FERC, CFTC, and State Energy Law Developments

As evidence that cyberattacks continue to threaten electric infrastructure in the United States, a report issued on December 14 by cybersecurity firm FireEye indicates that critical infrastructure industrial control systems (ICS) could be susceptible to a new type of malware. FireEye reported that the malware—dubbed “TRITON”—triggered the emergency shutdown capability of an industrial process within a critical infrastructure ICS. This is not the first time that hackers have successfully targeted ICS. In 2013, hackers believed to be operating on behalf of a state-actor managed to take partial control of the Bowman Avenue Dam near Rye Brook, New York. More recently, reports emerged this past summer that hackers gained access to the operational grid controls of US-based energy firms. Because of the destructive potential of these types of breaches, critical electric and other utility infrastructure will remain highly-prized targets for future cyberattacks.

As the pace of reported cyber attacks on ICS continues to pick up, scrutiny of electric utilities’ compliance with the Critical Infrastructure Protection (CIP) reliability standards by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) is likely to increase. It is highly likely that electric utilities will receive data requests or informal outreach from FERC or NERC in the near future to determine whether those utilities have similar equipment that could be exploited, and if so, what steps they have taken to mitigate the threat. Even in the absence of such requests, these events provide a good opportunity for electric utilities to test the sufficiency of their CIP compliance programs in identifying and remediating such threats.

In an admonishing response letter issued December 8, US Secretary of Energy Rick Perry granted the Federal Energy Regulatory Commission’s (FERC) request for a 30-day extension to consider final action on its Proposed Grid Reliability and Resiliency Pricing Rules. The proposed rules, if adopted, could provide economic support to coal and nuclear generation in organized markets.

FERC had emphasized in its request that extra time is needed to provide adequate opportunity for recently sworn-in Chairman Kevin J. McIntyre and Commissioner Richard Glick to consider the voluminous record in the proceeding that includes more than 1,500 comments in response to FERC’s solicitation for public comment on the proposed rules. Mr. Perry granted FERC’s request while noting in his letter that, as explained in his original directive, failure to act expeditiously within a 60-day timeframe would be unjust, unreasonable, and contrary to the public interest. Given the circumstances highlighted by FERC, he agreed to allow FERC to take final action by Wednesday, January 10, 2018. Despite granting the request, Mr. Perry strongly urged FERC to act before the deadline to ensure the “resilience and security of the electric grid.”

The DC Circuit has found that the Federal Energy Regulatory Commission (FERC) adequately and reasonably explained its decision to adopt the index formula that governs pipeline rates for the 2016 to 2021 period. Oil pipeline rates are governed by an indexed ratemaking system, and each year FERC calculates the index used to set pipeline-specific rate ceilings by using a formula that captures the cost change in the oil pipeline industry. FERC reviews this formula every five years and adopted the most recent one on December 17, 2015 after a notice and comment rulemaking.

The Association of Oil Pipelines challenged the index formula for the 2016-2021 period on the grounds that FERC did not apply the same methodology used in prior index reviews. First, FERC relied solely on the middle 50% of pipeline cost-change data and did not incorporate the middle 80%. Second, FERC used Page 700 cost-of-service data to calculate the index level instead of the Form No. 6 accounting data it had used in the past.

In the first quarter of 2017, more than 100 stakeholders, including utilities, technology providers, system operators, and state regulators submitted comments on the extensive notice of proposed rulemaking (NOPR) initiated by the Federal Energy Regulatory Commission (FERC) to encourage deployment of energy storage and aggregated distributed energy resources. While there has been no further official action at FERC (perhaps due to a lack of quorum from February 4 to August 9, 2017 and the need for a new commission to reassess priorities), an increasing number of states and utilities continue to advance investments in energy storage technologies:

  • In mid-October, the Washington Utilities and Transportation Commission issued a policy statement directing utilities to consider energy storage in their resource planning and procurement activities. While the statement does not go as far as setting a procurement mandate, it establishes an expectation that utilities will, among other things, model the sub-hourly benefits of a range of different storage technologies and include a storage alternative in their analysis of resource options.
  • Also last month, the Massachusetts Department of Public Utilities launched an investigation of the eligibility of energy storage systems for net metering and the role of net-metered resources in forward capacity markets.

A recent Smart Electric Power Alliance report on US energy storage deployments underscores that energy storage will continue to expand even though the timing and scope of federal regulation remains unknown. According to the report, utilities interconnected more than 200 megawatts (MW) of energy storage to the grid in 2016, bringing the total energy storage in operation nationwide to 622 MW across 2,399 systems. Even more staggering, GTM Research currently forecasts an elevenfold growth in the size of the 2016 market to 2.5 gigawatts (GW) by 2022.

Today, the Federal Energy Regulatory Commission (FERC) Office of Enforcement (OE) issued its 2017 Report on Enforcement. The report provides a review of OE’s activities during fiscal year 2017, which begins October 1 and ends September 30 annually, revealing likely areas of focus for FERC enforcement in the coming year.

The report indicates that even though FERC lacked a quorum for much of 2017, OE continued to focus on the same areas of market and operational risk that have traditionally captured its attention, which include (i) fraud and market manipulation; (ii) anticompetitive conduct; (iii) conduct that threatens transparency in regulated markets; and (iv) serious violations of mandatory reliability standards. OE does not anticipate that its priorities will change for fiscal year 2018. FERC also addresses its continued litigation of contested cases in federal courts. Additionally, similar to fiscal year 2016, the report indicates that the vast majority of alleged violations that come to OE’s attention are addressed informally through corrective actions voluntarily implemented by the subject of the investigation, without the need for a formal settlement. But this year, OE provides detailed examples of surveillance inquiries initiated by its Division of Analytics and Surveillance that are closed without referral to the US Department of Justice. Details on the topics in the 2017 Enforcement Report will be further described in a future LawFlash that will be posted as part of Morgan Lewis’s Power & Pipes energy law web postings. These issues will also be discussed in further detail during an upcoming webinar hosted by Morgan Lewis linked below.

2017 Year in Review: FERC Enforcement Webinar >>

We are changing the name of our FERC Law Updates blog, but we will continue to be your go-to source for concise analyses on law, policy trends, and developments affecting the energy industry.

Blog posts, LawFlashes, and webinar announcements from Morgan Lewis's energy team and other related practice areas will keep you up to date on these topics.

Like similar laws in many other states, Pennsylvania’s Alternative Energy Portfolio Standards Act (the AEPS Act) requires electric distribution companies (EDCs) and competitive retail electric generation suppliers (EGSs) to purchase an increasing percentage of energy from renewable energy sources. The AEPS Act also includes a “set-aside” that requires some of that renewable energy—as measured in alternative energy credits (AECs)—to be derived from solar photovoltaic (solar PV) facilities.

Until recently, Pennsylvania EDCs and EGSs could meet their solar PV requirements using solar AECs generated from solar PV facilities located anywhere within PJM, the regional transmission organization that includes Pennsylvania and all or part of 13 other states (including Washington, DC). Now, under Act 40 of 2017, signed into law on October 30 by Governor Tom Wolf, the rules have changed.

The US Senate has confirmed Kevin McIntyre and Richard Glick to join the Federal Energy Regulatory Commission (FERC), restoring the Commission to a full complement of five commissioners for the first time in over two years. Although FERC has had a quorum for two months, the full complement of commissioners should help the agency work through the backlog of pending proceedings that piled up in the six months that the Commission lacked a quorum. Major actions awaiting Commission action include the Department of Energy’s (DOE’s) notice of proposed rulemaking (NOPR) on generation resiliency, FERC’s 2016 electric storage NOPR, and numerous infrastructure proposals. Given the high speed at which the Commission is considering the DOE resiliency proposal, with an initial ruling due around the end of November, that action could be the first opportunity for the new commissioners to make their mark on a major policy initiative.

The Commodity Futures Trading Commission (CFTC) has delayed implementation of the reduction in the de minimis threshold by an additional year. Under the de minimis exception, a person is not considered to be a swap dealer unless its swap dealing activity exceeds an aggregate gross notional amount threshold. Currently, that threshold is set at $8 billion, and is subject to a phase-in period after which the threshold will be reduced to $3 billion. The phase-in period was scheduled to terminate on December 31, 2018, but on October 26, the CFTC issued an order extending the phase-in period by one year, terminating on December 31, 2019 instead of December 31, 2018. The CFTC previously extended the phase-in period by one year in October 2016, and at that time explained that the extension provides additional time for further information to become available to reassess the de minimis exception.

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