FERC, CFTC, and State Energy Law Developments

On April 14, the US Court of Appeals for the DC Circuit issued its opinion in Emera Maine v. FERC, vacating and remanding FERC’s Opinion No. 531 in which FERC established a just and reasonable rate of return on equity (ROE) for transmission-owning utilities in the Northeast (NETOs) and adopted a new methodology for determining the ROE for FERC-jurisdictional electric utilities.

The DC Circuit found two grounds for sending the case back to FERC. First, because the proceeding began through a complaint filed under section 206 of the Federal Power Act (FPA), the court found that FERC failed to find that the existing ROE for the NETOs was unjust and unreasonable before proceeding to set a new just and reasonable ROE. Second, the court found that FERC had not adequately justified its determination of the new just and reasonable ROE.

The court’s decision creates significant uncertainty in FERC ROE policy.

At its last open meeting on Jan. 19, 2017, the Federal Energy Regulatory Commission (FERC) issued a policy statement that serves to reaffirm FERC’s efforts to encourage the development of electric storage resources. Of all the publications from FERC so far in calendar year 2017, this policy statement is one of the most important for entities in the electric power sector.

Read the full article.

Energy partner Ken Kulak recently participated in an Energy Policy Now podcast produced by the Kleinman Center for Energy Policy at the University of Pennsylvania. During the podcast, Ken discussed the Federal Energy Regulatory Commission’s (FERC’s) Notice of Proposed Rulemaking (NOPR) on electric storage, highlighting several issues raised in the NOPR regarding the development of “participation models” for electric storage and distributed energy resources in organized electricity markets. Comments to the FERC NOPR are due by February 13, 2017.

The White House’s newly released National Electric Grid Security and Resilience Action Plan contains dozens of directives to various federal agencies for enhancing the electric grid’s resilience in the face of cyber threats, physical attacks, and natural disasters. Many of the directives build on different programs that federal agencies already run, but for the first time, this action plan synthesizes those disparate initiatives and focuses them on three goals: protecting the grid’s vulnerabilities, improving responses to contingencies, and building a more resilient system.

Notably, the action plan realizes that many of these directives can only be achieved with public utilities’ participation and that cost recovery of investments for grid resiliency is essential if the government expects significant private investment to address the existing system vulnerabilities.

Read the full LawFlash: White House Releases Checklist to Improve Grid Resiliency.

In a final rule issued on September 22, the Federal Energy Regulatory Commission (FERC) established requirements for certain entities to assess the vulnerability of their transmission systems to geomagnetic disturbance (GMD) events. Such events occur when the sun ejects charged particles that interact and cause changes in the earth’s magnetic fields.

Reliability Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) sets requirements for certain transmission and generator owners, planning coordinators, and transmission planners to assess the vulnerability of their systems to a benchmark GMD event, described as a “one-in-100-year” event. Those entities are required to develop

  • system models necessary to complete the vulnerability assessments at least once in every 60 calendar months and
  • criteria for acceptable steady state voltage performance during a benchmark GMD event.

On July 21, FERC modified its pro forma Small Generator Interconnection Agreement (SGIA) to require newly interconnecting small generating facilities to ride through abnormal frequency and voltage events and not disconnect during such events. Under the final rule, each public utility transmission provider that has an SGIA must submit a compliance filing within 65 days of the date that the final rule is published in the Federal Register to demonstrate that it meets the requirements set forth in the rule.

The final rule also allows entities to seek “independent entity variations” from the revisions to the pro forma SGIA. Additionally, the Commission stated that transmission providers that are not public utilities would have to adopt the requirements of this final rule as a condition of maintaining the status of their safe harbor tariffs or otherwise satisfying the reciprocity requirement of Order No. 888.

The Commission did not adopt specific frequency and voltage ride-through parameters, but instead will allow for the development of appropriate system-specific standards, which may be based on work by recognized standards-setting bodies such as the Institute of Electrical and Electronics Engineers (IEEE).

On November 12, the Commission resolved two certified questions and held that retail ratepayers have the right to file complaints and protest transmission rates and wholesale power sales rates when some portion of the rates will be flowed through to their retail bill.[1] This issue arose after an individual, who is an end-use customer, challenged transmission formula rate inputs, i.e., costs that flow through to the customer’s retail electric bill. These inputs go to the transmission of electric energy in interstate commerce and not local distribution. The customer asserted that she will pay a portion of the transmission rate when it is flowed through her retail bill, which the Commission found to be injury in fact.

The Commission noted that its ruling is consistent with prior holdings in which courts and the Commission concluded that protecting consumers is one of the Commission’s primary objectives.[2] The plain language of section 306 of the Federal Power Act (FPA) explicitly authorizes any person to file a complaint with the Commission. The Commission recognized that FPA section 201 generally limits its jurisdiction to the transmission and sale of electric energy at wholesale in interstate commerce, but noted that section 201 does not limit participation in Commission proceedings. Additionally, it has consistently ruled that FPA section 206 gives indirect/retail customers standing before the Commission. The Commission also found that allowing retail customers to challenge transmission and wholesale power sales rates does not violate principles of federalism.

[1] Am. Elec. Power Serv. Corp, 153 FERC ¶ 61,167 (2015).

[2] Id. at P 17 (citing cases including PATH, 140 FERC ¶ 61,229 (2012), Pub. Sys. v. fERC, 606 F.2d 973 (D.C. Cir. 1979), NC WARN, 151 FERC ¶ 61,079 (2015), Ass’n of Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Op., Inc., 149 FERC ¶ 61,049 (2014), and S. Union Gas Co. v. Natural Gas Co., 71 FERC ¶ 61,198 (1995)).

FERC found that a storage device using a utility’s distribution system in charging mode should share in the costs of the distribution system.

On June 18, the Federal Energy Regulatory Commission (FERC) upheld an earlier order allowing Commonwealth Edison Company (ComEd) to assess a wholesale distribution charge on Energy Vault, LLC (Energy Vault), which owns a battery energy storage facility directly interconnected to ComEd’s distribution system.[1] Because Energy Vault will use ComEd’s distribution system to charge its batteries, FERC concluded that that it would be appropriate for Energy Vault to be assessed the distribution charge.

ComEd assesses a wholesale distribution charge on non-generator customers connected to its distribution system that take distribution service. This wholesale distribution charge is a weighted average carrying charge that is calculated based on the distribution facilities that will be used in providing wholesale distribution service. Generator customers connected to the distribution system are not subject to this wholesale distribution charge because ComEd had previously concluded that reverse flows from generators may benefit its system by reducing congestion and line loading in some conditions.

FERC issued two decisions on October 16 involving its policies for determining the return on equity (ROE) for transmission-owning members of ISO New England (ISO-NE) and the Midcontinent Independent System Operator, Inc. (MISO). Opinion No. 531-A confirms that gross domestic product (GDP) growth should be used to approximate long-term growth rates as part of FERC’s recently adopted two-step discounted cash flow (DCF) methodology.[1] The decision echoes FERC’s tentative finding in Opinion No. 531 regarding the use of GDP in the two-step DCF.[2] In a separate order, FERC set for hearing a complaint that alleged MISO transmission-owning members’ 12.38% base ROE is unjust and unreasonable.[3]

Across the United States, there is a growing interest in distributed generation, which produces electricity in small quantities near the point of use, rather than in large amounts in a few places. Yet, distributed generation presents certain challenges for investor-owned utilities, independent power producers, and state and federal regulators. The integration of distributed generation resources onto the electric grid on a wide scale may dramatically impact utility investment and operations.

During this one-hour webinar, our presenters discussed distributed generation resources, their impact on utilities, and relevant policy considerations.

Topics included:

  • The benefits of distributed generation
  • The financial effect of distributed generation on utilities and customers
  • Grid operation and security issues
  • Jurisdictional and regulatory issues

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