First NERC Penalty Notices Suggest Focus on Enforcement

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

FERC Takes Action to Prevent Cross-Subsidization between Affiliates

FERC continues to tweak its rules regarding mergers and acquisitions under section 203 of the Federal Power Act (FPA), issuing new regulations that impose restrictions on affiliate transactions between certain public utilities and their unregulated affiliates.  FERC explained that it intends to fill a perceived regulatory gap in its current affiliate sales rules, and stated that this final rule, combined with an order issued the same day allowing for grants of blanket authorization for a public utility to dispose of voting securities, marks the completion of the "initial implementation" of the rules governing transactions conducted under section 203. 

Order No. 707 extends the affiliate transaction restrictions already in place for entities with market-based rates and utilities requesting merger approval to franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities.  Under the new rules, wholesale sales of power between such public utilities and power sales affiliates with market-based rate authority will require FERC approval.  In addition, such a public utility that sells non-power goods and services to an affiliate with market-based rate authority or an unregulated affiliate will be required to do so at a price that is the higher of either cost or market price.  Lastly, a public utility subject to the rules will not be permitted to purchase non-power goods or services from an affiliate at a price above market price, except that the public utility cannot receive non-power goods and services from a centralized service company above cost. 

Competing FERC and CFTC Jurisdictional Claims Are Court Bound

FERC in a November 30 order refused to reconsider its July 26 decision to impose $291 million in civil penalties against Amaranth Advisors (Amaranth) for gaming the natural gas futures market and manipulating the price of natural gas.  FERC upheld its own jurisdiction to impose penalties on Amaranth, rejecting the Commodities Futures Trading Commission's (CFTC) insistence that it alone has jurisdiction over manipulation of gas futures contracts.  FERC found instead that "the language and statutory purpose of Section 315 of the Energy Policy Act of 2005" (EPAct 2005) gave FERC "broad authority to sanction manipulative conduct by any entity 'in connection with' the purchase, sale or transport of natural gas within its jurisdiction." 

In the earlier July order, FERC had directed Amaranth to show cause why it had not violated the Natural Gas Act and FERC's anti-market manipulation rules, and proposed a $291 million civil penalty for allegedly manipulating the gas futures market by selling New York Mercantile Exchange (NYMEX) futures contracts just before they expired.  In an August request for rehearing, Amaranth argued that FERC did not have jurisdiction to impose the proposed civil penalties, and that the CFTC had exclusive enforcement authority for manipulation of gas futures markets.  The case has set up a turf war between FERC's expanded enforcement authority under EPAct 2005 and the CFTC's traditional regulation of commodities markets, and led the CFTC to argue that it has exclusive jurisdiction over this case.  Amaranth may now appeal FERC's orders to a US Court of Appeals, which may ultimately delineate the boundaries of FERC's expanded enforcement authority in relation to the CFTC's authority over commodity futures markets. 

Also in the November 30 order, FERC gave Amaranth 14 days to responds to the original show-cause order.

FERC Makes Good on Rate Incentive Promises to Transmission Developers

At its November 15 meeting, FERC announced three decisions awarding several incentive mechanisms to transmission developers.  The orders were issued in response to requests from Southern California Edison Company (SCE), Baltimore Gas & Electric Company (BG&E), and Pepco Holdings, Inc. (PHI), and were among the first substantive decisions since FERC's transmission incentive rulemaking order earlier this year, Order No. 679.  To transmission developers who can show their projects would ensure reliability or reduce transmission congestion that decision, Order No. 679 proposed to provide increased transmission rate incentives, such as higher Returns on Equity (ROE), adders to the rate basis, and inclusion of 100% of Construction Work in Progress (CWIP) and abandoned facilities in rate base.  The transmission developers, in order to qualify, must demonstrate a "nexus" between the incentives sought and the investment being made, i.e., the applicant must show that the incentives are rationally related to the investments being proposed.

Two of the instant orders provided incentives for companies seeking to construct new facilities in the transmission-constrained Southern California and Mid-Atlantic regions.  SCE is building several projects in Southern California:  the Devers-Palo Verde II Project, which consists of two transmission lines; the Rancho Vista Project, which includes a new 500 kV substation; and the Tehachapi Project, which consists of over 200 miles of transmission lines and three new substations and will be used to bring renewable energy (predominantly wind) onto SCE's transmission system.  In its order, FERC found that SCE had satisfied the "nexus" standard of Order No. 679.  The agency went on to allow a 125-basis point ROE incentive for the Devers-Palo Verde II and Tehachapi Projects, and a 75-basis point ROE incentive for the Rancho Vista Project.

Similarly, BG&E is constructing two baseline transmission projects in Maryland.  While FERC granted BG&E's request for a total of 150-basis point adders (for membership in the PJM Interconnection and for constructing baseline transmission), FERC denied BG&E's request to include 100 percent of its CWIP in rate base.  FERC also established a technical conference to determine whether BG&E's projects satisfied Order No. 679's "nexus" test.

In FERC's third order, it granted a request from PHI, on behalf of its transmission-owning public utility affiliates, Atlantic City Electric Company, Delmarva Power and Light, and Potomac Electric Power Company, for a 50-basis point adder to its authorized ROE for continued membership in PJM.  The adder moves PHI's overall ROE up closer to ROEs granted for PJM transmission facilities placed in service since 2006.  FERC explained that granting PHI's request furthered the Energy Policy Act of 2005 directive that FERC encourage utilities to join RTOs and ISOs.

FERC Extends Financial Houses’ Leave to Acquire Utility Securities

The role of financial institutions in energy markets is steadily increasing.  In furtherance of this trend, FERC recently granted blanket authorizations to three financial and investment companies allowing them to acquire securities of electric utility companies in the course of their business, without needing advance FERC approval under the Federal Power Act (FPA) for each transaction.

As part of the Energy Policy Act of 2005, Congress amended the FPA to require prior FERC approval for holding companies to acquire securities with a value of over $10 million of utilities or holding companies owning utilities.  Financial institutions have since sought and received from FERC waivers to allow them or their affiliates to acquire these securities in amounts exceeding $10 million without advance FERC approval, provided the acquisition is in their ordinary course of their business, which includes taking security for a loan, in connection with their asset management business, or as part of their routine activities as a broker, dealer, and trader. 

In 2006, FERC granted these blanket approvals for only one-year terms.  But having grown more comfortable with these arrangements, FERC now granted blanket approvals for a three-year term.  The authorization granted two of the companies, The Goldman Sachs Group, Inc. and Morgan Stanley, were renewals for these longer terms, while the third, Legg Mason, Inc., received an initial three-year authorization.  The conditions FERC imposed on each company include not exercising control over public utilities whose securities they acquire and compliance with reporting requirements.

DOE's Loan Guarantee Proposal Penny-Wise and Pound-Foolish, Say Commentators

On May 16, the Department of Energy (DOE) published its Notice of Proposed Rulemaking (NOPR) regarding loan guarantees for projects that would employ renewable energy systems, advanced nuclear facilities, and carbon sequestration units, among other innovative technologies.  In comments on the NOPR, lending and rating institutions slammed the proposal.

The Energy Policy Act of 2005 (EPAct 2005) authorizes DOE to guarantee loans "not to exceed an amount equal to 80 percent of the project cost of the facility."  In the  NOPR, however, DOE proposed to guarantee up to only 90 percent of a particular loan rather than 100% of a loan covering 80% of project cost.  DOE's proposal also prohibited selling off or "stripping" the guaranteed portion of the debt instrument because DOE wishes (1) to preclude the guaranteed portion of the loan from being sold and (2) to ensure that the lender and later debt holders maintain the same level of financial risk in the project as when the debt was issued in order to spur continued due diligence.

Credit Suisse, Lehman Brothers, Goldman Sachs, Merrill Lynch, Morgan Stanley, and Citigroup expressed concern that the proposed rule "is not workable" because it relegates 10 percent of project debt to an un-guaranteed, deeply subordinated tranche, and, by barring stripping, prevents marketability of the debt instrument.  The "hybrid instrument" created by the NOPR, they explained, has no natural market, and "the higher costs associated with financing [it] would deter sponsors from moving forward . . . [or] increase the risk of default."  Goldman Sachs also submitted very similar comments separately.

Standard & Poor's echoed concerns over the 90 percent guarantee limit and prohibition against stripping.  S&P cautioned that the "rating associated with a partially guaranteed obligation will be substantially lower than the 'AAA' rating of a fully guaranteed instrument" and will result in "a significantly higher cost of debt for the project than if it was fully guaranteed."  A 100 percent debt guarantee and/or removal of the no stripping requirement would lower the cost of debt and is likely essential to "the early commercial use of innovative technologies."

Banc of America Securities, LLC concluded that EPAct itself made clear that 100 percent of the loan is to be backed by the full faith and credit of the United States and the NOPR's proposal is consequently inconsistent with the statute.   The Electric Power Supply Association echoed this congressional intent argument when it urged DOE to guarantee 80 percent of the total project cost and up to 100 percent of the amount borrowed.  The Public Service Commission of Florida agreed, adding that the loan guarantee program "was intended to support the deployment of new technologies that reduce, avoid or sequester greenhouse gas emissions by providing a [100 percent] guarantee for up to 80 percent of project costs," not 90 percent of 80 percent of project costs.

Failing Commitment to Report Code of Conduct Infractions Lands Cleco $2 Million Penalty

On June 12 FERC again flexed its EPAct 2005 civil penalty authority muscle.  FERC's Office of Enforcement had alleged that Cleco violated its Code of Conduct and a 2003 settlement in which Cleco agreed to a stricter, more consolidated code of conduct requiring the independent operation of its unregulated affiliated power marketers and generation assets.  The June 12 Stipulation and Consent Agreement (Settlement) recapped specific allegations of Code violations from the summer of 2003 to winter 2005.  In addition, the Settlement accuses Cleco of failing to report those violations to the Office of Enforcement, even though Cleco did submit a self-report of possible violations after investigations had been initiated.  As a part of the Settlement, Cleco neither admitted nor denied that its conduct violated the 2003 settlement or its Code of Conduct.

Non-public, preliminary investigations of Cleco began in November 2005 when the Office of Enforcement reviewed the utility's October 2005 Quarterly Compliance Report as a requirement of the 2003 settlement with FERC.  The Office of Enforcement concluded that Cleco violated the independent functioning requirement in the Code of Conduct, which requires that, except in emergencies, employees involved in transmission must function independently of the power supply employees.  The Office of Enforcement concluded that: (1) operational employees impermissibly engaged in restructuring activities for Cleco's exempt wholesale generators; (2) employees conducted activities that were beyond the scope of permissible shared accounting support duties; (3) six Technical Services Department Planning Group employees performed generation outage planning, coordinating, and scheduling activities for affiliates; (4) certain employees were given access to non-public market information; (5) a non-public monthly risk report was circulated to affiliated companies' Chief Operating Officer(s); and (6) daily status reports were distributed to affiliates that contained non-public information. 

In addition to the $2 million penalty, Cleco is now subject to another compliance plan that requires semi-annual reports to the Office of Enforcement and a 12-month independent audit.  Both semi-annual report and the audit reports must identify all shared employees, report whether any provisions of the Code of Conduct were violated, and identify each instance where non-public information was shared with affiliates.  

Although Cleco self-reported some of the violations at a later date and has taken steps to prevent recurrence of similar violations, it was Cleco's violation of the earlier 2003 settlement agreement that peeved the regulator.  FERC Chair Kelliher admonished that the $2 million penalty would serve as "a reminder that the Commission will not tolerate such actions."  He went on to say that the Commission will "use [its] civil penalty authority to establish a culture of compliance."  The Commission acknowledged that Cleco's actions did not create undue discrimination, result in preference, or cause harm to third party competitors or customers.

Arizona Regulators Reject Cross-Border Transmission Line

The Arizona Corporation Commission (ACC) recently rejected an application by Southern California Edison Company (SCE) to construct a new transmission line from Devers, California to Palo Verde, Arizona.  The proposed Devers-Palo Verde No. 2 line ― a 230-mile, 1200 MW line estimated to cost approximately $600 million ― had already won approval of the California Public Utilities Commission (CPUC).  According to the CPUC, the line would serve as an important means of reducing the substantial congestion in southern California by expanding the transmission capacity into the area and allowing California utilities to import significant amounts of power from Arizona.  The ACC, on the other hand, dismissed the project as essentially allowing California to plug a "230-mile extension cord" into its generation supply, something the ACC found untenable at a time when Arizona's own population is growing rapidly. 

With both SCE and the CPUC considering appeals, the ACC's decision potentially sets up a fight under provisions of the Energy Policy Act of 2005 that allow FERC to site transmission facilities in certain Department of Energy (DOE)-designated National Interest Electric Transmission (NIET) Corridors for which state regulators have "withheld" approval for more than a year.  In a rulemaking issued late last year, FERC interpreted the word "withheld" in the statute to also mean "denied," thus potentially allowing transmission developers to bypass recalcitrant state regulators in favor of federal regulators.  In May, DOE proposed to designate an area encompassing the Devers-Palo Verde No. 2 line as a NIET corridor.

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. 

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.

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.

FERC Signs Off on 83 Mandatory Reliability Rules

Putting into place for the first time mandatory standards to ensure reliability in the nation's electric transmission system, on March 16, FERC issued an order adopting 83 out of 107 reliability standards that were proposed by the North American Electric Reliability Corporation (NERC) last year.  Certified as the Electric Reliability Organization (ERO) contemplated in the Energy Policy Act of 2005, NERC will play a primary role in developing, monitoring, and enforcing the reliability standards.  Most of the standards take effect this summer; FERC rejected calls by some industry participants for a phase-in or transition period

FERC directed substantial changes to many of the standards, but approved them as mandatory and enforceable nonetheless.  NERC can iron out details through its stakeholder process, FERC advised.  Those standards that were not adopted were remanded back to NERC for further development or for NERC to provide additional information.  FERC declined to adopt a blanket waiver from the standards for small entities; rather, FERC approved the continued use of the existing NERC compliance registration process and Functional Model to register entities who must comply with the standards.  Under this process, NERC will register:  distribution providers or load-serving entities with a peak load of 25 MW or greater and are directly connected to the bulk electric system or that are responsible entities as part of a required demand management (load-shedding) program; individual generating units that are 20 megavolt-amperes (MVA) or greater; generating plants with an aggregate MVA above 75; and transmission owners and operators with 100 kV or higher facilities.

In a separate notice of proposed rulemaking issued the same day, FERC proposed to extend the reliability standards to Qualifying Facilities (QF) above 20 MW, despite the fact that QFs are exempt from most FERC regulation.  Comments in this proceeding are due April 17, 2007. 

FERC Exercises New Natural Gas Civil Penalty Authority

FERC has approved a settlement agreement between its Office of Enforcement and Bangor Gas Company, LLC (Bangor Gas) requiring Bangor Gas to pay a civil penalty of $1 million for self-reported violations of FERC's shipper-must-have-title policy.  That policy requires shippers who transport natural gas using their own capacity to hold title to that natural gas.  The settlement represents the first time FERC has exercised the natural gas civil penalty authority granted to it by the Energy Policy Act of 2005.  That authority permits FERC to impose a penalty of up to $1 million per day per violation of FERC's rules, regulations, and orders issued under the Natural Gas Act.  In addition to the monetary penalty, the settlement requires Bangor Gas to file semi-annual reports with FERC's Office of Enforcement to ensure future compliance with FERC's natural gas transportation requirements, including the shipper-must-have-title policy.   

Senator Investigates Recent Natural Gas Price Volatility

Citing the "critical consumer protection issue" of natural gas price volatility, on February 6, Senator Jeff Bingaman (D-NM) sent letters to FERC Chairman Joseph Kelliher and Commodity Futures Trading Commission (CFTC) Chairman Reuben Jeffrey, posing a series of questions to both agencies about how they monitor gas futures trading on the New York Mercantile Exchange (NYMEX) and on the Intercontinental Exchange (ICE).  The Senator, who is the current chair of the Senate Energy and Natural Resources Committee, also asked for the agencies' cooperation in monitoring future market activity. 

At the heart of Senator Bingaman's concerns were price volatility seen at the end of January, as well as last fall's collapse of hedge fund Amaranth.  Amaranth, which had large positions in financial natural gas markets, lost hundreds of millions of dollars when it bet in the wrong direction on gas prices.  In the wake of the collapse, some at the company expressed concern that the markets had been subject to manipulation.  Senator Bingaman also cited a recent GAO report, which found that gas commodity prices have risen 190% since 1993 and that more of these costs are being passed on to end-use consumers. 

In his letter to Kelliher, Senator Bingaman asked how FERC can continue to find contract prices pegged to NYMEX price indices "just and reasonable" in light of this increased price volatility.  Senator Bingaman also highlighted the increased authority given to FERC by the Energy Policy Act 2005 to review transactions in financial markets, as well as the increased cooperation promised by FERC and the CFTC in an October 2005 Memorandum of Understanding.  The letter to CFTC focused additionally on whether ICE had been responsive to recent requests by CFTC for information related to the Amaranth collapse.

FERC Flexes New Civil Penalty Muscle

FERC issued orders January 18 exercising for the first time its expanded Energy Policy Act of 2005 penalty authority.  In each of five separate investigations, FERC blessed settlements that required the targets to pay substantial civil penalties ranging from $500,000 for an isolated two-day incident to $10 million for a broad pattern of Open Access Transmission Tariff (OATT) and Standards of Conduct violations. These penalties were assessed even though the violations resulted in little actual, financial harm to customers or to the markets.  The January 18 orders underscore FERC’s preference for negotiated settlements over litigation, and illustrate the importance the agency places on self-reporting of violations and cooperation with Office of Enforcement staff during audits and/or investigations.

The most serious of the violations were uncovered in investigations of PacifiCorp and SCANA.  Both companies self-reported behavior that included numerous violations of OATT requirements and proscriptions, and in PacifiCorp's case, FERC's Standards of Conduct.  In particular, both companies admitted to misusing network transmission service to support the utility’s or its affiliates’ off-system sales.  The PacifiCorp settlement also dealt with numerous instances in which PacifiCorp's merchant and transmission functions had improperly shared information, violating the Standards of Conduct.  PacifiCorp agreed to pay a $10 million civil penalty, and to contract for independent audits of its business practices, implement a compliance program, and submit quarterly reports to Enforcement on its compliance efforts.  SCANA agreed to a $9 million penalty, disgorgement of $1.4 million in profits, and repayment of $400,000 in transmission fees.  SCANA too agreed to implement an OATT compliance program.  While the civil penalties in both cases were quite high, FERC cautioned that, absent self-reporting in both cases, "the civil penalty sought would have been considerably higher."

The other three cases involved less pervasive violations.  Entergy, as a result of employee carelessness and system malfunctioning, lost several months of hourly Available Flowgate Capacity data, which violated FPA and FERC record retention requirements, and failed to comply with several OASIS posting requirements.  Entergy's OASIS system also responded erroneously to transmission service requests on several occasions.  Entergy agreed to pay $3 million ($1 million of which would go to a New Orleans charity) and implement going-forward compliance and reporting programs.  As for NorthWestern Corp., FERC found that it had failed on numerous occasions to respond timely (within 30 days) to transmission service requests.  One of its customers had called in a complaint to FERC's Enforcement hotline.  For the violations uncovered during FERC's investigation, NorthWestern agreed to pay $1 million and implement a two-year compliance program to ensure timely responses to service requests.  Finally, NRG Energy, Inc., agreed to pay $500,000 and implement a compliance plan, after self-reporting to the ISO-New England Market Monitor that one of its plant managers had intentionally misrepresented the availability of a generation unit that was under a Reliability Must-Run contract for a two-day period.

FERC Tinkers on Transmission Investment Incentives

Responding to concerns raised by state regulators, FERC closed out 2006 by amending its rules intended to induce investment in new transmission infrastructure.  FERC issued the original rule last July pursuant to EPAct 2005 (and the new FPA § 219), which decried a shortage of transmission investments and directed FERC to develop transmission incentives.  The original rule identified rate perquisites available to applicants that meet certain criteria.  While the incentives remain available to a broad range of investors, demonstrating eligibility has become more demanding. 

First, FERC clarified that its "nexus" requirement ─ that incentives must be tailored to meet the particular risks faced by the applicant ─ will be applied strictly, and will not be satisfied in every case.  Routine investments in the ordinary course of expanding an applicant's transmission system, for example, would be less likely to meet the nexus test than new projects presenting special challenges and encountering uncertain risks.  As opposed to the original approach, where the nexus test was applied to each incentive requested, now an applicant must demonstrate that the total package of incentives being applied for is tailored to address the demonstrable risks or challenges it faces.  In beefing up its nexus requirement, however, FERC declined to adopt a "but for" test ─ but for the incentives, the project would not be built ─ due to the difficulty of satisfying such a test.   

FERC also emphasized that it will not routinely grant an incentive ROE, and that any ROE it does grant will not always fall at the "top" of the zone of reasonableness.  In addition to justifying a higher ROE under the nexus test, an applicant must also justify where within the zone of reasonableness the return should lie.  FERC will continue to allow petitions for declaratory order seeking a specific ROE.  Finally, the new rule reaffirms the availability of an ROE incentive to transcos and to utilities that join or remain in ISOs and RTOs.   

Finally, the new rule seeks to alleviate state concerns that rebuttable presumptions, contained in the original rule, that would consider certain projects eligible for incentives, would not adequately measure whether the project would improve reliability or decrease congestion, as required by the FPA.  While FERC maintained a rebuttable presumption that a project is eligible for incentives if it results from a fair and open regional-planning process, or received state construction approval, if those processes do not consider whether the project ensures reliability or reduces congestion, then the applicant must independently validate that the project meets those criteria. 

Guidance on FERC Assessment of Civil Penalties

In an attempt to show it means business regarding its enhanced authority to assess civil penalties under the Energy Policy Act of 2005 (EPAct 2005), on December 21, FERC issued a statement of administrative policy detailing the procedures it will use in assessing civil penalties, but emphasized the continuing importance of negotiated settlements, which are not subject to the procedures.  In EPAct 2005, Congress authorized FERC to impose penalties of up to $1 million per day per violation, for violations of the statutes that FERC administers —  Parts I and II of the Federal Power Act (FPA), the Natural Gas Act (NGA), and the Natural Gas Policy Act (NGPA) —  and the rules, regulations, and orders issued pursuant to those statutes.  The December 21 policy statement complements a prior Policy Statement on Enforcement, issued in October 2005, which discussed the factors FERC would take into account in responding to violations and determining appropriate remedies, and emphasized the need for companies to create an internal "culture of compliance" and self-report violations.  [See FERC Explains Its Policy on New Penalty Enforcement.] 

FERC Chair Joseph Kelliher emphasized that FERC generally prefers settlement to litigation, and predicted that the majority of penalty decisions will likely be made through negotiated settlements.  Consequently, it is not entirely clear how often the civil penalty procedures will be put to use.  To the extent they are put to use, FERC explained that it will first provide notice describing a violation and the proposed penalty.  The targeted person or company will have a chance to respond and explain why the penalty should not be assessed.  Following the target's response or explanation:

• For violations of Part I of the FPA, if a final compliance order has been violated, then FERC will conduct an administrative hearing before an administrative law judge (ALJ); if no final compliance order has been violated, then an entity may choose between the ALJ hearing and an immediate assessment of the proposed penalty.
• For violations of Part II of the FPA, the entity may choose between a hearing before an ALJ or an immediate penalty assessment. 
• For violations of the NGA, FERC will require either a paper hearing or a hearing before an ALJ, depending on the circumstances involved, and will issue an order after considering an entity's response.  
• Finally, for violations of the NGPA, FERC explained that the NGPA does not provide for an on-the-record administrative hearing; rather, FERC will assess the penalties after considering the facts.

Once FERC issues a final order assessing the appeal, if the entity does not voluntarily pay the penalty within 60 days, FERC can institute a collection action in the appropriate United States district court.  At this point, proposed penalties are subject to de novo review by the district courts.  Entities assessed penalties may appeal final Commission decisions by following the usual appeal procedures, i.e., by filing a petition for review within the appropriate time to a U.S. Court of Appeal.

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. 

FERC to Electric Utilities and Qualifying Facilities: Presume This!

To address the energy shortages of the 1970s, the Public Utility Regulatory Policies Act was enacted to empower qualifying cogenerators or small power producers (from renewables) ― qualifying facilities or QFs ― to "put" their electric generation to an interconnected electric utility and charge the utility an avoided-cost rate, and also demand backup power from the utility.  Because the avoided-cost rate was often locked in at relatively high prices, utilities for years sough repeal or amendment of the "put."  In the Energy Policy Act of  2005, Congress agreed and directed FERC to end prospectively the "put" for post-October 8, 2005, power sales by QFs that are found to enjoy nondiscriminatory market access.

Responding to this directive, FERC originally proposed to end generically the "put" for all electric utilities participating in independent transmission system operations that offer auction-based day-ahead and real-time energy markets ― the so-called Day 2 markets of ISO New England, the Midwest ISO, the New York ISO and the PJM Interconnection.  But in an October 20 ruling, the agency retreated to a more nuanced approach that creates rebuttable presumptions as to when a QF enjoys nondiscriminatory market access and when it doesn't.

One presumption is that QFs of 20 megawatts or less do not have nondiscriminatory market access.  But for a QF larger than 20 megawatts the "put" presumptively ends if, on a utility purchaser's application, FERC finds the QF is connected to an open-access transmission system that can access a Day 2 market, a Day 1 (an auction-based real-time market only) RTO that also includes sufficiently competitive markets, or the functional equivalent of these.  New England, the Midwest, New York and PJM qualify as Day 2; pending implementation of scheduled new market redesigns, SPP and the California ISO will remain Day 1 (leaving to case-by-case determinations the question whether the markets are sufficiently competitive); and FERC deemed ERCOT a functional equivalent.  The larger QFs can rebut the presumption of nondiscriminatory access by showing that characteristics of how they operate ― for example erratic cogeneration available for sale or non-dispatchability, or where they operate ― for examples in proximity to a binding transmission constraint ― preclude market access.

The new rule provides not only for termination of the "put" in circumstances where a QF fails to rebut the presumption of nondiscriminatory market access, but also for its reinstatement where a QF later shows that the nondiscriminatory market access it once enjoyed is no longer accessible.   

FERC and DOE Lay Groundwork for Federal Transmission Corridors

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. 

FERC Finalizes Rule Promoting Transmission Investments; Grants Incentive Rates to AEP and Allegheny

On July 20, FERC issued its Final Rule implementing new transmission pricing provisions, aimed at creating new incentives for transmission investment and signaling an increasingly flexible transmission pricing policy.  After lamenting a sustained lack of investment in an aging transmission grid, in last year's Energy Policy Act of 2005 Congress directed FERC to develop transmission rates sufficient to induce investment.  FERC proposed incentive rates in a Notice of Proposed Rulemaking (NOPR) issued last November.  [See Rule Would Encourage Transmission Investment & Membership in Transcos & Transmission Organizations].  The Final Rule issued last week mostly adopts the NOPR.

Key provisions of the Final Rule include: 

• Incentive rates of return on equity for new transmission investment by public utilities (including both traditional utilities and stand-alone transmission companies, or transcos);
• Full recovery of prudently incurred construction work in progress;
• Full recovery of prudently incurred pre-operations costs;
• Full recovery of prudently incurred costs of transmission facilities that become abandoned or canceled;
• Use of hypothetical capital structures;
• Accumulated deferred income taxes for transcos;
• Adjustments to book value for transco sales/purchases;
• Accelerated depreciation;
• Deferred cost recovery for utilities precluded by retail rate freezes from passing through the costs of new transmission investments; and
• A continuation of the sometimes controversial approach of approving higher rates of return on equity for utilities that join and/or continue to be members of transmission organizations, including (but not limited to) RTOs and ISOs.

Public utilities must still obtain FERC approval to reap the benefit of any of these incentives.  The Final Rule also adopted a reporting requirement requiring public utilities that have received incentive rate treatment for specific projects to submit information regarding the level of actual transmission investment.   

In addition to the new rule, FERC applied it in granting investment incentives to American Electric Power Co. ("AEP") and Allegheny Energy, Inc., for their proposed projects in the Mid-Atlantic region.  AEP's proposed 765-kV transmission line would stretch 550 miles between New Jersey and West Virginia, while Allegheny's proposed 500-kV line would link southwestern Pennsylvania and Virginia.  For both projects, FERC approved rates of return on equity at the "high end of the zone of reasonableness."

Firm Transmission to Be Available for Terms of 10 Years in Organized Markets

FERC has adopted a final rule requiring organized electricity markets to offer load servers long-term firm transmission rights (FTR) in existing transmission capacity for a minimum of 10 years [Order No. 681].  In the Energy Policy Act of 2005 (EPAct 2005) Congress directed FERC to implement a new § 217(b)(4) of the Federal Power Act, which obligates FERC to use its authority to meet the "reasonable needs" of load serving entities to meet their long-term service obligations.  The new rule answers that directive and will likely become effective in late August.   

FTRs are used to manage the price risk of congestion charges in organized markets that manage congestion using locational marginal pricing (LMP).   The virtue of LMP is that it allows all generation resources in a market (as opposed to only the system operator’s resources) to participate in redispatch to manage congestion.  The disadvantage is that LMPs are ex post and can be volatile.  An FTR hedges volatility and uncertainty by flowing to its holder congestion revenues that largely (if not completely) offset LMP congestion charges.  Until now, however, FTRs have generally been available only for terms up to one year.   As a consequence, transmission customers in organized LMP transmission markets have been denied long-term transmission price certainty that is otherwise available to network and point-to-point customers in open-access markets.  FERC’s new requirement that all organized markets offer long-term FTRs in existing transmission capacity is directed at curing that deficiency.  This is significant since the absence of firm long-term transmission arrangements have deterred many power customers from committing to long-term power supply arrangements.    

While FERC originally proposed eight guidelines for designing and administering long-term FTRs, the final rule adopts only seven.  Long-term FTRs are to   

·        specify a source, a sink, and a quantity;

·        hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified;

·        be made available to any party that pays for upgrades or expansions that create the underlying transmission capacity;

·        be offered for terms (and/or with renewal rights) sufficiently long to meet the needs of load-serving entities to hedge long-term power supply arrangements entered into in order to meet a service obligation;

·        be allocated to load servers before customers lacking a load service obligation;

·        be assignable to the successor to a load server; and

·        be allocated initially with no requirement that recipients participate in an auction. 

The operator of an organized market required by the rule to offer long-term FTRs is accorded reasonable discretion to determine how many long-term FTRs it will make available and how many it will instead offer for shorter terms. 

In the one jettisoned guideline, FERC had proposed a preference for load servers with long-term power supply arrangements over those with only short-term power supply arrangements.  Many had objected to that preference on the ground that determining what constituted a long-term power supply would impose an unwarranted burden on the market operator.  FERC agreed and eliminated this preference in favor of a more general preference that makes the long-term FTRs available to all load servers before customers lacking a load service obligation.  In the final rule, FERC also maintained its current practice of requiring that FTRs be made available to those who pay for transmission upgrades or expansions that create the capacity underlying the FTRs, regardless of load service obligation.   

RTOs and ISOs must revise their tariffs in accordance with the new rule within 180 days of the rule's publication in the Federal Register, or alternatively explain how their existing tariffs already satisfy the long-term FTR requirement.  As PJM has already submitted to FERC a proposal for offering long-term FTRs [link to blog article on this], it will now need to review that proposal to ensure it conforms to the seven guidelines of the final rule.  [FERC Docket No. RM06-8]

FERC Proposes Rules for Federal Eminent Domain in National Interest Electric Transmission Corridors

In a June 16 notice of proposed rulemaking (NOPR) FERC details how it proposes to implement its new authority under section 216 of the Federal Power Act, added by EPAct 2005, to issue federal permits for the construction of electric transmission facilities in Department of Energy (DOE)–designated National Interest Electric Transmission Corridors (NIETCs).  Previously, only states could authorize the taking of private property for electric transmission rights of way.  Public comments on the NOPR must be submitted by August 25, 2006. 

EPAct 2005 directed DOE to study electric transmission congestion and designate NIETCs.  Projects slated for NIETCs will receive special attention during review procedures.  DOE expects to finalize this study by mid-August.  [DOE Congestion Study to Identify National Interest Electric Transmission Corridors]  FERC, in turn, can issue permits to construct or modify transmission facilities in any DOE-designated NIETC provided that the state where the facilities would be located lacks the authority to site the facilities (or the applicant does not qualify for siting approval there), or the state either withholds approval for more than one year or attaches unreasonable or uneconomical conditions to its approval.  FERC must also find that the proposed project would be in the public interest, further national energy policy, and be used for interstate power transmission. 

FERC's proposed rule implements both authorities that EPAct 2005 granted directly to FERC and other authorities that DOE has delegated to the agency.  The proposed rule would require permit applicants to establish Participation Plans that facilitate stakeholder (e.g., landowner, local governments) involvement in the permitting process.  In addition, FERC proposes an extensive and mandatory pre-filing process, along the lines of what it requires for natural gas pipeline projects.  FERC intends that the majority of the heavy lifting, including required studies and meetings with other reviewing agencies and designation of at least three potential contractors for preparing environmental impact statements or assessments, be accomplished during this pre-filing process in order to streamline later application preparation.  Monthly status reports required as part of pre-filing, for instance, would carry some bite:  failure to submit a report, respond to a request for more information, or progress sufficiently toward permit issuance would allow FERC to terminate the pre-filing (without prejudice to refiling). 

The proposed rule also details the information FERC would require as part of the application, as well as general conditions that FERC would impose all permits issued under the new rule; specific conditions may be imposed on individual projects.   

FERC has also proposed to modify its rules implementing the National Environmental Policy Act (NEPA) to include electric transmission projects among the activities for which environmental information must be provided to the agency and for which FERC will complete an environmental assessment or environmental impact statement.  In addition, FERC's new NEPA rules would provide for specific environmental filing requirements (resource reports) for electric transmission facilities.   

FERC Lessens Burden of Merger, Holding Company Rules

In two April 24 orders, FERC attempts to coordinate its overlapping merger and utility holding company rules.  FERC also aims to strengthen its protection of customers from risks perceived to arise from repeal of the Public Utility Holding Company Act of 1935 (1935 Act).  Driving these rules, FERC explains, is the agency's desire to stimulate investment in the electricity sector and accommodate public utilities' day-to-day financial operations. 

In Order No. 667-A, FERC tweaked its December 2005 Order No. 667, which implemented the Public Utility Holding Company Act of 2005 ("PUHCA 2005") primarily a recordkeeping statute that replaced the 1935 Act.  As originally proposed, these recordkeeping requirements were criticized as an unreasonable burden.  The April 24 order amplifies exemptions to the recordkeeping requirements.  For example, holding companies that own only QFs, EWGs, or FUCOs, while meeting the definition of a "holding company," would nevertheless be exempt from the recordkeeping requirements.  FERC also affirmed an exemption for holding companies that operate primarily within a single state, and explained that a company would qualify for this exemption if no more than 13% of its revenues from public utility operations were derived from outside that state.

FERC took the opportunity in Order No. 669-A to simplify its merger rules under Federal Power Act § 203.  FERC extended to domestic mergers the four-part test, which heretofore had applied only to foreign acquisitions.  A utility will now be required to verify that a transaction does not result in:  (1) transfer of facilities between traditional public utility associate companies with captive customers and associate companies; (2) new issuances of securities by traditional public utility associate companies with captive customers for the benefit of associate companies; (3) new pledges or encumbrances of assets of traditional public utility associate companies with captive customers in favor of associate companies; and (4) new affiliate contracts between non-utility associate companies and traditional public utility associate companies with captive customers.  If merger applicants cannot make these showings, then they may withdraw from the merger or undertake a more detailed demonstration that the transaction nonetheless would be consistent with the public interest.  FERC also clarified that companies owning only QFs, EWGs, or FUCOs are authorized to acquire securities of additional QFs, EWGs, or FUCOs.  Order No. 669-A also grants banks and financial institutions blanket authorization for the acquisition of securities  in connection with their fiduciary, underwriting, and hedging activities.  In addition, FERC expressed support for public utilities' participation in holding company intra-system cash management systems, and simplified its regulations to ensure that public utilities possess blanket authorization to acquire securities in connection with such money pools.

“Let It Be Me,” NERC Tells FERC

Within days of FERC clarifying final elements of its Electric Reliability Organization (ERO) rule, the North American Electric Reliability Organization (NERC) filed with the agency its long-awaited ERO application.  On February 3, FERC issued its final rule establishing the criteria it will use to select an ERO, as mandated in the Energy Policy Act of 2005.  FERC Rule Allows Regional Entities to Propose and Enforce Reliability Standards]  But the rule didn’t go into effect pending a FERC decision on how to handle conflicts between the ERO's reliability standards and FERC-approved tariffs.  The revised rule provides that if FERC finds a conflict to exist, it may offer an RTO or affected utility an opportunity to submit a revised tariff, or FERC itself may modify the tariff itself under its Federal Power Act authority. 

On April 4, NERC submitted to FERC its application for recognition as the US ERO, along with over 100 proposed reliability standards that it would enforce under its new designation.  [NERC ERO Application]  Simultaneously, NERC submitted applications to Canada's National Energy Board and various Canadian provinces to be recognized as the reliability coordinator in Canada.  Little doubt exists that NERC will be certified as the US ERO since it has served in essentially that capacity since the 1960s.  But robust debate is expected as to whom the ERO’s reliability standards will apply, as some EPAct provisions exempt entities that engage solely in power distribution.  In addition, the extent of the ERO’s authority, if any, to delegate to regional councils standard-setting powers is likely to be contentious, with regional entities vying for region-specific standards and FERC wanting to maintain uniform national standards.   

Legislator Questions Value of Post-PUHCA Consolidations to Ratepayers

National Grid USA (National Grid) announced its proposed acquisition of Keyspan, the largest distributor of natural gas in the Northeast and New York state's largest electricity generator.  At the completion of the merger, National Grid will have a combined 3.4 million natural gas customers and 8 million electric consumers in the New York and New England area.  Keyspan will continue to operate in its own name, although it will be a wholly owned subsidiary of National Grid.  The companies have targeted to close the transaction by early 2007.

This announcement comes on the heels of Exelon's purchase of PSEG, Mid-American's purchase of PacifiCorp, Duke Energy's planned acquisition of Cinergy, and the merger of  Florida-based FPL Group with Constellation Energy ― all made feasible by last year's repeal of  the Public Utility Holding Company Act of 1935 (PUHCA).  (See Energy Policy Act of 2005 Hands FERC a Long To-Do List, FERC Pares Back Accounting & Record Keeping, but Retains Strict Transfer Pricing for Public Utility Holding Companies under PUHCA 2005 and Congress Enacts Energy Bill)  Some legislators, such as Rep. Edward Markey, have begun to question whether these consolidations will benefit utility ratepayers, and have expressed concern that FERC may not properly scrutinize utility mergers and acquisitions, even though FERC was given authority to do so in connection with PUHCA's repeal.  Rep. Markey has called on the states to strengthen state laws concerning such mergers because due to the repeal of PUHCA, the Securities and Exchange Commission no longer has the authority to review debt financing associated with such transactions.

DOE Gears Up to Receive Comments on National Interest Electric Transmission Corridors

Recommendations to the Department of Energy (DOE) on whether and how to designate particular geographic areas exhibiting transmission constraints as National Interest Electric Transmission (NIET) Corridors must be submitted by March 6, 2006.  NIET Corridor designations are intended to facilitate the construction of new transmission facilities along these corridors.  Section 1221 of the Energy Policy Act of 2005 gives DOE the authority to conduct a study on transmission congestion and to designate particu