Energy Legal Blog

Long-Term Transmission Rights Arrive in Midwest ISO

The Energy Policy Act of 2005 (EPAct 2005) required FERC to enable load servers to obtain long-term transmission rights (LTTR).  Earlier versions of financial transmission rights offered in organized power markets were of short duration — typically monthly or yearly — which many load servers deemed inadequate for long-term planning and price certainty.  In its rulemaking to implement LTTRs, FERC directed organized market operators to prepare compliance plans consistent with FERC's guidelines.  Just as each organized market is idiosyncratic so too were the plans, and FERC is now addressing them, one by one.

In its plan, the Midwest ISO proposed not to allocated LTTRs directly to load servers, but instead to give them auction revenue rights (ARR).  A load server in the Midwest ISO can then choose whether to convert the ARRs to transmission rights or use them to collect the revenues from the sale of transmission rights in an auction.  The ARRs would have initial terms of one year each, but could be renewed annually for up to ten years.  FERC largely approved this approach. 

FERC went on to fault the Midwest ISO, however, for failing to fund fully its LTTR —that is, to ensure that the financial coverage offered would not change during its term.  While the Midwest ISO proposal would fully fund the ARRs, the associated transmission rights would not be fully funded, which could expose transmission users to revenue shortfalls, for example, when a transmission line goes out of service.  FERC directed the Midwest ISO to propose means for ensuring the transmission rights holder is fully compensated in all such instances. 

PJM was the first organized market operator to submit an LTTR compliance filing to FERC.  FERC approved PJM's LTTR proposal last fall, but also found that PJM had not met the full funding requirement.  PJM revised its proposal to use an "uplift" mechanism that distributes the shortfall costs to all financial transmission right holders to provide the revenue protection, and FERC sanctioned that approach. 

FERC also denied the demand of the Long Island Power Authority that it be allowed to obtain LTTRs in the PJM service territory.  LIPA only serves load outside the PJM territory, and PJM denied its requests for LTTRs.  LIPA argued its request was consistent with the EPAct and justifiable because it pays for its share of necessary transmission upgrades as well as the transmission service charge that covers the embedded costs of PJM transmission.  FERC agreed with PJM but not on the ground that LIPA only served load external to PJM.  Instead, FERC found that LIPA failed to meet the PJM prerequisite of having taken transmission service during a given reference year in the past and paying the embedded costs of the PJM transmission system. 

Qualifying Facilities No Longer Generically Exempt from Reliability Standards

On May 18, FERC made good on its promise to extend reliability standards to Qualifying Facilities (QF).  Order No. 696 overhauls regulations governing small power production and cogeneration facilities by eliminating previous exemptions of QFs from compliance with section 215 of the Federal Power Act.  According to the final rule, FERC believes "there is not a meaningful distinction between QF and non-QF generators that warrants a generic exemption of QFs from reliability standards."  QF generators, FERC explained, affect the bulk-power systems as much as non-QF generators and should therefore be similarly subject to new mandatory reliability standards that become effective on June 4, 2007.  

Commenters during the Notice of Proposed Rulemaking process for Order No. 696 urged FERC to consider a number of factors in its evaluation.  FERC was not persuaded and denied generic exemptions, including exemptions for QFs below a certain size or ones serving only behind the meter load.  FERC instead directed that North American Electric Reliability Corporation (NERC) or Regional Entities could consider factors warranting specific exemptions when an individual QF is evaluated for registration (the general procedures for registration are outlined at Section 500 of NERC's Rules of Procedure).   FERC explained that, in this regard, Order No. 696 puts QFs and non-QFs on equal footing "to not be subject to reliability standards" since the registration process is designed to determine applicability of the standards on a case-by-case basis.  FERC also pointed out that QF's still have the opportunity to appeal to the agency if the QF believes its registration was in error.

FERC Aggressively Responds To Natural Gas Violations

Over the past month, FERC has continued its heightened enforcement activity, approving two settlements with separate natural gas shippers who self-reported violations of the Commission's orders and regulations.  The settlements illustrate FERC's oft-stated preference for settling, rather than litigating, alleged violations.  FERC has now approved eight settlements, totaling $30 million, with natural gas and electric entities since the beginning of 2007.

On May 21, FERC approved a settlement with Columbia Gulf Transmission Company, in which the company agreed to pay $2 million to resolve an Office of Enforcement investigation into whether it violated orders allowing Tennessee Gas Pipeline Company to construct a receipt point interconnection on a Louisiana natural gas complex co-owned by Columbia Gulf and Tennessee.  In 2005, FERC issued an order approving Tennessee's proposal to construct a receipt interconnection at the complex, based on FERC's open-access policy.  The two companies subsequently disputed which one would operate the new interconnection, and in 2006, FERC attempted to settle the matter by directing Columbia Gulf to provide the taps necessary for Tennessee's interconnection.  FERC also referred the matter to the Office of Enforcement, which began an investigation into whether Columbia Gulf's actions violated FERC's orders approving the interconnection, and at the conclusion of its investigation, alleged that Columbia Gulf had substantially delayed and had created unwarranted obstacles to the project's completion.

The Columbia Gulf settlement comes on the heels of a May 9 order approving a stipulation and consent agreement with Calpine Energy Services, LP.  Calpine agreed to pay $4.5 million for entering into thousands of transactions in which it transported more than 150 billion cubic feet of natural gas on eight pipelines without holding title to the gas.  The settlement also resolved violations involving the misuse of pipeline capacity by Calpine affiliates to serve other affiliates and the improper movement of natural gas.  Calpine, which is currently in bankruptcy, received approval from the bankruptcy court for the settlement as a pre-petition unsecured claim.

FERC Approves Violation Risk Factors for NERC Reliability Standards

With only days to spare before Reliability Standards go into effect on June 1, FERC has approved Violation Risk Factors associated with those standards.  The Violation Risk Factors rank violations by the relative risk each poses to the high-voltage transmission grid.  These rankings will factor into setting penalties for violations of the Reliability Standards.  The accepted Violation Risk Factors will, like the Reliability Standards they enforce, go into effect June 1. 

FERC approved over 700 Violation Risk Factors that the North American Electric Reliability Council (NERC) had proposed.   Each relates to the 83 Reliability Standards that FERC approved in its Order No. 693 earlier this year.  Violation Risk Factors associated with proposed but not yet approved Reliability Standards will be addressed when FERC acts on those Reliability Standards themselves.  NERC categorizes Violation Risk Factors as high, medium, and low.  High risk violations could cause or contribute to bulk-power system instability, separation, or cascading failures.  Medium risk violations can affect the electrical state or the capability of the bulk-power system, or the ability to monitor and control bulk-power flows.  Low risk violations are more administrative in nature.

UPDATE: Senator Harry Reid Proposes Consolidated Energy Package, Energy Efficiency Promotion Act Incorporated

Senate Committees Take Up Energy Efficiency Standards and Clean Energy Investment Incentives

Two bipartisan energy efficiency bills are wending their ways through the US Congress.  In late April the Senate Energy and Natural Resources Committee held hearing on the Energy Efficiency Promotion Act of 2007, sponsored by Committee Chair Jeff Bingaman (D-NM) and Ranking Member Pete Domenici (R-NM).  And in the Senate Finance Committee, Senator Maria Cantwell (D-WA) introduced the Clean Energy Investment Assurance Act of 2007 on May 11.

Energy Efficiency Promotion Act of 2007

This bill rewards efficient use of oil, natural gas, and electricity, reduce oil consumption, and heighten energy efficiency standards for consumer products and industrial equipment.  The bill contains provisions to: (1) assist state and local governments in energy efficiency; (2) promote federal leadership in energy efficiency and renewable energy; (3) expand use of advanced lighting technologies; (4) implement new energy efficiency standards; (5) develop and market high efficiency vehicles, advanced batteries, and energy storage; and (6) otherwise establish energy efficiency goals.  As an example of the detailed proposals in the current version of the bill, the advanced lighting technologies section would set incandescent reflector lamp efficiency standards, offer Bright Tomorrow lighting prizes, and accelerate procurement of energy efficient lighting. 

Douglas Johnson, Senior Director of Technology Policy and International Affairs at the Consumer Electronics Association (“CEA”), has raised questions regarding design mandates in the bill that unwittingly could stymie innovation and conflict with successful existing federal programs such as Energy Star.  In addition, CEA is concerned that the bill redefines “energy conservation standard” in a way that mandates specific technologies and product components in addition to the energy efficiency products themselves.

While CEA has expressed its commitment to working with legislators to develop federal solutions, it fears that legislating over Energy Star could be “a step backwards.”

Clean Energy Investment Assurance Act of 2007

The bill proposes to amend portions of the Internal Revenue Code of 1986 to encourage investment in clean energy technologies using enhanced and predictable tax credits.  If enacted, the bill would (1) extend until 2013 the renewable electricity production credit; (2) extend and expand the Clean Renewable Energy Bond program that provides public power systems with interest-free borrowing for renewable energy projects; (3) extend two provisions until 2017, namely the 30-percent tax credit for the purchase of residential solar power, solar water heating, fuel cell equipment, and qualified energy storage air conditioner property and the 30-percent business tax credit for investments in solar energy equipment, fuel cell power plants, and qualified energy storage air conditioner property; and (4) extend three provisions until 2013, namely the tax credit for the construction of new energy-efficient homes, the deduction for investments in energy efficient commercial buildings, and the 10 percent investment tax credit for the cost of energy efficient materials used in the construction of buildings.

"Encouraging private investment in renewable energy is an indispensable part of reducing emissions and curbing our overdependence on fossil fuels," explained Senator Cantwell  "To get consumers better technology and cleaner, more renewable, more efficient energy options," she continued, "we need predictable federal incentives to encourage investment."

New Hampshire Commits to a Renewable Portfolio Standard of 25% by 2025

The New Hampshire Senate passed unanimously and will send to Governor Lynch House Bill 873, a renewable portfolio standard intended to promote fuel diversity, lower regional dependence on fossil fuels, reduce and stabilize energy costs, keep energy investment in the state, reduce greenhouse gases, improve air quality, and stimulate investment in renewable technologies.  Governor Lynch expressed his commitment for the RPS' ability to "help create jobs right here in New Hampshire by expanding uses for our wood products, in building clean power plants, and in research and development."

The legislature established four classes of renewable energy in its RPS.  Class I includes new (after January 1, 2006) electricity production from wind, geothermal, biomass and methane fuels, ocean thermal, wave, current or tidal energy, and energy displacement by end-users.  Class II includes new (after January 1, 2006) production of electricity from solar technologies.  Class III includes electricity production from existing (prior to January 1, 2006) small biomass and methane gas operations.  Class IV includes the production of electricity from existing (prior to January 1, 2006) hydroelectric energy.

Those utilities without renewable energy generation can purchase certificates in order to meet the requirements of the RPS.  Although certificates are to be purchased on the open market, they may be subject to price caps that vary according to the energy source.  In addition to setting target percentages by 2025, the legislature also established benchmark percentages for each classification in each year between implementation and 2025.

The PUC is charged with adopting rules to administer the RPS program, monitoring compliance with the rules, administering and making expenditures from the fund, and establishing procedures for classifying existing and proposed generation facilities.

Department of Energy Proposes $9 Billion in Clean Energy Loans

Nine billion dollars could flow to guarantee loans to clean energy projects under a May 10 Department of Energy (DOE) Notice of Proposed Rulemaking (NOPR) under the Energy Policy Act of 2005. Each approved project could receive guarantees covering up to 80% of total project costs.  To be considered by the agency, written comments must be submitted within 45 days from notice in the Federal Register — likely late June or early July.

DOE proposes loan guarantees for ten categories of projects and technologies, including:  renewable energy systems; advanced fossil energy technology, including qualifying coal gasification systems; residential, industrial or transportation hydrogen fuel cell applications; advanced nuclear facilities, carbon capture and sequestration practices; efficiency in electrical generation, transmission and distribution; end-use efficiency technologies; production facilities for fuel efficient vehicles; pollution control equipment; and certain crude oil refineries.

Allocation of the $9 billion in loans will not be equally distributed among the ten categories; rather, $4 billion is reserved for central power stations, $4 billion for biofuels and clean transportation fuels, and only $1 billion for projects involving new technologies for electric transmission or renewable power generation systems.  According to DOE, precise allocation of the guarantees will depend upon the merits and benefits of a particular proposal and the accompanying statutory and regulatory requirements.

While the program is a positive development for the energy industry as a whole, efficient and fair implementation by DOE is critical, and that implementation is the specific subject-matter of the May 10 NOPR.  Provisions of particular interest to potential loan applicants include payment of the Credit Subsidy Cost, assessment of fees to loan recipients, rules on financial structure and eligibility of lenders, regulatory review, and default and audit rules.

Those industries now participating in eligible technologies and those planning expansion into clean energy projects can find public comment and public meeting procedures at Section III of the NOPR.

Duke Energy's Save-A-Watt Promotes “Fifth Fuel” — Energy Efficiency

In a May 7 filing, Duke Energy asked the North Carolina Utilities Commission to compensate the utility for meeting growing power demand through investments in new technologies and energy efficiency just as it is compensated for investments in new generating plants.   Duke has recently trumpeted its commitment to place energy efficiency on equal footing with new generation investments.  According to Duke, "recovering financing costs as [it] build[s,] and implementing a regulatory framework that encourages investments in energy efficiency will result in smaller, more manageable rates."

The proposal would allow Duke to earn 90% of the depreciation and operating costs that could be avoided by not constructing and operating new plants or by retiring aged coal-fired plants.  This would translate to a 10% reduction in cost to customers over building and operating new power plants.  Duke asks that its plan be applied to all North Carolina rate schedules.

Duke acknowledges that new construction will still be needed to meet a projected 3,400 MW demand over the next four years, but nevertheless believes energy efficiency measures could provide as much as 1,700 MW of that demand over the same timeframe.  New low-emission coal, nuclear, natural gas and renewables generation would be coupled with residential energy assessments, an efficiency savings plan pilot, and an advanced power managed pilot to fulfill customers' power needs.  As part of another project, Duke also plans to retire 800 MW of aging coal-fired power and invest 1% of its annual retail revenue from North Carolina electricity sales in energy efficiency programs.

Duke's initiative is typical of the industry’s increasing resort to energy efficiency and demand response to meet or eliminate demand. For example, the California Public Utility Commission recently approved Pacific Gas & Electric and Southern California Edison's proposal to enter into agreements with demand response aggregators.  Interest is further spurred by recent state-federal collaborations specific to demand response and energy efficiency.  Notably, Jimmy Ervin, a North Carolina Commissioner and Chair of the National Association of Regulatory Utility Commissioners co-chaired the first meeting of a state-federal demand response collaboration with FERC Commissioner Jon Wellinghoff.  Commissioner Wellinghoff is an ardent supporter of demand response, energy efficiency, and renewable and distributed resources.

Washington State Enacts Climate Change Legislation

Washington State has enacted a climate change law half a year after a ballot initiative approved a renewable portfolio standard (RPS).   The new law applies to long-term power-purchase agreements signed by utilities after July 1, 2008 and all new power projects built in the state after that time.   It requires that baseload generation comply with an emissions performance standard of 1,100 pounds of greenhouse gases  per MWh.  This is compatible with the emissions from state-of-art gas-fired generators, but would preclude long-term contracts with or development of coal-fired generation unless the greenhouse gases are sequestered or mitigated.  The law also establishes long-term greenhouse gas emissions reductions goals for the entire state.

The new law recites the state's vulnerability from climate change, including the potential impact on the snow pack that supplies summer stream flows and the effect of rising sea levels on coastal communities.  Under the existing RPS laws, affected utilities must 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.  Most forms of renewable energy qualify as eligible sources, although hydropower is mostly excluded. 

How the greenhouse gas and RPS laws will work in tandem remains to be seen.  One impact is that new hydropower facilities could be used for compliance with the climate change law, but not with the renewable portfolio standard.  Washington State isn't the only state to have enacted both types of laws, as California has already gone down this path, and several other states with or without RPSs are working on various types of climate change proposals. 

In general, the two sets of legal requirements have some overlap, but also pursue different objectives.  A renewable portfolio standard doesn't by itself necessarily reduce overall carbon emissions, as it doesn't affect the type of generation that is not required to be renewable, i.e., the remaining 80% in an RPS that requires 20% renewable energy.  For example, if an RPS that requires 20% procurement of energy from renewable resources leads to wind and geothermal development that avoids CO2 emissions, the emissions of CO2 could still increase overall if the remaining 80% of generation includes emissions from sources such as coal-fired plants.  Conversely, setting CO2 limits without an RPS could lead to development of natural gas-fired generators with relatively low CO2 emissions, but would not necessarily promote renewable energy development.

DOE Proposes Two National Interest Electric Transmission Corridors

Several months after FERC's issuance of a final rule setting out the procedures it will follow to determine whether to site transmission facilities in Department of Energy (DOE)-designated national interest electric transmission (NIET) corridors, DOE has proposed two NIET corridors for review and comment.  The "Mid-Atlantic Area National Corridor" encompasses certain counties in Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia, and all of New Jersey, Delaware and the District of Columbia.  The "Southwest Area National Corridor" includes counties in California, Arizona, and Nevada.  Public comments on the proposed designations may be filed with the DOE within sixty days of the proposal's publication in the Federal Register.  Final designation is expected by the end of the year, possibly accompanied or closely followed by more draft designations of corridors in the areas of New England, San Francisco and Seattle-Portland, areas that DOE is also considering for NIET corridor designation. 

Final designation of these two NIET corridors would pave the way for FERC to utilize the so-called “backstop” siting authority that Congress granted to the agency in the Energy Policy Act of 2005 (EPAct 2005).  In an amendment to the Federal Power Act, EPAct 2005 empowered FERC to issue permits for construction of transmission lines and condemn right of way for those transmission lines.  Until now, only state regulators and siting authorities possessed this authority. 

Final designation would also raise the chances that several transmission operators, whose 2006 requests for "early" NIET corridor designation were rejected by DOE, would see their proposed projects come closer to fruition.  Those projects include AEP's proposed Mountaineer Project from West Virginia to New Jersey, Allegheny Power's Trans-Allegheny Interstate Line Project from Pennsylvania to West Virginia, and SDG&E's Imperial Valley project in southern California.

DC Circuit Remands ISO-NE Installed Capacity Orders to FERC

The US Court of Appeals for the DC Circuit on April 20 issued a per curiam order that sends back to FERC the issue of whether the agency has jurisdiction to authorize ISO-New England's (ISO-NE) implementation of an installed capacity requirement.  The Connecticut Attorney General Richard Blumenthal and the Connecticut Department of Public Utility Control (CDPUC) had challenged FERC's jurisdiction over the contentious installed capacity requirement, which obligates load servers to control capacity in excess of peak load.  The AG and CDPUC argued that the Federal Power Act (FPA) entrusted such power supply decisions to the states, and not the federal government, to decide such matters.  While the court did not necessarily agree with the Connecticut parties' arguments that installed capacity is really a form of generation resource adequacy that should be left to the states, it directed FERC to articulate a justification for federal jurisdiction.

The AG and CDPUC have been vehement opponents of the installed capacity proposal from the outset.  In its briefs to the court, the CDPUC attempted to downplay the relationship of installed capacity requirements to wholesale rates, indicating the connection was only "tangential[] or incidental[]."  The CDPUC sought a court order defining the scope of FERC's authority over generation resource adequacy and directing that FERC must defer to Connecticut's jurisdiction regarding the generation capacity requirements.  For its part, FERC countered that authority over generation capacity was conferred to it by the FPA's general grant of federal jurisdiction over the sale of electric energy in interstate commerce.  But that wasn't clear enough for the court, which accordingly remanded the case back to FERC.  However, the court did not go as far as the CDPUC and AG would have liked; by simply remanding to FERC for further explanation of its jurisdiction, the court gave FERC another shot to explain how and why it should regulate installed capacity, and it left for another day the merits of ISO-NE's proposal.

FERC Tailors Transmission to Connect Renewables

In response to a carefully crafted petition from the California Independent System Operator, the Federal Energy Regulatory Commission took a large step toward facilitating development of the transmission needed to harness wind and other renewable energy sources that are remote from load centers.  With its order granting the CAISO’s petition for declaratory order, FERC approved a financing mechanism that is intended to solve the "chicken or egg" sequencing problem of development of transmission lines and renewable energy generators in areas such as the Tehachapi region of California.

The problem vexing renewable energy advocates is that wind, geothermal and other renewable generators must be built where natural conditions allow.  But wind and geothermal hot spots are often far from the energy-thirsty urban centers, and little transmission is available at these remote locations.  Since most renewable energy projects are much smaller than large hydro or fossil-fuel plants, individual generators can’t afford to develop major new transmission projects.  Nor have transmission owners been keen on building lines to locations where the development of generation is either marginal or uncertain. 

To break this transmission logjam, some states have created transmission development agencies.  But California entities have focused more on creating cost recovery mechanisms that would allow the state's transmission-owning utilities to develop the transmission themselves.  In 2005, Southern California Edison initally proposed a "trunk line" model, but FERC objected  because ratepayers would pay for the entire facility, and because the utility would retain control of it.  FERC solicited an alternative, and the CAISO responded with a program having the following key terms:

• The project must provide access to an area with significant potential for development of remote energy resources.
• Initial costs of qualifying interconnection facilities would be rolled into the transmission revenue requirement of the transmission owner that constructs the facility, subject to a cost cap to protect ratepayers. 
• Later costs would be paid pro rata by generators who interconnect with the line.
• The project would have to be approved through the CAISO transmission planning process.
• A minimum level of generators must commit to the line before it can proceed, and another batch must have shown interest in joining. 

FERC earlier had resisted advantaging renewable energy through favorable transmission rules.  But with its approval of the CAISO program, FERC acknowledges that location-constrained resources are unique and warrant different access rules.