FERC, CFTC, and State Energy Law Developments

On August 15, the U.S. Court of Appeals for the District of Columbia Circuit rejected the challenges filed By various utilities, industry groups, and state commissions that claimed that the Federal Energy Regulatory Commission (FERC or the Commission) overstepped its authority when promulgating Order No. 1000.[1] The court’s decision in South Carolina Public Service Authority v. FERC,[2] which FERC Chairman Cheryl LaFleur hailed as “critical to the Commission’s efforts to support efficient, competitive, and cost-effective transmission,”[3] substantially strengthens FERC’s ability to establish the structures necessary to encourage and facilitate competitive transmission planning and development.

On July 17, the Federal Energy Regulatory Commission (FERC) proposed to approve[1] a new mandatory reliability standard that would require electric utilities to protect their transmission facilities and control centers against physical threats. Although FERC did not take issue with most of the language in the CIP-014-1[2] standard proposed By the North American Electric Reliability Corporation (NERC), FERC did express concern over the ability of utilities to identify their own critical facilities, even when that determination is subject to third-party review. To address that concern, FERC proposed to direct NERC to modify the standard so that FERC, or other appropriate federal agencies, could direct electric utilities to add additional facilities to their list of facilities that need physical security protections.

On June 19, the Federal Energy Regulatory Commission (the Commission) issued Opinion No. 531,[1] which affirmed in part and denied in part an initial decision[2] on the return on equity (ROE) for the public utility transmission-owning members of ISO New England (ISO-NE). In addition, the Commission announced a modification to its policies regarding ROE calculation for electric utilities.

Opinion No. 531 tentatively determined that the “just and reasonable base ROE” for the ISO-NE transmission owners would be 10.57%, which is halfway between the midpoint and the maximum point of a “zone of reasonableness” based on a range of cost-of-equity estimates. The Commission determined that the base ROE should be set above the midpoint because of the unusual capital market conditions and other indicators, including a review of state-approved ROEs, which demonstrate that simply setting the base ROE at the midpoint of the zone of reasonableness would be insufficient to attract capital for new investment in transmission.

In a Notice of Proposed Rulemaking issued on June 19, FERC proposed to approve a new Reliability Standard—MOD-001-2 (Modeling, Data, and Analysis)—to govern the calculation of the various components of Available Transfer Capability (ATC), including Total Transfer Capability, Existing Transmission Commitments, Transmission Reliability Margin, and Capacity Benefit Margin. If approved, MOD-001-2 will replace multiple existing Reliability Standards that currently address these issues, including MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2.

FERC has approved a new Reliability Standard to address Geomagnetic Disturbances (GMDs). EOP-010-1 (Geomagnetic Disturbance Operations) is the first in a set of Reliability Standards addressing the threat of GMDs to bulk-power system reliability. FERC’s concern with GMDs has been that they can create geomagnetically induced currents in transformers, which can, in turn, increase the absorption of reactive power, create harmonics, and cause transformer spot-heating. Ultimately, the loss of reactive power this causes could result in voltage instability, relay misoperations, and equipment damage.

New proposals aim to reduce regulatory burden on generation developers.

On May 15, the Federal Energy Regulatory Commission (FERC or the Commission) issued a Notice of Proposed Rulemaking (NOPR)[1] that proposes to relieve some of the existing regulatory burdens on generator-owned interconnection facilities. The relief FERC proposes includes the following:

  • Allowing a generation developer to conditionally keep control of certain interconnection-overbuild or excess capacity for a discrete period of time
  • Limiting the existing presumptive right of third parties to commandeer access to interconnection facilities
  • Eliminating certain related advance filing and approval requirements

The Commission now subjects Interconnection Customer’s Interconnection Facilities (ICIF), also known as generator tie lines, to extensive FERC transmission regulation, including compliance with Open Access Transmission Tariff (OATT), Open Access Same Time Information System (OASIS), and Standards of Conduct (SoC) requirements.[2] Most significantly, FERC presumes in most cases that a third party that desires transmission access may obtain rights to use another entity’s ICIF, as ICIF owners must make excess capacity available to third parties upon request unless they can compellingly demonstrate that they must reserve for themselves the currently available excess capacity for future generation development. Although many ICIF owners have been able to seek waiver of open access requirements by demonstrating a need for the full capacity of their ICIF, a formal waiver filing is typically required, and the results before FERC are far from assured. Typically, the ICIF may be the only transmission assets owned by the generator, and third-party requests to use ICIF capacity are rare. The Commission’s proposed rule would presume owner-only access for an initial five-year period.

At its May open meeting, the Federal Energy Regulatory Commission (FERC) softened its approach to considering state law rights of first refusal in Order No. 1000 regional transmission planning. This change suggests a new openness to the implications of the legal limitations unique to various states when considering Order No. 1000 compliance proposals, and more closely matches the FERC-directed federal planning structure to the restrictions on transmission development that also exist throughout the United States. More broadly, it may also represent a move By FERC to provide greater deference to the proposals developed By each region. However, given the thorny legal issues presented in the compliance filings still awaiting a ruling, whether this represents a decisive shift remains to be seen.

In a Notice of Proposed Rulemaking issued on September 20, 2012, FERC proposed to approve the Northeast Power Coordinating Council’s (NPCC’s) Regional Reliability Standard on Underfrequency Load Shedding (UFLS). The proposed PRC-006-NPCC-1 Regional Reliability Standard (Regional Standard) would address declining system frequency events in coordination with the existing continentwide PRC-006-1 UFLS Standard.

On May 17, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No. 1000-A, upholding its Order No. 1000 reforms to transmission planning and cost allocation.[1] In Order No. 1000-A, the Commission (1) upheld the minimum criteria that a regional and interregional transmission planning process must satisfy, and reiterated general principles for cost allocation; (2) upheld its decision to remove from Commission-approved tariffs and agreements any federal right of first refusal for transmission facilities selected in a regional or interregional transmission plan for purposes of cost allocation; and (3) did not alter or otherwise extend the deadlines for Transmission Providers to submit compliance filings implementing Order No. 1000. Accordingly, each public utility Transmission Provider must submit a regional Order No. 1000 compliance filing By October 11, 2012. Compliance filings for interregional transmission coordination and interregional cost allocation are due on April 11, 2013.

At FERC’s open meeting on April 19, 2012, FERC approved several orders addressing core aspects of Reliability Standards compliance, including cybersecurity Reliability Standards, compliance registration, and contingency planning issues. The newly approved cybsersecurity Reliability Standards significantly increase the scope of facilities subject to those requirements, the compliance registration decisions clarify the jurisdictional boundary between distribution and transmission facilities, and the planning orders represent a rejection of NERC’s approach to planning for firm load loss following a single contingency.