Last week, Rep. Alexandria Ocasio-Cortez (D-NY) and Sen. Ed Markey (D-MA) released more details on the much-anticipated “Green New Deal” in the form of a non-binding resolution. As the name suggests, the legislators modeled the proposal after President Franklin Roosevelt’s New Deal, credited with bringing the U.S. economy out of the Great Depression through federal investment in infrastructure and the workforce. This ambitious new “Deal” seeks to correlate investment in infrastructure and job creation with climate change-related goals, such as reducing greenhouse gas (GHG) emissions and shoring resilience to climate impacts. The proponents argue that transformative climate action will spur economic growth, create jobs, and support communities and workers across the United States in a “fair and just transition” to achieve net-zero GHG emissions and grow the economy.
On February 8, 2019, the Federal Energy Regulatory Commission (FERC or the “Commission”) issued a Final Rule revising its regulations in 18 C.F.R. § 385.2007 regarding computation of time periods prescribed or allowed by statute or FERC rule or order (“Rule 2007”). The changes, which are effective immediately, are shown here.
We are pleased to share a recording of Akin Gump’s annual energy briefing that took place last week, “The Global Energy Industry 2019: A Look to the Year Ahead.” Speakers included Akin Gump energy regulation, markets and enforcement practice co-head Chip Cannon, oil and gas partner Andy Lehman, global project finance practice co-head John Marciano, oil and gas partner Gabe Procaccini, and Will Zapalac, partner at Rockland Capital LLC. Oil and gas partner and partner in charge of the firm’s Houston office Christine LaFollette moderated the program, which included the panels below:
In 2005, Congress sought to encourage investment in the nation’s power grid by requiring the Federal Energy Recovery Commission (FERC) to establish “incentive-based” rate treatments for electric transmission facilities.1 Order No. 679,2 FERC’s transmission incentives rule adopted in 2006, created eight categories of incentive rate treatment for which utilities could apply, including a so-called “abandonment” incentive. An applicant seeking this incentive rate treatment may apply to FERC for approval to recover from ratepayers 100 percent of the prudently incurred costs of transmission facilities that are canceled or abandoned due to factors beyond the utility’s control. The idea behind this incentive rate treatment was to facilitate investment by mitigating some of the investment risk in transmission projects, including the state and local permitting process.3
San Diego Gas & Electric Company (SDG&E) filed a petition for declaratory order with FERC in September 2015 to establish its eligibility for the abandonment incentive for the South Orange County Reliability Enhancement Project, an effort to rebuild and upgrade a substation and to replace and relocate certain transmission and distribution line segments. By the time of the application, the company had already spent roughly $31 million on the project. FERC issued a declaratory order in March 2016 finding that, should the project be abandoned for reasons beyond the company’s control, SDG&E could recover 100 percent of the prudently incurred project costs going forward, but that it would not be entitled to recover all of the
$31 million that hasalready been spent on the project.4 Instead, half of those costs could be recovered from ratepayers in accordance with FERC’s pre-Order No. 679 practice. SDG&E appealed that decision, arguing that it should be entitled to the abandonment incentive rate treatment for the full cost of the project.
The D.C. Circuit sided with FERC in a split decision.5 Writing for the majority, Judge Pillard emphasized that the purpose of FERC’s incentive program is to encourage investment in needed infrastructure projects. The majority therefore agreed with FERC that the portion of the project that was already financed and paid for before receiving approval for the incentive rate treatment “lacked the requisite nexus to the facilitation of new investment.”6 In other words, the incentive rate treatment cannot encourage an investment that has already occurred. The company itself had acknowledged that it had incurred the $31 million of costs “without assurance of cost recovery.”7
In a lengthy dissent, Judge Randolph took issue with, among other things, the majority’s characterization of when the “incentive” to invest begins. “The fallacy in [the majority’s] theory is its failure to recognize that FERC created the incentive when it promulgated the regulation in 2006,” Judge Randolph wrote, “well before San Diego began incurring costs for its transmission project.” Judge Randolph points out that FERC has rejected a “but for” test (i.e., the applicant does not need to show that the investment would not occur but for the incentive rate treatment), and that lack of “certain recovery” prior to a FERC application does not render the incentive treatment meaningless. Indeed, even if an applicant is approved for the rate treatment, the applicant still lacks “certain recovery,” since it will later have to make a prudency showing to recover the costs from ratepayers.
FERC has granted preorder abandonment incentives before, although not in a case where a party objected to such recovery, as here. As the first case to litigate the precise issue of when the abandonment incentive rate treatment may begin, this decision establishes a precedent that FERC is likely to follow in future cases. FERC has emphasized, however, that each application for transmission incentives will be evaluated on a case-by-case basis.
1 Energy Policy Act of 2005, Pub. L. No. 109-58, § 1241, 119 Stat. 961 (2005) (codified at 16 U.S.C.
2 Promoting Transmission Investment Through Pricing Reform, Order No. 679, 116 FERC ¶ 61,057 (2006), order on reh’g, Order No. 679-A, 117 FERC ¶ 61,345 (2006), order on reh’g, Order No. 679-B, 119 FERC ¶ 61,062 (2007); see also Promoting Transmission Investment Through Pricing Reform, 141 FERC ¶ 61,129 (2012) (“Policy Statement”).
3 Order No. 679 at P 155; see also Policy Statement, 141 FERC 61,129, at P 14.
4 San Diego Gas & Elec., 154 FERC ¶ 61,158, at PP 17-18 (2016).
5 San Diego Gas & Elec. v. FERC, No. 16-1433 (D.C. Cir. Jan. 15, 2019).
6 Id. at 15.
7 Id. at 19.
On January 7, 2019, the Federal Energy Regulatory Commission (FERC or “the Commission”) issued an Order approving a settlement between its Office of Enforcement (Enforcement) and Algonquin Gas Transmission, LLC (Algonquin) for violating the terms of the FERC certificate (“Certificate”) for the Algonquin Incremental Market (AIM) Project, which authorized Algonquin to expand its natural gas pipeline system in the northeast.1 While the violation appears to be relatively minor, Algonquin will nevertheless pay a civil penalty of $400,000 and submit semiannual environmental compliance monitoring reports for up to two years. As explained below, certificate compliance historically has not been a focus of FERC’s enforcement efforts, but this case and other recent FERC actions suggest that could be changing.
On January 8, 2019, the Federal Energy Regulatory Commission (FERC) issued a Final Rule amending its regulations governing the maximum civil monetary penalties assessable for violations of statutes, rules and orders within FERC’s jurisdiction. The Final Rule is a result of the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015, which requires each federal agency to issue an annual inflation adjustment by January 15 for each civil monetary penalty provided by law within the agency’s jurisdiction. The adjustments in the Final Rule represent an increase of approximately 2.5 percent for each covered maximum penalty. FERC’s adjusted maximum penalty amounts, which will apply at the time of assessment of a civil penalty regardless of the date on which the violation occurred, are set forth here and will become effective upon publication in the Federal Register.
On January 4, 2019, the United States District Court for the District of Maine handed the Federal Energy Regulatory Commission (FERC or “the Commission”) a victory in FERC v. Silkman, a long-running market manipulation enforcement action against Competitive Energy Services (CES) and its managing member, Richard Silkman (the “Respondents”) for allegedly engaging in manipulative conduct in connection with an ISO New England demand response program. FERC and the Respondents each filed cross-motions for summary judgment on the Respondents’ defense that FERC’s claims are time-barred since FERC filed its district court enforcement action more than five years after the conduct occurred. The court resolved the motions in FERC’s favor, finding that the five-year statute of limitations only required FERC to initiate administrative proceedings against respondents within five years, with any subsequent district court enforcement action being subject to a separate limitations period beginning when the penalty is assessed administratively. The court’s decision is significant for the litigants because it allows FERC’s enforcement case to proceed. But, for reasons explained below, its effect beyond this litigation is uncertain and probably limited.
In June 2018, CXA La Paloma, LLC (“La Paloma”) filed a complaint at the Federal Energy Regulatory Commission (FERC or “the Commission”) seeking to require the California Independent System Operator (CAISO) to implement a centralized capacity market to procure the electric generation capacity that is needed to reliably operate California’s electric grid. La Paloma argued that California’s existing resource adequacy process—which principally relies on bilateral contracting between load-serving entities (LSEs) and generators—has produced outcomes that are unjust, unreasonable and discriminatory. A coalition of other generators supported La Paloma’s complaint. The generators claimed, among other things, that California’s resource adequacy process fails to send accurate price signals needed to attract and retain resources needed for reliability, does not provide generators with a reasonable opportunity to recover their costs, and results in CAISO having to resort to out-of-market mechanisms to acquire capacity that is needed to operate its system. These arguments are not new, but have been raised, in one form or another, by numerous generators doing business in California for years.