to Canada, Sea Breeze argued in support of its project that it would relieve other congestion in the area by providing an additional transmission path between western Canada and the U.S. 

The bitter fight over the impact of electricity restructuring in Maryland saw another twist last week when Maryland’s highest court, the Court of Appeals, voided parts of a state law that would have fired all members of the state’s Public Service Commission and replaced them with new members chosen by the legislature.  The court concluded that the law violated the state’s constitution by infringing on the governor’s authority to appoint members of the PSC, which is function reserved to the executive branch of government.

The dispute grew out of anger from the public and politicians at a 72% rate hike for Baltimore Gas & Electric that was to take effect following years during which BG&E's rates had been frozen pursuant to the state’s 1999 electricity deregulation legislation.  That legislation lowered BG&E’s retail rates to a level 6.5 % below the rates that had been set for the utility back in 1993.  Having grown accustomed to service at below-market rates, consumers reacted angrily to the rate increase that was to follow when the rate freeze ended this year.  The Court of Appeals ruling, however, did not address other parts of the state law, which included phasing-in increases in BG&E's rates until they approximate market prices, and carrying forward BG&E's losses for recovery in the future.  

The development of federal authority to site transmission projects within congestion corridors, mandated by the Energy Policy Act of 2005 (“EPAct 2005″), is occurring on two related fronts.  EPAct 2005 created backstop authority whereby  FERC can site transmission when states fail to do so.  FERC has received comments in its rulemaking regarding how it plans to implement this authority, and will likely finalize the rule in the next few months.  Meanwhile, DOE awaits comments on the study, issued last month, identifying areas of transmission congestion that would be subject to FERC’s new authority.   

DOE’s National Electric Transmission Congestion Study identifies those portions of the Eastern and Western Interconnections (but not ERCOT) that experience sufficiently constraining congestion as to warrant federal attention and possible designation as a national interest electric transmission (NIET) corridor.  To be considered, public comments on the Study must be submitted to DOE by October 10. 

Within a NIET corridor, FERC can permit and condemn right-of-way for construction of an electric transmission line provided that FERC finds that 

·        the state where the line is to be located lacks siting authority or state law prohibits siting to achieve interstate (as opposed to intrastate) benefits;

·        the permit applicant is not eligible for site approval because it does not provide retail service in the state;

·        the state with siting authority fails to act on an application within one year; or

·        the state siting body attaches conditions that will prevent congestion reduction or make the new line economically infeasible. 

This FERC authority, added in the Energy Policy Act of 2005, created for the first time federal eminent domain for electric transmission.  This differs from eminent domain that has been available for natural gas pipelines since enactment of the Natural Gas Act (NGA) in 1938 inasmuch as the NGA authority is exclusive and preempts state siting and condemnation.  In contrast Congress emphasized and FERC and DOE have affirmed their understanding that the new FPA electric transmission siting and condemnation authority is supplemental to and does not preempt state law except in the four narrow situations above.  Owner compensation for land federally condemned for natural gas pipelines and electric transmission lines continues to be determined under state law. 

The DOE Study identifies three types of congestion warranting federal attention.  First are two critical areas where existing or growing congestion is severe:  metropolitan New York extending down the MidAtlantic into Northern Virginia and Southern California from Los Angeles to San Diego.  Second are four areas of concern:  New England, Phoenix-Tucson, Seattle-Portland, and the San Francisco Bay.  Lastly are conditional areas not presently congested but which will likely see development of new generation additions that will cause congestion absent new transmission lines:  wind and coal generation in Montana-Wyoming; wind in the Dakotas-Minnesota and Kansas-Oklahoma; and nuclear in the Southeast. 

The Study makes no NIET designations at this time; designations are not expected until after the period for public comment expires October 10.  DOE disappointed several applicants who had sought early NIET designations, including American Electric Power for its AEP I-765 Corridor, Allegheny Energy for its Trans-Allegheny Interstate Line (TrAIL), the Bay Area Municipal Transmission Group for its San Francisco Greater Bay Area Corridor, Pepco Holdings for its Mid-Atlantic Power Pathway (MAPP), and NYRI Inc.’s New York Regional Interconnect, among others.

The U.S. South is considered to have less potential for new renewable energy development than various other regions, primarily because of its relatively low wind energy potential.  But efforts to increase green power development in the region continue, as evidenced most recently by the Georgia Public Service Commission’s (PSC) decision to reduce the premium paid by customers choosing to buy green power in the state. 

The green power premium will drop to $4.50 for one block (100 kWh), down from the $5.50 and $6.00 previously paid respectively by green power customers of Georgia Power and Savannah Electric (whose customers now receive service from Georgia Power).  The payment is in addition to charges for electricity usage.  The green power initiative was first introduced by Georgia Power and Savannah Electric in 2003 to allow customers to purchase a part of their electric power from renewable resources.  More recently, the utilities wanted the PUC to drop the price of a block of electricity in order to encourage a broader participation in the green initiative. 

In an August 17 decision, the United States Court of Appeals for the Seventh Circuit ruled that Cinergy Corp. violated the Clean Air Act by upgrading coal-fired power plants in Ohio, Indiana, and Kentucky in the late 1980s and early 1990s without installing controls to capture pollution and without updating its federal air pollution permit.  Judge Richard Posner’s decision perpetuates a deep split among federal appellate courts on how to interpret the  New Source Review (NSR) provisions of the Clean Air Act.  In particular, the Seventh Circuit's Cinergy decision conflicts with a 2005 Fourth Circuit decision that found that Duke Energy had not violated the NSR when it similarly upgraded power plants.  The U.S. Supreme Court has granted certiorari in the Duke case, and is expected to issue a decision in that case in early 2007.

NSR is a federal permitting program, enacted as part of the Clean Air Act in the late 1970s.  It requires power plants, factories, and other industrial facilities to obtain permits before constructing new facilities or adding on to existing ones.  The program is aimed at ensuring that plant additions and expansions do not degrade local air quality.  The primary issue in both the Cinergy and Duke cases involved whether particular actions by the utilities triggered the NSR requirements.  Specifically, both courts were called on to interpret the meaning of the phrase “emissions increase” for purposes of the NSR program, and to determine whether the utilities' actions can be considered “routine maintenance,” which is exempt from NSR, or are “major modifications,” which would require new federal permits and the installation of improved air quality controls. 

Duke and Cinergy both argued that NSR's pollution control requirements are triggered by increases in hourly emissions rates — which were virtually unchanged in both cases — and that the “routine maintenance” exemption refers to activities that are routine within the industry.  The Environmental Protection Agency (“EPA”), on the other hand, contended that NSR requirements are triggered by increases in annual emissions, and that “routine maintenance” refers to maintenance activities that are routine for a specific generating unit.  The Seventh Circuit in Cinergy sided with the EPA, reasoning that Cinergy's interpretation of the NSR provisions would give utilities an “artificial incentive” to renovate a power plant and continue using it beyond its expected lifespan, rather than replacing it with a more environmentally friendly plant.  According to Judge Posner, that incentive conflicted with the intent of the Clean Air Act.