Pratt’s energy law report

PRATT’S ENERGY LAW REPORT JULY/AUGUST 2016 VOL.16-7 JULY/AUGUST 2016 VOL. 16-7 ENERGY LAW REPORT EDITOR’S NOTE: REDUCTIONS IN FORCE Steven A. Meyerowitz EFFECTIVELY MANAGING WORKFORCE CONTRACTION IN TURBULENT TIMES Robert G. Lian Jr. and Brian Glenn Patterson ENERGY MERGERS AND ACQUISITIONS: A YEAR IN REVIEW – PART II William S. Lamb, Michael Didriksen, Elaine M. Walsh, Hillary H. Holmes, and Thomas E. Holmberg THE JONES ACT AND EXPORT OF CRUDE OIL AND LNG FROM THE U.S. Christopher R. Hart and Lisa Houssiere U.S. SUPREME COURT INVALIDATES MARYLAND PROGRAM THAT SUPPLEMENTS FERC-APPROVED CAPACITY PAYMENTS Adam Wenner and A. Cory Lankford DEPARTMENT OF TRANSPORTATION PROPOSES RULE EXPANDING SAFETY REQUIREMENTS FOR NATURAL GAS PIPELINES Scott Janoe, Gregory S. Wagner, Jerrod Harrison, and Gina Sagar CFTC ENERGY AND ENVIRONMENTAL MARKETS ADVISORY COMMITTEE MEETING Athena Yvonne Eastwood, Paul J. Pantano, Jr., Neal E. Kumar, and Michael Selig PRATT’S Pratt’s Energy Law Report VOLUME 16 NUMBER 7 JULY/AUGUST 2016 Editor’s Note: Reductions in Force Steven A. Meyerowitz 247 Effectively Managing Workforce Contraction in Turbulent Times Robert G. Lian Jr. and Brian Glenn Patterson 249 Energy Mergers and Acquisitions: A Year in Review—Part II William S. Lamb, Michael Didriksen, Elaine M. Walsh, Hillary H. Holmes, and Thomas E. Holmberg 256 The Jones Act and Export of Crude Oil and LNG from the U.S. Christopher R. Hart and Lisa Houssiere 278 U.S. Supreme Court Invalidates Maryland Program That Supplements FERCApproved Capacity Payments Adam Wenner and A. Cory Lankford 281 Department of Transportation Proposes Rule Expanding Safety Requirements for Natural Gas Pipelines Scott Janoe, Gregory S. Wagner, Jerrod Harrison, and Gina Sagar 284 CFTC Energy and Environmental Markets Advisory Committee Meeting Athena Yvonne Eastwood, Paul J. Pantano, Jr., Neal E. Kumar, and Michael Selig 289 0001 [ST: 1] [ED: m] [REL: 16-7] (Beg Group) Composed: Fri Jun 17 14:28:13 EDT 2016 XPP 8.4C.1 SP #3 FM000150 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [FM000150-Local:09 Sep 14 16:11][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-fmvol016] 0 QUESTIONS ABOUT THIS PUBLICATION? For questions about the Editorial Content appearing in these volumes or reprint permission, please email: Jacqueline M. Morris at ............................................................................... (908) 673-1528 Email: ............................................................................... [email protected] For assistance with replacement pages, shipments, billing or other customer service matters, please call: Customer Services Department at . . . . . . . . . . . . . . . . . . . . . . . . . . . (800) 833-9844 Outside the United States and Canada, please call . . . . . . . . . . . . . . . . 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Pratt® Publication Editorial Office 230 Park Ave., 7th Floor, New York, NY 10169 (800) 543-6862 www.lexisnexis.com (2016–Pub.1898) 0002 [ST: 1] [ED: m] [REL: 16-7] Composed: Fri Jun 17 14:28:13 EDT 2016 XPP 8.4C.1 SP #3 FM000150 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [FM000150-Local:09 Sep 14 16:11][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-fmvol016] 43 Editor-in-Chief, Editor & Board of Editors EDITOR-IN-CHIEF STEVEN A. MEYEROWITZ President, Meyerowitz Communications Inc. EDITOR VICTORIA PRUSSEN SPEARS Senior Vice President, Meyerowitz Communications Inc. BOARD OF EDITORS SAMUEL B. BOXERMAN Partner, Sidley Austin LLP ANDREW CALDER Partner, Kirkland & Ellis LLP M. SETH GINTHER Partner, Hirschler Fleischer, P.C. R. TODD JOHNSON Partner, Jones Day BARCLAY NICHOLSON Partner, Norton Rose Fulbright BRADLEY A. WALKER Counsel, Buchanan Ingersoll & Rooney PC ELAINE M. WALSH Partner, Baker Botts L.L.P. SEAN T. WHEELER Partner, Latham & Watkins LLP WANDA B. WHIGHAM Senior Counsel, Holland & Knight LLP Hydraulic Fracturing Developments ERIC ROTHENBERG Partner, O’Melveny & Myers LLP iii 0003 [ST: 1] [ED: m] [REL: 16-7] Composed: Fri Jun 17 14:28:13 EDT 2016 XPP 8.4C.1 SP #3 FM000150 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [FM000150-Local:09 Sep 14 16:11][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-fmvol016] 36 Pratt’s Energy Law Report is published 10 times a year by Matthew Bender & Company, Inc. Periodicals Postage Paid at Washington, D.C., and at additional mailing offices. Copyright 2016 Reed Elsevier Properties SA, used under license by Matthew Bender & Company, Inc. No part of this journal may be reproduced in any form—by microfilm, xerography, or otherwise—or incorporated into any information retrieval system without the written permission of the copyright owner. For customer support, please contact LexisNexis Matthew Bender, 1275 Broadway, Albany, NY 12204 or e-mail [email protected] Direct any editorial inquires and send any material for publication to Steven A. Meyerowitz, Editor-in-Chief, Meyerowitz Communications Inc., 26910 Grand Central Parkway Suite 18R, Floral Park, New York 11005, [email protected], 347.235.0882. Material for publication is welcomed—articles, decisions, or other items of interest to lawyers and law firms, in-house energy counsel, government lawyers, senior business executives, and anyone interested in energy-related environmental preservation, the laws governing cutting-edge alternative energy technologies, and legal developments affecting traditional and new energy providers. This publication is designed to be accurate and authoritative, but neither the publisher nor the authors are rendering legal, accounting, or other professional services in this publication. If legal or other expert advice is desired, retain the services of an appropriate professional. The articles and columns reflect only the present considerations and views of the authors and do not necessarily reflect those of the firms or organizations with which they are affiliated, any of the former or present clients of the authors or their firms or organizations, or the editors or publisher. POSTMASTER: Send address changes to Pratt’s Energy Law Report, LexisNexis Matthew Bender, 121 Chanlon Road, North Building, New Providence, NJ 07974. iv 0004 [ST: 1] [ED: m] [REL: 16-7] Composed: Fri Jun 17 14:28:13 EDT 2016 XPP 8.4C.1 SP #3 FM000150 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [FM000150-Local:09 Sep 14 16:11][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-fmvol016] 22 Energy Mergers and Acquisitions: A Year in Review—Part II By William S. Lamb, Michael Didriksen, Elaine M. Walsh, Hillary H. Holmes, and Thomas E. Holmberg* In this two-part article, the authors review recent energy mergers and acquisitions developments. The first part of the article, which appeared in the June 2016 issue of Pratt’s Energy Law Report, discussed regulated utilities, power companies and generation assets, renewables, master limited partnerships and YieldCos, LNG developments, and project finance. This second part of the article covers bankruptcy developments in the energy sector, environmental regulation, Federal Energy Regulatory Commission developments, Electric Reliability Council of Texas issues, U.S. Commodity Futures Trading Commission actions, Mexico’s implementation of new wholesale power markets, and distributed generation. BANKRUPTCY DEVELOPMENTS IN THE ENERGY SECTOR Crashing commodities prices for oil and other raw products generated a high number of energy-related bankruptcies and out-of-court restructurings in 2015 and early 2016. Oil prices set new record lows throughout 2015 and broke the $26 threshold in very early 2016. As commodities prices remain depressed and, * William S. Lamb ([email protected]) is a partner at Baker Botts L.L.P. advising both public and private companies in complex mergers, acquisitions, and divestitures, as well as financings. Michael Didriksen ([email protected]) is a partner at the firm handling mergers and acquisitions and project development in the energy sector. Elaine M. Walsh ([email protected]) is a partner at the firm counseling clients regarding energy company mergers, energy asset acquisitions, divestitures, and investments, as well as the development of electric generation and fuel transportation and storage projects. Hillary H. Holmes ([email protected]) is a partner at the firm focusing her practice on securities laws and capital markets transactions for master limited partnerships and corporations in the energy industry. Thomas E. Holmberg ([email protected]) is a partner at the firm assisting clients with energy projects and the development of liquefied natural gas and natural gas pipelines. Mr. Lamb authored the Introduction section and co-authored the Regulated Utilities section. Mr. Didriksen co-authored the Regulated Utilities section and authored the section on Renewables. Ms. Walsh authored the Power Companies and Generation Assets section. Ms. Holmes authored the Master Limited Partnerships and YieldCos section. Mr. Holmberg authored the LNG and Project Finance sections of Part I of this article and the sections on Bankruptcy Developments in the Energy Sector, Environmental Regulation, Federal Energy Regulatory Commission, the Electric Reliability Council of Texas, the U.S. Commodity Futures Trading Commission, Mexico Implementation of New Wholesale Power Markets, and Distributed Generation in this second part of the article. PRATT’S ENERGY LAW REPORT 256 0010 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 in some instances, continue to fall, the number of bankruptcies is expected to rise. In the oil and gas industry, while increasing supply plays the most visible role in falling prices, lower demand in China and other large economies also plays a significant part in driving companies to seek restructuring solutions. In 2015, a significant number of issuers in the industry engaged in up-tier exchanges in which the issuers issued new second lien debt in exchange for unsecured debt at significant discounts to the face value of the unsecured debt. In addition, a total of 42 companies in the oil and gas industry filed for bankruptcy in the U.S. and Canada. As oil prices continue to fall, more companies will seek restructuring solutions. Lower commodities prices affect industries beyond oil and gas. Companies associated with the manufacture, production, and sale of other raw products have experienced similar downward pressure. For example, the price of aluminum fell to six-year lows in 2015, in part driven by increased supply from Chinese producers backed by government subsidies. This increase in supply, among other factors, drove Sherwin Alumina Company, LLC, to file for bankruptcy in early 2016. The effects of these commodities-driven bankruptcies often reach companies providing support services as well. The struggles of oil and gas service companies are well documented, but the impact reaches even further. For example, the struggles of a commodity-dependent debtor directly impact the operations of other companies not immediately considered to bear commodityprice risk. Bankruptcy exit solutions are also more difficult in light of global market conditions. For example, in 2015 Energy Future Holdings Corporation (“EFH”) negotiated a transaction with an investor consortium to satisfy approximately $42 billion in debt and exit bankruptcy by restructuring the ownership of Oncor through a REIT to unlock its true value. ENVIRONMENTAL REGULATION EPA Moves Forward with Greenhouse Gas Regulations for Fossil FuelFired Power Plants On October 23, 2015, the Environmental Protection Agency (“EPA”) published two final rules regulating greenhouse gas (“GHG”) emissions for the first time. One rule sets new source performance standards for GHG emissions (“GHG NSPS”) from new, reconstructed, modified fossil fuel-fired electric generating units (“EGUs”). The other rule requires that states reduce GHG emissions from existing fossil fuel-fired electric generating units (the “Clean Power Plan”). The rules took effect on December 22, 2015. ENERGY M & A—PART II 257 0011 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 The GHG NSPS for steam generating units and stationary combustion turbines applies to new units that commenced construction after January 8, 2014 and units that were reconstructed or modified after June 18, 2014. EPA set a GHG NSPS of 1,400 pounds of CO2 per megawatt‐hour on a gross‐output basis (“lbs CO2/MWh‐g”) for new steam generating units and 1,000 lbs CO2/MWh‐g for new baseload stationary combustion turbines. EPA also set a 120 lbs CO2/MMBtu standard for new non-baseload stationary combustion turbines. These performance standards apply to each unit nationwide. The Clean Power Plan requires that states reduce carbon dioxide (“CO2”) emissions from existing fossil fuel-fired EGUs from 2022 to 2030. EPA established national performance rates of 1,305 lbs CO2 per MWh for steam generating units and 771 lbs CO2 per MWh for stationary combustion turbines (“subcategory rates”). EPA calculated these performance rates based on what it asserts is achievable through the “best system of emission reduction.” EPA determined that the best system of emission reduction for reducing CO2 emissions from existing fossil fuel-fired EGUs includes: • heat rate improvements at existing coal-fired units; • re-dispatch of existing coal-fired generation to existing natural gas combined cycle units; and • increased renewable energy sources. EPA assigned states an emissions reduction goal by applying the subcategory rates to a state’s unique generation mix. State goals range from a seven percent reduction for Connecticut to a 45 percent reduction for North Dakota. States must submit plans to EPA by September 6, 2016 (with the possibility of a two-year extension) detailing how they will achieve their emission reduction goals by 2030. A state may choose to apply the subcategory rates to each unit in its state, but states have the discretion to allow sources to achieve subcategory rates through a variety of other mechanisms, including emissions trading, increased renewable generation, increased nuclear generation, and increased end-use energy efficiency. If a state fails to submit a plan to EPA, then EPA will issue a federal plan to impose the required emissions reductions. EPA estimates that the Clean Power Plan will reduce CO2 emissions by 32 percent from 2005 levels. The Agency projects that by 2030 the regulation will cost $8.4 billion annually and will provide over $34 billion in benefits. Numerous states and industry petitioners are challenging both the GHG NSPS and the Clean Power Plan in the D.C. Circuit on multiple grounds. With respect to the Clean Power Plan, petitioners allege that EPA cannot consider emission reductions measures “outside the fenceline” of a fossil fuel-fired EGU, PRATT’S ENERGY LAW REPORT 258 0012 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 such as re-dispatch to natural gas combined-cycle units, renewable energy generation, and emissions trading when setting performance standards and state goals. Moreover, EPA has infringed on state’s authority to balance the statutory factors in setting emission limits for particular units by setting stringent goals. Some petitioners argue that the emissions reductions required under the rule are not achievable in the allotted time, particularly considering the additional natural gas and transmission infrastructure required. At the same time, some states and environmental groups have expressed support for the Clean Power Plan. Eighteen states have intervened in support of EPA in the Clean Power Plan litigation. On January 21, 2016, the D.C. Circuit denied motions to stay the Clean Power Plan. However, the court established an expedited briefing schedule. Oral argument will be held on June 2, 2016, which means that a decision could be announced as early as September or October. State and industry petitioners subsequently sought a stay of the Clean Power Plan from the U.S. Supreme Court. On February 9, 2016, the Supreme Court granted the application for a stay. The stay will remain in place until the Supreme Court either denies a petition for certiorari from the D.C. Circuit’s ruling or grants the petition for certiorari and enters its own judgment. We expect the stay to remain in effect until at least early 2017 and, if the Supreme Court grants certiorari, until late 2017 or early 2018. While the stay was granted on a 5-4 vote, Justice Scalia’s recent death has no impact on the continued applicability of the stay. FEDERAL ENERGY REGULATORY COMMISSION The Federal Energy Regulatory Commission (“FERC”) is in a period of transition. In April 2015, Commissioner Norman Bay, a former U.S. Attorney (New Mexico) who had previously served as FERC’s Director of the Office of Enforcement, was elevated to the position of Chairman, succeeding acting Chairman Cheryl LaFleur. Commissioner LaFleur remains on the Commission. In October 2015, after serving two terms, Phil Moeller left the Commission to become Senior Vice President of Energy Delivery and Chief Customer Solutions Officer at the Edison Electric Institute. In January 2016, Commissioner Tony Clark announced that he will not seek a second term and will depart the Commission when his term expires June 30, 2016. President Obama has not yet announced nominations to replace the two Republican commissioners. In December 2015 testimony before the U. S. House of Representatives Energy and Commerce Subcommittee on Energy and Power, Chairman Bay stated that his priorities for the upcoming year include: (1) promoting greater efficiency, competition, and transparency in the wholesale markets; (2) improvENERGY M & A—PART II 259 0013 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 ing grid reliability through physical and cybersecurity measures and coordination of electric and gas markets; and (3) incenting the development and facilitating the permitting of new infrastructure. Major developments and initiatives related to FERC are summarized below. FERC Addresses Common Control and Passive Investor Arguments In January 2016, FERC issued an order clarifying its policy as to when affiliated companies will be found to be under “common control” pursuant to 18 C.F.R. § 35.36(a)(9) and also confirming that passive investor status does not relieve investors in FERC-jurisdictional assets of applicable reporting obligations, including the requirement to file a notice of change in status.1 Backyard Farms Energy LLC and Devonshire Energy LLC (collectively, the “MBR Entities”), filed a petition for declaratory order asking that they should not be deemed affiliates or under common control with either (a) the funds and accounts managed by Fidelity Management & Research Company or its affiliates and subsidiaries (“Fidelity Accounts”) or (b) the funds and accounts managed by FIL Limited (“FIL”) or its affiliates and subsidiaries. The entities managing the Fidelity Accounts (“Fidelity Advisers”), FIL, and the MBR Entities are all indirect subsidiaries of FMR, LLC (“FMR”). The Fidelity Accounts consist of a family of mutual funds, commingled pools and several types of managed funds and accounts for institutional and retail clients. Because the Fidelity Accounts are owned by various shareholders, institutions or other clients of the Fidelity Accounts and because FMR was not involved in their day-to-day management, the MBR Entities argued that they should not be deemed affiliates of the MBR Entities or under common control. Rejecting this argument, FERC emphasized that regardless of the ownership of the Fidelity Accounts, the Fidelity Advisers manage and control the investments that the Fidelity Accounts make and also exercise voting rights for the mutual funds in some circumstances. FERC stated that the agency’s focus for purposes of determining affiliation is “whether the Fidelity Advisers directly or indirectly own, control, or hold with power to vote, the outstanding voting securities of any public utility or holding company in which Fidelity Accounts may invest.”2 With regard to FIL, the parent company of a financial services group specialized in management, administration and distribution of collective investments, institutional management, and retirement services, FERC held that, at the very least, the “significant degree of cross ownership . . . as well as 1 See Backyard Farms Energy LLC, 154 FERC ¶ 61,036 (2016). 2 Backyard Farms at 21. PRATT’S ENERGY LAW REPORT 260 0014 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 two common directors” between the MBR Entities and FIL is indicative of common control.3 In the Backyard Farms order, FERC also rejected the MBR Entities’ argument in the alternative, finding that the “passive investor” exemption under the Public Utility Holding Company Act of 2005 is not applicable in the market-based rate context and therefore could not provide a basis to excuse applicants from filing required notifications of change in status.4 Similarly, FERC distinguished the blanket authorizations under Section 203 of the Federal Power Act for investment funds to purchase, acquire, or take any security in a public utility company in the ordinary course of business, as fiduciaries, and not with the purpose or with the effect of changing control of the company5 because those blanket authorizations were granted subject to ongoing reporting requirements and investment limitations. Supreme Court Decisions Addressing FERC’s Jurisdiction Over the last year, the Supreme Court of the United States (“Supreme Court”) issued two opinions that clarified the extent of FERC’s jurisdiction under the Natural Gas Act (“NGA”) and the Federal Power Act (“FPA”). The Supreme Court also granted certiorari to review an opinion issued by the U.S. Court of Appeals for the Fourth Circuit that upheld a district court decision invalidating a state program to subsidize the entry of new generation in the wholesale market. The Supreme Court’s decisions, and the case pending before the Supreme Court, are discussed below. Federal Energy Regulatory Commission v. Electric Power Supply Association6 In recent years, FERC has sought to regulate price fluctuations in wholesale markets and improve reliability by encouraging consumers to reduce their consumption of electricity during periods of peak demand. In 2011, FERC issued Order No. 745, which required wholesale market operators to compensate demand response providers in the same way they compensate generators who sell power in wholesale markets so long as the demand response resource provided “net benefits” (i.e., the resource would actually reduce costs for wholesale purchasers). Order No. 745 also required wholesale purchasers, who benefit from the lower prices demand response creates, to share proportionately 3 Id. at 22. 4 See id. at 23. 5 See 18 C.F.R. § 366.3(b)(2)(i). 6 577 U.S. ___ (2016). ENERGY M & A—PART II 261 0015 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 the cost of demand response payments. The Electric Power Supply Association and others (collectively, “EPSA”) challenged Order No. 745, arguing that FERC lacked the statutory authority to regulate what they considered retail market activity. EPSA also asserted that FERC failed to adequately consider reasonable objections to the practice of compensating demand response resources at the same rate as wholesale providers. The U.S. Court of Appeals for the D.C. Circuit agreed with EPSA, concluding that demand response is “part of the retail market” because it “involves retail customers, their decision whether to purchase at retail, and the levels of retail electricity consumption.” The D.C. Circuit also found that Order No. 745 was arbitrary and capricious because it failed to address “reasonable (and persuasive) arguments” that Order No. 745 would result in unjust and discriminatory rates by overcompensating demand response resources. On January 25, 2016, in a 6-2 opinion delivered by Justice Kagan, the Supreme Court upheld Order No. 745, finding that FERC has the authority to regulate compensation of demand response bids in the wholesale market. The Court held that FERC has authority under the FPA to regulate any practice that “affects” wholesale power markets, so long as the effect is sufficiently “direct” and does not regulate retail rates. The Supreme Court also held that “FERC regulation does not run afoul of [the FPA] just because it affects—even substantially—the quantity or terms of retail sales.” On the contrary, “[w]hen FERC regulates what takes place on the wholesale market, as part of carrying out its charge to improve how that market runs, then no matter the effect on retail rates, [the FPA] imposes no bar.” The Supreme Court also rejected the D.C. Circuit’s finding that FERC’s decision to compensate demand response providers at the same price paid to generators was arbitrary and capricious. Oneok, Inc. v. Learjet7 On April 21, 2015, the Supreme Court affirmed a ruling by the U.S. Court of Appeals for the Ninth Circuit that state-law antitrust claims against interstate natural gas pipelines are not pre-empted by the NGA. The state-law antitrust claims were brought by a group of manufacturers, hospitals, and other institutions that bought natural gas directly from interstate pipelines. The petitioners, consisting primarily of interstate pipeline and marketing and trading companies, had argued to the Supreme Court that state antitrust lawsuits “are within the field that the [NGA] pre-empts” because they target anti-competitive activities that affect wholesale rates. The Court disagreed in a 7 575 U.S. __ (2015). PRATT’S ENERGY LAW REPORT 262 0016 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 7-2 opinion delivered by Justice Breyer, ruling that “where (as here) a state law can be applied to nonjurisdictional [retail] as well as jurisdictional [wholesale] sales, we must proceed cautiously, finding pre-emption only where detailed examination convinces us that a matter falls within the pre-empted field as defined by our precedents.” According to the Supreme Court, when an activity affects both wholesale and retail sales it must consider the target at which the state law aims to determine whether it is pre-empted. Applying that test, the Supreme Court found that the state antitrust claims brought by the respondents were aimed at practices affecting retail prices, and were based on laws that were broadly aimed at all businesses in the marketplace rather than specifically targeted to the natural gas industry. As a result, the Supreme Court found respondents’ claims fell outside of the regulatory field occupied by FERC and were not preempted by the NGA. Hughes v. Talen Energy Marketing, LLC, cert. granted sub nom. Hughes v. PPL EnergyPlus, LLC8 CPV Maryland, LLC v. Talen Energy Marketing, LLC, cert. granted sub nom. CPV Maryland, LLC v. PPL EnergyPlus, LLC9 In 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed a district court judgment invalidating a Maryland Public Service Commission (“PSC”) order requiring three electric distribution companies to enter into long-term agreements with a new generator to guarantee the price the generator received for both capacity and energy sold in the wholesale market operated by PJM Interconnection, LLC (“PJM”). The Fourth Circuit found that the Maryland PSC “functionally” set the new generator’s rate for wholesale capacity and energy, effectively supplanting the PJM market rate with an alternative rate set by the state. Accordingly, the Fourth Circuit held that the Maryland PSC was preempted under the FPA’s grant of exclusive authority to FERC to regulate the rates of wholesale sales of electric capacity and energy. Both the Maryland PSC and the generator petitioned for certiorari, which the Supreme Court granted on October 19, 2015. The questions presented to the Supreme Court are: • When a seller offers to build generation and sell wholesale power on a fixed-rate contract basis, does the FPA field pre-empt a state order directing retail utilities to enter into the contract?; and • Does FERC’s acceptance of an annual regional capacity auction preempt states from requiring retail utilities to contract at fixed rates 8 136 S. Ct. 382 (U.S. Oct. 19, 2015) (No. 14-614). 9 136 S. Ct. 356 (U.S. Oct. 19, 2015) (No. 14-623). ENERGY M & A—PART II 263 0017 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 with sellers who are willing to commit to sell into the auction on a long-term basis? Oral argument was held February 24, 2016. Given that many states have undertaken various programs to promote the development of new resources or the retention of existing resources, the Supreme Court’s decision will inform permissible state action as applied to generation resources that participate in organized wholesale markets regulated by FERC. Connected Entities Rulemaking and Reporting by Market Participants On September 17, 2015, FERC issued a notice of proposed rulemaking (“NOPR”) that seeks to require each regional transmission organization (“RTO”) and independent system operator (“ISO”) to deliver to FERC electronic data on an ongoing basis from their respective market participants that would (1) list their “Connected Entities,” (2) describe the nature of the relationship with each Connected Entity, and (3) identify each market participant using a common alpha-numeric identifier. FERC stated that the data collection would enhance transparency and assist FERC in screening and investigating cases involving market manipulation by providing the Office of Enforcement with a more complete view of the relationships between market participants and the incentives underlying their trading activities. The NOPR specifically notes that the targeted information will enhance FERC’s ability to identify and prosecute “cross-commodity” market manipulation, a common theory of many of FERC’s largest enforcement actions in recent years. In order to incorporate the new data submission requirement, FERC proposes that each RTO and ISO make a compliance filing setting forth in their respective tariffs a requirement that market participants submit a list of their Connected Entities, which would be defined to include: 1) an entity that directly or indirectly owns, controls, or holds with power to vote, 10 percent or more of the ownership instruments of a market participant, or an entity 10 percent or more of whose ownership instruments are owned, controlled, or held with a power to vote, directly or indirectly, by a market participant; 2) the chief executive officer, chief financial officer, chief compliance officer, and the traders of a market participant; 3) an entity that is the holder of a debt interest or structured transaction that gives it the right to share in the market participant’s profitability above a de minimis amount; or 4) entities that have entered into an agreement with a market participant that relates to the management of resources that participate in PRATT’S ENERGY LAW REPORT 264 0018 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 FERC-jurisdictional markets, such as tolling agreements, operating agreements, and management agreements. As proposed, this new rule could impose substantial, new record-keeping and reporting burdens on market participants and investors and potentially could lead to penalties for any failure to provide complete and accurate information. In December 2015, FERC held a technical conference to answer questions and provide further explanation of the Connected Entities NOPR, and in late January 2016, parties submitted written comments to FERC on the proposed rule. Numerous coalitions, trade groups and industry representatives argued in their written comments that the Connected Entities NOPR, as currently drafted, would be costly and time-consuming to implement, is overly vague, and is not the right tool to achieve the objectives identified by FERC. Many commenting parties also argued that FERC could issue a rule with a more limited definition of Connected Entity that would impose far less of a burden on market participants and be equally effective at providing the desired transparency. Some parties also filed comments in support of the proposed rule, but most of those parties still argued for some clarification, narrowing or exclusions to application of the proposed rule. There is no timetable for final FERC action on the Connected Entities NOPR. Considering the focus the Commission and Chairman Bay have placed on the agency’s enforcement capabilities, however, and the enforcement-related objectives identified in the Connected Entities NOPR, it seems likely that there will be further action and a final order on the Connected Entities NOPR in 2016. Deliverability of Fuel Supply for Fossil-fired Electric Generators The industry saw a continued focus on fuel deliverability in 2015, including further evolution of FERC’s natural gas-electric coordination studies, and major developments in the statues and regulations affection the exportation and transportation of crude oil. Natural Gas-Electric Coordination FERC took the next major step in advancing its efforts to enhance reliability of the electric grid through better coordination of gas and electric supply. In two final rules issued in 2015, FERC amended its regulations to adopt industry standards that moved the nationwide deadline for submitting nominations during the Timely Nomination Cycle (i.e., the first opportunity for scheduling natural gas transportation service during a gas operating day (“Gas Day”)) from 11:30 a.m. Central Clock Time (“CCT”) to 1:00 p.m. CCT. The standards ENERGY M & A—PART II 265 0019 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 adopted by the final rule also modified the intraday nomination timeline, adding an additional intraday scheduling opportunity (the “Intraday 3 Nomination Cycle”) during the Gas Day. FERC further amended its regulations to require pipelines to permit shippers to sign multi-party contracts, pursuant to which the contracting shippers would be able to share capacity under a single contract for which those shippers would be jointly and severally liable for payment. In the final rulemaking proceedings, FERC declined to adopt a proposal that would have more closely aligned the Gas Day with the electricity operating day. The proposal would have made the start of the Gas Day earlier (moving it from 9:00 a.m. to 4 a.m.) so that electric generators could respond to reductions or interruptions in the midst of the morning electric ramping period. FERC found that moving the start of the Gas Day was not supported by the evidence and that the lack of alignment between the start of the gas and electric nominating cycles had only been shown to have caused problems in isolated markets. With the completion of the rulemakings discussed above, FERC has addressed two of the four primary areas it identified in 2013 for further study or rule development to enhance gas and electric coordination. FERC addressed the first area in a 2013 rule that expressly authorized the day-to-day sharing of non-public, operational information between electric transmission operators and interstate natural gas pipelines. Other than the changes to its regulations related to multi-party contracts, FERC has yet to formally study or propose rules to address (1) the lack of alignment between firm and non-firm gas transportation products and electric market commitments, or (2) regional differences in resource mix, climate, scheduling, and other factors. Developments in Crude Oil Export and Transportation Policy Two major developments occurred in 2015 that could have profound impacts on the crude oil production sector. First, in December 2015, President Obama signed into law legislation lifting the decades-old ban on the exportation of unprocessed U.S. crude oil. Effective immediately, companies can begin exporting most types of crude oil produced in the U.S. without the need to seek any export permits from the federal government. Second, on May 1, 2015, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a final rule adopting requirements focused on the safe transportation of flammable liquids, including crude oil and ethanol, by rail (“Final Rule”). The Final Rule necessitates extensive retrofitting of existing railroad tank cars under a relatively aggressive timeline, high standards for new construction of tank cars, and stringent requirements for enhanced braking systems for certain trains. The new regulations have far-reaching and costly implications for the U.S. fuel transPRATT’S ENERGY LAW REPORT 266 0020 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 portation industry and producers in regions served by rail tank car transport. The Final Rule became effective in July 2015. FERC Enforcement Activities In 2015, the Federal Energy Regulatory Commission assessed civil penalties against several entities that elected to pursue litigation in the United States District Courts rather than settle or litigate the allegations before FERC. If those proceedings are resolved through litigation, they should either affirm or curtail FERC’s expansive view of its enforcement authority. Powhatan Energy Fund, LLC FERC issued an order Assessing Civil Penalties alleging that Powhatan Energy Fund, LLC, Houlian “Alan” Chen, HEEP Fund, Inc. and CU Fund, Inc. violated FERC’s Anti-Manipulation Rule by engaging in fraudulent Up-To Congestion trades in the PJM market in the summer of 2010. FERC determined that the respondents had engaged in wash trades that did not involve economic risks to improperly collect certain market payments. FERC assessed a total of $29.8 million in civil penalties and $4,718,784 in disgorgement. FERC filed a petition in the U.S. District Court for the Eastern District of Virginia to enforce its Order on July 31, 2015. On October 19, 2015, the respondents filed a motion to dismiss the petition. On January 8, 2016, the court denied that motion without prejudice and on January 15, 2016, the court scheduled a settlement conference for April 12, 2016. City Power Marketing, LLC FERC issued an Order Assessing Civil Penalties against City Power Marketing, LLC, and its owner K. Stephen Tsingas, alleging violations of FERC’s Anti-Manipulation Rule by engaging in fraudulent Up-To Congestion trades in the PJM market during the summer of 2010. FERC determined that the respondents engaged in three types of trades to improperly collect Marginal Loss Surplus Allocation (“MLSA”) payments intended for bona fide Up-To Congestion trades: (1) round-trip trades that constituted wash trades, (2) trading between export and import points that had the same prices, and (3) trading between two points (which had minimal price differences) not to profit from spread changes but instead for the purpose of collecting MLSA payments. FERC also found that City Power had violated section FERC’s regulations by making false and misleading statements and material omissions in its communications with Enforcement staff to conceal the existence of prevalent instant messages. FERC assessed $14 million in civil penalties against City Power and $1 million against Tsingas and ordered disgorgement of $1,278,358 in unjust profits, plus interest. On September 1, 2015, FERC filed a petition in the U.S. ENERGY M & A—PART II 267 0021 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:23 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 District for the District of Columbia to enforce FERC Order. On November 2, 2015, the respondents filed a motion to dismiss the petition, and that motion remains pending with the court. Barclays Bank, PLC FERC issued an Order Assessing Civil Penalties on July 16, 2013. In the order, FERC determined that Barclays Bank, PLC, and several of its traders had violated FERC’s Anti-Manipulation Rule by engaging in loss-generating trading of next-day, fixed-price physical electricity on the Intercontinental Exchange with the intent to benefit financial swap positions at primary electricity trading points in the western United States. FERC assessed civil penalties of $435 million against Barclays and $18 million against the named traders and ordered Barclays to disgorge $34.9 million in unjust profits, plus interest. On October 9, 2013, FERC filed a petition in the United States District Court for the Eastern District of California to enforce the civil penalty assessment. The respondents, in turn, filed a motion to dismiss the complaint or transfer venue, which the court denied in full on May 20, 2015. The court held that: 1) the manipulative scheme was jurisdictional to FERC and not within the Commodity Futures Trading Commission’s exclusive jurisdiction; 2) the occurrence of transactions on an open market is not a defense to manipulation; 3) the Federal Power Act’s anti-manipulation provision10 applies to individuals; 4) venue was proper in the Eastern District of California; 5) transfer to the Southern District of New York was not warranted; and 6) the statute of limitations had not run. On October 2, 2015, the court issued a scheduling order indicating that it will proceed with this case by reviewing FERC’s Order (and underlying administrative record) and will also consider whether a determination as to this penalty assessment requires supplementation of the record submitted by FERC and/or alternative means of fact-finding. Lincoln Paper & Tissue, Inc. FERC issued two Orders Assessing Civil Penalties in which it determined that Lincoln Paper and Tissue LLC, Competitive Energy Services LLC, and Richard Silkman had violated FERC’s Anti-Manipulation Rule in connection with a demand response program. FERC found that respondents had engaged 10 16 U.S.C. Section 824v. PRATT’S ENERGY LAW REPORT 268 0022 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 in a scheme to fraudulently inflate Lincoln’s energy load baselines and then offer load reductions against that inflated baseline. FERC assessed civil penalties of $5 million against Lincoln, $7.5 million against CES, and $1.25 million against Silkman and ordered disgorgement of $379,016 from Lincoln and $166,841 from CES, plus interest. On December 2, 2013, FERC filed two petitions in the U.S. District Court for the District of Massachusetts to enforce those penalty assessment orders (one against Lincoln and another against CES and Silkman). The court held a hearing on the respondents’ motion to dismiss. Maxim Power Corporation On May 1, 2015, FERC issued an Order Assessing Civil Penalties for violations of FERC’s Anti-Manipulation Rule. A civil penalty of $5 million was assessed against Maxim and a civil penalty of $50,000 was assessed against Kyle Mitton, an energy analyst at Maxim. FERC alleged that the respondents engaged in a scheme to mislead the ISO-NE market monitor to collect make-whole payments for reliability dispatches based on the price of oil when Maxim’s plant actually burned less expensive gas. FERC filed a petition to enforce the penalties on July 1, 2015 with the U.S. District Court of the District of Massachusetts. The defendants filed a motion to dismiss, which remains pending before the Court. FERC also settled several matters related to the electric industry that included violations of reliability standards, violations of FERC’s AntiManipulation Rule, and violations of FERC’s Prohibition of Electric Energy Market Manipulation. Western Electricity Coordinating Council FERC approved a settlement with Western Electricity Coordinating Council (“WECC”) on May 26, 2015 related to the 2011 outage that occurred in Southern California, Arizona and Baja California, Mexico leaving five million people without power for up to twelve hours. WECC agreed to pay a $16 million civil penalty. FERC resolved findings related to system operating limits and interconnection reliability operating limits. California Independent System Operator FERC approved a Stipulation and consent Agreement on November 28, 2014 that resolved an investigation of California Independent System Operator (“CAISO”) resulting from a September 8, 2011 power outage that left 2.7 million customers without power for multiple hours. FERC investigation determined that the entities responsible were not prepared to ensure reliable operation or prevent cascading outages in the event of a single contingency. CAISO agreed to pay $6,000,000 in a civil penalty. ENERGY M & A—PART II 269 0023 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 Coaltrain Energy L.P. On September 11, 2015, FERC published a “Staff Notice of Alleged Violations” that Coaltrain Energy L.P., its co-owners Peter Jones and Shawn Sheehan, its traders Robert Jones, Jeff Miller, and Jack Wells as well as its analyst Adam Hughes violated FERC’s Anti-Manipulation Rule by devising and executing a scheme to manipulate the Up-To Congestion trading in PJM Regional Transmission Organization between June and September 2010. EtraCom LLC On July 27, 2015, FERC published a “Staff Notice of Alleged Violations” that EtraCom LLC and Michael Rosenberg violated FERC’s AntiManipulation Rule by engaging in manipulative virtual trading at the New Melones Intertie in the California Independent System Operator footprint during May 2011. ERCOT The Electric Reliability Council of Texas (“ERCOT”) saw record peak demands in 2015, and much of that demand seems to have been driven by population and economic growth as much as by weather. Nevertheless, reserve margins appear to have been sufficient, and resource adequacy discussions remained largely on the back burner. The final step in a multi-year phase-in raised the price cap (the System Wide Offer Cap) in ERCOT to $9,000/MWh effective June 2015; and the market continued to assess the performance of a new operating reserve demand curve (“ORDC”). Three issues that attracted attention in 2015 were efforts to overhaul the ERCOT ancillary services market, the proposed sale of Oncor Electric in connection with the EFH bankruptcy, and a debate over whether to address load growth in the Houston area through regulated transmission construction or by relying on market incentives for the construction of new generation. The proposed sale of Oncor is addressed elsewhere in this document. The Future Ancillary Services initiative and the Houston Import Project are summarized here. Future Ancillary Services In November 2014, ERCOT filed Nodal Protocol Revision Request (“NPRR”) 667 with the Protocol Revision Subcommittee (“PRS”) proposing to introduce some new and redefined ancillary services. NPRR 667 responds to an increase in inverter-based generation resources, such as wind and solar, and also to new technologies that change the ways in which various generation resources can provide ancillary services. NPRR 667 would separate frequency response services and contingency response service, which are bundled in the current PRATT’S ENERGY LAW REPORT 270 0024 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 responsive reserve service. It would also recognize that fast frequency response has greater value than primary frequency response under certain system conditions and would tie the amount of primary frequency response that a resource can provide to that resource’s past performance. Non-spin reserve service would be replaced by several contingency reserve and supplemental reserve services, which would more closely track system conditions. Under NPRR 667, no single resource would be permitted to carry more than 25 percent of the total ERCOT system regulation requirement, thus ensuring that there are, at all times, at least four different resources providing that service. In December 2014, NPRR 667 was tabled. Comments were filed by a number of parties in January and February of 2015. In December 2015, the Brattle Group published a cost-benefit analysis of the proposal.11 New comments (following the Brattle report) were filed on January 25, 2016, and a workshop was held on February 1, 2016. PRS was expected to take up NPRR 667 at its February 11, 2016 meeting. If approved, it still would have to go through one or more other subcommittees and then to the Technical Advisory Committee (“TAC”) and the ERCOT Board. Houston Import Project In April 2104, the ERCOT Board of Directors voted to endorse a new transmission project—the Houston Import Project—to increase the capacity to import power into the Houston area and deemed the project critical for reliability. In May 2014, NRG and Calpine challenged ERCOT’s decision at the PUC, arguing that ERCOT had ignored its own protocols in determining the need for the new line. In November, the PUC rejected the challenge by NRG and Calpine, finding that ERCOT had followed the proper procedures. At the same time, however, the PUC voted to open a new rulemaking project to review the transmission planning process at ERCOT. NRG and Calpine appealed the PUC’s ruling. In early 2015, however, CenterPoint Energy and Cross Texas Transmission filed applications seeking certificates of convenience and necessity authorizing them to build their respective portions of the Houston Import Project. With the filing of the CCN cases, the focus of this debate shifted away from the NRG/Calpine appeal and the rulemaking toward the contested CCN cases. In addition to challenging many of the assumptions and methodologies used by ERCOT and the utilities to support the need for the project, NRG and Calpine argued that relying on a transmission solution would disrupt the 11 Available at http://www.ercot.com/content/wcm/key_documents_lists/73770/2015_11_ 03_Brattle_FAS_BCA_Study_Results_Draft.pdf. ENERGY M & A—PART II 271 0025 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 market pricing signals needed in an energy-only market to encourage generation investment in locations where it is most needed. The utilities countered that generation had not, in fact, developed in the Houston area and that the existing import paths were already showing signs of overloading. In late October 2015, the administrative law judges who heard the case recommended approving the project. The Public Utility Commissioners considered the case in a series of open meetings in December 2015 and January 2016 and ultimately voted to approve the project. As of early 2016, there has been no further movement in the NRG/Calpine appeal or in the rulemaking. CFTC The Commodity Futures Trading Commission (“CFTC”) has implemented several requirements under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), including transactional reporting requirements, which became effective in 2013, recordkeeping obligations, as well as central clearing requirements with respect to certain swaps. These clearing requirements are currently limited to specified interest rate and credit default swaps and do not yet extend to energy-related derivatives. Parties that enter into the affected swaps for purposes of hedging risk may elect the “end-user” exception to the clearing requirement. End-users may claim the exception by filing an annual certification with a swap data repository, including a board resolution authorizing the company to enter into non-cleared swaps. The CFTC also has issued guidance on the extra-territorial application of its Dodd-Frank rules, explaining that it will regulate swaps involving non-U.S. subsidiaries of U.S. entities, as well as non-U.S. entities that either guarantee the swap-related obligations of their U.S. affiliates or that enter into swaps for the purpose of hedging the risks of their U.S. affiliates. The Securities Industry and Financial Markets Association, the International Swaps and Derivatives Association and the Institute of International Bankers filed a lawsuit challenging the CFTC’s cross-border application of its regulations. The United States District Court for the District of Columbia rejected the challenge, holding that the CFTC’s cross-border guidance does not “purport to carry the force of law” and is, therefore, not a “final agency action” subject to judicial review under the Administrative Procedure Act. According to the court, because the cross-border guidance is not a rulemaking, it “is binding on neither the CFTC nor swaps market participants.” Nevertheless, the court noted, if entities engaging in potentially regulated swaps act contrary to the CFTC’s policy guidance, they may be required to defend themselves from administrative action by the agency under the CFTC’s general extraterritorial authority granted under the DoddFrank Act. Entities entering into swaps outside the United States that nevertheless have some connection to the U.S., such as a guarantee provided by PRATT’S ENERGY LAW REPORT 272 0026 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 a U.S. person to one of the swap parties or a back-to-back swap involving a U.S. affiliate, will be faced with the decision of whether to comply with the CFTC’s Cross-Border Guidance, even though the agency has not provided binding rules as to when those requirements apply. The district court’s decision indicates that the CFTC likely will not face a high hurdle in justifying extending its regulations to non-U.S. swaps with a connection to the U.S., and that a cautious swap participant will treat the cross-border guidance as a strong indication of the way the CFTC will apply its regulations in a specific case. The CFTC has revised its prior guidance on regulation of physical commodity transactions that contain embedded volumetric optionality. Previously, it had announced that it would not regulate such transactions where the optionality cannot be severed and marketed separately from the transaction, both parties are commercial parties and intend to settle the transaction physically, and the exercise or non-exercise of the option is based primarily on physical factors or regulatory requirements outside the control of the parties. In May 2015, the CFTC clarified that the parties’ intentions should be evaluated at the time of contracting rather than each time the option is exercised, and that the optionality need not be entirely “outside the control of the parties” so long as the optionality is primarily intended to address potential variability in a party’s supply of or demand for the commodity. This recognizes that the parties can have some role in deciding whether to exercise the optionality, so long as that decision is not driven by addressing price risk. Where parties to an option do not satisfy these factors, the CFTC has announced that it will more lightly regulate commodity trade options in which the parties intend that, if exercised, the option will be physically settled. Trade options between non-swap dealers need only be reported on an annual basis (on March 1) rather than a transaction-by-transaction basis. The CFTC decreased from four Commissioners to three in 2015. In August 2015, Mark Wetjen, a Democrat whose term began in 2011, left the Commission. MEXICO IMPLEMENTS NEW WHOLESALE POWER MARKET On September 8, 2015, Mexico’s Secretary of Energy published the Bases of the Electric Market (“Bases”). The Bases outline the implementation and operation of the new wholesale power market, parts of which commenced operation in January 2016. Under the Bases, the Centro Nacional de Control de Energía (“CENACE”) will operate the wholesale power market, which will include markets for: • Electricity: The short-term energy market will be comprised of a day-ahead market, a real-time market and, in a second stage, an hour-ahead market. The short-term energy market will allow market ENERGY M & A—PART II 273 0027 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 participants to submit offers to sell and purchase energy and ancillary services. CENACE will utilize sale and purchase offers to carry out economic dispatch for each submarket. The economic dispatch algorithm will calculate locational marginal prices (“LMPs”), which will be comprised of marginal energy, congestion, and loss components. • Financial Transmission Rights: Financial Transmission Rights will grant market participants the right to charge and the obligation to pay the amount resulting from the differences in value between the marginal congestion components of LMPs between an origin node and a destination node, excluding certain costs. Financial Transmission Rights will be defined in four-hour blocks. With the exception of grandfathered (legacy) Financial Transmission Rights, Financial Transmission Rights will be sold in auctions. • Capacity: The capacity balancing market will be an annual auction in which market participants buy and sell capacity. • Clean Energy Certificates: CENACE will operate a spot market for clean energy certificates. The clean energy certificate market will be operated at least annually. Separately, parties may buy and sell clean energy certificates through independently negotiated bilateral contracts. • Medium and Long-Term Auctions: Medium-term auctions will offer three-year electricity and capacity contracts. Long-term auctions will offer fifteen-year contracts for electricity and capacity, and twenty-year contracts for clean energy certificates. Both medium- and long-term auctions will be held at least annually, although auctions may occur more frequently if required by the business practice manuals (to be released at a future date). In addition to the markets described above, market participants may enter into bilaterally negotiated contracts for electricity, capacity and clean energy certificates. Market participants may also structure bilateral contracts conveying the same rights and obligations as Financial Transmission Rights issued by CENACE. The historical lack of a private market for electricity in Mexico has led to significantly higher electricity prices in Mexico than in the United States. Indeed, on the first day of trading in the day-ahead market for Baja, California, power sold at an average price of 354.69 pesos ($19.20) a megawatt-hour—a price close to the day-ahead prices in Texas for the same day. Given that Baja, California, is much less populated than other regions of Mexico, some observers have hypothesized that prices will be even higher in more high-demand, urban centers when those regions join the market. These initial results suggest that PRATT’S ENERGY LAW REPORT 274 0028 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 Mexico’s new power market will provide a multitude of opportunities for foreign investors and new participants. DISTRIBUTED GENERATION 2015: A Mixed Year for Distributed Generation as Growth Continues In 2015, distributed generation utilizing renewable energy sources, including small-scale solar photovoltaic (“PV”) residential and commercial installations, continued to experience growth. The U.S. Energy Information Administration (“EIA”), which recently began reporting monthly state-level distributed generation data, estimates that solar energy produced 3.6 million MWhs in September 2015, of which 33 percent was generated by small-scale installations.12 The EIA also reported growth in both small-scale and utility-scale distributed solar generation capacity across the residential, commercial, and industrial sectors. The growth is generally expected to continue in 2016; EIA projects a 9.5 percent increase in all renewable electric generation resources for 2016.13 As distributed generation grew in deployment in 2015, it experienced mixed success from a regulatory perspective, and regulatory opportunities and challenges are expected to be a hallmark of 2016. Extension of the PTC and ITC The extension of the federal Production Tax Credit (“PTC”) and the Investment Tax Credit (“ITC”) for solar and wind projects in late 2015 by Congress marked an important victory for distributed generation. The 30 percent residential and commercial solar ITC was set to expire at the end of 2016, but has now been extended at the 30 percent level for projects which commence construction by the end of 2019, with step-downs in the credit level then occurring through 2022. This was covered in more detail in the section on Renewables. Regulatory Battles over Net Metering At the state-level, net metering and retail electric rate policies supporting the development of distributed solar generation experienced setbacks or challenges. Net metering allows an electric retail customer with distributed generation to receive a credit for electricity provided to the grid during those times when the 12 EIA, Today in Energy—EIA Electricity Data Now Include Estimated Small-Scale Solar PV Capacity and Generation, available at http://www.eia.gov/todayinenergy/detail.cfm?id= 23972 (Dec. 2, 2015). 13 EIA, January 2016 Short Term Energy Outlook—Electricity and Heat Generation from Renewables, available at https://www.eia.gov/forecasts/steo/report /renew_co2.cfm (Jan. 12, 2016). ENERGY M & A—PART II 275 0029 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 output of the customer’s installation exceeds the customer’s demand. The value of the credit in most states is set at the per-kWh retail rate, so that the credit offsets the customer’s retail electricity purchases on a one-to-one per-kWh basis and surplus credits are typically rolled over month to month. Utilities in states with high distributed generation penetration such as Hawaii, Nevada, and California have challenged how the net metering credit is valued, claiming that it should be set at an energy-only, wholesale-type rate, instead of the higher retail rate which includes transmission and distribution components. Many utilities argue that the lower energy-only rate more accurately reflects the value of the product provided by the customer, reduces the revenue shortfall resulting from customers relying less upon retail electricity but still remaining connected to the grid, and lessens cross-subsidization by customers without distributed generation. Proponents of the retail rate claim that distributed generation creates value beyond just electricity by reducing dispatch of fossil fuel generation, lessening transmission congestion, and promoting grid reliability. Results before state utility commissions have been mixed for both sides. In Hawaii, the Public Utilities Commission issued an order on October 12, 2015 approving a reduction in the net metering credit for new residential solar customers interconnecting the service territories of Hawaiian Electric Industries utilities (existing customers are grandfathered and will continue to receive the higher credit).14 The new credit will be set at between about 15 and 28 cents depending upon location, down from 26 to 38 cents. In addition, new residential solar customers will have a $25.00 minimum monthly bill in recognition of the costs of maintaining distribution facilities and providing other services to the customer. The Commission’s order also established a new self-supply rate option for customers who do not export electricity to the grid, as well as a time-of-use rate option. Solar advocates supporting retail-rate based net metering credits sought judicial review of the Commission’s order in Hawaii Circuit Court, but did not prevail. An appeal of that decision is anticipated by solar advocates. The Commission’s net metering order will also be followed by a second-phase proceeding in 2016 which will consider distributed generation policy on a longer-term basis. In Nevada, the Public Utilities Commission eliminated the retail-rate net metering credit for both existing and new customers of utility NV Energy in a controversial December 22, 2015 order.15 In the same order, the Commission also approved increases in the basic fixed service charge for all net metering 14 Haw. Pub. Util. Comm., Decision and Order No. 33258, Docket No. 2014-0192 (2015). 15 Pub. Util. Comm. of Nev., Order on Application of Nevada Power Co., et al., Docket Nos. 15-07041, et al. (2015). PRATT’S ENERGY LAW REPORT 276 0030 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0 customers. The Commission’s order prompted the filing of class action lawsuits against the Commission by existing distributed generation customers who made long-term investment decisions based upon the availability of the retail net metering rate. In response to customer reaction, it also prompted NV Energy to propose to the Commission grandfathering the retail rate net metering credit for existing customers for 20 years. The Commission agreed on January 25 to reconsider its decision as to whether to grandfather existing customers, and the matter is pending. In California, the Public Utilities Commission issued a final order on January 28, 2016 after a 3-2 vote adopting most of its December draft proposal to retain retail-based net metering rates for customers of California’s major utilities as part of Net Energy Metering 2.0 (“NEM 2.0”).16 Under NEM 2.0, distributed generation retail customers will receive the retail rate for electricity exported to the grid, less certain non-bypassable charges. A significant change from the December proposal is that NEM 2.0 customers will not have to pay for non-bypassable transmission charges, which has the result of lowering the non-bypassable charges paid by net metering customers. In addition to preserving retail net metering rates, the Commission also requires NEM 2.0 customers to be billed according to time-of-use tariffs which provide for different rates during different times of day depending on costs and demand. Under the order, Customers who receive NEM 2.0 service will be grandfathered for 20 years. The Commission will revisit future net metering policies again in 2019. 16 Calif. Pub. Util. Comm., Decision Adopting Successor to Net Energy Metering Tariff, Rulemaking 14-07-002 (2016). ENERGY M & A—PART II 277 0031 [ST: 247] [ED: 100000] [REL: 16-7] Composed: Fri Jun 17 14:28:24 EDT 2016 XPP 8.4C.1 SP #3 SC_00052 nllp 1898 [PW=468pt PD=702pt TW=336pt TD=528pt] VER: [SC_00052-Local:26 May 16 16:49][MX-SECNDARY: 10 Jun 16 07:46][TT-: 23 Sep 11 07:01 loc=usa unit=01898-ch1607] 0