Energy Legal Blog

FERC, Industry Exchange Views on Enforcement

Two years after Congress granted FERC enhanced enforcement authority in the Energy Policy Act of 2005 and FERC issued its Policy Statement on Enforcement, and following the first year in which FERC has acted on this authority, FERC this month held a technical conference to discuss how it is implementing its new authority.  The conference revealed a gap between how FERC understands and is implementing its enforcement authority and an industry that is uncertain what is expected of it and fearful of the penalties it could unwittingly incur.  

In anticipation of the conference, a coalition of seven trade groups representing the electric and natural gas industries submitted a white paper highlighting concerns with FERC's implementation of its enforcement authority.  The coalition urged FERC to ensure that penalties fit the infraction.  It also warned FERC not to enforce against legitimate market behavior. 

In a statement issued prior to the conference, FERC Chairman Kelliher responded to the white paper and tried to clarify FERC's approach to implementation of its enforcement authority, disclosing that FERC intended to focus on punishing violations that cause the most serious harm or entail great risk of serious harm, violations of core regulatory requirements, and companies with weak compliance programs.  He cited FERC staff's report tallying the 64 enforcement investigations conducted in the last two years to argue that FERC has exercised this authority fairly, pointing out that of those, 47 concluded with no sanctions imposed and the remainder resulted in 13 settlements involving civil penalties and two show-cause orders.  Kelliher touted the value of self-reporting, and clarified that FERC will consider both actual and potential harm as the most important factor when determining a penalty. 

Parties Submit Joint Settlement of Pacific Intertie Dispute

On November 21, PacifiCorp, Pacific Gas and Electric Company (PG&E), the California Independent System Operator (CAISO), and several others proposed to FERC an uncontested settlement that would resolve disputes over a 94-mile segment of the Pacific AC Intertie (PACI) transmission line between Oregon and northern California.  Uniquely, the 94-mile line at issue is jointly owned by two utilities, one, PG&E,  inside the CAISO, and the other, PacifiCorp, outside of it.  Under the proposed settlement, PacifiCorp and PG&E agreed to share equally the transmission capacity over the PACI between Malin, Oregon and Round Mountain, California, with PacifiCorp eventually providing service on its portion of the line under its open-access transmission tariff (OATT).

The dispute over the PACI began earlier this year.  The two 500 kV lines that comprise the PACI are co-owned by several parties.  PacifiCorp owns the northern half of the 94-mile segment on the eastern line, and PG&E owns the southern half of that segment and has turned operational control of its capacity over to the CAISO.  Since 1967, PacifiCorp had leased its share of the capacity for a low, fixed amount to several California utilities under a 40-year agreement.  Those utilities, in turn, placed PacifiCorp's portion of the line, along with PG&E's portion of the line, under the CAISO's operational control. 

With the capacity lease set to expire by its terms in July 2007, PacifiCorp filed a notice of termination in May, and informed FERC that it intended to begin to offer service over its 47-mile segment under its OATT.  This filing drew opposition from California utilities, the California Public Utilities Commission, and the CAISO.  PG&E in turn proposed revisions to the operating agreements for the line.  In July, FERC ruled that neither PacifiCorp's nor PG&E's proposals had been shown to be just and reasonable and convened a paper hearing to sort out the details. 

With the December 31 end of the suspension period fast approaching, the parties agreed that PacifiCorp and PG&E would "swap" portions of the capacity each owns under a 20-year agreement, such that each party will have rights to half of the capacity on the entire 94-mile path.  PacifiCorp also agreed to lease a portion of its capacity back to PG&E for a ten-year period, with some capacity becoming available under PacifiCorp's OATT beginning in 2012.  PacifiCorp and the CAISO also filed a joint operating agreement for PacifiCorp's share of the line, which continues to provide for CAISO operation of the capacity.  Other agreements relating to the operation of the California-Oregon Interface were also modified to reflect the settlement arrangements, and changes were made to PG&E's Transmission Owner tariff to implement cost recovery under the ten-year lease.  The settlement will thus compensate PacifiCorp for use of its portion of the line, while keeping the capacity within the CAISO's operational control.  The Commission has yet to act on the settlement agreement, and will need to do so by the end of the year in order for the new arrangements to take effect when the existing arrangements expire.

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.

EPA Rulemaking Will Provide Guidelines for Underground CO2 Storage

The Environmental Protection Agency has announced it is preparing a rulemaking to develop guidelines for permanent underground storage of carbon dioxide.  Underground sequestration of carbon may be a valuable tool for combating climate change, as it complements usage of fossil fuels such as coal that are widely available but also relatively high in carbon content.  The potential success of carbon sequestration and storage, however, depends on resolution of numerous technological challenges, including means for separating out the carbon from fossil fuels and transporting it to and storing it in secure underground locations.

The EPA will evaluate the potential impact of underground carbon storage on health, safety and the environment, including underground sources of drinking water.  The agency stated that rules are needed to determine what parties have responsibility and liability for storage of carbon dioxide.  The EPA’s timeline is unlikely to provide much near-term guidance, as its proposed rules would appear in mid-2008 and final rules not until 2010 or later.  The proposed rules will not address the high-profile issue of who would get credit for any reductions in carbon emissions related to reduced emissions or underground storage of CO2. 

Energy Expands Loan Guarantee Program, Picks 16 Pre-Applications for Further Analysis

FERC, NERC Flesh Out ERO Operations, Penalties, Disclosures & Budgets

Five months after FERC authorized mandatory Reliability Standards to go into effect last June, it  is now sorting out to whom the Standards apply.  It is also slogging through issues of organization and management of NERC as the Electric Reliability Organization (ERO).   

Application of Reliability Standards 

Among the issues being debated are when a participant on the electric power grid sufficiently impacts grid operations to require registration with a Regional Entity and to what extent pure power marketers should be subject to Reliability Standards.

On October 18, 2007, FERC remanded to NERC its determinations that the Florida Reliability Coordinating Council properly included Mosaic Fertilizer, LLC and City of Tampa, Florida on its compliance registry.  Mosaic and Tampa appealed their registration to NERC and then to FERC.  FERC determined that NERC did not adequately show that the either was properly registered and, in any event, failed to respond adequately to arguments against registration. 

Penalties, Budget & Business Plan

The back-and-forth between FERC and NERC to define the ERO continues.  FERC issued an order October 18 directing NERC to clarify that the maximum penalty that it or a Regional Entity could impose for violation of a Reliability Standard is $1 million per violation, per day, consistent with the Federal Power Act, and to clarify how it would address specific situations that do not fit the one-violation, one-day fact pattern.  FERC generally accepted NERC's compliance filing on these issues, and directed small follow-up clarifications to the proposed sanctions language.  Alternative situations will be handled as follows:  repeated violations during a single day may result in a $1 million penalty  for each violation; NERC will amend Reliability Standards requirements measured as an average over time to specify the minimum period in which a violation could occur and how to determine when a violation arises; and for requirements of Reliability Standards that involve discrete events that are measured only periodically or are reported by exception, a violation arises when that event occurs and continues until it is cured.

In response to FERC's request that NERC describe how it will process requests for information, NERC clarified that the requestor must explain the need for the information and how it will be used.  NERC clarified that requests would be met so long as they were not frivolous, too-broad or unreasonable, and that the requestor's description of the anticipated use of the information would not limit the use of the information once disclosed.  FERC accepted these clarifications.  NERC also proposed to include a new section 1600 in its rules of procedure, to establish a process for NERC or Regional Entities to issue requests for data or information needed to fulfill their obligations.  

Also on October 18, 2007, FERC accepted NERC's proposed budget and business plan for 2008, including the budgets and business plans for each of the eight regional entities and the Western Interconnection Regional Advisory Body.  FERC noted that it plans to compare proposed budgets to actual expenditures, and will require NERC to provide a true-up for itself and each Regional Entity by April 1 of each year.  FERC also directed several compliance filings with regard to the Regional Entities' proposed budgets and business plans, focusing especially on inconsistencies between the Regional Entities' income statements and their business plans, and on its concern about the adequacy of separation and independence of the SPP Regional Entity from the SPP RTO.