Energy Legal Blog

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. 

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.

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.

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.

To help transmission grid customers navigate this thicket of Standards and Risk Factors, FERC has directed NERC to prepare a matrix that explains the relationship between each Reliability Standard, its component Requiremenst, and associated Violation Risk Factor and penalties.

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.”