On October 4, 2017, in a decision with significant implications for the energy project finance community, the Federal Energy Regulatory Commission (FERC or the “Commission”) granted a petition for declaratory order filed by the Ad Hoc Renewable Energy Financing Group (“Petitioners”)1 and held that certain non-managing (i.e., passive) “tax equity” interests in public utilities are not “voting securities” for purposes of Section 203 of the Federal Power Act (FPA).2 For that reason, FERC held that (1) the “issuance or transfer of such interests does not constitute a transfer of control with respect to the public utility and does not require” prior FERC authorization under Section 203(a)(1); and (2) “the acquisition of such interests by a holding company qualifies” under Section 203(a)(2) for the blanket authorization in Section 33.1(c)(2)(i) of FERC’s regulations.3 The decision expressly extends to Section 203 FERC’s precedent from the Section 205 context regarding whether certain tax equity interests are voting securities, a welcome outcome for sponsors of, and passive investors in, renewable energy projects.
On October 2, 2017, the Federal Energy Regulatory Commission (the “Commission”) terminated its inquiry into the need for, and potential effects of, modifications to the North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection Reliability Standards (“CIP Standards”) regarding the cybersecurity of control centers used to monitor and control the bulk electric system. That inquiry, initiated, in part, in response to a 2015 cyberattack on Ukraine’s electric grid, sought industry and stakeholder feedback on whether the Commission should modify the CIP Standards to require (i) separation between the Internet and BES cyber systems in control centers performing transmission operator functions and (ii) “application whitelisting”—a computer administration practice used to prevent unauthorized programs from running—for such systems. After reviewing comments on its Notice of Inquiry (NOI), the Commission concluded that the risks and operational challenges that might result from requiring isolation or whitelisting do not outweigh the potential benefits.
On September 27, 2017, Sens. James M. Inhofe (R-OK) and Martin T. Heinrich (D-NM) introduced S. 1860, the Parity Across Reviews Act (“PARs Act”), which, if enacted, would add a $10 million value threshold to the requirement in Section 203(a)(1)(B) of the Federal Power Act1 for prior Federal Energy Regulatory Commission (FERC or “Commission”) authorization for transactions involving the merger or consolidation of FERC-jurisdictional facilities. The PARs Act also would require FERC to establish a 30-day postclosing notification requirement for such transactions involving facilities worth more than $1 million but less than $10 million. The PARs Act is identical to H.R. 1109, which passed in the House of Representatives on June 12, 2017.2
On September 19, 2017, the Court of Appeals of North Carolina (“Court”) held that companies that install solar panels on customer rooftops are “public utilities” under state law, at least when they retain ownership of the panel and sell the output to the customer. The ruling represents a blow to potential solar providers, and a victory for North Carolina’s franchised utilities, which believe that rooftop solar will undermine their rate base, increasing expenses for other customers.
Large-scale solar development is big business, and solar EPC Contracts are big business by association. In Q2 2017, the U.S. solar market installed 2,387 MWdc, an 8% increase year-over-year, and the largest second quarter everi. Utility PV accounted for 58% of those installations, making that the seventh consecutive quarter that the utility-scale space added more than 1 GWdcii. In today’s solar market, there is significant competition among project developers in search of debt lending and equity investment partners. This means that in order to develop a competitive edge, developers need to prepare a solar project with the strongest level of guaranteed revenue in order to increase the likelihood of selling the project to such potential debt and equity companies. Given that the majority of a solar project’s capital expenditure is EPC costs (approximately 70%-90%)iii, the cornerstone of any bankable solar project is a properly negotiated EPC Contract. As such, developers must offer lenders and investment partners bankable EPC Contracts that centralize the responsibility for meeting many of the perceived challenges associated with a big solar project and make the risk profile of the entire solar project more attractive to such potential partners. This article identifies the five fundamental risks facing any project developer in an EPC Contract and lays out an easy to use checklist of legal and commercial tools to mitigate them and to ensure the developer is able to present debt lenders and equity investors with the most bankable EPC Contract possible - one that is the most likely to deliver a well-performing solar project on time and on budget.
The Federal Energy Regulatory Commission (FERC or the “Commission”) recently restored its quorum with the swearing in of Commissioners Neil Chatterjee and Robert Powelson, but the casualties from the six-month, quorumless period continue to pile up. East Kentucky Power Cooperative (EKPC), a generation and transmission cooperative in PJM Interconnection, L.L.C., is the latest victim. On September 7, 2017, FERC granted EKPC’s application seeking to terminate its obligation to purchase electric energy and capacity from qualifying small power production facilities (QFs) with a net capacity in excess of 20 MW (the “September 2017 Order”). The September 2017 Order represents a pyrrhic victory of sorts for EKPC, though, because FERC ruled that the termination does not apply to two Kentucky QFs that protested the application — a result that would not have occurred if FERC had a working quorum earlier in the year.
On August 23, 2017, the Department of Energy (DOE) released its Staff Report assessing the reliability and resilience of the electric grid. The highly anticipated report was commissioned in April 2017 by Secretary of Energy Rick Perry, who expressed concerns that the “premature retirement” of traditional baseload generation, such as coal and nuclear—possibly driven, in part, by subsidies for renewables—would place the long-term reliability of the grid at risk, particularly in the organized wholesale electricity markets. The Staff Report finds that there is no immediate crisis due to the changing resource mix, although the continuing evolution of the grid may pose future challenges and risks. Although its findings and conclusions are relatively uncontroversial and consistent with findings made in similar reports and analyses by grid operators and other stakeholders, the Staff Report provides a valuable perspective on the past and future of the electric grid and the wholesale markets.
On August 28, 2017, the Federal Energy Regulatory Commission (FERC or the “Commission”) approved a Stipulation and Consent Agreement between FERC’s Office of Enforcement (OE) and American Transmission Company, LLC (ATC) to resolve an OE investigation of numerous violations by ATC of Sections 203 and 205 of the Federal Power Act (FPA). ATC identified the violations during an internal compliance review precipitated by a March 2014 settlement between OE and certain subsidiaries of ITC Holdings Corp. regarding similar violations, as described here.