Court Decisions Affirm States’ Authority to Incentivize Generation Development and Retention

In two recent federal court decisions, the Second Circuit Court of Appeals and the U.S. District Court for the Northern District of Illinois affirmed state authority to implement programs to incentivize generation development and retention. The two decisions are the latest in a line of federal court cases navigating the jurisdictional dividing line between state and federal energy regulators. In FERC v. Electric Power Supply Association, the Supreme Court held that the Federal Energy Regulatory Commission’s (FERC) demand response compensation rule did not intrude on states’ authority over retail markets.  And in Hughes v. Talen Energy Marketing, the Supreme Court held that a Maryland program incentivizing the construction of new electric generation was preempted by the Federal Power Act (FPA) because it premised payments to the generator on the successful completion of sales into a FERC-jurisdictional wholesale capacity market.

Allco Finance Ltd. v. Klee. On June 29, 2017, the Second Circuit issued its decision in Allco Finance Ltd. v. Klee, denying an appeal challenging Connecticut’s Renewable Portfolio Standard (RPS), as well as a Connecticut statute authorizing the state’s energy regulators to (a) solicit proposals for renewable energy generation and (b) direct state‑regulated utilities to enter into contracts with the winning bidders.  The plaintiff in Allco argued that Connecticut’s renewable energy procurement statute was preempted by the FPA, and that locational qualifications in Connecticut’s RPS program violated the dormant Commerce Clause.  The Second Circuit affirmed the a decision by the federal district court in Connecticut dismissing the plaintiff’s preemption claims, finding the renewable procurement to be “a permissible exercise of the power that the FPA grants to Connecticut to regulate its [load-serving entities].”  The court also affirmed the district court’s dismissal of the plaintiff’s dormant Commerce Clause claims, finding that “Connecticut’s RPS program serves its legitimate interest in promoting increased production of renewable power generation in the region,” and that the burden of the program’s geographic restrictions on interstate commerce was not “clearly excessive in relation to the putative local benefits.”

Village of Old Mill Creek v. Star and Electric Power Supply Association v. Star. More recently, on Friday, July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed a pair of complaints challenging Illinois’ “Future Energy Jobs Act.”  The statute created a new commodity—the “Zero Emission Credit” (ZEC)—intended to compensate qualifying nuclear facilities for the environmental attributes of their power production.   In the two companion cases, Village of Old Mill Creek v. Star and Electric Power Supply Association v. Star, the plaintiffs challenged the Illinois ZEC program on grounds that it was preempted by the FPA and that the program burdened interstate commerce in violation of the dormant Commerce Clause.

The Illinois plaintiffs argued that the ZEC payments intruded on FERC’s exclusive jurisdiction under the FPA because those payments would “effectively replac[e] the auction clearing price received by [ZEC recipients] with the alternative, higher price preferred by the Illinois General Assembly,” and would distort the outcomes in FERC’s wholesale electricity markets. Additionally, Plaintiffs asserted that Illinois’ ZEC Program violated the dormant Commerce Clause because it would “solely benefit [in-state nuclear generators] . . . to the disadvantage of out-of-state producers who compete in the wholesale market.”

The district court disagreed, finding that “Plaintiffs’ preemption claims do not constitute ‘proper cases’ for private suits for injunctive relief,” but, even if they did, the ZEC program did not run afoul of the jurisdictional divide between states and FERC because it “falls within Illinois’ reserved authority over generation facilities,” and “Illinois has sufficiently separated ZECs from wholesale transactions such that the [FPA] does not preempt the state program under principles of field preemption.” The court likewise declined to find conflict preemption, determining instead that the “Plaintiffs’ theory . . . that distorting the wholesale market conflicts with FERC’s preference for competitive auctions” was “too broad a theory of preemption” and would inappropriately limit state authority.  The court found that FERC’s power was “undiminished” by the ZEC program, noting that FERC “can address any problem the ZEC program creates with respect to just and reasonable wholesale [electricity] rates.”

The court likewise dismissed the plaintiffs’ dormant Commerce Clause challenges, holding that “[t]he statute is not facially discriminatory because it does not preclude out-of-state generators from submitting bids for ZECs,” nor did “the circumstances surrounding the enactment of the statute . . . warrant an inference of discrimination.” The court went on to find that “[t]he creation of the ZEC has created a new market, and while that market may affect the wholesale energy market, it is an incidental burden on the channels of interstate commerce in which plaintiffs participate.”  Accordingly, the court found that “[t]he alleged harm to out-of-state power generators who will be competing in auctions against subsidized participants is not clearly excessive” when balanced against the states’ interests in environmental protection.

Motions to dismiss similar challenges to New York’s ZEC program remain pending before the U.S. District Court for the Southern District of New York.*

*The Members of the New York Public Service Commission, defendants in the S.D.N.Y. litigation, are represented by Spiegel & McDiarmid LLP attorneys Scott H. Strauss, Peter J. Hopkins, Jeffrey A. Schwarz, and Amber L. Martin.

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Lawrence Berkeley National Laboratory Issues Report on Multiyear Rate Plans

Earlier this month, the Lawrence Berkeley National Laboratory issued a report entitled State Performance-Based Regulation Using Multiyear Rate Plans for U.S. Electric UtilitiesThis report provides in-depth analysis of multiyear rate plans (MRPs).  MRPs are a particular type of performance-based regulation, a broad approach to regulation that emphasizes incentives.  MRPs typically include three key characteristics: (1) a rate case moratorium that reduces the frequency of rate cases to once every four or five years, (2) an attrition relief mechanism that permits rates to increase during the years between rate cases, and (3) various performance incentives for service quality. While MRPs are not used in most states, the report analyzes case studies from Maine, California, New York, and Iowa, as well as from Canada and Great Britain.

According to the report, MRPs have several advantages over traditional cost of service regulation in addressing contemporary challenges.  Well-designed MRPs can strengthen performance incentives and increase operating flexibilities during the years between rate cases, allowing utilities to more easily adopt new technologies.  In addition, MRPs can include incentive provisions that encourage utilities to facilitate demand-side management and distributed energy resources.  These consumer-side programs may also benefit from the decoupling of utilities’ revenue and costs under MRPs, which reduces utilities’ incentives to maximize total sales between rate cases.  Furthermore, since MRPs require rate cases only every four or five years, they can free up regulatory resources for other uses.  However, the report also notes that MRPs can be complicated to initially implement and may require significant changes to states’ regulatory systems.

The report concludes that MRPs can improve the efficiency of regulation and utility cost performance.  As a result, the report predicts that the use of MRPs will increase over time and recommends that state utility regulators, consumer groups, and utility managers consider MRPs when undertaking grid modernization efforts.

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4th Circuit Vacates Ruling that EPA Must Consider Impact of its Regulations on Coal Jobs

The Fourth Circuit Court of Appeals recently issued an order vacating a West Virginia Federal District Court decision that had held that Clean Air Act Section 321(a) required EPA to conduct an evaluation of the impact of Clean Air Act regulations on coal industry jobs.  The Fourth Circuit found that the district court lacked jurisdiction to hear the case, and sent the matter back to the district court, directing that it be dismissed.

Murray Energy (and the other associated plaintiff coal companies) had filed their suit in district court under Clean Air Act Section 304(a)(2), which allows “any person [to] commence a civil action on his own behalf” when alleging a failure of the EPA “to perform any act or duty under this chapter which is not discretionary.” Construing Clean Air Act Section 304(a)(2) “narrowly,” the Fourth Circuit found that Clean Air Act Section 321(a) “imposes on the EPA a broad, open-ended statutory mandate” and leaves EPA “with considerable discretion” as to how to manage those duties.  It further found that “[a] court is ill-equipped to supervise this continuous, complex process.”

The court held that the district court lacked jurisdiction over the suit because Section 304(a)(2) did not authorize Murray Energy to sue the EPA regarding its Clean Air Act Section 321(a) obligations.  The court further noted that neither the Administrative Procedure Act nor the mandamus statute provide an alternative basis for jurisdiction.

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Hawaiian Electric Companies Propose Grid Modernization Strategy Focused on Integrating Distributed Energy Resources and Renewables

Last month, the Hawaiian Electric Companies (HECO) filed a Draft Grid Modernization Strategy describing the scope and cost of changes that will be needed to update the HECO grid to help the state meet its goal of 100% renewable energy by 2045.  The proposal is HECO’s second attempt at a grid modernization plan, coming after the Hawai‘i Public Utilities Commission rejected HECO’s first proposal in an order issued earlier this year.  That order found that HECO’s proposal, which had a price tag of $340 million over five years, was not cost-effective and that the proposal asserted “only an indirect link to address the primary issue currently facing Hawaii’s distribution grids, i.e., [distributed energy resources] and renewable energy integration, more broadly.”

Hawai‘i is a national leader in the integration of customer-sited private solar—in 2016, 26% of HECO’s customers were powered by renewable sources.  But that success has also strained the capacity of the grid.  HECO’s latest proposal acknowledges that it faces unique challenges in modernizing the grid to accommodate safely and reliably two-way power flow from many resources.  HECO describes these challenges as including maintaining system reliability on HECO’s relatively small island grids without the ability to call on neighboring states to make up for generation shortfalls.

HECO’s latest proposal states that its vision for modernization is “to use advanced technologies to modernize our existing grid into a state‐of‐the‐art cyber‐physical platform . . . that will enable the integration and optimal utilization of customers’ resources through existing and new distributed energy resources . . . and demand response . . . programs.”  The cost to implement the Draft Grid Modernization Strategy is estimated at roughly $205 million over six years.  HECO’s plan for near-term grid modernization work calls for:

  • Distribution of smart meters “surgically” rather than system-wide, primarily for enhanced sensing and monitoring purposes . . . ;
  • Reliance on advanced inverter technology to enable greater private rooftop solar adoption;
  • Expanded use of voltage management tools, especially on circuits with heavy solar penetration, to maximize circuit capacities for rooftop solar PV and other customer resources;
  • Expanded use of sensors and automated controls at the substation and neighborhood circuit level;
  • Expansion of a communication network enabling greater operational visibility and efficient coordination of distributed resources, along with smart devices placed on problematic circuits and automation for improved reliability; [and]
  • Enhanced outage management and notification technology.
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Monthly Renewable Generation Exceeds Nuclear Output For First Time Since 1984

The Energy Information Administration reports that in March and April 2017, monthly electricity generation from utility-scale renewable generators exceeded output from nuclear generators for the first time in over three decades.  According to the EIA, the last time renewable output surpassed nuclear generation was in July 1984.  The EIA attributes this outcome to a perfect storm of factors, including record generation from wind and solar, increased output from hydro (EIA treats all hydro generation as renewable for purposes of this report), and reduced nuclear plant availability due to maintenance and refueling, which typically tends to be scheduled during the spring and fall months.  EIA also notes that although renewable generation has been steadily increasing, net generation from nuclear has remained reasonably flat since the late 1990s, and more and more nuclear units have retired in recent years.

The trend is unlikely to be a lasting one, however.  The EIA’s Short-Term Energy Outlook  released June 6, 2017, projects nuclear output once again outpacing renewable generation in summer 2017.

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