Energy Legal Blog

Federal-State Cooperation Will Promote Demand Response in Power Markets

FERC has embarked on dialogue with state regulators about demand response — the designation assigned a variety of potentially promising measures consumers (as opposed to the suppliers) can take in power markets to reduce demand and prices.  The federal-state dialogue on demand response policies is auspicious because development of effective demand response that is capable of materially reducing prices will require coordination of federal regulation of wholes and state regulation of retail power markets. 

In response to directives in the Energy Policy Act of 2005, FERC prepared a report assessing demand response and advanced metering.  FERC’s August 2006 report concluded that demand response was promising and the subject of widespread interest, but yet illusory due to disconnects between wholesale and retail pricing (which fails to pass through wholesale price signals to retail consumers), economic disincentives for utilities to offer retail demand response, and other regulatory and industry barriers.  FERC also found that the use of advanced metering — meters that show consumers the present cost to generate and deliver power — varies greatly between regions and averages only 6% of electric meters nationwide. 

Discussion about demand response often lack focus.  In one sense it is any type of energy conservation, for instance turning off the lights in an empty room.  More complex versions of demand response include the incentive programs run by several regional transmission organizations and independent system operators.  These provide payments to users who reduce their power consumption under certain circumstances, in particular when demand is at its peak.  As a result, the RTO/ISO may be able to avoid dispatch of high-cost (inefficient) generators, which leads to a lower clearing price for the market and savings for other consumers.  This form of demand response does not necessarily conserve energy, as the participants in the demand response program may simply shift their energy consumption to other (non-peak) hours.  FERC’s report relies on a definition that encompasses both time-based use of electricity and incentive payments for reducing demand at times of high wholesale market prices or when demand is threatening system reliability. 

More ambitious discussions about demand response tout it as a potential substitution for power, capacity, transmission, and even ancillary services such as operating reserve.  In these contexts, demand response is seen not just as a means for customers to save money, but to allow new industries to earn money through demand response programs and measures.  The extent to which demand response can play this larger role remains to be seen and will turn in large measure on how effectively FERC and state regulators coordinate to induce suppliers to forego sales and, more importantly, to induce consumers to forego consumption in order to promote the common goods of lower prices and/or system reliability.

Court Decision Likely to Roll Back Applicability of Standards of Conduct for Both Pipeline and Utility Affiliates

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit in a November 17 ruling struck down a divided (2-1) FERC expansion of the applicability of Standards of Conduct that prohibit interstate natural gas pipelines and electric transmission grid owners/operators from sharing non-public pipeline or transmission- grid information with affiliates.  Before the November 2003 expansion, the Standards applied only to the marketing affiliates of the pipes and transmission systems; after, it applied to all “energy affiliates.”   Responding to natural gas pipelines’ complaints that the expanded applicability would cost the industry an estimated $240 million annually and was based on no evidence of preferential treatment of “energy affiliates,” the panel held that FERC’s “vast expan[sion] of the reach of the Standards,” based only on a theoretical possibility of affiliate favoritism, violated the Administrative Procedures Act requirement of reasoned decisionmaking.  FERC has 45 days to petition for rehearing, barring which the case will be remanded to the agency.  On remand, according to panel, FERC may (1) confine the Standards to market affiliates — those who actually buy and sell the transmission capacity of the pipes and wires, (2)  develop a factual record of abuse that would justify the expanded applicability, or (3) try to develop support for the expansion based on a “theoretical threat of abuse.”  The panel cautioned that the theoretical approach would likely fail.

As precedent, the panel decision reigns in the Standards as applied only to “energy affiliates” of natural gas pipelines, such as producers, gatherers, processors and risk managers, and not to the comparable affiliates of electric transmission system operators.  But this distinction is likely to vanish on remand since the agency prefers uniform rules for accessing natural gas pipelines and electric transmission systems to the extent possible.  Moreover, since one of the most vocal opponents of the expansion from early in its genesis, then-Commissioner Joe Kelliher, is now the FERC Chair, odds are that the agency won’t seek rehearing and, instead will retreat on remand to its original application of the Standards only to marketing affiliates of the pipes and grid operators.

Federal-State Tension Accompanies FERC's Final Rule on Backstop Transmission Siting

FERC has issued a Final Rule establishing procedures that it will use for permitting construction of transmission lines in National Interest Electric Transmission Corridors (NIET) corridors.  In EPAct 2005, Congress authorized the Department of Energy to designate NIET corridors in congested areas of the high-voltage power grid.  Congress, in turn, granted FERC new authority to permit construction of transmission lines within designated NIET corridors in instances when a state permitting authority either has not acted or is unable to act on an application for siting authority.  The federal permit is controversial because it confers on the permit recipient a new federal right of eminent domain to condemn private property for rights of way ― a right previously available only from state and local authorities.   

Most elements of the Final Rule track an earlier proposed rule.  FERC must find that the proposed facilities would meet five basic criteria, including reducing congestion and enhancing energy independence.  Applicants for permits must file Participation Plans to maximize stakeholder contributions, and engage in a prefiling process at FERC.  The Final Rule does change this prefiling process.  Under the proposed rule, while an applicant was required to wait one year after applying to state or local authorities before filing its permit application at FERC, it could nevertheless begin the prefiling activities at FERC earlier, concurrent with ongoing state siting proceedings.  In response to loud outcry from state regulatory agencies concerned that FERC would effectively commandeer ongoing state review of transmission projects in NIET corridors, the Final Rule now prohibits both filing an application and initiating prefiling activities at FERC before one year following the beginning of state proceedings.   

Another controversial provision related to the states was resolved in favor of a stronger FERC authority.  EPAct allows FERC to grant a permit where a state has "withheld approval" of transmission facilities.  FERC determined that "withheld approval" applies both to where states deny permits and where states fail to act on permits.  While FERC Chair Kelliher supported this decision, calling it a reasonable interpretation, Commissioner Kelly disagreed, arguing that the interpretation leaves states with little choice: either permit the facilities or FERC will do it for you.  Kelliher pointed out that FERC could have legally implemented a process that ran simultaneously with state processes, but did not do so.  The practical result of this middle ground, however, is a lengthier permitting process – Kelliher admitted that projects that fail to win state siting approval face another 20 months of regulatory review at FERC. 

"Other" Washington Approves Renewable Portfolio Standard

While legislators in Washington, D.C. have yet to approve a national renewable portfolio standard (RPS), renewable energy advocates in Washington State prevailed in a ballot initiative that would require the state's larger utilities to procure up to 15% of their energy from renewable resources.

Washington is rich in hydro-resources and through integrated planning, some incremental renewable energy generation has also been built.  Supporters of the ballot initiative sought to set higher and more quantifiable standards, while some utilities raised concerns about costs, particularly if the federal production tax credit expires.  With passage of the initiative, affected utilities will have to procure 3% of their energy from renewables by 2012, 9% by 2015, and 15% by 2020, subject to different standards for utilities without load growth.  Qualifying types of renewable energy includes wind, solar, geothermal, various kinds of biomass, landfill and sewage-treatment gas, wave, ocean, tidal.  Hydropower is excluded, except for utility-owned hydropower efficiency upgrades.  Utilities can acquire the renewable energy from facilities in the Pacific Northwest, from other facilities capable of delivering power to Washington, or through equivalent renewable energy credits.

The initiative also requires utilities to identify and pursue cost-effective conservation measures, which are defined as reductions in power consumption due to increased efficiency in energy use, production, or distribution. 

Industry and Regulators Aim to Synchronize Natural Gas Supply and Power Markets

During a northeastern cold spell in January 2004, natural gas-fired electric generators had significant problems obtaining adequate fuel supplies in time to participate in the ISO New England market and provide emergency power.  This experience caused the industry and its regulators to question whether the ISO/RTO scheduling and market-clearing practices are compatible with the scheduling of natural gas purchases and transportation. 

The North American Energy Standards Board (NAESB) established a Gas-Electric Coordination Task Force to look at the problem.  The Task Force identified several features of ISO/RTO tariffs that discouraged gas-fired generators from participating in ISO/RTO markets during periods of heightened demand or supply interruptions.  At the top of the list were discrepancies between gas nomination timelines and ISO/RTO market clearing timelines.  For example, a generator may submit an offer to sell into an ISO/RTO organized market based on prevailing natural gas prices, but by the time the ISO or RTO accepts the offer and clears the market, during extreme conditions, gas prices may have increased dramatically.  ISO/RTO market rules generally do not provide the flexibility for a generator to increase its offer price in response to the increased natural gas price.  Exposure to that risk can cause a gas-fired generator to refrain form offering its output at all during periods of heightened demand when that generation is needed most.  In an attempt to avoid these disincentives, and to increase coordination between the gas and electric markets, FERC recently directed each ISO or RTO by January 16, 2007, either to propose revisions to its offering and market clearing deadlines or to explain why such revisions are not needed.

One of the NAESB Task Force's reports also included recommended standards for natural gas transmission service providers' communications with electric power generators and independent transmission system operators.  Noting that improved communication would help address, but would not completely resolve, the coordination difficulties, FERC proposed to adopt these communication standards into its regulations in a recent notice of proposed rulemaking, on which public comments are due December 18, 2006.

Studies: Growth in Renewables Sector Can Create 160,000 New Jobs in Three States

Constellation, FPL Abandon Merger

Giving way to what they characterize as a "perfect storm" of uncertainty and risk, Constellation Energy Group and FPL Group Inc. have decided to abandon their plan to merge.   

Constellation and FPL's merger proposal had been facing an increasingly hostile climate for months.  Contributing to the storm was the impending end of a retail rate cap in Maryland, rising commodity prices, and a hard-fought gubernatorial race also in Maryland.  Citing a mutual conclusion that the path to regulatory approval remained very unclear and was likely to result in a protracted review, FPL acceded to Constellation's request to call it quits. 

Constellation and FPL will withdraw their merger approval applications pending before the Maryland Public Service Commission and FERC, and FPL will drop its suit against Maryland and the PSC for a timely decision on the proposal.  With the merger put to rest, Constellation plans to turn its attention more fully to the rate stabilization plan developed in a special session of Maryland's General Assembly earlier this year and other Maryland regulatory issues.   

Divided FERC Approves Incentive for New England Transmission

FERC voted by a 3-2 margin to raise by 100 basis points (1%) returns on equity invested in New England electric transmission that ISO New England identifies as necessary.  The Republican majority, including FERC Chair Joseph Kelliher, concluded that incentive rates were needed to encourage transmission expansion and reduce regional congestion; the Democratic dissenters contended that, even if targeted investment incentives may be warranted, across-the-board increases in transmission investment returns had not been justified.

The order reverses a FERC judge’s May 2005 decision that such transmission incentives should only be awarded to projects that would not be built “but for” the incentives.  In the Energy Policy Act of 2005 Congress directed FERC to develop transmission rates sufficient to induce investment.  In July 2006 FERC finalized a transmission pricing rule intended to induce investment in transmission without requiring the “but for” predicate that the judge endorsed.  By rejecting the “but for” requirement, the FERC majority appears to have been persuaded that ISO New England’s 2004 regional transmission planning ensures that the benefits of new transmission and congestion relief justify the added expense.
The dissenters were unwilling to buy so completely into the ISO New England planning process.  Commissioner Suedeen Kelly found the majority’s decision troubling because transmission owners would be able to get the 100-basis point adder regardless of whether it was in fact necessary for a given project to be constructed or the specific benefits from the project.  Commissioner Jon Wellinghoff expressed similar concerns, adding that such transmission incentives should be limited to those projects that provided incremental benefits such as energy efficiency.