On November 20, 2015, the Federal Energy Regulatory Commission (“FERC”) issued an order directing each regional transmission organization (“RTO”) and independent system operator (“ISO”) to submit a report addressing five categories of complex issues related to price formation in organized wholesale electricity markets. The order is the latest in a series of actions taken by FERC in its effort to understand and potentially remedy impediments to efficient price formation in the markets administered by RTOs/ISOs. The agency held technical workshops on price formation issues starting in 2014 and recently issued a notice of proposed rulemaking that would, if finalized, address a discrete set of relatively noncontroversial price formation problems (market settlement intervals and shortage pricing triggers).
FERC Reaffirms and Clarifies Exemption for Certain Qualifying Facilities from Section 203 of the Federal Power Act
On November 19, 2015, the Federal Energy Regulatory Commission (FERC) reaffirmed and clarified the exemption for certain Qualifying Facilities (QFs) from Section 203 of the Federal Power Act (FPA) set forth in Section 292.601(c) of FERC’s regulations. Specifically, FERC held that any QF that qualifies for that exemption—including those with “otherwise jurisdictional assets” such as market-based rate tariffs and generator interconnection facilities—is exempt from the requirement of Section 203(a)(1) of the FPA to obtain prior FERC authorization for certain changes in ownership or control.
FERC Proposes to Require Wind Generators to Supply Reactive Power, Seeks Comment on Compensation Methods
At its November open meeting, the Federal Energy Regulatory Commission (FERC) proposed to require all new wind generators interconnecting to the transmission grid to possess the capability to provide reactive power service. This proposal would, if adopted, end a decade-old exemption for wind plants from the reactive power obligations generally imposed on generators. FERC’s proposal highlights the difficult issue of determining how wind generators should be compensated for providing such service, however, and seeks comment on that and other issues.
Reactive power is required in an alternating current (AC) electric system to control transmission system voltage. Generators are generally obligated under the terms of their FERC-approved generator interconnection agreement to either supply or consume reactive power to help the transmission grid maintain the required voltage.
Congress passed the Public Utility Regulatory Policies Act (PURPA) in 1978. It quickly proved controversial in practice, and remains so today. PURPA introduced competition to the electric industry by creating a market for non-utility owned cogeneration (cogen) and small power production and mandating that utilities buy the power produced by these “qualifying facilities” (QFs) at the utility’s “avoided cost.” Small power producers are renewable generators of 80 MW or less that meet certain efficiency standards. Qualifying cogen can be any size.
On November 17, 2015, the Federal Energy Regulatory Commission (FERC or the “Commission”) issued an order officially terminating consideration of a three-year-old proposal to require quarterly reporting of every Natural Gas Act (NGA)-jurisdictional next-day or next-month natural gas transaction. When the Commission issued the Enhanced Natural Gas Market Transparency Notice of Inquiry (NOI) in November 2012, the Commission noted that the proposed reporting requirement would improve natural gas market transparency and enhance FERC’s ability to identify manipulative conduct in the natural gas markets. In response to the NOI, several parties filed comments raising various concerns with the proposal. Many commenters argued that the reporting requirement proposed in the NOI would not enhance natural gas market transparency, because it would apply to only NGA-jurisdictional sales, which comprise only a small portion of total natural gas sales. In addition to receiving comments, the Commission’s Office of Enforcement, in connection with the NOI, obtained additional information regarding natural gas marketing activities by sending data requests to certain natural gas marketers (the responses to which the Commission treated nonpublicly). In the November 17, 2015, order terminating the NOI proceeding, the Commission noted that “[a]fter gaining ongoing access to additional physical natural gas market data, we have determined that the NOI’s proposed reporting requirement is not necessary at this time” and that the Commission therefore would “exercise [its] discretion to terminate this proceeding.”
Notably, while the Commission officially terminated further consideration of a new natural gas transaction reporting requirement, it continues to consider implementing substantial new reporting requirements for participants in the wholesale power markets. See our prior coverage here and here.
On November 10, 2015, the Federal Energy Regulatory Commission (FERC or the Commission) scheduled a technical conference regarding its Notice of Proposed Rulemaking (NOPR) on the collection of “Connected Entity” data from regional transmission organizations (RTOs) and independent system operators (ISOs),1 which it issued on September 17, 2015.2 FERC directed its staff to convene the technical conference on December 8, 2015, and postponed the deadline for comments on the NOPR from November 30, 2015, until January 22, 2016, 45 days after the technical conference.
As we reported earlier, FERC proposed in the NOPR to amend its regulations to require each RTO and ISO to electronically deliver to FERC, on an ongoing basis, data required from its market participants that would: (i) identify the market participants by means of a common alpha-numeric identifier; (ii) list their “Connected Entities,” including “entities that have certain ownership, employment, debt, or contractual relationships to the market participants,” as specified in the NOPR; and (iii) describe in brief the nature of the relationship of each Connected Entity. FERC asserted in the NOPR that such information “is being sought to assist the Commission in its screening and investigative efforts to detect market manipulation, an enforcement priority” of the agency.
On November 6, 2015, the chairmen of several congressional energy committees and subcommittees sent a letter to the Federal Energy Regulatory Commission (FERC or “Commission”) requesting that FERC convene a technical conference to review the implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA). PURPA, a product of the energy crisis of the 1970s, sought to encourage alternate forms of energy production in what was, at the time, an industry dominated by natural monopoly electric utilities. The law requires utilities to buy power from “Qualifying Facilities,” or “QFs,” which are small, renewable generation facilities and cogeneration facilities that meet certain operating and efficiency standards.
In the past three years, the number of claims filed by renewable energy investors under the Energy Charter Treaty (ECT) has risen significantly. In particular, Spain, who had been the subject of only a handful of investor-state arbitrations prior to 2013, has been named as a respondent in 20 cases filed under the ECT. The Czech Republic and Italy (who recently completed its withdrawal from the ECT, though it remains bound by the ECT’s provisions for investments made before its withdrawal until 2035) have also been named as a respondent in investor-state arbitrations by renewable energy investors defending against three and seven claims, respectively. More claims are expected to follow. This blog post briefly explores the ECT and the recent rise in claims filed under that treaty.
The ECT is a multilateral agreement that was signed in 1994 and entered into force four years later in 1998. Its purpose was to facilitate investment and development of the energy sector and, in particular, the Eurasian energy market. The ECT provides levels of protection similar to those of Bilateral Investment Treaties. It includes seven articles on investment promotion and protection, most notably Article 10, which affords investors Fair and Equitable Treatment, Most-Favored-Nation Treatment, National Treatment, and Non-Arbitrary or Discriminatory Treatment. Article 13 includes an explicit prohibition on expropriation.
As the electric power industry considers the options for compliance with an unprecedented suite of new environmental requirements, it faces continued uncertainty as to the fate of some of the most significant new regulations. In recent months, litigation over two of the Environmental Protection Agency’s (EPA) most significant rules—the Mercury and Air Toxics Standards (MATS) and Clean Power Plan (CPP)—has moved forward swiftly. Meanwhile, the EPA has sought to provide additional guidance to states regarding the CPP’s near-term compliance plan deadline and opened a new comment period on its proposed federal implementation plan and “model trading rules,” each of which could be a key basis for many states’ plans to comply with the CPP.
States and Industry Seek Stay of CPP Pending Judicial Review
The CPP establishes limits on carbon emissions from existing fossil-fuel, electric generating units under Section 111(d) of the Clean Air Act (CAA). Pursuant to this statute, the CPP requires each state to develop a compliance plan that describes the measures it will take to achieve the required emissions reductions.
On October 21, Akin Gump’s Houston office hosted “Weathering the Oil Decline: Risks, Challenges and Opportunities in the Energy Market,” an event featuring partners from across the firm alongside financial and energy sector professionals, all of whom offered analysis and discussion around the ongoing risks, challenges and opportunities in the energy market.
Akin Gump Houston office partner in charge Chris LaFollette opened the event, which was moderated by global energy and transactions group chair Rick Burdick. Among the panelists were energy partners Shubi Arora, Mike Byrd and Bill Morris, funds partner Blayne Grady and financial restructuring partner Sarah Schultz.
To see a video recording of the event, please click here.
On October 16, 2015, the Federal Energy Regulatory Commission (FERC) issued Order No. 816, a Final Rule streamlining its requirements for authorization to make wholesale sales of electric energy, capacity and ancillary services at market-based rates (MBR), including eliminating or modifying certain filing requirements.1 FERC stated that the purposes of the Final Rule are to reduce the administrative burden of the MBR program on sellers and FERC, provide clarification regarding the standards for obtaining and maintaining MBR authority, and increase transparency while ensuring that MBRs charged by public utilities are just and reasonable. This post summarizes FERC’s major modifications and clarifications in the Final Rule, which will become effective 90 days after publication in the Federal Register.
On October 15, 2015, the Federal Energy Regulatory Commission (FERC or the “Commission”) issued an order clarifying the extent to which natural gas asset management agreements (AMAs) provide an exemption from the Commission’s prohibition on buy/sell transactions. In response to a petition for a declaratory order filed by Rice Energy Marketing, LLC, the Commission clarified that the exemption from the prohibition on buy/sell transactions for certain transactions with asset managers applies to both “delivery” AMAs and “supply” AMAs, even though the Commission previously addressed the exemption in the context of only delivery AMAs.
Akin Gump Strauss Hauer & Feld LLP partner David Burton will chair the American Wind Energy Association’s webinar on October 27 at 3 p.m. ET on YieldCos. The other panelists are Ray Wood (Managing Director – Head of U.S. Power & Renewables for Bank of America Merrill Lynch) and Julie Dumoulin-Smith (Executive Director – Equity Research, UBS Securities LLC).
YieldCos have opened up new capital markets for wind projects while creating enormous buzz around growth potential. The sector has also experienced challenges in turbulent markets; this webinar will discuss the latest news share analysis as to how YieldCos may fare in the future.
Registration for the webinar is available here.
*This blog post was originally on Tax Equity Telegraph.
On Wednesday, October 14, 2015, the parties to the U.S. Supreme Court case FERC v. EPSA made their arguments before the justices. This case involves the validity of the Federal Energy Regulatory Commission’s (FERC or “Commission”) Order No. 745, which set the level of compensation for demand response (i.e., commitments not to consume energy) sold in wholesale electricity markets run by Regional Transmission Organizations and Independent System Operators (RTOs) at the full price established for generators that sell electric energy there (i.e., the full locational marginal price (LMP)). FERC sought Supreme Court review after the U.S. Court of Appeals for the District of Columbia Circuit, in a divided March 2014 opinion, struck down Order No. 745. The D.C. Circuit held not only that the compensation structure for demand response set by Order No. 745 was arbitrary and capricious, but also, more dramatically, that FERC did not have jurisdiction over demand response. The court reasoned that FERC lacked jurisdiction because demand response is part of the retail market, which, under the Federal Power Act, is reserved exclusively for state jurisdiction. While the full scope of the latter holding has yet to be determined, at a minimum, it would prevent FERC from setting a price to be paid to demand response providers in the RTO energy markets and, likely, in the RTO capacity markets. Broader readings of this jurisdictional ruling would further limit FERC’s authority with respect to demand-side resource participation in wholesale markets generally.
Signifying a historic shift in U.S. energy policy, the House of Representatives passed legislation on October 9 that would lift the nearly 40-year ban on crude oil exports by a vote of 261 to 159. Twenty-six Democrats joined 235 Republicans to vote in favor of the bill.
During debate in the House, supporters of H.R. 702, which was introduced by Rep. Joe Barton (R-TX), emphasized the economic and geopolitical benefits of lifting the ban. Opponents, however, raised concerns about the bill’s impact on consumers, refiners and the environment. A number of members also raised concerns about the speed with which the bill was moving through the legislative process¾arguing that more time was needed to consider the implications of a policy change of this magnitude.
Arizona Increased its Tax Credit for Renewable Energy Facilities Used for Self-Consumption by Five Times per Facility, and Broadened Scope of Eligible Taxpayers
Arizona has enacted Arizona House Bill 2670 (adding Arizona Revised Statute 41-1520 and amending Arizona Revised Statutes 42-5063, 42-5159, 42-6012, 43-1083.04 and 43-1164.05), which includes taxpayer-friendly revisions to the state’s tax credit for investment in renewable energy facilities used for self-consumption (with such revisions now including defining “self-consumption” very broadly, as described below).
Taking the first formal step in its year-long effort to examine price formation issues in the wholesale energy and ancillary services markets operated by regional transmission organizations and independent system operators (RTOs/ISOs), the Federal Energy Regulatory Commission (FERC or Commission) recently issued a Notice of Proposed Rulemaking (NOPR) proposing to reform how RTOs/ISOs settle energy and operating reserve transactions and how they price energy during system shortages. The September 17, 2015, NOPR is based on the record developed in three Commission staff technical conferences on various price formation issues.
To Aid Enforcement Efforts, FERC Proposes Significant Expansion of Data Required from RTO and ISO Market Participants
On September 17, 2015, the Federal Energy Regulatory Commission (FERC) proposed to significantly expand the types and amount of data that regional transmission organizations (RTOs) and independent system operators (ISOs) collect from their market participants and provide to FERC. FERC claims that the additional market participant data is necessary to enhance its ability to detect and deter market manipulation and other anticompetitive conduct in organized electricity markets and to create a “clear window” into the sometimes complex legal and financial relationships between market participants and other entities. Specifically, FERC proposes to require each RTO and ISO to collect and electronically provide to FERC, on an ongoing basis:
- a unique, alphanumeric “legal entity identifier” (LEI) for each market participant, including sellers and buyers in any RTO/ISO market
- a list of every “Connected Entity” of each such market participant, including all entities with certain ownership, employment, debt or other contractual relationships with the market participant
- a brief description of the nature of the relationship of each Connected Entity to the market participant.
FERC estimates that the proposed reforms would affect 6,000 market participants in the six FERC-jurisdictional RTO/ISO markets and an additional 9,000 Connected Entities. Although the new requirements would not cover non-RTO/ISO market participants, FERC estimates that approximately 90 percent of electricity sales subject to its jurisdiction are made by covered market participants or companies related to them by ownership. FERC’s proposal, if adopted, would supplant existing RTO/ISO affiliate disclosure requirements, unless an RTO or ISO requested and demonstrated a “particularized need” to retain its existing affiliate disclosure rules. While FERC says that its proposal has the potential to increase efficiency for certain market participants that participate in multiple RTO or ISO markets, it could significantly increase administrative and compliance burdens for many entities.
Comments to the proposal are due November 30, 2015.
At its September 17, 2015 Open Meeting, the Federal Energy Regulatory Commission (“Commission” or FERC) issued a Notice of Proposed Rulemaking (“NOPR”) that would require the North American Electric Reliability Corporation (NERC) to provide FERC and its staff with access to certain transmission and generation reliability data collected by NERC. The NOPR, which is one of a number of recent FERC initiatives seeking increased access to industry data, is likely to raise concerns that FERC will become more aggressive in directing NERC’s future activities. It may also raise confidentiality concerns for transmission and generation owners.
Two weeks ago, a diverse group of electric industry entities in the Pacific Northwest filed a Petition for a Declaratory Order asking the Federal Energy Regulatory Commission (FERC) to decide issues raised by establishing a Centrally Cleared Energy Dispatch Market (“CCED Market”) for the region. This market would be a voluntary, centralized platform for buyers and sellers to trade energy on a 15-minute basis.
California Legislature Boosts Renewables Portfolio Standard to 50 Percent and Increases Energy Efficiency Goals; Balks at Increased Reductions in Greenhouse Gas Emissions and Petroleum Use
Following a raucous debate fueled by intense lobbying by environmental organizations and the oil industry, the California Legislature has approved an ambitious plan by Gov. Jerry Brown (D) to boost targets for renewable energy generation to 50 percent and to increase energy efficiency. However, the Legislature rejected proposals to reduce petroleum usage by 50 percent and to reduce California’s GHG emissions by 80 percent by 2050.
On September 4, 2015, the U.S. Court of Appeals for the 9th Circuit issued an opinion remanding a series of Federal Energy Regulatory Commission (FERC) orders approving, with modifications, two settlements related to wholesale power sales made in the Pacific Northwest during the 2000-2001 California energy crisis. Stopping short of considering the merits of the required modifications, the court held that FERC abused its discretion and failed to follow its own precedent by treating the settlements as “uncontested” in spite of on-the-record opposition by other market participants. Invoking the words of the classic Eagles song “Hotel California”— “[y]ou can check out any time you like, but you can never leave”—the court remanded the long-running proceedings back to FERC for further consideration within 60 days of its mandate.
On September 8, 2015, Mexico’s Ministry of Energy (SENER) published the Electricity Market Guidelines (the “Guidelines”) in the Federal Official Gazette. The Guidelines define and specify rules and procedures for the administration and operation of the Wholesale Electricity Market (the “Market”) in Mexico. SENER prepared a draft of the Guidelines in February 2015; however, the final Guidelines published last Tuesday include valuable input from users, private companies and the Federal Electricity Commission.
On September 9, 2015, the U.S. Court of Appeals for the District of Columbia Circuit denied an emergency petition filed by 15 states that sought an immediate stay of certain deadlines in the Environmental Protection Agency’s (EPA) final Clean Power Plan (CPP).
Here is a link to an article by David Burton and Richard Page published on Solar Industry’s website.
The article describes a recent Internal Revenue Service (IRS) private letter ruling that blesses individual taxpayers claiming a 30 percent tax credit under Section 25D of the Internal Revenue Code for owning solar modules that are part of a community solar project. The facts of the ruling are that the individual owners of the community solar project benefit from a net metering program with the regional utility so that the value of the electricity that the project provides to the grid reduces the electric bills for the project owners' residences. Prior IRS guidance regarding community solar had not sanctioned this type of net metering arrangement. The ruling was first made public by an industry group. Since the article was written, the IRS has also released the ruling and assigned a number to it. Here is a link to P.L.R. 201536017 (Jul. 28, 2015).
*This blog post was originally on Tax Equity Telegraph.
FERC’s Office of Energy Projects Publishes Suggested Best Practices
for Natural Gas Industry Stakeholder Outreach Programs
On July 28, 2015, following a marked increase in protests at Federal Energy Regulatory Commission (FERC) open meetings and outside FERC headquarters—which in one case to date resulted in the rescheduling of an open meeting to “better ensure the safety of [FERC] staff and the public”1 —as well as rule changes prohibiting “disruptive conduct” at FERC open meetings,2 the staff of FERC’s Office of Energy Projects (OEP) published a guide entitled “Suggested Best Practices for Industry Outreach Programs to Stakeholders” (the Outreach Guide). The Outreach Guide seeks to present best practices and highlight tools that OEP believes FERC-regulated natural gas companies “can use to effectively inform and engage stakeholders” in the application and review processes for the siting, construction and operation of interstate natural gas facilities and liquefied natural gas (LNG) terminals.
An article by David Burton and Richard Page analyzes a recent Tax Court opinion regarding the definition of a capital asset. The Tax Court case involved a real estate developer that sold its real estate and sought to treat the transaction as a sale of a capital asset, but the court held that it was the sale of an ordinary asset. The article discusses lessons from the case for renewable energy developers seeking to structure their exit strategies so as to realize capital gains. The article is available here.
*This blog post was originally on Tax Equity Telegraph.
7th Circuit Affirms FERC Finding That Wind Generators Are Responsible for Corrected Costs of Additional Interconnection Network Upgrades
On August 19, 2015, the United States Court of Appeals for the 7th Circuit deniedtwo wind generators’ (“Generators”) petitions for review of various Federal Energy Regulatory Commission (FERC) orders assigning the corrected costs of additional interconnection network upgrades to the Generators. The originally calculated costs, which were computed by the grid operator, Midcontinent Independent System Operator, Inc. (MISO), were made in error. The 7th Circuit noted that FERC, acting in accordance with its policy under Order No. 2003,1did not act arbitrarily or capriciously in assigning the corrected costs to the Generators.
Mexico’s Energy Industry: Final Model Contract and Bidding Guidelines Published for Ronda Uno, Second Tender
On August 25, 2015, the Comisión Nacional de Hidrocarburos (CNH) published the final form of the Bidding Guidelines (“Guidelines”) and the Model Production Sharing Contract (PSC) for the Second Tender initially published on February 27, 2015 (“Second Tender”). Currently, 20 companies from around the world, grouped into 14 prequalified Individual and Consortium Bidders, will vie for 5 shallow-water extraction areas located off the Gulf of Mexico coastlines of Veracruz, Tabasco and Campeche.
Click here to read the full alert.
The Environmental Protection Agency (EPA) released today a suite of requirements that impose strict new limits on the emission of volatile organic compounds (VOC) and methane by the oil and natural gas industry. The proposals include:
- new leak detection and repair requirements
- more stringent requirements for the capture of natural gas from the completion of hydraulically fractured oil and gas wells
- additional requirements to limit emissions from new and modified pneumatic pumps and equipment used at transmission compressor stations, including compressors and pneumatic controllers.
Comments on EPA’s proposal—totaling more than 1,100 pages—must be received within 60 days after the proposals are published in the Federal Register.
A Federal Energy Regulatory Commission (FERC) Administrative Law Judge last week issued an Initial Decision finding that BP America (BP) and certain related BP entities violated FERC’s Anti-Manipulation Rule. Following a 13-day hearing, Judge Carmen Cintron found that, during a two-and-a-half month period in 2008, BP sold next-day physical gas at the Houston Ship Channel (HSC) in a way designed to lower market prices at HSC to benefit BP’s corresponding short financial position. FERC’s Office of Enforcement (OE) had alleged that BP—in an effort to maintain a price spread between Katy and HSC that was favorable to BP’s financial positions—engaged in uneconomic trading and transportation of gas between Katy and HSC using the Houston Pipeline (HPL). FERC is expected to issue a final order in the case after the parties submit briefs addressing the Initial Decision.
The BP case presents many interesting legal and factual issues, not the least of which is the possibility that the case could lead to another federal appellate decision addressing the extent to which — if at all — FERC’s “in connection with” enforcement jurisdiction extends beyond the traditional jurisdictional boundaries of FERC’s authority under the Natural Gas Act (NGA) and the Federal Power Act (FPA). The Energy Policy Act of 2005 amended the NGA and FPA to provide FERC with enforcement authority over manipulative conduct “in connection with” FERC-jurisdictional transactions. FERC has interpreted this antimanipulation authority broadly to cover otherwise nonjurisdictional conduct that “affects” FERC-jurisdictional markets. In 2013, however, the U.S. Court of Appeals for the District of Columbia in Hunter v. FERC rejected FERC’s assertion of jurisdiction over allegedly manipulative trading of natural gas futures contracts on the basis that futures markets are subject to the Commodity Futures Trading Commission’s (CFTC) exclusive jurisdiction. FERC had argued in that case that its authority under the NGA to prosecute manipulation “in connection with” jurisdictional natural gas transactions allowed it to prosecute manipulative trading of nonjurisdictional futures contracts if such trading affected prices in FERC-jurisdictional markets.
U.S. Government Approves Crude Oil Swaps with Mexico While Congress Considers Repealing the Underlying Export Restrictions
On August 14, 2015, the U.S. Department of Commerce’s, Bureau of Industry and Security (BIS) indicated that it would approve a number of export license applications permitting parties in the United States to swap crude oil with counterparties in Mexico. These decisions could open a new market for U.S. oil producers who are faced with an oversupply of light crude oil and have been previously foreclosed from this export market by the U.S. ban on crude oil exports. To take advantage of this opportunity, U.S. companies will need to structure swap transactions with Mexican companies that satisfy BIS’s criteria for approval. Companies may also want to consider engaging with lawmakers in Congress who are currently contemplating legislation to repeal the export ban on crude oil altogether.
Litigation over the Environmental Protection Agency’s (EPA) recently issued “Clean Power Plan” (CPP) has already begun. On August 13, 2015, 15 States 1 (the “States”) filed an emergency petition in the United States Court of Appeals for the District of Columbia Circuit seeking an immediate stay of the deadlines in the final CPP for states to submit plans to comply with its requirements. The States’ petition describes the significant effort, time and expense they believe will be required immediately to comply with the final CPP and previews some of the legal arguments they are likely to advance in hopes of upending the rule in the courts.
The final CPP, issued on August 3, 2015 (and briefly summarized in earlier Speaking Energy coverage), establishes limits on carbon emissions from existing fossil-fuel electric generating units under Section 111(d) of the Clean Air Act (CAA). Final state compliance plans detailing how they will achieve the rule’s emission limit requirements, or an initial compliance plan with a request for extension, must be submitted to EPA by September 6, 2016. All completed final compliance plans must be submitted by September 6, 2018.
On August 10, 2015, the United States Court of Appeals for the 9th Circuit, in Northwest Requirements Utilities v. FERC, denied several petitions for review of Federal Energy Regulatory Commission (FERC) orders requiring Bonneville Power Administration (“Bonneville”)—a federal agency that markets electricity and operates a large portion of the transmission grid in the Pacific Northwest—to provide transmission service on terms “not unduly discriminatory or preferential.” FERC issued the underlying orders pursuant to Section 211A of the Federal Power Act (FPA), which was enacted by Congress in the Energy Policy Act of 2005 and allows FERC to require a transmission utility not otherwise subject to FERC jurisdiction (such as governmental entities like Bonneville and electric cooperatives) to provide transmission service on terms not unduly discriminatory or preferential.
The court did not reach the merits of the orders, which were FERC’s first exercise of its Section 211A authority. Instead, the court found that Bonneville’s wholesale electricity customers did not have “statutory standing” to challenge FERC’s orders because their interests — namely, reducing Bonneville’s costs (which are passed on to them by statutory mandate) by reducing access to Bonneville’s transmission system — did not align with the purpose of Section 211A to increase access to transmission and increase wholesale competition.
Lawyers at Akin Gump held a briefing on July 29, titled “The Global Energy Industry: 2015 Mid-Year Energy Briefing,” which looked at some of the big issues affecting the global energy industry this year. The event was held as an in-person briefing in the firm’s Houston, Washington, D.C. and London offices and as a webinar for participants around the world.
Here is a link to a North American Windpower article that David Burton and Richard Page published that discusses rules enacted in Colorado to provide for an election for tax credits for renewable energy projects in “enterprise zones” in Colorado to be refundable.
U.S. Department of Commerce Places Severe Export Restrictions on Russian Deepwater Oil and Gas Field
On August 7, 2015, the U.S. Department of Commerce’s Bureau of Industry and Security (BIS) published a final rule adding the Yuzhno-Kirinskoye Field, a Russian oil and gas field located in the Sea of Okhotsk, to its Entity List, a restricted party list maintained by BIS which identifies foreign persons that engage in activities contrary to U.S. national security and/or foreign policy interests. Consequently, exports, reexports and transfers (in-country) of all items subject to the Export Administration Regulations (EAR) to this Russian field require a license from BIS. Furthermore, BIS will consider such license requests with a presumption of denial.
House and Senate Introduce Bipartisan Energy Packages Addressing FERC’s Role in Pipeline Processing and LNG Exports, Grid Infrastructure, Electric Reliability and Energy Efficiency
On July 22, 2015, the House Energy and Commerce Subcommittee on Energy and Power unanimously passed a diverse energy bill designed to expedite Federal Energy Regulatory Commission (FERC) natural gas pipeline reviews, modernize grid infrastructure, and promote energy efficiency and security. The 95-page bill is divided into four titles, each with a distinct aim: (i) Modernizing and Protecting Infrastructure, (ii) 21st Century Workplace, (iii) Energy Security and Diplomacy, and (iv) Energy Efficiency and Accountability.
In a similar move, the Senate Committee on Energy and Natural Resources unveiled its 357-page iteration, The Energy Policy Modernization Act of 2015, which features five titles similar to the House’s bill: (i) Efficiency, (ii) Infrastructure, (iii) Supply, (iv) Accountability, and (v) Conservation. After initial markups, the Senate bill passed the committee stage by a vote of 18-4.
Mexico’s Energy Industry: Updated Bidding Guidelines and Contract Terms for Ronda Uno, Second Tender
On August 4, 2015, the Comisión Nacional de Hidrocarburos (the CNH) released revised versions of the Bidding Guidelines (the Guidelines) and the Model Production Sharing Contract (the PSC) for the Second Tender published on February 27, 2015 (the Second Tender). The Second Tender contains five (5) mature contract areas located in shallow waters off the Gulf of Mexico coastlines of Veracruz, Tabasco and Campeche.
Click here to read the full alert.
EPA’s Clean Power Plan: Tougher CO2 Emissions Requirements, but More Time and Flexibility to Meet Them to Ensure Electric Grid Reliability
On August 3, 2015, the Environmental Protection Agency (EPA) issued the “Clean Power Plan” (CPP). The much-anticipated final rule establishes limits on carbon (CO2) emissions from existing fossil-fuel electric generating units under Section 111(d) of the Clean Air Act.
Policy-makers and industry participants have raised a variety of legal and technical concerns since EPA first proposed the CO2 emissions limits in June 2014. The Federal Energy Regulatory Commission (FERC) and industry participants have focused particular attention on the potential impact of such limits on the reliability of the electric grid, given the massive changes in the energy supply portfolio envisioned by the proposed rule. As we reported in earlier coverage in Speaking Energy, in May of this year, all five sitting FERC commissioners signed a joint letter to EPA highlighting industry concerns regarding the timing of the proposed CO2 emissions reductions and outlining two potential roles that FERC (as well as planning authorities and reliability entities) could play to address any reliability issues that arise during the process of complying with a final rule. EPA adopted several changes in the final CPP to address potential legal challenges and technical concerns raised in response to the proposed rule. Among the changes are certain additional measures that respond to reliability concerns and the FERC commissioners’ suggestions regarding reliability issues.
On July 30, 2015, two weeks after the Office of Enforcement (OE) of the Federal Energy Regulatory Commission (FERC) issued a staff notice of alleged violations (“Notice”) to Columbia Gas Transmission LLC (“Columbia Gas”) for “failing to post . . . notices of the auctions of its available firm capacity on the public side of its Electronic Bulletin Board (EBB) . . . between January 1, 2010 and May 1, 2013,” FERC approved a settlement between OE and Columbia Gas that resolves “all issues relating to the transparency of Columbia Gas’ auctions of its available firm capacity.” Under the settlement, Columbia Gas admits that the conduct at issue violated its FERC Gas Tariff and agrees to pay a $350,000 civil penalty. FERC did not require additional compliance measures, because Columbia Gas has already implemented improved compliance procedures, including “written procedures and internal controls to ensure Columbia Gas reports accurate and consistent data in its posted capacity reports.”
On July 27, 2015, the Comision Reguladora de Energia (CRE) issued its proposed regulations for the pipeline transportation and storage of petroleum, LNG and petrochemicals (Midstream Regulations). They are currently under review and open for public comments at the Comision Federal de Mejora Regulatoria (“COFEMER”), a federal entity in charge of managing all procedural aspects of any federal regulatory proposals. Based on the timeline established in the Ley de Hidrocarburos enacted on December 2013, the Midstream Regulations must be published and enacted by August 11, 2015.
The governor of Iowa has signed into law House File 645 (the “Act”)modifying statutory provisions related to Iowa’s renewable energy tax credits, effective June 26, 2015.1 There are four primary changes, three of which are beneficial to renewable energy investors and one of which is detrimental.
For taxpayers who decide to pursue Iowa’s solar energy system tax credits as opposed to Iowa’s renewable energy tax credits (you cannot claim both),2 the value of the solar energy system tax credits has been revised downward, from a rate of 60 percent, to a new rate of 50 percent, of the corresponding federal tax credits applicable to the taxpayer.3 The applicable federal tax credits a taxpayer would rely on to claim Iowa’s solar energy system tax credits would be either (1) the residential energy-efficient property credits related to solar energy provided in Sections 25E and 25D of the Internal Revenue Code, or (2) the energy credits related to solar energy systems provided in Section 48 of the Internal Revenue Code,4 which is commonly referred to as the “federal Investment Tax Credit,” or simply the “ITC.”
Rebutting the Fraud-on-the-Market Presumption in Securities Class Actions: Halliburton Class Certified Over Price Impact
On July 25, 2015, Judge Barbara Lynn of the Northern District of Texas issued a formative opinion in the class actions securities arena. The case,The Erica P. John Fund, Inc., et al. v. Halliburton Co., et al., No. 3:02-CV-1152-M, is viewed as a bellwether among securities class actions due to its treatment of novel issues regarding, among other things, a defendant’s ability to disprove reliance—i.e., a causal link between alleged misrepresentations and an eventual drop in stock prices upon correction—for purposes of class certification.
Rather than requiring plaintiffs to prove reliance for each individual shareholder, securities class action cases have long permitted a more efficient approach to establish the necessary causal link. This approach, set forth in Basic v. Levinson, 485 U.S. 224 (1988), invokes a rebuttable presumption in favor of reliance if certain elements are met. Recently, in connection with the Halliburton case, the Supreme Court held this presumption can be rebutted if a defendant shows an alleged misrepresentation did not affect the market price of a security. If the presumption is rebutted, the class cannot be certified.
FERC Eliminates Annual Retail Purchaser List Filing Requirement for Exempt Wholesale Generators and Certain Other Public Utilities
On July 16, 2015, the Federal Energy Regulatory Commission (FERC) eliminated the requirement for certain public utilities, including regional transmission organizations (RTOs), independent system operators (ISOs) and exempt wholesale generators (EWGs)—approximately 900 entities in total—to file FERC-566, an annual report of such public utilities’ 20 largest retail customers for each of the three years preceding the filing date. FERC also eliminated the FERC-566 filing requirement for any public utility that has not made any reportable sales (i.e., any retail sales) in any of the preceding three years. In addition, for the approximately 200 public utilities that remain subject to the filing requirement because they make retail sales, FERC eliminated the requirements to identify individual residential customers by name and address and to notify all customers identified in FERC-566 filings. These changes will become effective on October 6, 2015.
FERC Staff Notice of Alleged Violations Accuses Columbia Gas of Failing to Publicly Post Notices of Auctions of Available Firm Capacity for Four Years
On July 16, 2015, the Federal Energy Regulatory Commission (FERC) issued a staff notice of alleged violations (“Notice”) stating that its Office of Enforcement has preliminarily determined, in a nonpublic investigation, that Columbia Gas Transmission LLC (“Columbia Gas”) violated its FERC Gas Tariff “by failing to post the notices of the auctions of its available firm capacity on the public side of its Electronic Bulletin Board (EBB), Navigates, between January 1, 2010 and May 1, 2013.” Specifically, “[b]eginning in 1993, Columbia Gas offered available firm capacity through notices of auctions posted on the public side of its EBB, Navigator,” as required by its tariff. Then, in 2008, “Columbia Gas replaced Navigator with a new software program, Navigates, which required a login ID to access its password-protected side. In 2009, the notices of the auctions were removed from the public side of Navigates and placed on its password-protected side.”
Results of Ronda Uno, First Tender
On July 15, 2015, the First Tender initially published on December 11, 2014 (First Tender), came to a conclusion when the Comisión Nacional de Hidrocarburos (CNH) conducted the Opening and Presentation of Bid Proposals Ceremony. This historic event marked the official reopening of the Mexican energy industry to global participants after more than seventy (70) years.
Click here to read the full alert.
On July 14, 2015, Iran and the P5+1 countries (China, France, Germany, Russia, the United Kingdom and the United States), with the High Representative of the European Union for Foreign Affairs and Security Policy, finalized the Joint Comprehensive Plan of Action (JCPOA), a nuclear agreement that would grant Iran sanctions relief in exchange for implementing significant limitations on its nuclear program.
Under the agreement, Iran will be required to remove two-thirds of its uranium-enriching centrifuges and reduce its existing low-enriched uranium stockpiles by up to 98 percent, among other nuclear-related measures. President Obama emphasized Tuesday that the agreement, which is expected to freeze most of Iran’s nuclear efforts for a decade, is “not built on trust,” but “verification.” The International Atomic Energy Agency (IAEA) will monitor and verify Iran’s nuclear-related measures and inspect its facilities, including military sites. If any issues or disputes arise over Iran’s nuclear commitments, a joint commission, consisting of the P5+1 and Iran, will attempt to resolve the matter over a 30-day period. If unresolved after 30 days, the issue will be referred to the United Nations Security Council (UNSC), which will vote on whether to continue sanctions relief or re-impose sanctions on Iran.
In exchange, most European Union (EU) and U.N. sanctions against Iran will be lifted. The United States will generally remove sanctions that apply to non-U.S. persons. U.S. sanctions will continue to apply to non-U.S. entities owned or controlled by U.S. persons, but certain transactions by such entities may be licensed if they are consistent with the terms of the JCPOA. U.S. sanctions that apply to U.S. persons will largely remain in place, with the exception of a permissible licensing regime for the importation into the United States of Iranian carpets and foodstuff (including caviar and pistachios), and trade in civil aircraft and parts. In sum, Iran will still be subject to robust U.S. sanctions, but opportunities will exist for certain non-U.S., as well as U.S., companies in a limited number of industries.
On July 7, 2015, the Federal Energy Regulatory Commission (FERC) issued a notice seeking comments on a petition for rulemaking filed by the American Wind Energy Association (AWEA). The petition asks FERC to implement reforms to the rules governing the interconnection of electric generation facilities to the transmission system, which typically involves a complex and time-consuming interconnection study process conducted by the relevant transmission provider. AWEA argues in its petition that reforms to FERC’s pro forma Large Generator Interconnection Procedures (GIP) and Large Generator Interconnection Agreement are necessary to address various challenges in the interconnection process that are presenting barriers to entry for new development. The proposed reforms involve, among other things, enhancing certainty and timeliness in the interconnection study process.
For example, AWEA notes in the petition that transmission providers have no real obligation under their governing rules to provide timely interconnection study results, because they are held to a vague and difficult-to-enforce “reasonable efforts” standard. While FERC’s pro forma GIP provides approximate time frames for the study process, AWEA argues that the “reasonable efforts” standard imposes no consequences on a transmission provider that fails to comply with the GIP timelines. AWEA therefore asks FERC to remove the “reasonable efforts” standard from the pro forma GIP and require transmission providers to provide study results by the dates listed in the provider’s GIP. AWEA proposes financial penalties for transmission providers that fail to adhere to the study timelines.
Ronda Uno, First Tender
On June 9, 2015, the Comisión Nacional de Hidrocarburos (“CNH”) published the final form of the Bidding Guidelines (“Guidelines”) and the Model Production Sharing Contract (“PSC”) for the First Tender initially published on December 11, 2014 (“First Tender”). Currently, 38 companies from around the world, grouped into 26 prequalified Individual and Consortium Bidders, will vie for 14 shallow-water Contract Areas located in the Gulf of Mexico. Even though the deadline to qualify as Individual and/or Consortium Bidders has passed, much action is yet to come, since (i) Consortia may add new financing partners or Individual Bidders to their groups, (ii) Operators may present bids with their Consortium partners or proceed as Individual Bidders, and (iii) Individual Bidders may still join a Consortium as an Operator or as a financing member (subject to prior notice requirements and the CNH’s final approval). Capitalized terms not defined herein have the meanings ascribed to such terms in the Guidelines and PSC.
This email alert highlights the last changes in the final Guidelines and PSC, as well as a general overview of the most relevant features therein. The final Guidelines and PSC have significantly evolved since they were first published, mainly driven by an open dialogue between the Mexican government and international and domestic oil and gas companies, and the fluctuating global energy market conditions. Overall, while not perfect, it seems that these documents provide a fundamentally sound framework to analyze, prepare and present competitive bids, as well as to establish successful, productive and competitive exploration and production projects in Mexico for the next 30 years.
On May 15, 2015, the five sitting Federal Energy Regulatory Commission (FERC) commissioners sent a joint letter to Janet G. McCabe, acting assistant administrator of the Environmental Protection Agency (EPA), regarding the EPA’s Clean Power Plan (CPP) proposal. With the final CPP proposal from the EPA expected this summer, FERC and other industry participants have expressed a concern about how the new rules to reduce CO2 emissions from power plants may affect the reliability of the electric grid. The commissioners described in their letter two potential roles that FERC could play in the CPP proposal that may address some of these concerns.
Senator Angus King Introduces the Free Market Energy Act of 2015 to Promote the Integration of Distributed Energy Resources
On May 6, 2015, Sen. Angus King (I-ME) released a discussion draft of the Free Market Energy Act of 2015 (the “Act”), a bill that would radically change the landscape for distributed energy resources (DERs) – small-scale renewable generation, energy storage and demand response, among others – by establishing a set of parameters for the governance of DERs at the state level. In effect, as Sen. King says in a press release accompanying the Act, the parameters would “protect the right of people to connect their technology to the grid, ensure that grid-owners and operators receive their due compensation, and support the continued development of energy resources.”
At its core, the Act would amend the Public Utility Regulatory Policies Act of 1978 (PURPA) to direct states to “consider just and reasonable rates for DERs” through the unbundling of rates by taking into account a DER’s time-of-use pricing, locational value, capacity, peak monthly demand, and societal value, among other factors. However, if a state chooses not to implement unbundled rates, the Act would amend PURPA so that DERs in those states would be treated as Qualifying Facilities (QFs). In receiving QF status, a utility would be required to purchase the excess output of the DER at the utility’s full retail electricity rate, or net energy metering. The Act anticipates that costs associated with the integration of DERs and net metering may force utilities to impose monthly fees on its customers, and, thus, caps any such fee at $10 a month. Other benefits of a DER receiving QF status under the Act could include the following, based on a unit’s generation type and size: (i) guaranteed interconnection to the grid, (ii) exemption from the Public Utility Holding Company Act of 2005 and (iii) an exemption from certain Federal Energy Regulatory Commission filing requirements.
IRS Comes Out With Proposed Regulations Clarifying the Scope of Assets and Activities That Qualify for MLP Treatment
On May 5, 2015, the IRS issued proposed regulations that provide guidance on whether income from activities with respect to minerals or natural resources is qualifying income for publicly traded partnerships (MLPs). The proposed regulations come after a long pause in the IRS’s issuance of rulings in this area while the IRS studied the issues. Prior to the proposed regulations, the authority in the minerals and natural resources MLP area was limited to the statute, legislative history and a body of private letter rulings that could not be relied upon by anyone as binding legal precedent other than the taxpayer that received the ruling.
Under the proposed regulations, qualifying income includes only income and gains from “qualifying activities” with respect to minerals or natural resources. For this purpose, “qualifying activities” include exploration, development, mining or production, processing, refining, transportation and marketing of minerals or natural resources, as well as certain active support activities that are “intrinsic” to the exclusive list of activities described above.
On April 16, 2015, the Federal Energy Regulatory Commission (FERC) issued Order No. 809, its Final Rule regarding the coordination of scheduling between interstate natural gas pipelines and electric public utilities. FERC ordered several scheduling changes and revised its regulations to require pipelines to offer multiparty firm transportation contracts upon shipper request. However, FERC declined to change the start of the natural gas operating day (“Gas Day”), stating that the record did not support such a change, given its possible detrimental effects on natural gas pipeline operations.
Increasing dependence on natural-gas-fired generation has focused attention on scheduling mismatches between natural gas pipelines and gas-fired generation facilities, particularly after extreme cold weather events in the Southwest and Northeast highlighted the need for improved coordination. After hosting multiple technical conferences on gas/electric interdependence and coordination, FERC issued a Notice of Proposed Rulemaking (NOPR) that proposed three changes to gas scheduling practices: (1) move the start of the Gas Day from 9 a.m. Central Clock Time (CCT) to 4 p.m. CCT; (2) move the start of the first day-ahead gas nomination opportunity (the “Timely Nomination Cycle”) from 11:30 a.m. CCT to 1 p.m. CCT and (3) provide for four intraday nomination cycles, as opposed to two. The NOPR also proposed requiring that pipelines offer multiparty transportation contracts that would allow multiple shippers to share pipeline capacity to increase flexibility.
On April 30, 2015, the Comisión Nacional de Hidrocarburos (CNH) released a revised version of the Bidding Guidelines for the First Tender published on December 11, 2014. This first tender seeks to auction fourteen (14) shallow water exploration and production blocks in the Gulf of Mexico under a production-sharing scheme.
The most relevant change in the recently revised Bidding Guidelines is the extension of the timeline for the CNH to review and publish the parties that will be prequalified to present bids. As indicated in the timeline here, the dates have been extended from May 8 to May 20 and from May 15 to May 25, respectively.
On April 21, 2015, the Supreme Court issued a divided opinion declining to find federal pre-emption by the Natural Gas Act (NGA) of certain state antitrust claims. In Oneok, Inc. v. Learjet, Inc., a group of manufacturers, hospitals and other institutions that buy natural gas directly from interstate pipelines (the “Respondents”) sued a group of interstate pipelines, alleging that the pipelines had engaged in behavior that violated state antitrust laws. The question before the Court was whether the NGA pre-empted Respondents’ state-law antitrust claims. In a split decision, the majority held that it did not, with Justices Scalia and Roberts dissenting. Justice Thomas wrote a concurring opinion.
In the competitive natural gas markets, purchasers rely on privately published price indices to determine appropriate prices for their natural gas contracts. These indices reflect the price of the commodity in various competitive markets in the United States and are based on voluntarily reported information from natural gas traders. The alleged anticompetitive behaviors of the pipelines in this proceeding involved false price reporting, wash trades and other collusive behaviors that distorted the price indices on which customers relied when setting contract rates. The Respondents alleged that they overpaid for certain transactions with the pipelines due to these manipulative behaviors. Importantly, the alleged practices of the pipelines affected both wholesale and retail sales of natural gas.
Several states and Murray Energy Corp. (“Murray Energy”), supported by numerous intervenors and amici, presented oral arguments today before the D.C. Circuit challenging the Environmental Protection Agency’s (EPA) proposed rule establishing carbon emissions guidelines for existing power plants.1 Petitioners received rigorous questioning from Judges Griffith and Kavanagh on both the jurisdictional hurdles to their challenge and the substance of their arguments. It appears likely that this critical piece of the Obama administration’s climate policies will survive its first test.
By making their challenge to EPA’s proposed rule, the petitioners had to overcome arguments that the case was not ripe because EPA had not yet issued a “final agency action” suitable for judicial review and that petitioners had no standing to sue.
Akin Gump partner Ed Zaelke will be moderating a panel at WINDPOWER 2015 in Orlando, Florida on May 18-21, 2015, and he invites our Akin Gump friends and family to receive a $50 discount to attend. WINDPOWER is one of the most powerful gatherings of the wind energy industry in the world and registering as an event attendee is a perfect way to experience the wind industry for three full days of education, networking, and exhibition.
Please click here to register, and enter promotional code SPKWP50 to receive $50 off.
In a move designed to breathe life into the United Kingdom’s North Sea oil and gas industry, the United Kingdom’s Chancellor of the Exchequer has announced a suite of tax cuts as part of the 2015 Budget. The cuts are a response to falling oil prices and industry lobbying to reverse previous increases, with the sector suffering its worst performance since the 1970s.
Today, negotiators from the United States, Iran and other world powers announced they have agreed on a framework for a Joint Comprehensive Plan of Action regarding Iran’s nuclear program to be finalized by June 30, 2015. This framework provides a path towards potential easing of international sanctions on Iran, if negotiators succeed in working out a final agreement with Iran in the weeks ahead. However, there have been no changes yet in established U.S. and EU sanctions measures. Moreover, the scope of potential sanctions relief ultimately possible through this process appears to be limited to sanctions measures that focus on Iran’s nuclear program and does not extend to other Iran sanctions connected with antiterrorism and proliferation.
Congressman Ed Whitfield Proposes Means for States to Avoid Compliance with the EPA’s Clean Power Plan
On March 23, 2015, Congressman Ed Whitfield (R-KY), Chairman of the Energy and Power Subcommittee of the House Energy & Commerce Committee, released a discussion draft of the Ratepayer Protection Act of 2015 (the Act). According to Rep. Whitfield, the Act “would empower states to protect households and businesses from the harmful effects of” the Environmental Protection Agency’s (EPA) proposed Clean Power Plan. To do so, the Act would provide for “judicial review of any final rule addressing carbon dioxide emissions from existing fossil fuel-fired electric utility generating units before requiring compliance with such rule, and to allow States to protect households and businesses from significant adverse effects on electricity ratepayers or reliability.” The Energy and Power Subcommittee will hold a hearing on the Act on April 14, 2015, the details of, and witness list for, which are yet to be announced.
In effect, the Act would (1) delay the implementation of the Clean Power Plan until all judicial challenges to any aspect of a resulting final rule are resolved; and (2) provide a means for governors, even if all reviewing courts uphold all aspects of the Clean Power Plan, to avoid compliance if, in their judgment, doing so would significantly increase electricity rates or adversely affect reliability.
Ronda Uno, First Tender
On March 25, 2015, the Comisión Nacional de Hidrocarburos (“CNH”) released revised versions of the Bidding Guidelines (the “BG”) and the Model Production Sharing Contract (the “PSC”) for the First Tender published on December 11, 2014 (the “First Tender”). The First Tender contains fourteen exploration Contract Areas located in shallow waters off the Gulf of Mexico. Thus far, 49 companies have approached CNH to participate in the First Tender and 29 of those companies have prequalified to participate.
This summary discusses relevant changes in the BG and PSC which address some of the concerns expressed by multiple industry participants. The evolution of these terms will have a direct impact on the economic viability of the projects and should improve Mexico’s competitiveness in the global energy market.
Click here to read the full alert.
The Supreme Court heard oral arguments yesterday on whether the Environmental Protection Agency (EPA) unreasonably decided not to consider the cost of regulation when the EPA determined it was “appropriate and necessary” to regulate such emissions in the 2012 mercury and air toxics standards (MATS). Michigan v. EPA, U.S., No. 14-46, 14-47, 14-49 (argued 3/25/15) In a split decision, the U.S. Court of Appeals for the District of Columbia Circuit had upheld the MATS rule after concluding that the EPA's interpretation of the Clean Air Act was plausible and entitled to deference. White Stallion Energy Ctr. LLC v. EPA, 748 F.3d 1222 (D.C. Cir. 2014).
Three of the justices–Ginsburg, Sotomayor and Kagan–appeared willing to agree with the D.C. Circuit that the EPA’s interpretation of the statute was plausible. Chief Justice Roberts, along with Justices Scalia, Breyer, Alito and Kennedy, expressed skepticism that the statute allowed the EPA to establish control standards irrespective of the costs of compliance. Justice Thomas, as is his practice, asked no questions.
Why is change of control an issue?
In addition to contractual provisions amongst joint venture parties, change-of-control restrictions are often also included in a country’s petroleum laws.
Although these provisions can seem standard and unremarkable when licences are signed, they can cause issues resulting from subsequent corporate activities. In the United Kingdom, these provisions have arisen as existing North Sea investors divest assets through share sales.
On this issue, the government has demonstrated a concern in ensuring the suitability and financial capability of new, and often foreign, licence holders. A recent case has demonstrated the willingness of the Department of Energy and Climate Change (DECC) to use its powers to take action where it determines a new holder of a licence is unsuitable.
Entergy Sues New York’s Public Service Commissioners, Alleging Constitutional Violations in Awarding an Out-of-Market Contract to the Dunkirk Generating Facility
New York is under fire, like Maryland and New Jersey before it, for allegedly advantaging an incumbent generator competing in Regional Transmission Organization markets with an out-of-market contract. Entergy has sued the New York Public Service Commission (the “Commission”) in federal court for keeping “the uneconomic Dunkirk generator in the market for a decade (through 2025), propped up by subsidies from a local utility and from a state agency.” 1 In 2012, NRG announced that Dunkirk was uneconomic and would be mothballed. In 2013, however, New York’s governor announced that National Grid would repower Dunkirk as a natural gas-fired plant. The Commission approved an agreement by National Grid to pay Dunkirk $20.4 million a year in return for Dunkirk’s commitment to participate in NYISO’s markets through 2025. Entergy argues that this arrangement will artificially suppress market prices, which will, over time, reduce supply and, then, ultimately cause prices to rise. Entergy argues that this arrangement interferes with FERC-approved markets in violation of the Constitution’s supremacy and commerce clauses.2
On March 3, 2015, the Federal Energy Regulatory Commission (“FERC”) issued Opinion No. 531-B, 1 an order denying rehearing of Opinion No. 531.2 Opinion No. 531 involved a challenge to the New England Transmission Owners’ (NETO)3 base return on equity (ROE) reflected in the ISO New England Inc. tariff. FERC denied requests for rehearing of Order No. 531 filed by NETO, the Eastern Massachusetts Consumer-Owned Systems (EMCOS), and a group of complainants and intervenors (referred to collectively as the “Petitioners”). For our previous coverage of Opinion Nos. 531 and 531-A, click here and here.
In Opinion No. 531, FERC announced a new, two-step discounted cash flow (DCF) approach for calculating the base ROE for electric utilities. The new approach considers long-term growth projections when estimating a company’s cost of equity, while FERC’s former approach considered only short-term growth projections. FERC also established a paper hearing proceeding to consider whether the long-term growth projection should be based on projected long-term growth in gross domestic product (GDP). In Order No. 531-A, FERC concluded that the long-term GDP growth rate is the appropriate metric for determining the long-term growth rate in the DCF analysis.4 This order also established a base ROE for the NETOs of 10.57 percent (halfway between the midpoint and the top of the zone of reasonableness), with a maximum ROE, including incentives, of 11.74 percent.5
David Burton and Richard Page authored an article reviewing the cash and state tax benefits for corporate investors in solar projects in ten states. The article was published in Power Finance & Risk. Here is a link to the article.
Today, the IRS published Notice 2015-25 that provides guidance the wind power industry has been waiting for since the extension of the production tax credit (PTC) in December.
Notice 2015-25 provides that any wind power project (or other PTC-eligible project1) that started construction prior to 2015 has until the end of 2016 to be placed in service so as to avoid the application of either the “continuous construction” or the “continuous work” standards promulgated by the IRS in Notice 2013-29.2
Here is a link to the presentation from the Strafford webinar on REITs and Renewables from March 9. Akin Gump partner David Burton participated in this webinar with tax advisors from two other firms.
Akin Gump partner Dino Barajas will be speaking at the Mexican Energy Forum in Mexico City on May 11-13, 2015, and he invites our Akin Gump friends and family to receive a 10 percent discount to attend. The Mexican Energy Forum is being held in response to recent energy reforms in Mexico and will cover the complete spectrum of opportunities in Mexico’s energy sector, assessing key investment areas in the upstream, midstream/infrastructure, electricity, power and downstream sector. The event will also cover important industry priorities and challenges, including local content, security, fiscal terms and more.
Please click here to register, and enter promotional code MEF15AGSHF to receive 10 percent off.
At the end of January, the D.C. Circuit denied rehearing en banc in Smith Lake Improvement and Stakeholder Association v. FERC.1 Smith Lake clarified when a party denied rehearing at the Federal Energy Regulatory Commission (FERC) should seek a second rehearing and when it should file a petition for review with an appellate court. The court reiterated that a party to a FERC proceeding must file a petition for review within 60 days of FERC issuing an order on rehearing. A party should seek a second rehearing with FERC only if FERC’s rehearing order significantly changed the outcome of the proceeding with regard to the party seeking rehearing. The court also advised that a litigant who is uncertain as to whether a change in outcome is sufficiently significant should file a petition for review, rather than seeking a second rehearing, regardless of any notations FERC might have included in its rehearing order.
In Smith Lake, the D.C. Circuit dismissed as untimely a petition for review of a FERC order, because the petitioners had missed the 60-day window for filing a petition for judicial review after FERC denied their initial request for rehearing. FERC had asked the court to hear the case on the merits, rather than dismiss it as untimely, because the petitioners had apparently believed they needed to file a second request for rehearing with FERC prior to seeking review.2 FERC was not the only entity sympathetic to the petitioners’ confusion. On January 30, 2015, the D.C. Circuit denied rehearing of the case en banc.3 Unusually, the judges who comprised the original panel simultaneously issued a statement expressing sympathy for the petitioners’ position, chiding FERC for confusing notations, and amending their prior order, albeit without changing the result.4
On February 6, 2015, the Federal Energy Regulatory Commission (FERC) issued an Order on Rehearing of its Order No. 768, in which FERC expanded its Electric Quarterly Report (EQR) filing requirements by, among other things, requiring EQR filers to submit electronic tag ID (“e-Tag ID”) information for each transaction reported in an EQR if an e-Tag1 were used to schedule the transaction. The e-Tag ID requirement was to become effective with the EQR for the third quarter of 2013, but FERC delayed its implementation pending FERC action on requests for rehearing of the new requirement. Last week, on rehearing, FERC determined that the potential benefits of the e-Tag ID requirement do not justify the likely substantial costs and burdens of complying with it. Accordingly, FERC eliminated the e-Tag ID requirement.
The Infocast Wind Power Finance & Investment Summit 2015 was held from February 10 to 12 in San Diego. Below are selected sound bites regarding the tax equity market and other finance related matters.1
IRS PTC Eligibility Start of Construction Guidance
Multiple speakers expressed the sentiment that the market believes it is likely the IRS will extend the placed-in-service safe harbor deadline in Notice 2013-60, that allows a project owner to avoid the applicable continuous work or continuous efforts requirements of the production tax credit (PTC) eligibility rules, from the end of 2015 to the end of 2016 to reflect the one-year extension enacted by Congress at the end of 2014.
FERC Issues Order to Show Cause and Notice of Proposed Penalty for Alleged Market Manipulation in New England
On February 2, 2015, the Federal Energy Regulatory Commission (FERC) issued an Order to Show Cause and Notice of Proposed Penalty (Show Cause Order)1 directing Calgary-based Maxim Power Corporation and certain of its subsidiaries (collectively “Maxim”)2 and Kyle Mitton, a former energy marketing analyst at Maxim during the relevant summer 2010 period (collectively “Respondents”), to show cause why they should not be found to have violated the Federal Power Act and FERC’s regulations prohibiting electric energy market manipulation by allegedly defrauding ISO New England Inc. (ISO-NE) “through a scheme to obtain payments for reliability dispatches based on the price of expensive fuel oil when Maxim in fact burned much less costly natural gas.” FERC also directed Maxim to show cause why it should not be found to have violated FERC’s market behavior rules by making, through Mr. Mitton, “false and misleading statements and omit[ing] material information in its communications with the [Internal Market Monitor (IMM) for ISO-NE] about its oil-based offers during the relevant period.” FERC proposed civil penalties of $5 million for Maxim and $50,000 for Mr. Mitton, and noted that it did not propose an additional disgorgement remedy because the IMM already “applied mitigation to recoup what it viewed as excessive payments to Maxim.”
In the Office of Enforcement (OE) staff report attached to the Show Cause Order, OE alleges that Maxim, through Mr. Mitton, “engaged in a series of transactions with [ISO-NE] and misleading communications with the [IMM] for the purpose of obtaining inflated make-whole payments at high fuel oil prices when a Maxim plant was dispatched for reliability, even though the plant was actually burning much less expensive natural gas.” Specifically, OE alleges that, “[d]uring July and August 2010, Maxim regularly submitted Day Ahead offers to ISO-NE at high oil prices, but on 22 days when it got reliability commitments, burned much less expensive gas to produce all or almost all of the plant’s energy.” The plant at issue is Maxim’s 181-MW, dual-fuel generating facility in Pittsfield, Massachusetts, which from December 2005 to May 2010 was the subject of a “reliability must-run” agreement with ISO-NE.
FERC Issues Proposed Policy Statement on “Hold Harmless” Commitments in Federal Power Act Section 203 Proceedings
The Federal Energy Regulatory Commission (FERC) last week issued a proposed policy statement to clarify FERC’s allowance of “hold harmless” commitments in applications filed under Section 203 of the Federal Power Act (FPA). Although the policy statement largely reiterates and clarifies existing practices, as a practical matter, the proposals, if adopted, would have a significant effect on the preparation of Section 203 applications and post-transaction submittals by applicants going forward.
FPA Section 203 provides for prior FERC review of transactions affecting regulated utility assets. FERC must approve a transaction if the transaction is determined to be “consistent with the public interest.”1 In making this determination, FERC considers three factors: the effect of the transaction on (1) competition, (2) rates and (3) regulation.2 In addition to the public-interest determination, FERC evaluates whether the transaction will result in the subsidization of nonutility affiliates by utility ratepayers or the pledge or encumbrance of utility assets for the benefit of nonregulated affiliates.
This blog posting is the fifth of a series of five postings from the 2014 year-end energy briefing.
This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.
Burdick: For our final topic, the discussion will be led by Steve Davis, a partner in the Global Energy Practice, Ed Rubinoff, a partner in the International Trade Practice, and Vera Neinast, a senior counsel in the Energy Regulation, Markets and Enforcement practice. Steve, Ed and Vera will discuss U.S. energy exports.
This blog posting is the fourth of a series of five postings from the 2014 year-end energy briefing.
This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.
Burdick: Now let's move onto Mexico and an update from Steve Otillar, a partner in the Energy and Global Transactions practice, and Dino Barajas, a partner in the Global Projects and Finance practice. Steve and Dino will discuss reforms and other developments in Mexico’s energy industry
Otillar: To give you a sense of what Mexico is going through, suffice it to say that almost everything you knew about Mexico’s energy industry has changed. I can’t say that clearly enough. Last year’s debate over a change in Mexico’s Constitution spurred extraordinary emotional responses, with one congressman even disrobing during the debate, saying “You're going to strip everything from the country,” and so forth. Today, life goes on in Mexico; business is moving, and the government has been trying to do a tremendous amount of work in a very short period of time. The secondary regulations were published in August. We've reviewed them, and while there are some conflicts or problematic scenarios here or there, a significant amount of work has been done, including a staggering number of new and amended laws.
This blog posting is the third of a series of five postings from the 2014 year-end energy briefing.
This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.
Burdick: Leading our next discussion is Wynn Segall, a partner in the International Trade practice. Wynn will provide an update on the situation in Ukraine and Russia.
This blog posting is the second of a series of five postings from the 2014 year-end energy briefing.
This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.
Burdick: Continuing with the political theme, our next presenters are Jamie Tucker, a partner in the Public Law and Policy practice, and Charlie Johnson, a partner in the Public Law and Policy practice. Jamie and Charlie will present a point/counterpoint discussion on the impact of the election on U.S. energy policy.
Tucker: The prospects for energy legislation in 2015 improved dramatically as result of the November elections, in which Republicans essentially ran the table.
This blog posting is the first of a series of five postings from the 2014 year-end energy briefing.
This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.
The Editor presents a summary of an energy briefing hosted by Akin Gump Strauss Hauer & Feld LLP, held on December 10, 2014, and featuring energy industry updates along five topics from 12 members of the firm’s Global Energy and Transaction team. Moderating the briefing was Rick L. Burdick, Partner and Chair of the firm’s Global Energy and Transactions group and also Managing Partner for the firm’s international offices.
The recent sharp fall in oil prices, which has seen Brent crude oil and US crude oil both fall below $50 a barrel, has shocked the oil industry. Growing US shale production and high Organisation of the Petroleum Exporting Countries (OPEC) output, combined with weak demand in Europe and Asia, have contributed to a price drop of more than 45% from recent highs. While the full ramifications of the new market conditions are yet to be seen, certain winners, losers and opportunities are beginning to emerge. In addition, lessons can be learnt from the last time the market was at this low level.
On December 30, 2014, the Department of Commerce, Bureau of Industry and Security (BIS) issued long-awaited frequently asked questions (FAQs) and related answers in an attempt to provide guidance on restrictions on crude oil exports. Most significantly, the FAQs attempt to clarify the “processed through a distillation tower” test for determining whether crude oil has been transformed into a petroleum product and to identify the factors BIS considers in applying this test. The guidance likely will encourage more companies to submit classification requests (CCATS) to BIS and/or to self-classify their products, which is also legally permissible, because it provides a demonstrable basis for making these determinations. The FAQs also address commingling foreign and domestic crude oil in the context of license applications for the export of foreign crude.
Below is (i) background regarding crude oil export restrictions and prior developments, (ii) more detailed analysis of the FAQs and (iii) a discussion of their impact on the debate over lifting the export restrictions on crude oil.
Many issues facing FERC in 2014 have carried over to 2015. Topping the list is the uncertain future of demand response in wholesale electricity markets. Demand response’s future hinges on decisions at FERC, in the federal courts, and now in Congress. Last May, the D.C. Circuit voted 2 to 1 that FERC lacks jurisdiction over demand response in wholesale energy markets. This unexpectedly broad ruling rocked the electric industry, which had thought the court would merely rule on the reasonableness of FERC’s demand response compensation scheme. FERC asked all the D.C. Circuit judges to rehear the “EPSA decision,” but they declined to do so. On January 15, the U.S. Solicitor General will file a petition for a writ of certiorari with the Supreme Court, asking it to review EPSA. Others, including demand response providers and state public utility commissions, will also seek Supreme Court review. It is, of course, uncertain whether the Supreme Court will grant the petitions, and if it does, whether it will reverse EPSA.
The D.C. Circuit has stayed its order while all this plays out, but that has not moderated the filings at FERC to nevertheless remove demand response from both energy and capacity markets. Also, in November, U.S. Senator Martin Heinrich (D-NM) introduced a bill to amend the Federal Power Act to effectively overrule EPSA by authorizing FERC to include demand response in wholesale energy, capacity and ancillary service markets. Heinrich will reintroduce his bill soon. Rumor has it bets are being placed that demand response will again top the list of unsettled FERC matters in 2016.
Reprinted with permission from the Friday Burrito, published by 2015 Foothill Services Nevada Inc.
On December 30, 2014, the Federal Energy Regulatory Commission (FERC) issued an Order Approving Stipulation and Consent Agreements (Order) approving four Stipulation and Consent Agreements (Settlement Agreements) between FERC’s Office of Enforcement (OE) and the following: (1) Twin Cities Power – Canada, Ltd., Twin Cities Energy, LLC, and Twin Cities Power, LLC (collectively, Twin Cities); (2) Jason F. Vaccaro; (3) Allan Cho; and (4) Gaurav Sharma (collectively, the Traders).1 The Order resolves OE’s investigation, about which we wrote in June 2014, into whether Twin Cities and the Traders violated FERC’s Anti-Manipulation Rule by scheduling and trading physical power into and out of markets operated by the Midcontinent Independent System Operator, Inc. (MISO) in order to benefit related financial positions that settle off of real-time MISO prices, including the MISO Cinergy Hub Balance-of-Day Swap traded on IntercontinentalExchange, Inc., during the period from January 1, 2010 through January 31, 2011.
FERC Issues Order to Show Cause and Notice of Proposed Penalties to Powhatan Energy Fund, LLC and Related Parties
On December 17, 2014, as amended December 18, 2014, the Federal Energy Regulatory Commission (FERC) issued an Order to Show Cause and Notice of Proposed Penalty (Show Cause Order)1 directing Houlian (Alan) Chen, HEEP Fund, Inc. (HEEP Fund), CU Fund, Inc. (CU Fund), and Powhatan Energy Fund, LLC (Powhatan) (together, the Respondents) to show cause why they should not be: (1) found to have violated the Federal Power Act and FERC’s regulations prohibiting electric energy market manipulation by engaging in allegedly fraudulent “Up-to Congestion” (UTC) transactions in the energy markets administered by PJM Interconnection, L.L.C. (PJM); and (2) assessed civil penalties and required to disgorge unjust profits totaling more than $34.5 million.
Yesterday, Sol-Wind filed its S-1 with the Securities & Exchange Commission for its listing on the NYSE. Its ticker symbol will be SLWD.
Here is a link to my structure diagrams for Sol-Wind and comparisons of it to a yieldco, a private equity fund manager MLP and an oil and gas MLP.
On December 17, 2014, the U.S. Department of Commerce (DOC) announced its final determinations in the antidumping duty (AD) and countervailing duty (CVD) investigations of crystalline silicon photovoltaic products (“solar products”) from China and Taiwan (AD only). DOC’s final determinations are the latest in a series of trade remedy actions taken by the United States, the European Union and Canada since 2012 against Chinese exports of solar products. The current “Solar II” investigations follow AD and CVD orders imposed by DOC in 2012 following the “Solar I” investigations.
In its final determinations, DOC found AD margins ranging from 26.71 to 165.04 percent and CVD rates ranging from 27.64 to 49.79 percent for Chinese companies, and AD margins ranging from 11.45 to 27.55 percent for Taiwanese companies. The final determinations will be enforced by U.S. Customs and Border Protection (CBP) through the collection of cash deposits in the applicable amounts from U.S. importers of record. The AD cash deposit requirements will become effective on the date of publication of DOC’s final determinations in the Federal Register, expected on December 23, 2014. CVD cash deposits will become effective on the date of publication in the Federal Register of any final affirmative determination by the U.S. International Trade Commission (ITC), expected in early February 2015.
On December 19, President Obama signed into law the National Defense Authorization Act (NDAA), which includes significant non-defense provisions, including one that reforms the process by which the National Highway Safety Traffic Administration (NHTSA) awards Corporate Average Fuel Economy (CAFE) credits for natural gas vehicles. The language included in the defense bill largely mirrors, although it is not identical to, S. 2065, bi-partisan legislation introduced by Senators Jim Inhofe (R-OK) and Carl Levin (D-MI) who, respectively, represent natural gas producing and auto manufacturing states.
Under the new law, auto makers will have an additional compliance tool to meet CAFE targets based upon incentives provided for in the sale of natural gas vehicles (NGVs). When the Obama administration promulgated regulations in 2012 for fuel efficiency and greenhouse gas emissions for light-duty vehicles, it awarded strong greenhouse gas credits for NGVs, but CAFE credits were constrained statutorily. The newly enacted provision eliminates the previous statutory cap on fuel economy credits for dual-fuel NGVs and lowers the minimum driving range requirement for dual-fuel NGVs from 200 to 150 miles, thus providing automakers an additional incentive for the production of light-duty NGVs.
On December 5, 2014, the United States Court of Appeals for the D.C. Circuit remanded an order of the Federal Energy Regulatory Commission (FERC) denying refunds to certain Louisiana-based utility companies for rates that FERC had previously ruled “unjust and unreasonable.” 1 The December Order is the third time the D.C. Circuit has remanded an order in the long-running dispute, and the second time the D.C. Circuit has remanded on the issue of refunds.2
The dispute originated in 1995, when the Louisiana Public Service Commission (LPSC) filed a complaint with FERC under Section 206 of the Federal Power Act (FPA). The Complaint objected to the way in which capacity costs were allocated among three Louisiana utilities, all of which were subsidiaries of Entergy Corporation. FERC dismissed the complaint, and the LPSC petitioned the D.C. Circuit for review. In 1999, the D.C. Circuit remanded the order to FERC for further explanation.3 On remand, FERC decided that the allocation of capacity costs was unjust and unreasonable, but ordered relief only on a prospective basis.4 FERC declined to order refunds because it found it could not make the required finding under FPA Section 206(c) that Entergy’s subsidiaries would be able to recover the costs of the refunds from their ratepayers.5
The Tax Increase Prevention Act of 2014, H.R. 5771, was passed by the Senate on December 16 and by the House on December 3. The President is expected to sign the bill in the coming days.
H.R. 5771 extends to the end of 2014 the dozens of tax incentives that expired at the end of 2013. For the production tax credit (PTC), Section 155 of the act provides that a wind project must “start construction” before January 1, 2015, to be eligible for tax credits, rather than the lapsed deadline of starting construction before January 1, 2014.
As is the case with the last extension, this extension does not have a deadline for wind projects to be placed in service (i.e., operational) in order to qualify for tax credits, so long as the project started construction prior to January 1, 2015. The Internal Revenue Service (IRS) in Notice 2013-29 took the position that it would not consider a project to have started construction by the deadline, unless the project owner engaged in “continuous” activity toward completing construction from the start date to the date the project is placed in service. A discussion of Notice 2013-29 is available here and here.
On Saturday, the U.S. Congress passed the Ukraine Freedom Support Act of 2014 (H.R. 5859), which, once signed by the president, will impose or authorize broad sanctions on Russia’s energy and defense sectors and increase military and nonmilitary assistance to Ukraine.White House officials have indicated that the President is expected to sign the legislation into law.
The legislation includes a mix of mandatory and discretionary sanctions that could significantly discourage investment in, and transactions with, Russia’s energy and defense sectors. The legislation also authorizes extraterritorial sanctions aimed at foreign financial institutions that facilitate certain sanctionable activities. Below is a summary of the key sanctions provisions provided in the legislation.
OFAC Clarifies Treatment of Deferred Payments, Oil and Gas “Production,” and Arctic Offshore Projects Under Russia Sanctions Regime
On December 11, 2014, the U.S. Department of Treasury’s Office of Foreign Assets Control (OFAC) released new guidance related to existing U.S. sanctions against Russian entities designated on the Sectoral Sanctions Identification List (“SSI List”). Specifically, OFAC released the following three Frequently Asked Questions (FAQs) on its website:
- FAQ 419 providing guidance regarding the treatment of deferred payment terms under Directives 1, 2 and 3
- FAQ 420 clarifying the meaning of “production” in Directive 4
- FAQ 421 explaining the meaning of “Arctic offshore” projects in Directive 4.
Today, the House passed H.R. 5771. To become law, H.R. 5771 must still pass the Senate and be signed by the president. We expect both of those steps to occur by the end of the year.
H.R. 5771 would extend the 50 tax incentives that expired at the end of 2013 through the end of 2014. For the production tax credit (PTC), Section 155 of the bill provides that a wind project must “start construction” prior to January 1, 2015, to be eligible for tax credits. This would be a change from the current deadline of January 1, 2014.
5th Circuit Denies Louisiana Public Service Commission’s Petition for Review of FERC’s Entergy Bandwidth Implementation Orders
On November 14, 2014, the U.S. Court of Appeals for the 5th Circuit denied the Louisiana Public Service Commission’s (LPSC) petition for review of various Federal Energy Regulatory Commission (FERC) orders on the implementation of a “bandwidth remedy” in Entergy Corporation’s System Agreement (“System Agreement”), an interconnection and pooling agreement among Entergy’s six operating companies (the “System”). The 5th Circuit concluded that FERC’s decisions were not arbitrary and capricious.
FERC interprets Entergy’s System Agreement as requiring a rough production cost equalization among the six operating companies. FERC has required Entergy to implement a bandwidth remedy by which production costs for any single operating company may deviate from the System average by a maximum of +/- 11 percent. If necessary, payments are made by the low-cost operating company(ies) to the high-cost operating company(ies) so that all operating companies are within 11 percent of the System average.1
Preferred stock issuances by Delaware corporations are often effected through a board’s “blank check” power contained in a company’s certificate of incorporation and permitted by Section 151(a) of the Delaware General Corporation Law (the “DGCL”). If “blank check” authority has been established by the company’s certificate of incorporation, a company’s board may adopt a resolution with the desired preferred stock terms and file a certificate of designations containing the resolution with the Delaware secretary of state, thereby creating a new preferred series by way of an amendment to the company’s certificate of incorporation, all without the need for stockholder approval. However, practitioners should keep in mind that a company’s flexibility as to a preferred series (and the related certificate of designations) created under “blank check” authority pursuant to Section 151(a) of the DGCL may be limited by a company’s underlying certificate of incorporation if it was not drafted to afford full flexibility in the event of a future preferred stock issuance:
Even if stockholder action by written consent is expressly permitted by the certificate of designations for a series of preferred stock, a blanket prohibition on written consents in the certificate of incorporation would control. If the underlying certificate of incorporation contains a blanket prohibition on stockholders acting by written consent as permitted by Section 228 of the DGCL, this prohibition cannot be overridden in a preferred certificate of designations adopted by a company’s board under Section 151(a) of the DGCL, even in the case of a consent of preferred shares voting as a separate class. In some circumstances, preferred shares are issued to only one or two stockholders that would otherwise prefer to act by written consent and both the company and the investors desire that the certificate of designations for that preferred series expressly permit those preferred holders to so act. Nevertheless, if the certificate of incorporation itself broadly prohibits written consents of stockholders, the preferred stockholders could only act at a meeting held in accordance with the DGCL and the company’s certificate of incorporation and bylaws. A public company may desire to prohibit action by written consent of its common stockholders but permit action by written consent of one or more series of preferred stockholders, particularly if the preferred shares are intended to be offered and sold to a limited number of investors that may also desire such a right. To achieve both goals, however, the original certificate of incorporation must prohibit action by written consent to each class and series of stockholders except to the extent action by written consent is permitted for a particular series of preferred stock by the certificate of designations for such series, or the certificate of incorporation must be amended, with stockholder approval, to so provide.
On Tuesday, November 4, 2014, 59 percent of voters elected to ban the practice of hydraulic fracturing (“fracing”) in the city of Denton, which sits on top of the hydrocarbon-rich Barnett Shale. Although the ban does not prevent conventional drilling operations, the ban essentially forbids fracing, effectively expelling the drilling industry from city limits. Other municipalities sitting on top of the Barnett Shale—such as Fort Worth, Dallas and Arlington—have grappled with urban drilling as well, but Denton’s complete prohibition marks the first of its kind in Texas.
Cities in other states have had varying success in their attempts to ban fracing. In the Marcellus region, Buffalo, Ithaca, Geneva, Pittsburgh and Cresson, among others, have instituted fracing bans. And on November 4, similar initiatives passed in California’s San Benito and Mendocino counties and in Athens, Ohio, but failed in Santa Barbra County, California and in the Ohio cities of Gates Mills, Kent and Youngstown.
Some industry participants and observers are confused about what the investment tax credit (ITC) rules for solar will be on January 1, 2017. In an effort to provide some clarity to this issue, below are frequently asked questions about the pending changes to the solar ITC.
1. Absent a change in law, what percentage of the ITC will be available for investors in solar systems on January 1, 2017?
Answer: Ten percent.1
On October 31, the IRS released Private Letter Ruling 201444025, which was addressed to a manufacturer of solar systems that are mounted on real estate. The nature of the real estate, along with many other interesting facts, was redacted from the version of the ruling released to the public.
The ruling is a reminder that, with respect to solar power systems, only “equipment that uses solar energy to generate electricity, and includes storage devices, power conditioning equipment, transfer equipment, and parts related to those items” are eligible for the investment tax credit provided for under section 48 of the Internal Revenue Code. 1
With the election on Tuesday, the wind industry’s attention is particularly focused on the prospects for the extension of the production tax credit (PTC). There have been four interesting developments related to the extension of the PTC.
First, in the current 113th Congress, only 185 bills have been signed into law. Many observers characterized the 112th Congress as unproductive, but the 113th Congress has managed to enact only 80 percent of the numbers of bills that the 112th Congress did.1 Of course, in the post-election, lame- duck session, there is still hope for the 113th Congress to find its footing and extend the PTC and address other important issues. It is my view that it is more likely than not that the PTC will be extended through 2015 during the lame-duck session, and the Senate Finance Committee has already passed a bill that extends the PTC for projects that start construction prior to the end of 2015. A blog post discussing the Finance Committee’s approval of that bill is available here.
As we previously reported, on May 23, 2014, the D.C. Circuit vacated FERC’s Demand Response Order No. 745, holding that the order (1) exceeded FERC’s jurisdiction, and (2) was arbitrary and capricious, particularly in its failure to address Commissioner Moeller’s arguments that the order overcompensates demand response resources.1 FERC, several States, and various industry representatives sought rehearing en banc, but the court denied all petitions for rehearing on September 17, 2014.2
FERC Reduces New England Transmission Owners’ Base ROE to 10.57 percent and Caps Total ROE at 11.74 percent
On October 16, 2014, the Federal Energy Regulatory Commission (FERC) issued Opinion No. 531-A, an order on the paper hearing it established in Opinion No. 531 regarding the long-term growth rate to use to calculate the New England Transmission Owners’ (NETOs) base return on equity (ROE) under the two-step constant growth discounted cash flow (DCF) methodology that FERC adopted for public utilities. In Opinion No. 531-A, FERC determined, among other things, that the NETOs’ existing base ROE of 11.14 percent is unjust and unreasonable and reduced the NETOs’ base ROE by approximately five percent to 10.57 percent, with a maximum ROE, including incentives, of 11.74 percent. Requests for rehearing of Opinion No. 531 remain pending before FERC.
As we wrote in June 2014, in Opinion No. 531, FERC adopted the two-step DCF methodology for determining base ROE for public utilities and tentatively found that the long-term growth rate component of the ROE formula—which represents 1/3 of the overall growth rate variable in the DCF model—should be based on projected long-term growth in GDP. However, because the parties to the ROE complaint case against the NETOs had not litigated the appropriate long-term growth rate, FERC reopened the record and established a paper hearing to enable the parties to brief that issue.
Discovery Order Issued in “SolarCity” Cash Grant Litigation — Treasury to Provide Benchmarking Materials
On October 6, 2014, Judge Eric G. Bruggink of the U.S. Court of Federal Claims issued an order on the disputed production of documents and interrogatory responses requested from the U.S. Department of the Treasury by plaintiffs, investors in cash-grant-eligible solar projects sponsored by SolarCity, in connection with their challenge to Treasury’s calculation of their Section 1603 cash grant awards. Judge Bruggink heard oral argument on the discovery disputes on August 29, 2014. That hearing is covered in a September 3 blog post, which also references earlier posts providing background and early developments in the case.
Consistent with his rulings issued from the bench during the August 29 oral argument, Judge Bruggink ordered Treasury to produce documents sufficient to identify the “benchmark” or “threshold” amounts it used in evaluating Section 1603 solar project applications and, to the extent such benchmarks were higher than the amounts claimed in plaintiffs’ applications, documents sufficient to identify how such benchmarks were derived. He also ordered Treasury to produce all documents and information, including materials submitted by third parties in connection with the Section 1603 program, upon which Treasury relied in evaluating plaintiffs’ Section 1603 applications.
The Department of the Treasury has announced that for fiscal year 2015 the Cash Grant 1 sequester rate will be increased from 7.2 to 7.3 percent. The announcement is available here. The change applies to Cash Grants paid on or after October 1, 2014, and on or before September 30, 2015, regardless of when the application was submitted to Treasury.
The effect of the sequester is that if a solar project has an “eligible basis” of $1,000 then the 30 percent Cash Grant would have been $300; however, the 7.3 percent sequester results in it being only $278.10. If a project owner wishes to avoid the sequester, it has the option to claim the 30 percent investment tax credit under Section 48 of the Internal Revenue Code; however, efficient use of that credit requires a federal income tax liability that can be offset by the credit.
Dino Barajas will be speaking at the LDC Gas Forum in Los Angeles on October 6-8, 2014 and invites our Akin Gump friends and family to receive a $125 discount to attend. Join over 300 attendees to discuss vital regional and national issues affecting all aspects of natural gas marketplace.
Please click here to register and enter promotional code AKIN-125 to receive $125 off. This discount expires on October 3, 2014.
Akin Gump partner, David Burton and Alfa Business Advisors partners, Vadim Ovchinnikov and Gintaras Sadauskas are hosting a seminar on Tax Equity Structuring, Financial Modeling and HLBV Accounting on Tuesday, September 23, 2014. This seminar will be a live presentation in the New York office of Akin Gump and will also be available as a webinar.
The seminar will cover a variety of topics, including levered/unlevered partnership and lease structuring, the recent production tax credit “start of construction” guidance from the IRS, and the financial modeling complexities during the capital raise and operating stages of renewable energy projects. The session will also include a discussion of hypothetical liquidation at book value (HLBV) accounting.
To view the invitation and register please click here.
On September 8, 2014, the U.S. Court of Appeals for the Fifth Circuit dealt a blow to Exelon Corp. (“Exelon”), rejecting challenges by various Exelon wind-generating entities to a Texas Public Utility Commission (PUCT) regulation and a 2009 PUCT order involving the sale of power from Qualifying Facilities (QFs)1 to a public utility under the Public Utilities Regulatory Policies Act (PURPA). The Fifth Circuit’s opinion raises important questions about the roles Congress gave to state and federal regulatory authorities to implement portions of PURPA.
The Federal Energy Regulatory Commission (FERC) has created two pricing structures for QFs to sell power to utilities under PURPA: (1) on an “as-available” basis, where price is determined at the time of delivery; or (2) pursuant to a “Legally Enforceable Obligation,” where price can be determined either at the time of delivery or at the time the obligation is incurred. In a somewhat unusual statutory scheme, PURPA orders states to implement the federal law. The federal law therefore requires state public utility commissions, such as the PUCT, to adopt rules that comply with FERC’s regulations implementing PURPA.2
Third Circuit Affirms District Court Decision Invalidating New Jersey’s Long-Term Capacity Pilot Program
On September 11, 2014, a three-judge panel of the U.S. Court of Appeals for the Third Circuit unanimously affirmed an October 2013 decision of the U.S. District Court for the District of New Jersey that New Jersey’s Long-Term Capacity Pilot Program Act (LCAPP) is preempted by federal regulation of interstate capacity markets.
LCAPP, which sought to promote the development of new electric generating capacity in New Jersey, instructed the New Jersey Board of Public Utilities (BPU) to solicit bids for new generation facilities and award fifteen-year, fixed-price Standard Offer Capacity Agreements to new generators that met certain requirements. The BPU then compelled New Jersey electric distribution companies to enter into the Standard Offer Capacity Agreements with successful LCAPP bidders. Several existing generators and two electric distribution companies sued the BPU in the District Court, arguing that the Federal Power Act (FPA) preempts LCAPP and seeking an injunction prohibiting the enforcement of the New Jersey law. As we reported here, the District Court in October 2013 determined that the FPA does preempt LCAPP, declared the law unconstitutional, invalidated the Standard Offer Capacity Agreements, and enjoined New Jersey from enforcing the law. The BPU and an LCAPP generator appealed.
Here is the presentation from the webinar MLPs, REITs and YieldCos for Renewables Webinar 2.0 that I chaired on September 4. The presentation explains each type of vehicle, how the vehicles differ from each other, how the vehicles can invest in renewables and how master limited partnerships (MLPs) could invest to a far greater extent in renewables if Congress changes the definition of “qualifying income” to include income generated by renewable energy projects.
In last week’s post, we did an analysis of several recent Yieldcos. As we stated, a number of significant developers in the renewable energy space have either formed Yieldcos, filed for an initial public offering of Yieldco securities or announced plans to form a Yieldco.
So, why this rush to form Yieldcos? There are several reasons:
The primary reason is simply cheaper capital, since, in the renewable energy industry, the fuel, i.e. the wind or the sun, is free. If the project is properly constructed with current top quality wind or solar technology, what makes the project economically viable is the cost of the capital needed to build the project in the first instance. With Pattern’s yield now down near 4% and NRG’s yield below 3%, and with development equity returns fluctuating somewhere between 8 and 20%, it is easy to see how Yieldco funds would be attractive, even if they only replace a third of the owner’s equity in the projects.
On August 29, 2014, Judge Bruggink heard oral argument and ruled on plaintiffs’ motion to compel the production of documents and information requested from the Department of the Treasury (“Treasury”) regarding plaintiffs’ challenge to Treasury’s calculation of Section 1603 cash grant awards for solar projects. Plaintiffs, special-purpose entities that invested in cash-grant-eligible solar projects sponsored by SolarCity, filed a complaint in the Court of Federal Claims on February 22, 2013, challenging adjustments made by Treasury that resulted in reduced cash grant awards.
Background and early developments in the case are covered in blog posts of May 21, June 2, July 9, August 14 and September 20, the most recent of which concerns Judge Bruggink’s denial of the Department of Justice’s (DOJ) motion to dismiss the complaint. Since that time, discovery disputes have slowed the progress of the litigation, leading plaintiffs to file the motion to compel at issue in the hearing held last Friday.
In our post on August 19, “Yieldcos – The New “Promised Land” of the Renewable Energy Space?”, we explored the Yieldco structure and why some renewable energy companies are considering them. We will now turn our attention to an analysis of several recent Yieldcos.
In the last 12 months, a number of significant developers in the renewable energy space have either formed Yieldcos, filed for an initial public offering of Yieldco securities or announced plans to form a Yieldco. By most measurements of the success of an initial public stock offering, the Yieldcos have done quite well.
On August 20, the American Wind Energy Association (AWEA) held a webinar to discuss Internal Revenue Service (IRS) Notice 2014-46, which clarified the rules for wind projects to be grandfathered for production tax credit (PTC) eligibility purposes as having started construction in 2013. A prior post discussing Notice 2014-46 is available here.
The highlight of the panel was that it included representatives of the IRS who commented on Notice 2014-46 and answered questions from the other panelists. The IRS’s primary representative was Christopher Kelley, who recently rejoined the IRS after a stint at Treasury. Mr. Kelley was joined by his IRS colleagues Jaime Park, Philip Tiegerman and Jennifer Bernardini.
Non-incumbent transmission developers scored a big win last week. As we previously reported here, the D.C. Circuit Court of Appeals upheld FERC’s Order No. 1000. Among other things, Order 1000 mandated that a regional transmission planning process consider projects proposed by non-incumbent developers. FERC required that public utility transmission providers remove certain rights of first refusal from their federal tariffs and contracts, thereby eliminating their automatic right to construct transmission facilities within their service territories. In the wake of Order 1000, regional transmission planning groups across the country have adopted a variety of competitive processes for selecting transmission proposals and assigning construction rights. The court held that FERC has the authority to require federal ROFR elimination and rejected arguments that the relationship between the ROFR and FERC-jurisdictional rates is too attenuated to trigger FERC’s Federal Power Act section 206 authority or that it violates the Mobile-Sierra doctrine.
On August 19, 2014, the U.S. Department of Energy (DOE) issued a Notice of Public Comment on its draft triennial National Electric Transmission Congestion Study (“Congestion Study”). DOE prepares such congestion studies every three years pursuant to Section 216 of the Federal Power Act (FPA), as added by the Energy Policy Act of 2005 (EPAct 2005).
In the draft Congestion Study, DOE identifies transmission constraints and congestion and their consequences (including monetary, policy and adverse consumer consequences), focusing on the recent past and current expectations for the next three to five years. The draft Congestion Study presents regional findings for the four geographic quadrants of the United States, excluding the area covered by the Electric Reliability Council of Texas. DOE does not propose in the draft Congestion Study to designate any “national interest electric transmission corridors” (National Corridors) under Section 216 of the FPA. Such a designation would be a prerequisite for the potential exercise by the Federal Energy Regulatory Commission of its “backstop” transmission siting authority also created by EPAct 2005. However, DOE states that it might designate one or more National Corridors in the final version of the Congestion Study if doing so would be an appropriate response to transmission constraints or congestion in a specific area. The draft Congestion Study’s assessment of transmission constraints and congestion does not address whether or how to fix constraints or congestion, but rather seeks to inform discussion regarding potential mitigation of those issues. In addition, this draft Congestion Study differs from prior congestion studies in several ways, including that DOE increased its consultation with states during the preparation of the study.1
For the most part, with the exception of a limited number of projects referred to as “community wind,” America’s roughly 70,000 MW of installed utility scale wind and solar projects are owned directly or through subsidiaries of large American or European utility companies, large independent power producers or companies funded by large private equity firms. Up until just recently, small individual investors have not been included in the ownership mix of renewable energy projects. The lack of individual investors has a number of drawbacks, including limiting the dissemination of positive information about the benefits of wind and solar and restricting what could be much broader political support. Possibly the most significant impact, however, is on the cost of capital for wind and solar projects where expected unlevered returns by the current owners range from 6-16 percent per annum. By comparison, both the oil and gas industry, through master limited partnerships, and the real estate industry, through real estate investment trusts, are able to access the small, private investor in order to significantly reduce the capital costs for those industries. With savings interest rates hovering just above 1 percent and 10-year treasury bills below 2.5 percent, the small, private investor is hungry for any low-risk product that can offer even a modest yield.
D.C. Circuit Upholds Order No. 1000, FERC’s Landmark Transmission Planning and Cost Allocation Rulemaking Order
On August 15, 2014, the United States Court of Appeals for the District of Columbia Circuit unanimously affirmed Order No. 1000, a landmark set of rules approved by the Federal Energy Regulatory Commission (FERC) in 2011 to reform the transmission planning and cost allocation requirements for the nation’s public utility transmission providers.1 Among other things, Order No. 1000 required transmission providers to participate in regional planning processes with neighboring utilities. FERC reasoned that evaluating transmission alternatives at the regional level could resolve a region’s transmission needs more cost-effectively than through local planning without mandated coordination. Multiple parties, including state regulatory agencies, transmission providers, regional transmission organizations, and industry trade associations (collectively, “Petitioners”) appealed Order No. 1000 to the D.C. Circuit, challenging FERC’s authority to adopt the new rules and arguing that they were arbitrary and capricious.
The Federal Power Act (FPA) does not expressly give FERC the authority to regulate transmission planning by public utilities. Nevertheless, the D.C. Circuit held that FERC has the authority under FPA Section 206 – which provides for FERC to remedy “any . . . practice” that “affect[s]” a rate for interstate electricity transmission services “demanded” or “charged” by “any public utility” if such practice “is unjust, unreasonable, unduly discriminatory or preferential”2 – to require transmission providers to participate in a regional transmission planning process.
Dino Barajas will be speaking at REFF-West in San Francisco on September 16-17, 2014 and invites our Akin Gump friends and family to receive a 20% discount to attend. Join over 400 high-level attendees as the speakers discuss the latest trends in renewable energy financing and give you practical takeaway advice on how to move your projects forward.
Please click here to register and enter promotional code DB20RW to receive 20% off.
Today, the Internal Revenue Service (IRS) issued Notice 2014-46, which clarifies the rules for a wind project to be deemed to have started construction in 2013 as is necessary to be eligible for production tax credits (PTC) or the investment tax credit (ITC). The notice is available here.
The new guidance is generally consistent with the industry’s requests for clarifications;1 however, it adds unanticipated complexity with respect to the transfer of grandfathered projects. Also, it provides rules that the industry did not request with respect to projects that fall short of meeting the safe-harbor of spending 5 percent of their total cost in 2013.
The applicability of the guidance is not limited to wind projects. It also applies to geothermal, biomass, landfill gas and some hydroelectric and ocean energy projects. Solar projects are not subject to the guidance and qualify for a 30 percent investment tax credit, so long as they are “placed in service” by the end of 2016.
FERC Accepts CAISO’s Proposed Generator Interconnection Process Enhancements To Facilitate Project Downsizing
On July 31, 2014, the Federal Energy Regulatory Commission (FERC) accepted amendments to the California Independent System Operator Corporation (CAISO) tariff designed to improve the efficiency and flexibility of the CAISO’s generator interconnection process. The amendments provide an annual opportunity for interconnection customers in good standing to “downsize” their generation projects. The amendments also clarify the circumstances under which the CAISO will not seek to terminate an interconnection agreement and disconnect a generation project due to a developer’s failure to build a project to its full studied capacity. The amendments are intended to help facilitate renewable energy project development in California by accommodating the scalability inherent in many renewable projects, thereby mitigating disconnection risk concerns related to changes in project size over time. The revised tariff provisions went into effect on August 1, 2014.
Wall Street Journal Focuses on Power Africa, the U.S.-Africa Leaders Summit and U.S.-Africa Investing Report Featuring Contributions from Akin Gump’s Carl Fleming
The Wall Street Journal article “African Consumer Spending Expected to Double by 2020,” looks at opportunities for the U.S. business community to greatly expand investment in Africa. The article cites a comprehensive report on investing in Africa that was released this week in connection with the U.S.-Africa Leaders Summit. The report is titled Africa and the United States: A defining relationship of the 21st century, produced by the U.S. Chamber of Commerce and Investec Asset Management.
Akin Gump associate Carl Fleming’s ongoing work on Power Africa is featured in the report among other Africa experts. His section called “Spotlight on Electrify Africa Act” discusses the potential impact of Power Africa and the pending legislation on investment on the continent. In particular, he outlines the way in which the Electrify Africa Act, passed by the U.S. House of Representatives in May would help U.S. investors and redefine “how certain US agencies do business in Africa,” among them the Millennium Challenge Corporation, the U.S. Agency for International Development, the Treasury Department and the Overseas Private Investment Corporation.
Fleming presented an overview of the U.S.-Africa Leaders Summit, an introduction to Power Africa and an update on the pending legislation, including the recent introduction of the Energize Africa Act, in this July 31 post.
On August 5, 2014, the Federal Energy Regulatory Commission (FERC) issued a Staff Notice of Alleged Violations (Preliminary Notice) stating that FERC’s Office of Enforcement has preliminarily determined, in a non-public investigation, that Houlian (Alan) Chen, two companies owned and controlled by Mr. Chen, and Powhatan Energy Fund, LLC (Powhatan), which had control over Mr. Chen’s trading activity on its behalf during the relevant period, violated FERC’s electric market Anti-Manipulation Rule by engaging in manipulative “up-to congestion trading” in PJM. Such trading allows a transmission customer to specify the maximum price it is willing to pay for congestion between two physical points on the transmission system (the source and the sink) as a hedge against uncertain congestion prices, i.e., to protect itself from paying uncertain congestion charges by guaranteeing that it would pay no more than the amount reflected in its bids.1 The Preliminary Notice is FERC’s first public action related to the Chen/Powhatan investigation since Powhatan launched its unprecedented and widely-publicized website in March 2014 criticizing FERC’s investigation of the conduct addressed in the Preliminary Notice.
On July 31, 2014, a consortium of state attorneys general, state regulators, state consumer advocates and transmission customers 1 filed a complaint at FERC against New England transmission owners (NETOs), seeking to reduce their authorized return on equity (ROE).2
In Opinion No. 531, the Commission adopted a new methodology for determining the just and reasonable ROE in electric cases.3 Applying the methodology detailed in Opinion No. 531 to the most recent six months of financial data, the complaint asserts that (a) the appropriate Base ROE is 8.84 percent, not 11.14 percent and (b) the ROEs currently on file exceed the upper end of the range of proxy company results.
On July 28, 2014, the House of Representatives passed three bills aimed at enhancing the cybersecurity efforts of the Department of Homeland Security (DHS) in certain critical infrastructure sectors, including the energy sector: 1
- H.R. 3696 – the National Cybersecurity and Critical Infrastructure Protection Act (NCCIPA), the primary bill of the three, which passed by voice vote;
- H.R. 2952 – the Critical Infrastructure Research and Development Act (CIRDA), a bill promoting cybersecurity research and development, which passed by voice vote and
- H.R. 3107 – the Homeland Security Cybersecurity Boots-on-the-Ground Act, a bill seeking to bolster the cybersecurity workforce, which passed by a 395-8 vote.
African Growth and Opportunity Act, Electrify Africa Act and Power Africa Program to Take Center Stage at U.S.-Africa Leaders Program August 4-6
From August 4-6, President Obama will host approximately 45 leaders from across the African continent in Washington, D.C., for a three-day U.S.-Africa Leaders Summit (the “Summit”). This is the first such event of its kind and is the largest event any U.S. President has held with African heads of state and government. The Summit is intended to advance the administration’s focus on power and investment in Africa. As such, the Summit will focus heavily on the administration’s new Power Africa initiative, as well as the renewal of the African Growth and Opportunity Act (AGOA). These initiatives and pending Power Africa legislation, including the Electrify Africa Act and the Energize Africa Act, are of importance to anyone looking to invest in Africa in the future.
A recent decision by the D.C. Circuit has prompted much speculation about possible changes to the traditionally opaque and secretive national security review process administered by the Committee on Foreign Investment in the United States (CFIUS or the Committee). On July 15, 2014, a three judge panel of the D.C. Court of Appeals determined that a presidential order requiring Ralls Corporation (Ralls)—a U.S. company owned by two Chinese investors—to divest its interest in four Oregon wind farms based on national security concerns deprived Ralls of due process of law. The case has now been remanded to the D.C. District Court for further review. Additional information providing the legal and regulatory background can be found here.
Although some observers consider this initial decision to be a victory for proponents of greater transparency in the CFIUS process, the actual implications of the decision, at least at this stage, remain unclear. The decision itself is narrow and limited solely to the due process requirements for a presidential order, which is an extraordinarily rare occurrence in CFIUS proceedings. Nevertheless, the D.C. Circuit’s decision, and the questions left to the District Court, create the possibility of expansive changes to the underlying CFIUS process. We analyze below the aspects of the CFIUS process that remain the same and the significant issues left open by the decision that could eventually lead to changes.
Corporate Renewable Energy Buyers’ Principles Highlight the Promise of Consumer/Utility Collaboration in Renewable Power Procurement
As we wrote earlier this year, end-use corporate energy consumers large and small are increasingly turning to distributed power generation using solar, wind and other technologies to reduce purchased power costs and price volatility, earn tax benefits, improve reliability and meet customers’ environmental stewardship requirements.1 But, for some companies, investment in distributed renewable generation at the required scale can be infeasible, uneconomic or otherwise unattractive, prompting such consumers to seek alternative means to procure renewable power to serve similar ends. While the renewable power market continues to expand, large-scale corporate end users still face numerous challenges to increased use of renewable power, including diverse, complex market structures, premium pricing and access to cost-effective and functional solutions to meet their needs.2
Options for Obtaining Regulatory Guidance and/or Approval Related to the Export of Crude Oil and Petroleum Products
As previously reported on Speaking Energy (available here), the U.S. Department of Commerce, Bureau of Industry and Security (BIS) has recently indicated that it is willing to work with U.S. energy companies to navigate restrictions on the export of certain types of crude oil. In particular, BIS has been providing companies guidance regarding which hydrocarbons are classified as “crude oil” that is subject to strict export controls, as opposed to a “petroleum product” that can be exported more freely. Alternatively, BIS may also be willing to license certain crude oil exports under the existing rules. Understanding how the regulations and licensing regime apply to your business can prove critical in structuring operations and allocating capital to take advantage of the export market for petroleum from the United States.
On July 3, 2014 the United States Department of Energy (DOE) issued its latest solicitation under Section 1703 of Title XVII of the Energy Policy Act of 2005 for applications to obtain loan guarantees to finance innovative and renewable or energy efficient technologies which avoid, reduce, or sequester the emission of greenhouse gases (the Solicitation). DOE has authority to issue up to $2.5 Billion of loan guarantees, supplemented by limited authority to fund up to approximately $170 million of credit subsidy costs associated with the issuance of these loan guarantees. Eligible projects may receive loan guarantees for up to 80% of eligible project costs.
General Electric (GE) stated on its quarterly earnings call today that it expected that the clarification to the Internal Revenue Service’s (IRS) production tax credit (PTC) “start of construction” guidance would be released in the next week or two. The guidance will clarify the rules with respect to what is required for a project to be deemed to have started construction in 2013 in order to be eligible for the PTC that lapsed at the end of 2013. A discussion of the existing guidance is available here.
Here is the pertinent remark from Jeffrey Bornstein, CFO of GE:
[W]e had 400 or 500 wind units that moved out of the quarter, really just awaiting clarification from the Treasury department on what constitutes start of construction to be eligible for PTC. And these are projects that involve bank financing and tax equity investors. So very tough to move those projects along until they're absolutely certain that they're going to qualify for the PTC and we expect that clarification to come from the Treasury in the next week or two. And we've seen that clarification, and we think it's helpful.1
On Friday, July 11, the Supreme Court of Iowa issued a decision holding that a solar energy company entering into a third-party power purchase agreement (PPA) with an Iowa municipality would not be considered a public utility under state law. The decision affirmed a lower court’s opinion overturning the ruling of the Iowa Utilities Board, which would have prohibited the PPA from going forward. The Iowa Supreme Court’s decision means that Iowa now joins several other states, including solar-heavy California, Nevada, Arizona, New Mexico and Colorado, in allowing developers to enter into third-party PPAs without becoming subject to rate regulation as public utilities under state law.
Eagle Point Solar (“Eagle Point”) proposed to enter into a PPA with the city of Dubuque, Iowa (“Dubuque”), in which Eagle Point would own, install, operate and maintain an on-site (i.e., “behind-the-meter”) PV solar generation system at a municipally owned building. The PPA required Dubuque to purchase the full output of the solar facility on a per-kWh basis. The output would supply some, although not all, of the facility’s power needs, and, therefore, the municipal building would remain connected to the local electric utility, Interstate Power and Light Company, to service the remainder of its load.
You may have noticed the Federal Energy Regulatory Commission (FERC) has received lots of heated criticism over its enforcement of alleged market manipulation and fraudulent behaviors. You may also have noticed FERC has not responded to the criticism. That’s because the Department of Justice (DOJ) frowns on that. Market manipulation cases are high profile and can involve criminal proceedings. DOJ does not want enforcement agencies to fan those fires. So it was with an interest heightened by lack of information that I devoured a just-published article adapted from a speech given last October by Commissioner Tony Clark on FERC’s enforcement policy. It’s called “Ensuring Reliability and a Fair Energy Marketplace,” and I commend it to you. It’s a great read at 25:2 Colo. Nat. Resources, Energy & Envtl. L. Rev. 2014. In it, Commissioner Clark explains how FERC administers principles-based enforcement. In response to the argument that FERC should specify by rule all specific misconduct in which a market participant could conceivably engage, he observes that such an approach is not only unrealistic but also leads to unacceptable gaming. He cites former imprisoned Enron exec, Andrew Fastow, who confessed that he “used the rules to break the rules.” Fastow explains that the more complex the rules are, the more opportunity they present to subvert them. A reformed Fastow now preaches that one should ask “not what is the rule, but what is the principle?” Clark concedes that FERC must provide clear guidance as to the nature of prohibited conduct, but he also exhorts market participants to “use judgment.”
Reprinted with permission from the Friday Burrito, published by 2014 Foothill Services Nevada Inc.
Creating A Regulatory Framework For Demand-Side Investment Equivalent To Generation & Grid Investments
Demand-side management (DSM) promises a reduced-emission, lower cost, efficient solution to the ever-increasing demand for reliable power, with added benefits to system operations and the integration of intermittent renewables, storage and distributed generation. However, as an alternative to additional investment in generation and grid infrastructure, DSM deployment has faltered. In the United States, for example, Demand Response (DR) programs are widespread, yet existing DR programs are employed nearly exclusively in “emergency” conditions as a last resort, and not as a structured grid resource.
One reason for this limited utilization is that vertically-integrated regulated utilities have hesitated to invest in DSM solutions that create expenses and erode revenue. While in a broader context the benefits of working on the demand-side are clear, conventional demand-side models do not contribute to the long-term support of a utility business. Regulated utilities recover their revenue requirement through their electricity rates, earning a return on the infrastructure that they own and operate. DSM poses unique ratemaking challenges because the “product” is reduced consumption of electricity (“negawatts”). 1
On July 9, 2014, the Federal Energy Regulatory Commission (FERC) issued a Staff Notice of Alleged Violations (Preliminary Notice) stating that FERC’s Office of Enforcement has preliminarily determined, in a non-public investigation, that Direct Energy LLC (Direct Energy) violated FERC’s anti-market manipulation rule in 18 C.F.R. § 1c.1 by making “illegal trades of physical gas at Algonquin on May 1, 2, 7, 8, and 9, 2012 and at Transco Zone 6 on May 11, 2012, designed to move the market to benefit [its] related financial positions.” The Preliminary Notice does not provide additional details regarding the investigation or the alleged manipulation.
The Preliminary Notice represents another example of the increasingly common market manipulation case involving the sort of “tool and target” framework that Office of Enforcement director and still pending FERC nominee Norman Bay described in Senate subcommittee testimony in January 2014. Under that framework, alleged market manipulation often, as here, involves conduct in a FERC-jurisdictional physical market (the tool) designed to raise or lower prices in that market for the purpose of improving a “benefitting position” in a related physical or financial market (the target, which sometimes is not FERC-jurisdictional).
In response to the growing threat from cyber-attacks, the oil and gas industry has announced the formation of an information sharing clearinghouse. The new group, known as the Oil and Natural Gas Information Sharing and Analysis Center (ONG-ISAC), looks to facilitate the sharing of critical information among peers and competitors and to coordinate industry-wide responses to attacks. ONG-ISAC Chairman David Frazier explains that member companies will benefit from learning some of the “raw indicators” of malware and cybercrime activity reported by other member companies, even as specific details about a breach are omitted for confidentiality reasons. According to the new group’s website, more than half of the cyber incidents reported across all critical infrastructure sectors in the first half of fiscal year 2013 involved attacks on the energy sector.
The Renewable Energy Finance Forum Wall Street was held on June 25 and 26. Below are selected sound bites about YieldCos, tax equity and the capital markets opportunities for renewables. This post was prepared without the benefit of a recording or transcript. If there are any misquotes please contact the author for a correction.
“Developers are waiting for YieldCos to show up and have a cost of capital equivalent to their dividend yield. That’s a perception issue on the developer side.”
- David Giordano, Managing Director, BlackRock Alternatives – Infrastructure Investment Group-Renewable Power
On June 25, 2014, the US House of Representatives approved H.R. 6, the Domestic Prosperity and Global Freedom Act, by a 266-150 vote. The Energy and Commerce Committee reports that the bill, authored by Rep. Cory Gardner (R-CO), is intended to expedite exports of US liquefied natural gas (LNG), boosting the US economy and increasing global energy security. The bill would amend the US Department of Energy (DOE) approval process for LNG exports, as follows:
- 30 Day Deadline. The bill would require DOE to issue a final decision on any application to export LNG within 30 days of the conclusion of the National Environmental Policy Act (NEPA) review of the LNG export facilities. See our related blog on a pending DOE proposal to defer action on applications to export LNG from the Lower-48 states to countries that do not have a relevant free trade agreement (FTA) with the US until the applicants have completed the NEPA review process.
- Federal Court Review of DOE Decisions. The bill would (1) grant the United States Court of Appeals for the circuit in which the export facility will be located original and exclusive jurisdiction over any civil action to review DOE’s order on an LNG export application or DOE’s failure to issue a final decision, and (2) further require that any such matter be set for expedited consideration. If the court finds that DOE has failed to issue a final decision on the application, “the Court shall order the Department of Energy to issue such final decision not later than 30 days after the Court’s order.”
- Public Disclosure of Export Destinations. The bill would require the applicant to publicly disclose the specific export destinations as a condition for approval of any LNG export authorization.
Déjà Vu, All Over Again: Seventh Circuit Again Remands PJM’s Cost Allocation Methodology for New, High-Voltage Transmission Facilities to FERC
On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit, with Judge Richard A. Posner writing for himself and Judge John Daniel Tinder, granted petitions for review of Federal Energy Regulatory Commission (FERC) orders addressing, and remanded to FERC for the second time, the cost allocation methodology for new, 500 kV and higher-voltage transmission facilities in the PJM Interconnection, L.L.C. (PJM) region. Judge Richard D. Cudahy dissented. The decision is the most recent milestone in a lengthy battle among PJM stakeholders and suggests that uncertainty in this area could continue.
In 2009, the same Seventh Circuit panel, also divided in that instance, held that FERC had not adequately supported its decision to approve the socialization, through a “postage-stamp” cost allocation methodology, of the costs of new, 500 kV and higher-voltage transmission facilities based on PJM utilities’ load-ratio shares. Under that approach, the costs of the facilities would be allocated to all PJM utilities in proportion to the amount of load served in each transmission zone. Previously, such costs had been allocated on a “beneficiary pays” basis according to the benefits that each PJM utility would receive from the new facilities. The court remanded the rate design issue to FERC, which in March 2012 reaffirmed the “postage-stamp” methodology, concluding that it is just and reasonable and not unduly discriminatory or preferential. FERC denied rehearing in March 2013 and these appeals followed.
On June 19, 2014, the Federal Energy Regulatory Commission (FERC) initiated a proceeding with the aim of evaluating price formation issues in the wholesale energy and ancillary services markets. The new initiative comes in the wake of this year’s so-called “polar vortex,” during which many of the FERC-jurisdictional markets experienced dramatic price spikes amid record-setting levels of demand for power. Recent input from stakeholders has suggested that inefficient market rules prevented the markets from effectively responding to these conditions. FERC’s new initiative also looks to build upon a proceeding initiated last year to address problems in the organized wholesale capacity markets.
FERC will hold a series of workshops aimed at gathering stakeholder input on a variety of issues related to price formation, including: (1) the use of uplift payments; (2) offer price mitigation and offer price caps; (3) scarcity and shortage pricing; and (4) operator actions that affect prices. The first workshop will be held in September, with the remaining ones stretching into the fall and winter.
Earlier this week, the Wall Street Journal published an article with the headline: “U.S. Ruling Loosens Four-Decade Ban on Oil Exports.” The report announced that two energy companies, Pioneer Natural Resources Co. and Enterprise Product Partners LP, had received U.S. government “rulings” permitting them to export “unrefined American oil [for the first time] in nearly four decades.” This news sparked a flurry of interest from energy companies, both upstream and downstream, as it could have a major impact on market access and the allocation of capital. While U.S. Department of Commerce officials who administer the relevant regulations claim that these rulings do not represent a change in U.S. government policy, they nevertheless offer new guidance on the scope of the long-standing ban on exporting U.S. crude oil and may provide an path forward for the export of petroleum products that result from the initial stages of crude oil processing.
As background, the U.S. government has restricted the export of crude oil from the United States since the 1970s due to concerns regarding short supply of domestic crude oil. The U.S. Department of Commerce, Bureau of Industry and Security (“BIS”) administers the regulations, the Export Administration Regulations (“EAR”), that control these exports. While authorization for exports of crude oil can be obtained, the circumstances in which exports have been permitted are fairly limited. On the other hand, BIS more freely permits the export of petroleum products that have been processed.
On June 23, 2014, in Utility Air Regulatory Group v. EPA et al., No. 12-1146 (and related cases), the Supreme Court held that the Environmental Protection Agency (EPA) may require certain greenhouse-gas emitters to install the “best available control technology” to limit the emissions of greenhouse gases (GHGs). Although the Court held (5-4) the EPA’s more sweeping interpretation of the Clean Air Act unlawful, the Court upheld (7-2) much of EPA’s authority to require compliance with GHG standards through the Prevention of Significant Deterioration (PSD) preconstruction permitting program for stationary sources already subject to PSD.
On June 19, 2014, the Federal Energy Regulatory Commission (FERC) issued Opinion No. 531, an order affirming in part and reversing in part an administrative law judge’s August 2013 Initial Decision concerning a complaint filed pursuant to section 206 of the Federal Power Act (FPA) challenging the New England Transmission Owners’ base return on equity (ROE).
In Opinion No. 531, FERC announced a new, two-step, constant growth discounted cash flow (DCF) approach for determining the base ROE for public utilities, and eliminated its existing practice of making post-hearing adjustments to ROEs based on changes in U.S. Treasury bond yields. Overall, the new approach is expected to produce a narrower zone of reasonableness, with ROEs (including incentives) capped at the upper end. As applied to the New England Transmission Owners, the new methodology produced a higher ROE than the administrative law judge had proposed in the Initial Decision (see Table 1 below). Opinion No. 531 and related orders in five other dockets should help eliminate much of the regulatory uncertainty that has surrounded electric utility ROEs in recent years by helping to clear the logjam of pending ROE dockets.
Abengoa Yield plc began trading on the NASDAQ on June 13th. The Form F-1 (the equivalent of a form S-1 for a foreign issuer) is available here. The IPO was priced at $29 a share. This was above the expected range of $25 to $27. Abengoa sold 29 percent of Abengoa Yield plc and raised $721 million. Below are some highlights from the prospectus.
Corporate Details: Abengoa Yield is a public limited company organized under English law. Its corporate headquarters is in the United Kingdom (U.K.).
Investment Profile: “[R]enewable energy, conventional power, electric transmission and water in the U.S., Canada, Mexico, Chile, Peru, Uruguay, Brazil, Colombia and the European Union.” Its initial portfolio does not include projects in all of those jurisdictions or water projects.
Asset Diversification: Abengoa Yield, like the very successful NRG Yield, has a diversity of technology. Its initial portfolio includes concentrating solar power (CSP), wind, conventional energy projects and transmission. Currently, the only assets in the United States are two CSP projects. The only asset in Spain is a CSP project and the only other renewables project is a wind farm in Uruguay.
On June 12, 2014, the Federal Energy Regulatory Commission (FERC) issued a Staff Notice of Alleged Violations (Preliminary Notice) stating that FERC’s Office of Enforcement has preliminarily determined, in a formal, nonpublic investigation, that Twin Cities Power-Canada, U.L.C. and certain affiliates, including Twin Cities Energy, L.L.C. (TCE) and Twin Cities Power, LLC (TCP), and individuals Allan Cho, Jason F. Vaccaro and Gaurav Sharma (collectively, the “Subjects”) each violated FERC’s prohibition of electric energy market manipulation in 18 C.F.R. § 1c.2.
The Preliminary Notice alleges that the Subjects violated FERC’s anti-manipulation rule “by scheduling and trading physical power” in the Midcontinent Independent System Operator, Inc. (MISO) market “to benefit related swap positions that settle off of real-time MISO prices, including the Cinergy Hub Balance-of-Day Swap traded on IntercontinentalExchange, Inc.” during the period from January 1, 2010 through January 31, 2011. The Preliminary Notice does not provide any additional details regarding the investigation or the alleged manipulation, but Twin Cities Power Holdings, LLC, which owns TCE and TCP and formerly owned Twin Cities Power - Canada, Ltd., which ceased operations in 2012, has been disclosing the existence of the investigation, initiated in October 2011, in Securities and Exchange Commission filings since at least June 2012.
On June 11, 2014, Acting FERC Chair Cheryl LaFleur announced that FERC will seek rehearing en banc of the May 23rd, 2014, decision of the D.C. Circuit that vacated FERC’s controversial rulemaking on demand response compensation in wholesale energy markets. The compensation rule, known as Order No. 745, requires Regional Transmission Operators and Independent System Operators to pay demand response resources the full locational marginal price paid to generators.1 The D.C. Circuit found that FERC lacked jurisdiction over demand response because it is part of the retail market and, thus, exclusively within state jurisdiction. In addition, the court held that the compensation provisions of the rule are arbitrary and capricious.2
The court is not required to grant FERC’s request to rehear the case. Under the Federal Rules of Appellate Procedure, en banc rehearings are generally disfavored and will not be ordered unless the proceeding “involves a question of exceptional importance” or en banc consideration is needed to ensure uniformity of the court’s decisions.3 A majority of the D.C. Circuit’s justices who are in regular active service and who are not otherwise disqualified must agree to rehear the case en banc.4
Yesterday, the IRS issued a notice confirming the effects of the Cash Grant sequestration with respect to the tax attributes associated with the renewable energy projects that received the Cash Grant.1 Notice 2014-39 is available here.
Sequestration became effective due to the inability of Congress and the president to effectuate the reduction in the federal deficit required by the Budget Control Act of 2011 (BCA). The BCA reflected a legislative compromise in 2011 to increase the debt ceiling while imposing automatic future budgets cuts (i.e., sequestration) if deficit reduction targets were not achieved. The targets were missed and another legislative compromise was unable to reached, so the automatic budget cuts went into effect on January 2, 2013.
On June 3, 2014, the U.S. Department of Commerce (DOC) announced its preliminary determination in the countervailing duty (CVD) investigation of crystalline silicon photovoltaic products (“solar products”) from China. DOC preliminarily found that China has subsidized the solar products covered by its investigation at rates ranging from 18.56 to 35.21 percent.
DOC’s preliminary determination will be enforced by U.S. Customs and Border Protection (CBP) through the collection of CVD cash deposits in the applicable amount from U.S. importers of record. The cash deposit requirement will become effective on the date of publication of DOC’s preliminary determination in the Federal Register, expected on or around June 10, 2014.
On June 4, 2014, the United States Court of Appeals for the 2nd Circuit (2nd Circuit) denied emergency stays of two Federal Energy Regulatory Commission (FERC) orders implementing a new capacity zone (NCZ) in New York (“NCZ Orders”).1 When the NCZ went into effect on May 1, 2014, FERC had not yet acted on requests for rehearing the NCZ Orders. Central Hudson Gas & Electric Corp (Central Hudson), the Public Service Commission of the State of New York (NYPSC) and the State of New York petitioned the 2nd Circuit for relief on May 12, 2014. In addition to the emergency stays, the petitioners requested a writ of mandamus compelling FERC to act on the pending requests for rehearing. On May 27, 2014, prior to oral arguments before the 2nd Circuit, FERC issued an order largely denying rehearing on the NCZ issues (“Rehearing Order”).
The petitioners had requested a decision from the 2nd Circuit by June 6, 2014, three days before the next New York Independent System Operator, Inc. (NYISO) monthly spot market auction. Oral arguments were held on June 3, 2014. Litigants argued over the merits of creating an NCZ and the legal standard for staying an agency order. Among other things, the parties’ arguments addressed the issue of whether the lack of a stay would cause irreparable harm to consumers. FERC argued that any harm would be purely economic and redressable, while Central Hudson and the NYPSC emphasized that it is impractical for NYISO to issue refunds.
The Fourth Circuit Affirms District Court Decision Finding Maryland’s Contract for Differences Unconstitutional
As we reported here, in October 2013, the United States District Court for the District of Maryland declared unconstitutional an order of the Maryland Public Service Commission (PSC) directing the state’s utilities to enter into a contract for differences with Competitive Power Ventures (CPV), pursuant to which CPV would construct a 661 MW natural gas-fired combined cycle generator in Charles County, Maryland.1 Under the contract, the actual revenues received by CPV for its sale of energy and capacity in the markets administered by PJM Interconnection, L.L.C. (PJM) would be compared to what CPV would have received for those sales had the contract prices been controlling, and any difference would be settled between CPV and its utility counterparties. On June 2, 2014, the United States Court of Appeals for the Fourth Circuit affirmed the District Court’s decision.2
Relying on a “wealth of case law” confirming the exclusive power of the Federal Energy Regulatory Commission” (FERC) to regulate wholesale sales of energy in interstate commerce, the Fourth Circuit concluded that the Maryland PSC order is field preempted “because it functionally sets the rate that CPV receives for its sales in the PJM auction” and “thus effectively supplants the rate generated by the auction with an alternative rate preferred by the state.” The court rejected the argument that the Maryland program to incentivize new generation within its borders does not actually set a rate, finding rather that contract price guaranteed by the state supersedes the PJM rates that CPV would otherwise earn. In response to the argument that the court should “apply a robust version of the presumption against preemption,” the court found that, while states retain the ability to regulate generating facilities, they may not exercise that authority in such a manner as to impinge on FERC’s exclusive jurisdiction over wholesale rates.
On Thursday, May 29, 2014, the U.S. Department of Energy (DOE) released two new reports on the potential environmental impacts of liquefied natural gas (LNG) exports from the United States to countries that do not have a free trade agreement with the United States requiring national treatment of natural gas (non-FTA countries). Both reports are being made available for public comment for 45 days, after which the reports and comments received from the public will be considered by the department in its public interest determinations in connection with applications to export LNG to non-FTA countries. All comments must be received by DOE no later than 4:30 p.m., Eastern Time, July 21, 2014. The reports were released contemporaneously with DOE’s announcement of proposed new rules for approving LNG exports from the United States to non-FTA countries. Please see our related blog post here.
Addendum to Environmental Review Documents Concerning Exports of Natural Gas from the United States
The first report, titled Addendum to Environmental Review Documents Concerning Exports of Natural Gas from the United States (Addendum), addresses potential environmental impacts associated with unconventional gas production in the Lower-48 states that may be induced by LNG exports. DOE states that it is not required to consider these potential environmental impacts under the National Environmental Policy Act.1 Moreover, “it is not reasonable to assume that unconventional natural gas production and the associated potential impacts will not occur if natural gas exports to non-FTA countries are prohibited.”2 However, DOE “prepared this Addendum in an effort to be responsive to the public and provide the best information available.”3 DOE states that “[i]t is likely that potential impacts will be less than represented herein, as regulations and best management practices continue to improve.”4
Yesterday, the United States Department of Energy (DOE) issued proposed new procedures for liquefied natural gas (LNG) export decisions. The proposal applies only to applications to export LNG from the Lower-48 states to countries that do not have a free trade agreement with the United States requiring national treatment for trade in natural gas (non-FTA countries). DOE is soliciting public comments on this proposal, and comments are due July 21, 2014.
Proposed New Procedures
Under the proposal, DOE would no longer act on applications under Section 3 of the Natural Gas Act to export LNG from the Lower-48 states to non-FTA countries according to the order of precedence published December 5, 2012.1 Instead, DOE would act on those applications in the order in which they were deemed to have completed the review process under the National Environmental Policy Act (NEPA).2 Specifically: (1) for those projects requiring an environmental impact statement (EIS), thirty days after publication of a final EIS; (2) for projects for which an environmental assessment has been prepared, upon publication of a finding of no significant impact; or (3) upon a determination by DOE that an application is eligible for a categorical exclusion pursuant to DOE’s regulations implementing NEPA.3
Last Friday, the North American Electric Reliability Corporation (NERC) submitted for approval by the Federal Energy Regulatory Commission (FERC), in Docket No. RM14-15, a proposed new physical reliability standard. The proposed new standard is intended to comply with FERC’s March 7, 2014 order directing NERC to propose one or more reliability standards to require certain entities to “take steps or demonstrate that they have taken steps to address physical security risks and vulnerabilities related to the reliable operation of the Bulk-Power System.”
The Federal Energy Regulatory Commission (the “Commission” or “FERC”) granted partial rehearing in three separate orders last week involving Order No. 1000 compliance filings.1 Most notably, the Commission reversed course on a prior holding that Commission-jurisdictional tariffs and agreements may not contain references to state laws favoring incumbent transmission developers. Commissioner Norris issued a partial dissent.
FERC issued Order No. 1000 in 2011 with the aim of reforming certain aspects of the electric transmission planning process and the associated cost allocation methods. Among other things, Order No. 1000 required transmission providers to eliminate from all Commission-jurisdictional tariffs and agreements any federal right of first refusal (ROFR) for incumbent transmission providers for transmission facilities selected in a regional transmission plan for purposes of cost allocation.2 The Commission determined that federal ROFRs create a barrier to entry for non-incumbent transmission developers.
Today the United States Court of Appeals for the D.C. Circuit vacated in its entirety FERC’s controversial rule governing demand response resources in wholesale energy markets, known as “Order 745.”1 The majority (Judges Brown and Silberman) held that “[b]ecause FERC’s rule entails direct regulation of the retail market—a matter exclusively within state control—it exceeds the Commission’s authority.” Even if FERC had statutory jurisdiction over demand response, “Order 745 would still fail because it was arbitrary and capricious.” Judge Edwards dissented.
Order 745 directs ISOs and RTOs to pay demand response providers, including aggregators of retail customers, the full locational marginal price (LMP) that is used to compensate generators. Demand response providers get to keep the savings from reducing their energy usage, and they also get paid (for their “negawatts”) the same price generators do for real megawatts. Opponents of the rule have argued that FERC-mandated compensation levels are too high, and give demand response providers an unjust and unreasonable windfall.
The U.S. Court of Appeals for the Sixth Circuit held this week that the Department of Energy (DOE) complied with its obligations under the National Environmental Policy Act (NEPA) in providing funding for a cellulosic ethanol plant. Klein v. EPA, No. 13-1165 (6th Cir. May 21, 2014). In accordance with the Energy Policy Act of 2005, DOE awarded a grant of $100 million to Frontier Renewable Resources LLC to build a 20-million-gallon-per-year cellulosic ethanol production plant in Michigan’s Upper Peninsula. Before rendering its final funding decision, DOE prepared an Environmental Assessment (EA) pursuant to NEPA, concluding that the project would not have a “significant adverse effect on the environment.”
The Sierra Club along with an individual who had a compromised immune system and resided near the proposed plant, challenged DOE’s decision. The U.S. District Court for the Western District of Michigan ruled that the plaintiffs did not have standing to sue and that, even if they had standing, DOE’s EA complied with NEPA. Klein v. Energy Department, No. 11-cv-00514 (W.D. Mich. Dec. 11, 2012). The Sixth Circuit affirmed the holding with respect to NEPA compliance, but reversed the lower court’s standing ruling. The Court held that DOE’s assessment consisted of “more than 400 pages” and met all NEPA requirements. The Court, bolstered by Circuit Judge Stranch’s concurrence, provided concise guidelines for demonstrating standing.
The Senate Energy and Natural Resources Committee held a hearing on Tuesday on the nominations of Norman Bay and Cheryl LaFleur to the Federal Energy Regulatory Commission (the “Commission” or “FERC”). Mr. Bay, who currently serves as the Director of the Commission’s Office of Enforcement, has been selected by the President to serve as the next Chairman. Ms. LaFleur, who has served as acting Chair since the departure of former Chairman Jon Wellinghoff, and who served prior to that as a Commissioner, has been nominated to serve another term as Commissioner.
Given Mr. Bay’s background as the head of FERC’s Enforcement operation, much of the hearing’s questioning involved what critics view as that office’s controversial investigatory practices. Since receiving enhanced civil penalty authority in the Energy Policy Act of 2005, the Office of Enforcement, under Mr. Bay’s leadership, has ramped up its prosecution of alleged manipulation of the energy and natural gas markets and other violations of Commission rules and tariffs. FERC has ordered payment of over $1 billion in civil penalties and disgorged profits under Mr. Bay, putting the previously little known independent agency in the unfamiliar position of grabbing national headlines and sparking public debate. Critics have argued that FERC has failed to clearly draw the line between acceptable market behavior and actions that cross into manipulation or fraud. Some critics also allege that FERC has failed to provide adequate due process during its investigations.
FERC Sets Enforcement Case Against BP for Hearing, Takes Expansive View of Jurisdiction to Enforce Anti-Manipulation Rule
In an order1 issued on May 15, 2014 that takes a broad view of its jurisdiction over conduct that allegedly violates the Natural Gas Act’s (NGA) prohibition against market manipulation, the Federal Energy Regulatory Commission (FERC) established a hearing to investigate whether BP America Inc., BP Corporation North America Inc., BP America Production Company and BP Energy Company (collectively, “BP”) manipulated the next-day, fixed-price natural gas market at the Houston Ship Channel (HSC) from mid-September 2008 (following Hurricane Ike) through November 2008. Rejecting BP’s motion to dismiss, FERC determined that there were genuine issues of material fact in dispute that warrant a hearing before an administrative law judge (ALJ). FERC directed the ALJ to make findings of fact that would enable FERC to determine penalties in the event that BP is found to have engaged in manipulative conduct in violation of FERC’s Anti-Manipulation Rule.2 FERC reserved for later consideration whether it should impose on BP any civil penalties, sanctions or disgorgement of unjust profits. In the May 15 order, FERC makes clear its position that the Anti-Manipulation Rule applies to nearly all gas trading and transportation activities, including sales and transportation activities not otherwise subject to FERC jurisdiction.
Last week, the U.S. House of Representatives passed the Electrify Africa Act of 2014, approving a plan to bring power to over 50 million Africans and further open the door for U.S. investors in the continent's development and growth.
The Electrify Africa Act, which mirrors many aspects of the Power Africa initiative unveiled last year by President Obama, aims to make government-backed credit more accessible to the private sector in order to deliver access to energy for more than 50 million people in sub-Saharan Africa. This important development could help interested investors access a $300 billion energy market in sub-Saharan Africa and tap into the demand for an additional 20,000 megawatts in the region.
“A letter of intent is the invention of the devil [that] should be avoided at all costs.” -- Stephen R. Volk, Esq. regarding the now (in)famous Texaco-Pennzoil case
A Dallas jury recently reminded us why Mr. Volk lamented letters of intent. Enterprise Products Partners, L.P. is currently appealing that jury’s finding of $319MM in actual damages and $914MM for improper benefits due to breach of the duty of loyalty related to an aborted pipeline “joint-venture” with Energy Transfer Partners, L.P. The jury found that a statutory partnership existed between the two pipeline giants despite the absence of a definitive agreement and the presence of substantial written disclaimers and waivers in the nonbinding letter of intent (“LOI”) and related agreements.
In response to the April 20, 2010, Deepwater Horizon incident and under the auspices of the United States Department of Interior’s (DOI’s) “Idle Iron Policy,” the Bureau of Safety and Environmental Enforcement (BSEE) has invested significant oversight resources in the decommissioning of idle oil and gas wells and related structures in the Gulf of Mexico (GOM). As of January 2014, a total of 1,650 wells and 284 platforms have been decommissioned in the GOM, typically underwritten by the most recent operators of record.
On the same day as President Obama’s speech championing solar, the Department of the Treasury proposed regulations defining “real estate assets” for purposes of the definition of a real estate investment trust (REIT). The same definition would apply for purposes of the real estate component of the qualified income standard in the publicly traded partnership definition used to determine whether a master limited partnership (MLP) will be taxed as a partnership.
The proposed regulations describe three fact patterns involving solar and analyze whether the assets involved are real estate for purposes of the REIT rules. It is critical to a REIT that the assets in which it invests qualify as “real estate” because two of the most salient elements of the definition of a REIT are that 75 percent of its assets must be real estate assets or real estate mortgages, and 95 percent of its gross income must be derived from real estate assets or real estate mortgages. It can also be critical that an MLP owns real estate, as 90 percent of its gross income must be “qualifying income,” which includes rents and gains from real estate.
On Friday, Christopher Kelley of the Treasury Office of Tax Legislative Counsel announced that the IRS would be issuing additional guidance to determine whether projects started construction in 2013 as is necessary to be eligible for production tax credits. Kelley’s comments were made in at an American Bar Association Section of Taxation meeting in Washington, DC.1
The guidance is in response to requests from the wind industry for further clarification as to two issues. First, what level of physical work was required for projects, which did not opt to satisfy the 5% safe harbor, to be deemed to have started construction in 2013 as is necessary for production tax credit eligibility? Second, what level of legal stake must a developer have had in a project in 2013 to have purchased equipment pursuant to a master supply agreement with a manufacturer that is subsequently transferred to the project in order to enable the project to satisfy the 5% safe harbor?
Here’s the link to the poster that I presented at WindPower on master limited partnerships (MLPs), real estate investment trusts (REITs) and YieldCos.
The poster explains (i) the limited extent to which MLPs and REITs, each of which have a tax-advantaged status, can invest in wind projects under current tax law, (ii) how proposed changes in tax law if enacted would permit MLPs to expand their ability to invest in wind projects and (iii) how the yieldco vehicle, which is a publicly traded C-corporation without any special tax status, is being used for wind projects in lieu of MLP vehicles.
The Clean Air Act of 1970 (CAA)1 requires that states be “Good Neighbors” and regulate their in-state sources of pollution so that those sources do not “contribute significantly” to pollution in other states downwind.2 Congress assigned the Environmental Protection Agency (EPA) the unenviable task of orchestrating compliance through the cooperative federalism framework of the CAA, and over the last two decades, the EPA has made repeated, and highly controversial, attempts to implement the “Good Neighbor Provision.”3 The most recent of these efforts, the Cross-State Air Pollution Rule (CSAPR)4 received a stamp of approval from the Supreme Court on April 29, 2014 in EPA v. EME Homer City Generation.5 However, despite the EPA now having a regulatory framework that passes muster, increased neighborliness does not appear imminent.
CSAPR is designed to provide a solution to a seemingly intractable problem: “Most upwind States propel pollutants to more than one downwind State, many downwind States receive pollution from multiple upwind States, and some States qualify as both upwind and downwind.”6 The EPA found and evaluated nearly 2,500 such “linkages” between downwind and upwind states.7 The challenge, then, was to create a legal framework for reducing these streams of pollution, but only to the extent that they “contribute[d] significantly” to the non-attainment of National Ambient Air Quality Standards (NAAQs) by downwind states.
Yet again the Mexican government has surpassed the expectations of the international marketplace. Many prognosticators and industry participants believed that the constitutional restrictions against international participation in the upstream sector would never be changed. The PRI and PAN changed it. Then, when most believed that the government would never be able to introduce the critical secondary legislation reforms to implement the changes to the constitution during the legislative session that ended yesterday. It did.
The timely introduction of legislation to the Congress, when most in the industry believed that the government would miss the deadline, is another sign of how committed Mexico is to the process of reform. This should be received as an extremely positive sign by the markets, and despite PEMEX reporting its sixth consecutive quarter of losses, the future is bright for them and the industry.
On April 24, the US Partnership for Renewable Energy Finance (USPREF) which is affiliated with American Council on Renewable Energy published an analysis of the effect of favorable governmental policies on the deployment of renewable energy in the United States.
The analysis points to tangible data that demonstrates how favorable policies have spurred deployment of renewable energy projects, which has spurred cost reductions and improvements in efficiency. The analysis is available here.
Dino Barajas, Partner at Akin Gump Strauss Hauer & Feld will participate in a webinar titled “The Latin American and Caribbean Markets” on April 30 hosted by ACORE. The webinar will focus on nearby markets of Latin America and the Caribbean. Following an overview of current opportunities and developments in key markets, the panelists will discuss alternative considerations for selecting and advancing successful off-shore project opportunities. Please register for the webinar here.
Akin Gump will be hosting a half day seminar, sponsored by the New York City Bar Association, Energy Committee focusing on increasing enforcement activity and related investment risks. Our panelists will provide practical advice for companies that have been targeted for enforcement action, and will focus on helping your company create a compliance culture, training, risk controls and other tools to mitigate the risks associated with enforcement actions. We also address the changing economic and regulatory landscape and how these changes may impact the utility of the future.
The seminar will take place on May 1 starting at 1:30pm at One Bryant Park, 43rd Floor, New York, NY 10036. To register, please click here.
With both chambers of Congress considering the extension of the production tax credit (PTC), the Congressional Research Service published a report on April 7, 2014, The Renewable Energy Production Tax Credit: In Brief. The report is available here.
The report is relatively even handed and provides a number of interesting data points. Overall, the report is generally supportive of the PTC but suggests that a direct tax on carbon emissions would be more efficient. A tax on carbon would eliminate the costs associated with executing tax equity transactions. That is tax equity investors do not provide wind developers with a dollar-for-dollar benefit for each dollar of PTC allocated to them. From a policy perspective, I find it difficult to favor the PTC over a direct carbon tax; however, a direct tax on carbon is not a viable legislative strategy given the current composition of Congress. In contrast, the PTC has greater political viability, in the form of bipartisan support since its enactment in 1992, and promotes reduction in carbon emissions.
Last week the United States Department of Energy (the DOE) announced two programs supporting the Obama administration’s commitment to renewable energy development.1 On April 16, the DOE released a draft solicitation for up to $4 billion in loan guarantees for renewable energy projects and energy efficiency projects (the Loan Guarantee Solicitation). Just one day later, on April 17, the DOE announced the $15 million Solar Market Pathways program for community solar development.
Loan Guarantee Solicitation
Under the Loan Guarantee Solicitation, up to $4 billion in DOE loan guarantees will be available for innovative renewable or energy efficiency technologies that reduce or capture greenhouse gas emissions and would have difficulty obtaining traditional commercial financing.
The National Renewable Energy Laboratory (NREL), which is a component of the U.S. Department of Energy, has published a report analyzing the implications of the extension of the production tax credit (PTC) for U.S. manufacturing and employment levels. The report is available here.
The report finds that significant manufacturing facilities have opened in the U.S. due to the growth of wind electricity production which is bolstered by the PTC. The report concludes (1) that to maintain the current level of U.S. manufacturing related to the industry would require wind deployment levels at the average that occurred from 2008 to 2012 and (2) to maintain that level of deployment would require extension of the PTC through 2021.
A panel of the U.S. Court of Appeals for the D.C. Circuit held today that a portion of the SEC’s conflict minerals reporting regulations – and possibly a portion of the underlying Dodd Frank Act – compel speech in violation of the First Amendment. Nat’l Assn. of Mfgrs. V. SEC, No. 13-5252 (D.C. Cir. April 14, 2014).
The National Association of Manufacturers (NAM) challenged the requirement that an issuer describe its products as not “DRC conflict free” in its conflict minerals report to the Commission and on its public website. The SEC regulations require certain publicly traded companies to conduct due diligence on their supply chains to determine if certain of their products contain gold, tin, tantalum, or tungsten that originate in the Democratic Republic of Congo or adjoining countries and if those minerals benefit certain “armed groups”. Covered companies must then publicly list such products and state that they “have not been found to be ‘DRC Conflict Free.’”
Arjuna Capital, a sustainable wealth management platform, and As You Sow, an environmental corporate responsibility advocacy group, have been advocating for publicly traded companies to assess and disclose the risks that their assets will be “stranded” as a result of changing regulatory regimes designed to address climate change. The rationale underlying these efforts derives from the notion that a “carbon bubble” exists. Author and climate activist Bill McKibben is often credited with introducing the notion, basing it on a U.K. research group’s contention that upwards of 80 percent of the world’s oil, gas and coal reserves would become “stranded” if GHG emissions were controlled sufficiently to limit global warming to an increase of 2º C. Click here.
The entire carbon-bubble concept and the resulting drive for disclosure rests on the assumption that the major emitting countries will be able to agree to effective and binding requirements to reduce emissions. Experience under the United Nations Framework Convention on Climate Change, the international treaty that purportedly set binding obligations on industrialized countries to reduce emissions of greenhouse gases, suggests that this assumption is, by no means certain to prove reliable. If anything, the individual self-interest of so many countries emitting significant amounts of GHGs renders the assumption highly uncertain.
Today, the U.S. Senate Committee on Energy and Natural Resources held a standing-room only hearing titled “Keeping the lights on — Are we doing enough to ensure the reliability and security of the U.S. electric grid?” While the hearing was organized into two panels focusing on cyber security and physical security, the questioning from the lawmakers focused on physical security, particularly whether tighter controls need to be placed on information concerning critical energy infrastructure and whether the expected retirement of generation resources within the footprint of PJM Interconnection, L.L.C. (PJM) poses reliability concerns.
The first panel included Cheryl LaFleur, acting Federal Energy Regulatory Commission (FERC) chairman; Gerry Cauley, North American Electric Reliability Corporation president and CEO; Sue Kelly, president and CEO of the American Public Power Association; and Colette Honorable, President of the National Association of Regulatory Utility Commissioners (NARUC). The panelists fielded several questions on the response to the April 2013 sniper attack on Pacific Gas & Electric Company’s Metcalf transmission substation and information recently published in the Wall Street Journal concerning the transmission grid’s vulnerability to attack. Both Senator Mary Landrieu (D-LA), Chair of the Committee, and Ranking Member Lisa Murkowski (R-AK) asked LaFleur about FERC’s handling of sensitive infrastructure data, including measures to properly classify documents and ensure a culture of compliance. Murkowski said she would submit interrogatories to FERC concerning the transmission grid vulnerability study that was the subject of the Wall Street Journal’s March 12, 2014 story. LaFleur said she believes that FERC has a culture of compliance, noting that FERC is privy to confidential information every day, and there have not been leaks in the past. However, she affirmed her commitment to a compliance culture that starts at the top and extends to every person within the agency.
On April 1, 2014, the Federal Energy Regulatory Commission (FERC) held a technical conference on “Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators.” FERC’s Office of Enforcement presented its preliminary observations and analysis, available here of the operations of the natural gas and the Regional Transmission Organization and Independent Systems Operators markets during the first three months of 2014, which were marked by historically cold weather, record high natural gas and electric demand, and record high natural gas prices, which translated into abnormally high electricity prices.
According to FERC staff’s preliminary analysis, cold weather combined with high levels of generation outages placed some regions near their capacity to meet system demand. Mechanical failures in generator systems, fuel deliverability and fuel handling problems led to high levels of forced generation outages which contributed to the stressed conditions in the markets. The RTOs and ISOs declared emergency conditions on several occasions and some implemented emergency procedures, including emergency demand response, voltage reduction, emergency energy purchases, and public appeals for conservation.
As part of its coverage of the role women are taking in Houston’s energy boom, the Houston Business Journal, after consulting with industry experts, named Akin Gump oil and gas practice head and Houston partner in charge Chris LaFollette among “the area’s top females in the oil and gas industry.”
The Journal notes her leadership role in the Houston office as well as her service on Akin Gump’s firmwide management committee and on the Houston office’s diversity committee. LaFollette’s service as a director of the Houston World Affairs Council and for the National Association of Corporate Directors’ Houston chapter and the Texas General Counsel Forum is also featured.
LaFollette has received several recognitions in recent months, including as a Law360 Female Powerbroker and as one of the “movers and shakers” in the energy field in Houston Business Journal’s 2013-2014 Who’s Who in Energy.
Senator Wyden (D-OR), chairman of the Senate Finance Committee, stated that he will release his “extenders” bill on March 31 and that the included provisions will be renewed through the end of 2015. Senator Rockefeller (D-WV) stated that Wyden’s bill will not include “offsets” for the cost of the extenders.1
An extension through 2015 would be good news for the wind industry; however, there are still questions that the wind industry will not have answered until it sees the bill on March 31. For instance, will Wyden retain the “start of construction” approach from the last extension or revert to the customary “placed-in-service” standard? There is a significant difference, since start of construction would merely require that a wind project start construction by the end of 2015, while a placed-in-service standard would require the project to be operational by the end of 2015.
In the first half of this decade, solar developers in the United States were largely focused on utility scale projects. “Mega-projects,” such as SunPower’s approximately 580 MW Solar Star projects, First Solar’s 550 MW Topaz project and BrightSource’s 377 MW Ivanapah project, exemplify the industry’s success.
Yet, even with more than 18GW of utility scale solar expected to be online in the United States by 2016, the future growth of the U.S. solar market will likely be through distributed generation projects (panels on homes, businesses, car parks, etc.) instead of large-scale utility projects. Fewer power purchase agreements, stringent regulatory requirements and the impending decrease in the ITC have made utility scale projects more difficult to develop and finance, causing developers to shift their focus to distributed generation projects.
In President Obama’s 2014 State of the Union address, he said: “Every four minutes, another American home or business goes solar; every panel pounded into place by a worker whose job can’t be outsourced. Let’s continue that progress with a smarter tax policy that stops giving $4 billion a year to fossil fuel industries that don’t need it, so that we can invest more in fuels of the future that do.”
With such an endorsement, the solar industry thought its tax priorities were in a prime position in the executive branch, but five weeks later the administration’s fiscal year 2015 budget proposal was released and included a proposal to completely repeal the solar investment tax credit after 2016.1
ITC Companies Settle FERC Enforcement Action Regarding Federal Power Act Section 203 and 205 Violations for $750,000
On March 11, 2014, the Federal Energy Regulatory Commission (FERC) issued an order approving a settlement between the FERC Office of Enforcement (OE) and four subsidiaries of ITC Holdings Corp. (the ITC Companies) that resolves OE’s investigation of numerous alleged violations by the ITC Companies of Sections 203 and 205 of the Federal Power Act (FPA) from 2003 to 2011.
Summary of Alleged Violations and Settlement Terms
As we explained in a prior post, OE’s investigation focused on:
- Whether the ITC Companies violated Section 203(a)(1)(B) of the FPA and Part 33 of the FERC’s regulations by acquiring certain FERC-jurisdictional facilities, in 20 transactions valued between $0 and $6.7 million between 2005 and 2011, without obtaining FERC authorization (the ITC Companies subsequently obtained prospective authorization for those transactions); and
- Whether certain of the ITC Companies violated Section 205 of the FPA and Part 35 of the FERC’s regulations by, between 2003 and 2011, commencing or terminating FERC-jurisdictional service without providing the required notice to the FERC, succeeding to certain FERC-jurisdictional contracts without timely providing notice to the FERC, or failing to submit complete information in their Electric Quarterly Reports. In total, the ITC Companies disclosed 174 jurisdictional documents not properly filed with the FERC, 171 of which have since been filed, and of 165 of which the FERC has accepted, with the remainder still pending or requiring third-party consents yet to be obtained.
On March 6, 2014, Sen. Mark Begich (D-Alaska) proposed amendments to Section 3 the Natural Gas Act (NGA) to expand the list of export destinations that are eligible for an expedited permitting process at the Department of Energy (DOE). The same day, Sen. Edward J. Markey (D-Massachusetts), Chairman of the Foreign Relations Subcommittee with jurisdiction over international energy security, introduced legislation that would delay the approval of additional exports to some destinations for up to two years – or longer.1 The competing bills highlight the controversy surrounding natural gas exports, particularly in light of recent calls to expedite exports of natural gas to the Ukraine to ease that country’s dependence on Russia to meet its energy needs.
Senator Begich Proposes To Expedite Natural Gas Exports
Senator Begich’s bill, S-2096 , would expand the list of export destinations that are eligible for an expedited permitting process at the DOE. Under Section 3(c) of the NGA, the exportation of natural gas to a nation with which there is in effect a free trade agreement requiring national treatment for trade in natural gas “shall be deemed to be consistent with the public interest,” and applications for such exports “shall be granted without modification or delay.” In practice, DOE processes applications to export natural gas to countries that have a free trade agreement with the U.S. in a matter of weeks. Senator Begich would expand the list of export destinations eligible for such expedited treatment to include:
- A member country of the North Atlantic Treaty Organization;
- Japan, so long as the Treaty of Mutual Cooperation and Security between the U.S. and Japan remains in effect; and
- Any other foreign country if the Secretary of State, in consultation with the Secretary of Defense, determines that exportation of natural gas to that foreign country would promote the national security interest of the United States.
On February 27, 2014, the House Committee on Foreign Affairs passed H.R. 2548, the Electrify Africa Act, to improve access to electricity in sub-Saharan Africa, through a comprehensive U.S. government approach to electricity projects in the region. The bipartisan legislation would establish a U.S. strategy to support affordable, reliable electricity in sub-Saharan Africa in order to improve economic growth, health and education in Africa, while helping job creation in the United States through greater exports.
The main purpose of the Electrify Africa Act is to make government-backed credit more accessible to the private sector in order to deliver access to energy for more than 50 million people in sub-Saharan Africa. This important development could help interested investors access a $300 billion energy market in sub-Saharan Africa and tap into the demand for an additional 20,000 megawatts in the region.
FERC Directs NERC to Propose Mandatory Reliability Standards Regarding Physical Security Risks to the Bulk-Power System
On March 7, 2014, the Federal Energy Regulatory Commission (FERC) issued an order directing the North American Electric Reliability Corporation (NERC) to propose one or more Reliability Standards to require certain entities to “take steps or demonstrate that they have taken steps to address physical security risks and vulnerabilities related to the reliable operation of the Bulk-Power System.” The FERC’s related news release is available here. The proposed Reliability Standards are due by June 5, 2014, and will be subject to comment in a rulemaking proceeding. The FERC also provided an opportunity for interested parties to be heard in the proceeding in which it issued the order, and set a deadline for notices of intervention or motions to intervene of March 28, 2014.
Even though the need for additional natural gas infrastructure in the Northeast was known long ago, the impact of this winter's extreme weather on electricity and gas prices could stimulate more political support to pursue the best ways to get new gas pipeline capacity built in the region, according to a top energy industry attorney.
"Depending on what your opinion is about whether the cold weather we've experienced this winter is an anomaly or the new normal, either way the need for additional infrastructure is pretty clear," Julia Sullivan, a partner and co-chair of the energy regulation, markets and enforcement practice at Akin Gump Strauss Hauer & Feld LLP, said in an interview.
For its article “Effectively delivering energy capital projects,” FierceEnergy spoke with Akin Gump energy partner Gabriel Procaccini on managing the many components of a complex capital project.
Procaccini said, “The companies that do it well get their legal advisors, their technical team and financial advisors together as early in the process as possible, so those groups can get up to speed, so everyone's on the same page.”
Here’s a chart that compares how Pres. Obama’s fiscal year 2015 budget proposal addresses renewable energy to how Rep. Camp’s (R-MI) proposal for fundamental tax reform addresses renewable energy. Camp is chairman of the Ways and Means Committee.
A prior blog post addressed former Sen. Baucus’s (D-MT) energy tax reform proposal. Sen. Baucus introduced his proposal in his capacity as chairman of the Finance Committee but shortly thereafter accepted an appointment to be ambassador to China. This has left his proposal without a champion.
Facing Civil Penalty, Paper Mill Asks District Court to Find that FERC Lacks Jurisdiction Over Demand Response
After a long investigation dating back to 2008, the Federal Energy Regulatory Commission (Commission) concluded in 2013 that Lincoln Paper and Tissue, LLC (Lincoln), a Maine paper mill, had engaged in fraud through its participation in the ISO New England Inc. (ISO-NE) demand response program. Under this program, ISO-NE—an independent operator of the New England bulk transmission system and administrator of Commission-jurisdictional wholesale power markets in New England—compensates customers for reducing electricity consumption during periods of high demand. To measure the extent to which a participating customer reduces consumption, the customers must establish a “baseline” level of consumption. The baseline is intended to reflect the amount of power the customer pulls from the grid during normal operating conditions. The Commission found in its 2013 order that Lincoln engaged in an “intentional fraudulent scheme” by artificially inflating its baseline, which allowed Lincoln to collect substantial demand response revenues without having to actually reduce load below normal operating levels. Lincoln allegedly inflated its baseline by strategically curtailing its use of on-site generation during the period when its customer baseline was being developed. Lincoln denies any wrongdoing.
In the 2013 order, the Commission directed Lincoln to pay a $5 million civil penalty and to disgorge $379,016.03, plus interest, of unjust profits to ISO-NE. After Lincoln did not make the required payments, the Commission petitioned the United States District Court for the District of Massachusetts in December 2013 to enforce the penalty. Lincoln filed a Motion to Dismiss on February 14, 2014, alleging, among other things, that the Commission’s petition to enforce the penalty is barred by the statute of limitations and that, in any event, the Commission lacks jurisdiction over demand response.1
The security of the electric grid, both cyber- and physical, recently has received much public attention due to publicity surrounding a sniper attack on a California substation (see our blog post on grid security here). But FERC Commissioners John R. Norris and Philip D. Moeller advise against widespread panic and superfluous spending on security measures that could “inadvertently promote the prospect of additional copycat attacks” by publicly highlighting the grid’s areas of vulnerability. In their February 20, 2014 statements (available here and here), both Commissioners acknowledged that there is always room for improving security measures. Commissioner Norris suggested that utilities continue to focus on “modernizing” the grid with the further deployment of phasor measurement units, wide-area management systems, enhanced situational awareness to improve reliability and efficiency, and increased use of microgrids and smart grid technology to improve system resiliency. Norris also championed the planned initiatives between NERC and industry stakeholders as concrete, smart solutions to growing threats. Norris fears, however, that actions such as the erection of physical barriers—called for specifically by Sen. Charles E. Schumer (D-NY) (statement here)—are “20th century solution[s] for a 21st century problem.”
Norris’s words of caution are well-timed. It has recently been reported that Dominion Virginia Power is planning to spend up to $500 million on the installation of anti-climb fences and other steel barriers around their most critical infrastructure. In addition, a recent order issued by the New York State Public Service Commission requires that Con Edison invest $1 billion over the next four years to protect its infrastructure from natural threats such as Hurricane Sandy, and human security threats such as the Metcalf incident. While Commissioner Norris conceded that some such measures may be warranted, he highlighted the risk of “piling up billions in consumer costs in rate base” attempting to protect “400,000 miles of transmission lines and 55,000 substations” with walls and fences.
Two years ago, the Supreme Court upheld the major domestic policy initiative of President Obama’s first term, ruling that the Affordable Care Act passed constitutional muster. This coming June, the Court will determine the legitimacy of what is perhaps the major domestic policy initiative of the president’s second term, his administration’s efforts to reduce the emission of greenhouse gases (GHGs).
The Court heard an argument today in Utility Air Regulatory Group v. Environmental Protection Agency addressing a deceptively simple question-“whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” For more than three decades, EPA has interpreted the Clean Air Act (CAA) to authorize it to regulate pollutants emitted by any source once it had issued rules to regulate those pollutants from any single type of source. EPA’s interpretation of the CAA in this fashion did not generate significant controversy until the EPA sought to apply it to GHGs.
On February 20, 2014, the United States Court of Appeals for the Third Circuit denied several petitions for review challenging a series of 2011 orders from the Federal Energy Regulatory Commission (the Commission or FERC). The Commission orders involved the PJM Interconnection, L.L.C. (PJM) Minimum Offer Price Rule (MOPR), a complex market rule designed to prevent certain uncompetitive market behavior.
The MOPR was first established as part of the settlement agreement instituting PJM’s capacity market, known as the Reliability Pricing Model (RPM). The purpose of the MOPR was to prevent the exercise of buyer-side market power. Conceptually, buyer market power in capacity markets occurs when an entity engages in behavior intended to lower market clearing prices below a competitive level. Because some market participants are both buyers and sellers of capacity in RPM, an entity that is substantially “net short” on capacity—that is, an entity that buys more capacity than it sells—may have a rational economic incentive to lower prices. The MOPR seeks to ensure that a new market entrant offers into the capacity auction at a competitive price that reflects the resource’s costs (and not an artificially low price aimed at ensuring that the resource clears the auction).
The timing of the 7th Annual Storage Week conference fell during Southern California Edison's review of storage proposals to meet the 50 MW storage mandate for the West Los Angeles Basin planning and the deadline for the state's investor owned utilities to file their plans for the storage procurement processes under the statewide 1.3 GW energy storage mandate. Considerable information and insight was shared about storage market developments throughout the country such as:
1. the increased penalties imposed in the MISO market after implementing FERC Order 755's requirement for more accurate measurements in the ancillary services markets,
2. PJM's reporting that 4.5 MWs of storage are under construction in its territory to go with the approximately 80.5 MWs already in operation,
3. ERCOT's statements that it still is carefully observing the developments in other storage markets but nonetheless has 3 compressed air energy storage projects in the cue and noticed that there seemed to be a shortage of battery projects under serious consideration in its territory and
4. Puerto Rico's PREPA continuing evaluation of the proper balancing of its storage requirements that accompany solar projects.
On February 11, 2014, Acting Chairman Cheryl A. LaFleur of the Federal Energy Regulatory Commission (FERC) responded (available here) to a letter from four members of the Senate, which asked if further regulatory measures were needed to protect the physical security of the bulk power system. Acting Chairman LaFleur explained that steps were being taken to coordinate with utilities and other government agencies to improve physical security. She agreed, however, that further regulation might be warranted, and asked for Congress to address related issues of confidential information and emergency response.
The letter (available here), signed by Senate Majority Leader Harry Reid (D-NV) and Senators Ron Wyden (D-OR), Dianne Feinstein (D-CA), and Al Franken (D-MN), was sent to Acting Chairman LaFleur and Gerry Cauley, the President and CEO of the North American Electric Reliability Corporation (NERC). It referenced the sniper attack on the Metcalf electrical substation in California on April 16, 2013. During the highly organized attack, 17 transformers were damaged and phone and internet cables nearby were cut. Both the perpetrators and their motive remain unknown, but there are fears that the attack was a “dress rehearsal” for a larger attack on the bulk power system. The Senators noted that FERC and NERC have “clear and unmistakable” authority to develop mandatory reliability standards governing physical grid security under Section 215 of the Federal Power Act. The letter expressed concern that voluntary measures might not be sufficient to meet the risk of physical attacks such as that on the Metcalf Facility.
FERC Alleges Numerous Federal Power Act Section 203 and 205 Violations by Subsidiaries of ITC Holdings Corp.
On February 11, 2014, the staff of the Office of Enforcement (OE) of the Federal Energy Regulatory Commission (FERC) issued a Staff Notice of Alleged Violations (Notice) stating that it has preliminarily determined that four operating company subsidiaries of ITC Holdings Corp. (ITC) violated Section 203 of the Federal Power Act (FPA) and FERC’s regulations by failing to obtain FERC authorization prior to consummating certain transmission asset transactions and/or Section 205 of the FPA and FERC’s regulations by failing to timely file with FERC certain FERC-jurisdictional agreements.
The Notice alleges that International Transmission Company, d/b/a ITCTransmission, Michigan Electric Transmission Company, LLC (METC), ITC Midwest, LLC (ITC Midwest), and ITC Great Plains, LLC violated Section 203(a)(1)(B) of the FPA and/or Part 33 of FERC’s regulations by acquiring jurisdictional transmission facilities in twenty transactions between 2005 and 2011 without obtaining prior FERC authorization. The Notice also alleges that ITCTransmission, METC, and ITC Midwest violated Section 205 of the FPA and Part 35 of FERC’s regulations by failing to timely file with FERC nearly 175 jurisdictional agreements the companies inherited or executed between 2003 and 2011.
The Washington Post in an editorial of January 20 described the extension of the production tax credit (PTC) for wind as “wasteful.” The Post’s editorial is available here.
However, The Post’s editorial board has penned multiple editorials expressing concern about climate change and noting that the United States lacks a coherent policy to address it. Below is my letter to the editor responding to the mischaracterization of the PTC and noting the inconsistency in being concerned about climate change and then characterizing the PTC as wasteful.
New York Association of Public Power Files Complaint to Reduce Niagara Mohawk Power Corporation’s ROE
On February 6, 2014, the New York Association of Public Power (NYAPP) filed a second complaint (Second Complaint) against Niagara Mohawk Power Corporation d/b/a National Grid (NMPC) asking the Federal Energy Regulatory Commission (FERC or the Commission) to reduce the Return on Equity (ROE) used to calculate NMPC’s transmission rates under the New York Independent System Operator’s Open Access Transmission Tariff (OATT).1 Please click here to read complaint. NYAPP filed a similar compliant on September 11, 2012 (First Complaint), recommending a base of ROE of 9.49 percent for NMPC, based on market conditions at that time.2 Please click here to read complaint. The Second Complaint, using updated information, recommends an ROE of 9.36 percent. NMPC’s current base ROE is 11.5 percent.
NYAPP’s Second Compliant is essentially a renewal of the First Compliant. The Federal Power Act (FPA) limits refunds to a fifteen month period, starting no earlier than the filing of a compliant. Assuming that FERC choses to set the refund effective date for the First Compliant as of the date of that filing, the refund period would have run out in December 2013. NYAPP therefore filed the Second Complaint to “prevent a gap in refunds,”3 and provide an updated analysis of NMPC’s ROE. The Municipal Electric Utilities Association of New York State (MEUA) filed its own complaint on November 2, 2012 (MEUA Complaint) asking for a reduction in NMPC’s ROE.4 Please click here to read complaint.
On February 7, 2014, the Federal Energy Regulatory Commission (FERC) approved a Stipulation and Consent Agreement between the Office of Enforcement (OE) and Louis Dreyfus Energy Services, L.P. (LDES) to resolve an investigation of whether LDES violated FERC’s Anti-Manipulation Rule in connection with certain virtual and Financial Transmission Rights (FTR) trading activity in the Midcontinent Independent System Operator, Inc. (MISO) footprint from November 2009 through February 2010. OE began the investigation in April 2010 after a referral from the MISO Independent Market Monitor. The order comes soon after FERC first publicized its preliminary findings in a notice issued on January 6, 2014.
LDES did not admit or deny the alleged violations, but stipulated to certain facts and agreed to: (1) disgorge $3,340,000 (plus interest of $383,743) to MISO, to be allocated at MISO’s discretion, subject to OE approval, for the benefit of MISO market participants; (2) pay a civil penalty of $4,072,257; and (3) implement compliance safeguards related to virtual transactions in MISO, including filing semi-annual compliance reports through at least 2016. In addition, Xu Cheng, an LDES trader and signatory to the settlement, will pay a civil penalty of $310,000, and not engage in virtual trading in FERC-jurisdictional markets for two years. Cheng also did not admit or deny the alleged violations.
Some common themes regarding the current state of the US solar market emerged this week at the Solar Power Generation Congress 2014 in San Diego, where I chaired and moderated the keynote session and the debt finance.
In the US the highest growth is expected to continue in the already robust Southwest and Northeast given that the fundamentals--load growth and utility rates--are not expected to change in the short term. California Energy Commissioner, David Rochschild, remarked that California remains enthusiastically supportive of solar development. There is rising promise in areas of the Southeast US, especially Georgia and North Carolina, which mostly is resulting from the growing pricing competitiveness of solar technology and not as much from policy developments in those states.
FERC Approves PJM’s Proposed Changes to Market Rules Governing the Participation of Demand Response Products in the Capacity Market
On January 30, 2014, the Federal Energy Regulatory Commission (FERC) issued an order approving rule changes proposed by PJM Interconnection, L.L.C. (PJM) to the clearing of its capacity market, referred to as the Reliability Pricing Model (RPM).1 FERC explained that PJM’s proposal was “intended to correct for the unintended adverse market and reliability impacts of certain capacity market rule changes adopted by PJM in 2011, when PJM first introduced its existing menu of demand response [DR] product alternatives.”2
The purpose of PJM’s 2011 rule changes was to accommodate the participation of DR providers in RPM auctions. The 2011 rule changes established a minimum procurement target for the highest availability capacity product, so-called “Annual Resources.”3 The 2011 rule changes left in place the pre-existing limited DR product (renamed “Limited DR”) and added two less-limited DR products, referred to as “Extended Summer DR” and “Annual DR.”
On January 24, the U.S. Court of Appeals for the Fourth Circuit upheld an order issued by the Federal Energy Regulatory Commission (FERC) in 2012 denying rehearing (Rehearing Order) of a 2008 order granting Virginia Electric and Power Company (VEPCO) rate incentives for eleven different transmission projects (Incentives Order). On appeal, the North Carolina Utilities Commission (the NC commission) challenged FERC’s decision to grant incentives for five of the projects. The NC commission argued that FERC should be required to apply a subsequent change in policy, announced by FERC in 2010, to the VEPCO incentives. The NC commission also argued that FERC erred in granting incentives to the five projects in the first place. The Fourth Circuit disagreed with the NC commission and affirmed the Rehearing Order as falling within FERC’s broad discretion and expertise.
FERC issued the Incentives Order pursuant to Section 219 of the Federal Power Act, finding a required “nexus” between the risks and challenges faced by VEPCO in developing the projects and the requested transmission incentives. The NC commission filed a petition for rehearing. However, in the words of the Fourth Circuit: “[f]or reasons that remain unsatisfactorily explained even after oral argument, FERC failed to issue its Order Denying Rehearing until almost four years after its initial order . . . .” In the interim, FERC changed its policy regarding the nexus requirement, deciding that it would no longer consider unrelated projects in aggregate when deciding if there was a nexus with the requested incentives. Under the new policy, FERC requires a nexus between the requested incentives and each individual project. In the Rehearing Order, FERC acknowledged that, had VEPCO made its request for incentives under the new policy, the outcome might have been different.
Mainstream media have recently noted efforts by business interests to address potential risks to their business from a changing environment; for example, “Industry Awakens to Threat of Climate Change,” New York Times, available here; “Survey Roundup: Unaware CEOs, Climate Risks to Supply Chains,” Wall Street Journal available here. As business entities assess potential risks, the drumbeat for disclosure of such assessments in public announcements grows louder.
Earlier this month, a former Securities and Exchange Commission member and a former deputy chief accountant, along with a London-based investor activist, called for the Financial Accounting Standards Board (FASB) to require companies with “significant fossil fuel reserves” to disclose information regarding assets that would be rendered “unburnable” by more stringent regulation. The authors suggest that such disclosure will permit investors to “pass judgment on the future viability of fossil fuel reserves.” Click here.
FERC Paves the Way for Higher Capacity Prices in Advance of the Upcoming ISO-NE Capacity Market Auction
On Friday January 24, 2014, the Federal Energy Regulatory Commission issued companion orders: (1) approving a proposal to double the administrative price that will apply in instances of inadequate supply or insufficient competition in the upcoming ISO New England capacity auction; and (2) directing ISO-NE to develop a new capacity market design that makes use of a downward-sloping demand curve.
ISO-NE administers the “Forward Capacity Market” to identify the lowest-cost generation resources to satisfy the region’s capacity needs. In order to ensure that enough capacity resources are available, including resources that will need to be constructed, ISO-NE commits generation resources three years in advance of the relevant capacity commitment period. In general, ISO-NE relies on an auction to solicit competitive bids and set the price for capacity resources that are cleared; however, ISO-NE relies on an administratively-set price when a review of bids shows that there was inadequate supply, insufficient competition, or capacity carried into the auction from a previous cycle in the relevant auction. The administrative price acts as a floor to ensure sufficient incentives for generation resources to supply capacity in adequate amounts.
On January 22, 2014, the staff (Staff) of the Office of Enforcement of the Federal Energy Regulatory Commission (FERC of the Commission) issued a Staff Notice of Alleged Violations (Preliminary Notice) relating to a September 8, 2011, blackout in the Southwest. The outage affected 2.7 million customers in parts of Arizona, Southern California, Baja California and Mexico. In the Preliminary Notice, Staff alleges that the blackout resulted from violations of one or more reliability standards by each of Arizona Public Service Company, the California Independent System Operator Corporation, Southern California Edison Company, Imperial Irrigation District (IID), the Western Area Power Administration's Desert Southwest division, and the Western Electricity Coordinating Council's reliability coordinator. The issuance of the Preliminary Notice follows the April 2012 release of a joint report (Joint Report) by the staffs of FERC and the North American Electric Reliability Corporation (NERC), which found that adequate real-time situational awareness and operations planning could have prevented the event. The Joint Report, however, made no findings with regard to whether there had been violations of the reliability standards.
FERC Enforcement Chief Norman Bay Testifies Regarding FERC’s Energy Market Oversight and Enforcement Authority and Approach
On January 15, 2014, Norman C. Bay, Director of the Office of Enforcement (OE) of the Federal Energy Regulatory Commission (FERC), testified before the U.S. Senate Banking, Housing, and Urban Affairs Subcommittee on Financial Institutions and Consumer Protection regarding FERC’s efforts to detect, investigate, and, as necessary, prosecute fraud and manipulation in FERC-regulated energy markets. Mr. Bay faced relatively light questioning from the Subcommittee compared to his co-panelists, with most of the questions directed to him focusing on financial information sharing between FERC and the Commodity Futures Trading Commission (CFTC), whose Vincent A. McGonagle, Director of the Division of Market Oversight, also was a witness. Mr. Bay’s prepared testimony is available here and a webcast of the hearing is available here.
In his prepared and live testimony, Mr. Bay summarized FERC’s broad statutory authority to protect consumers from fraud in or manipulation of FERC-regulated electricity and natural gas markets. FERC’s authority arose from Energy Policy Act of 2005 (EPAct 2005) revisions to the Federal Power Act and Natural Gas Act. EPAct 2005 also enhanced FERC’s civil penalty authority from $10,000 per day per violation to $1 million per day per violation for violations including fraud and manipulation. These tools, Mr. Bay noted, are “critical to FERC’s efforts to protect consumers from market manipulation.” Using its enhanced authority, FERC has imposed and collected approximately $873 million in penalties and disgorgement (excluding penalties levied in recent cases still to be reviewed in federal court, such as the Barclays Bank PLC case we addressed here).
Mr. Bay also addressed: (1) FERC’s current capability to detect and investigate violations of and, if necessary, enforce EPAct 2005’s anti-fraud and manipulation rules; (2) the basic mechanics of common manipulative conduct; (3) obstacles to FERC’s anti-fraud and manipulation oversight, focusing on the longstanding issues of financial information sharing and enforcement jurisdiction between CFTC and FERC; (4) market risks and consequences of financial institutions’ involvement in FERC-regulated markets; (5) emerging trends associated with financial institutions’ energy market operations; and (6) FERC’s coordination with other regulators with regard to enforcement matters.
2013 was another remarkable year in the Eagle Ford. Whereas five years ago few had heard of it, today the Eagle Ford is one of the largest oilfields in the United States. What is most exciting is that the play is just beginning to develop. The Railroad Commission of Texas has issued a total of 4,416 permits for wells through 2013 yet a study conducted by the University of Texas in San Antonio forecasts that there will be a total of 24,363 wells in the Eagle Ford Shale by 2022.
The first of the Eagle Ford wells was drilled in 2008 by Petrohawk in La Salle County and flowed at a rate of 7.6 million cubic feet of gas per day. Today the Eagle Ford has swiftly grown to 22 active fields across 26 Texas counties, heavily impacting Texas and the energy field at large. Anadarko, for example, was just one of the producers who saw boosted volumes in 2013 with help from the Texas play, achieving record U.S. onshore sales volumes.1
The Eagle Ford continues to grow in natural gas, oil and condensate production. Natural gas production from January to October of 2013 increased 27% compared with all of 2012.2 The Eagle Ford has reached an average of 3,239 MMcf per day for January-October of 2013 compared to original natural gas production in 2008 of 2 MMcf. Oil production has currently increased by 65% since 2012. The average oil production in 2012 was 400,377 barrels per day, increasing to an average of 659,092 for January to October of 2013. Condensate production also increased by 19% since 2012, reaching 186,719 Bbl per day for the January-October period of 2013.
On January 15, 2014, the Federal Energy Regulatory Commission (“Commission”) issued an order approving a Stipulation and Consent Agreement between the Commission’s Office of Enforcement and Erie Boulevard Hydropower, L.P. (“Erie”) and Erie’s affiliate, Brookfield Power US Assets Management, LLC (“Brookfield”). While neither admitting nor denying that it violated Commission regulations, Erie agreed to pay a $4,000,000 civil penalty in response to events at an Erie project in Oswego, New York that led to the deaths of two fishermen. Both Erie and Brookfield agreed to budget $1,700,000 for public safety enhancements at their U.S. hydroelectric projects.
Erie operates the Oswego River Project, a hydroelectric facility consisting of several developments, including the Varick development (“Varick”), which contains a gravity dam, a 32-acre reservoir, and a powerhouse containing four generating units. The High Dam Project (“High Dam”), a hydroelectric facility owned by the City of Oswego, is located about a half mile upstream from Varick. Water flow and water levels at Varick are affected by its close proximity to High Dam, and both Varick and High Dam are operated remotely by a system control operator in a Massachusetts facility owned by Brookfield.
Traditional utility securitizations, enabled by statute in approximately 17 states, have been used numerous times over the past 16 years to recover “stranded costs” resulting from deregulation, and environmental/pollution control equipment, storm damage, reconstruction and deferred power procurement costs. The following potential benefits of these securitizations are generally recognized in the industry:
- Immediate recovery of financed costs upon the sale of the bonds to investors
- Ability to use the proceeds from the issuance of the bonds to pay existing higher cost debt
- Principal and interest on the bonds and other financing costs are generally paid from charges paid by customers
- Improved credit metrics (while the debt issued in the securitization typically will appear on the electric utility’s consolidated balance sheet, rating agencies generally ignore the debt for credit analysis purposes because it is an obligation of the SPV issuing the debt and not the electric utility)
- Lower debt costs as compared to traditional utility debt due to higher credit ratings on securitization debt (typically AAA)
Commissioners John Norris and Philip Moeller plan to begin developing this month a first-of-its-kind licensing program for traders and other players in FERC-regulated markets. A licensing requirement could give FERC a mechanism to impose new standards of conduct on individual traders and to bar individuals from future trading activity. By giving FERC additional leverage over individual traders, the new rules could increase cooperation by these key witnesses in agency investigations.
FERC’s existing authority to regulate individual traders is unclear. Section 4A of the Natural Gas Act and Section 222 of the Federal Power Act authorize FERC to assess penalties of up to $1 million per day per violation against “any entity” that uses a “manipulative or deceptive device or contrivance” in connection with a jurisdictional purchase or sale of natural gas, natural gas transportation service, electric energy, or electricity transmission services. In Hunter v. FERC, FERC assessed a $30 million civil penalty against Brian Hunter, formerly a natural gas trader for Amaranth Advisors, LLC, for allegedly manipulating natural gas futures prices. Hunter appealed to the D.C. Circuit, arguing, among other things, that “NGA § 4A’s prohibition directed at ‘any entity’ cannot reasonably be read to include individuals.” The D.C. Circuit dismissed the case against Hunter on other jurisdictional grounds, leaving FERC’s authority over individuals unclear. FERC’s assessment of civil penalties against four individuals for allegedly manipulative conduct in the electricity market is currently being litigated in a federal district court,1 but it may be years before the issue is resolved.
FERC – CFTC Memoranda of Understanding, Finalized Three Years Late, Fail to Resolve Uncertainty Regarding FERC’s Enforcement Jurisdiction
Only three years late, the Federal Energy Regulatory Commission (“FERC”) and the Commodity Futures Trading Commission (CFTC) (jointly, the “Commissions”) have signed Memoranda of Understanding (MOUs) as directed by Section 720 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank).1 The MOUs, which were supposed to be in place by January 2011, address issues of jurisdiction and information sharing. Please click here and here to see memos.
The four-page MOU on jurisdiction (“Jurisdiction MOU”) does not resolve outstanding questions involving the Commissions’ respective jurisdiction over financial energy products and the interactions of those products with physical markets. Instead, it requires the Commissions to inform each other of matters that may fall within their overlapping jurisdiction, and, apparently on a case-by-case basis, to “develop an approach that meets both agencies’ regulatory concerns.”
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank” or the “Act”) authorizes the Commodity Futures Trading Commission (“CFTC”) to comprehensively regulate energy trading activities. Dodd-Frank is intended to increase transparency and reduce the risk of counterparty default, but to accomplish these objectives it imposes considerable regulatory burdens. What features of a given contract might trigger regulation under Dodd-Frank and what might such regulation entail? While each transaction will require fact-specific analysis, these six questions provide a simple framework for analyzing most energy trades.
1. Is this contract a “swap”?
Dodd-Frank applies to a wide variety of energy-related agreements, contracts and transactions classified as “swaps.” The CFTC’s final rule defining the term “swap” runs 160 pages in the Federal Register,1 and the agency can grant exceptions on a case-by-case basis. The specific terms and conditions of each transaction must be carefully considered in light of the CFTC’s evolving and complex rules.
Today, the chairman of the Senate Finance Committee, Max Baucus (D-MT), released his proposal for energy tax incentives as part of overall tax reform. The proposal is thoughtful and merits serious consideration by the renewable energy industry. Importantly, it eliminates the discrepancy in the tax benefits available to different types of energy technologies. Here are links to the official documents: a one page summary, an eight page summary, a 30 page legislative history and the statutory language.
What the Proposal Would Mean for Solar?
Solar projects placed in service prior to 2017 would remain eligible for a 30 percent investment tax credit. Solar projects placed in service in 2017 and later would be eligible for either (i) a 20 percent investment tax credit (ITC) or (ii) a 2.3 cents per KWh production tax credit (PTC) for ten years. The proposed PTC is the same as the PTC available to wind projects under current law and would continue to be adjusted for inflation.
What the Proposal Would Mean for Wind?
The current PTC would be extended for projects placed in service prior to 2017. Further, the option to elect ITC would also be extended for projects placed in service prior to 2017. Wind and other PTC eligible projects under current law that “started construction” prior to 2014 would have to be placed in service prior to 2017; effectively, the “start of construction” rules would have no bearing on any projects’ tax credits eligibility.
Wind projects placed in service in 2017 and later would be eligible for either (i) a 20 percent investment tax credit (ITC) or (ii) a 2.3 cents per KWh PTC for ten years with the inflation adjustment continuing. This is the same as solar.
On December 12, 2013, the Mexican House of Deputies passed a constitutional reform bill approved by the Senate the day before that is intended to open the Mexican energy industry to increased participation from international energy players and spur the development and expansion of the Mexican energy industry (the “Energy Reform Bill”). The Energy Reform Bill seeks to amend three articles of the Mexican Constitution (the “Constitution”) and it provides 21 transitional articles detailing the regulatory and legal framework to be established to implement these reforms (the “Transitorios”). After a vigorous debate from the opposition, the Senate, followed by the House of Deputies, overwhelmingly approved the amended bill sponsored by the PRI, the ruling Mexican political party. In order to be published and become law, the Energy Reform Bill must be approved by a majority of Mexico’s State Legislatures. The political pact between the PRI and the PAN, the Mexican minority political party, should easily be able to pass this hurdle now that the Senate and House of Deputies have approved the Energy Reform Bill.
On December 13, 2013, the United States Court of Appeals for the District of Columbia Circuit ruled in favor of the Federal Energy Regulatory Commission (“FERC”) in TC Ravenswood, Inc. vs. FERC, No. 12-1008.The dispute focused on FERC’s decision to suspend the capacity market demand curves proposed by the New York Independent System Operator (“NYISO”) for the full five months permitted by statute. TC Ravenswood, Inc. and the NRG Companies (“Petitioners”) claimed that the suspension term was arbitrary and capricious because FERC’s precedent called for only a nominal suspension.
Section 205 of the Federal Power Act authorizes FERC to suspend proposed rates for a maximum of five months before they become effective. In West Texas Utility Co., 18 FERC ¶ 61,189 (1982), FERC stated that, as a general matter, it would suspend rate proposals for only one day, rather than the statutory five-month maximum, in cases where only 10 percent or less of the proposed rate increase may be excessive and therefore not just and reasonable. However, if “extraordinary factors” could result in “irreparable harm” to wholesale customers, FERC reserves the right to impose a five-month suspension.
Steve Otillar, an energy partner at Akin Gump, is quoted in an Associated Press article about a change in Mexico’s energy sector that would, for the first time, permit overseas investment in that country’s oil and gas fields.
The proposed constitutional amendment would end a longstanding monopoly held by Petróleos Mexicanos, or Pemex, the Mexican state-owned oil company, and allow other companies to share in the production of oil or contract independently of Pemex. The amendment has passed both houses of Mexico’s Congress and now awaits approval by the legislatures of 17 of Mexico’s 31 states.
Otillar, who focuses on upstream projects in emerging markets, observes there are “a lot of naysayers who thought the constitution would never be changed. People are [now] going to acknowledge that this is real and will happen and are going to start moving.”
The structure of new agreements signed with private companies will likely be based on the oil and gas assets being developed, according to Otillar. He told Law360, “If there’s a lot of exploration risk, or there’s a high technology component … you’re going to see a certain regime that will be structured in a way to incentivize an international oil company.” If the oil and gas fields are mature or the projects have a lower exploration risk, he said “you’ll see more of a service contract model, where you’ll have payment based on production.” (Click here to read this article.)
In a Houston Chronicle article that appeared before the votes in Congress, Otillar commented that this move “will help Mexico enjoy the energy renaissance taking place in the United States and modernize its economy on the back of energy reform.”
On December 12, 2013, Mexico’s lower chamber of Congress approved the country’s largest energy reform legislation in more than 75 years. The proposal ends Mexico’s state-owned monopoly of the oil and gas industry. Beginning in 1938, Mexicans have recognized Oil Expropriation Day, the day set aside to commemorate the nationalization of the oil industry. Since that time, the Mexican government, through the Petroleos Mexicanos (“Pemex”), has controlled all oil exploration and production as well as all retail gas stations throughout the country.
Opponents of the historic energy reforms primarily consisted of the leftist group the Party of the Democratic Revolution (PRD). During more than nine hours of debate on the floor of the Senate on December 11, opponents noted that approximately one-third of Mexico’s federal budget is funded through oil and gas revenue. All profits from Pemex went directly to the federal treasury. They also argued that the nation’s resources belonged to all Mexican people and could not be sold to private companies outside of Mexico.
Barron’s in August of this year published an article critical of SolarCity’s use of tax credits and grants for its solar projects.1 That article led Senator Sessions to send a harsh letter with a number of pointed questions to the Secretary of the Treasury. My blog post regarding the senator’s letter is available here. SolarCity has now posted a response to the Barron’s article on its own blog. SolarCity’s post is available here.
Overall SolarCity’s post is thoughtful and clear. However, the post’s wording contains a technical misstatement with respect to federal income tax law:
“SolarCity does not use a ‘more complex’ method than similar installers in valuing solar projects, and solar companies cannot “estimate” the fair market value in applying for grants under Section 1603. That fair market value-which of course is the price the buyer actually paid for the system-must also be determined by an independent appraiser.”
FERC Commissioners Appear Before House Subcommittee on Energy and Power To Discuss Regulatory Responses to A Rapidly Changing Industry
The four sitting Commissioners of the Federal Energy Regulatory Commission appeared before the House Committee on Energy and Commerce, Subcommittee on Energy and Power yesterday to discuss FERC’s response to rapid shifts in the electric and natural gas industries. Commissioner LaFleur, who fielded the majority of questions over nearly two hours, was joined by Commissioners Philip Moeller, John Norris, and Tony Clark. The hearing marked the first appearance before Congress of Cheryl LaFleur in her new role as FERC’s Acting Chairwoman.
Republican members of the panel, led by Subcommittee Chairman Ed Whitfield (R-KY), asked a range of questions largely focused on the speed of permitting for gas pipeline and LNG export infrastructure and the potential impacts of new EPA regulations and the Obama Administration’s climate policy on reliable electric supplies. Republican members also questioned whether FERC Order 1000’s transmission planning and cost allocation reforms are saddling customers with costs associated with transmission projects for which they will see little, if any, benefit.
On October 1, 2013, we reported here that the Federal Energy Regulatory Commission (FERC) issued orders on August 29, 2013, assessing civil penalties against, and requiring disgorgement of profits by, Lincoln Paper and Tissue, LLC (Lincoln), Competitive Energy Services, LLC (CES), and Dr. Richard Silkman, the managing member of CES. Please see here. FERC found that Lincoln, CES, and Dr. Silkman had violated the energy market manipulation prohibitions of the Federal Power Act (FPA) and FERC’s Anti-Manipulation Rule with a scheme to generate demand response payments in the ISO New England, Inc. (ISO-NE) Day‑Ahead Load Response Program without reducing electricity consumption from the grid. Lincoln owns and operates a paper mill in Maine, which participated in program using on-site generation. CES and Dr. Silkman provided consulting services to the Rumford Paper Company, which settled with FERC regarding similar allegations of fraud in March 2013.
The penalties were assessed pursuant to a procedure which allows the target of a FERC enforcement proceeding to bypass an administrative hearing and request that FERC immediately assess penalties. If those penalties are not paid within 60-days, the FPA directs FERC to commence an action in a United States District Court for an order affirming the penalty, in which the court may review the assessment of the civil penalty de novo. This procedure has proved popular in recent enforcement actions because it bypasses the time and expense of an administrative hearing in favor of quick access to a forum that may potentially be more sympathetic.
On December 2, 2013, FERC filed two petitions with the United States District Court for the District of Massachusetts, requesting orders affirming its assessment of penalties against Lincoln, and CES and Dr. Silkman, respectively. Massachusetts was chosen as a venue because ISO-NE is headquartered in Massachusetts. FERC requested a jury trial on the petitions, but suggested that the court affirm the penalty based on the record. The petition regarding CES and Dr. Silkman can be found here and the petition regarding Lincoln can be found here.
(Houston, Washington and New York) – Today, members of Akin Gump’s global energy and transactions group provided a briefing for members of the media that included a look forward to U.S. and global trends in energy production in 2014.
The panel comprised energy regulation, markets and enforcement practice co-head Suedeen Kelly, energy partner Stephen Davis, London partner and Moscow partner in charge Sebastian Rice, global project finance practice co-head Adam Umanoff and financial restructuring partner Ira Dizengoff. The briefing was moderated by Rick Burdick, chair of the firm’s global energy and transactions group.
Ms. Kelly discussed distributed generation (DG)—“electric generation that’s connected to the distribution system as opposed to the transmission system,” in her definition, based in small generators typically but not exclusively owned by electric customers rather than utilities. She noted that it has the potential to be a game-changer for the electric industry, taking market share away from traditional electric utilities. She pointed to five factors driving DG’s growth: its affordability, customer empowerment, reliability, environment and efficiency, and new market opportunities in the face of stagnant electricity demand.
The Congressional Research Service (CRS) on October 30 published a report on the Obama Administration’s proposal to repeal or modify certain tax benefits provided to the oil and gas industry. The report is available here.
Two of the changes are repealing tax credits that have phase outs when oil prices are high (under the theory that, when oil prices are high, further encouragement from the Internal Revenue Code is not necessary). Since oil prices have been high for several years, the credits have not been applicable for some time.
Four of the changes apply to only independent oil and gas producers. The changes conform the tax provisions to apply to the independents as they presently apply to the “major” oil and gas companies (e.g., ExxonMobil). Because the majors have managed to achieve record profits under these tax provisions, it is difficult to forecast too dire a result for the independents due to these changes.
Two of the changes in the Administration’s 2014 budget proposal are specific to oil and gas; however, their general repeal is on the short list for revenue raises in almost every discussion of fundamental tax reform. These changes are repeal of the “domestic manufacturing deduction” and “last-in-first-out” (LIFO) inventory tax accounting. Thus, it would appear that, in any event, these tax provisions’ days may be numbered.
Mexican President Enrique Peña Nieto has responded to more than a decade of declining oil and gas production with vocal support of the Mexican energy sector reform. While the Mexican Constitution provides PEMEX a monopoly in the upstream oil and gas sector, the new president’s vision would amend Articles 27 and 28 of the Constitution to allow foreign participation in the sector, as well as eliminate the various state-controlled oil and gas monopolies. Such changes should facilitate an influx of capital, technology and international market participation that could create an energy revolution on par with the American shale phenomenon.
Despite the promise of an economic boom, in order to effectuate constitutional reforms Peña Nieto must win support from the opposition PAN. Constitutional change, however, is just the beginning of the reform process-the real work will be drafting the actual text of the implementing legislation. Some critics argue that Peña Nieto’s proposed reforms do not go far enough1 because any new legislation is unlikely to impact PEMEX’s position as the sole entity controlling the Mexican upstream sector. However, in the context of PEMEX’s 75 year history and progressive origins, the young leader’s approach is remarkably bold. This fact is made even more apparent when contrasted to the more recent trend of resource nationalism seen in Venezuela.
FERC Reforms Small Generator Interconnection Procedures and Agreement to Facilitate Interconnection of Small Solar Generation and Energy Storage Projects
On November 22, 2013, the Federal Energy Regulatory Commission (FERC) issued a Final Rule (Order No. 792) promulgating reforms to its pro forma Small Generator Interconnection Procedures (SGIP) and pro forma Small Generator Interconnection Agreement (SGIA), which set forth terms and conditions for interconnection service for generators and other resources not larger than 20 MW, to make more efficient and less costly the Small Generating Facility interconnection process while continuing to ensure safety and transmission system reliability. The reforms largely track the changes addressed in FERC’s Notice of Proposed Rulemaking issued in January 2013, as summarized in a prior post, with various adjustments to reflect suggestions and concerns raised in the rulemaking proceeding, and likely will further facilitate the growing market penetration of small generation and energy storage resources. Renewable energy industry groups applauded the Final Rule for its potential to expedite and reduce the cost of interconnecting new solar-powered generating facilities.
Akin Gump partners, David Burton, Adam Umanoff and Josh Williams hosted a webinar earlier in November that discussed the new IRS guidance with respect to the start of construction rules to qualify for the production tax credit (PTC) or for qualified technologies the investment tax credit (ITC). The presentation is available here and the webinar discussed the following:
- What clarifications did the recent IRS guidance offer on the expanded “start of construction” safe harbor for renewable energy projects?
- What steps should projects take to meet the start of construction requirements?
- What are solutions to typical problems confronted by project owners seeking to start construction in 2013?
December 2013 will mark the first “anniversary month” of the antidumping (AD) and countervailing duty (CVD) orders on Chinese-origin crystalline silicon photovoltaic (PV) cells, whether or not assembled into modules. The U.S. Department of Commerce (DOC) imposed the orders following AD/CVD investigations conducted as a result of petitions filed by SolarWorld Industries America Inc. (“SolarWorld”). During the anniversary month, interested parties will have the opportunity to request DOC to conduct administrative reviews of the AD/CVD orders to determine the actual duties to be collected on PV cells that have been imported under the order.
The AD/CVD orders are among the largest by value that the United States has ever imposed, covering billions of dollars’ worth of imports annually. The upcoming administrative reviews, coupled with significant disputes over the scope of products covered by the orders, are creating uncertainty for both foreign producers and exporters as well as for U.S. importers and purchasers of these products. This uncertainty is exacerbated by ongoing settlement discussions between the United States and China.
On November 21, 2013, the House voted 252-165 in favor of H.R. 1900, also known as the Natural Gas Pipeline Permitting Reform Act (“Act”), to expedite the process for obtaining a pipeline permit from the Federal Energy Regulatory Commission (FERC). The bill, which was introduced by Rep. Mike Pompeo (R-KS), would add the following new provisions to section 7 of the Natural Gas Act:
First, FERC would be required to approve or deny an application for a gas pipeline permit within 12 months after providing public notice of the application.
Second, other agencies responsible for issuing licenses, permits or approvals in connection with the siting, construction, expansion or operation of a gas pipeline would be required to approve or deny authorization within 90 days after FERC issues a final environmental impact statement. This deadline may be extended for an additional 30 days upon petition to FERC if circumstances beyond an agency’s control warrant such an extension.
Senator Coons (D-DE), the lead sponsor of the Master Limited Partnership Parity Act (S. 795), has received the scoring estimate for that bill from the Joint Committee on Taxation. According to the senator’s office, it is scored at a $1.3 billion cost over its first 10 years.1 Ten years is the period used for scoring. One would hope it would be relatively easy to find “revenue raisers” to offset that modest cost. Revenue raisers are often closing what are perceived by the public to be tax loopholes.
The typical cost of a one-year extension of the production tax credit is usually several times the estimate for the permanent legislative changes proposed in the MLP Parity Act; however, tax credits are also far more valuable to the renewables industry than the MLP Parity Act is. See here. Thus, the MLP Parity Act should be passed to give renewables the same tax advantage provided to fossil fuels, rather than as a trade for not extending tax credits for renewables.
On November 12, 2013, a group of industrial and commercial end-users in the Midwest filed a complaint at the Federal Energy Regulatory Commission (FERC) against the Midcontinent Independent System Operator, Inc. (MISO) and the transmission-owning members of MISO (MISO TOs). The complainants are seeking, among other things, a reduction in the base return on equity (ROE) used in the MISO TOs’ formula transmission rates contained in Attachment O of MISO’s FERC-filed Tariff. The base ROE currently in effect for all of the MISO TOs except American Transmission Company LLC (ATC) is 12.38 percent, and the base ROE currently in effect for ATC is 12.2 percent. These base ROEs are fixed and do not change from year to year, as do most of the other Attachment O formula rate inputs. In addition, certain of the MISO TOs have in place incentive adders that increase their base ROEs by 50 to 150 basis points.
The complainants argue that the base ROEs are no longer just and reasonable “due to changes in the capital markets,” and that the MISO TOs’ base ROE should not exceed 9.15 percent. The complainants argue that the current cost of equity for the MISO TOs is in the range of 7.97 percent to 10.33 percent, with a midpoint of 9.15 percent. The complainants conclude that electric consumers are overcompensating the MISO TOs by approximately $327 million annually under the current base ROEs, as compared to rates using the complainants’ recommended 9.15 percent base ROE.
Economists Lawrence Goulder and Marc Hafstead in October published Tax Reform and Environmental Policy: Options for Recycling Revenue from a Tax on Carbon Dioxide on behalf of Resources for the Future. The paper is available here. The paper analyzes the effect on the U.S. economy of the adoption of a $10 per ton carbon tax starting in 2013 that increases 5 percent per year to the year 2040. The paper considers three scenarios for using the revenue raised by the carbon tax: (i) cash rebates to households; (ii) a reduction in personal income tax rates; and (iii) a reduction in corporate income tax rates. However, in all scenarios, 15 percent of the revenues from the carbon tax are used to provide “tradeable exemptions” for companies in the 10 industries projected to suffer the largest reductions in profits due to the carbon tax. Further, in none of the scenarios is an economic benefit included for the health or environmental benefits of reduced carbon emissions.
Elliot Hinds speaking at PowerGen International in Orlando next week (November 13, 1:30p) where he will be expanding on his recent talks on energy storage. In addition to addressing the latest developments at FERC and in California, his presentation at PowerGen will explore what the components of a financeable storage PPA may be. Elliot’s talk at PowerGen International will be more weighted with towards the conventional power space, which is a significant portion of his energy background. His most recent talks have been before largely renewables audiences (SPI in Chicago and AES in San Diego) but storage is an issue that transcends resources. However, it is important point for financing that storage resources that are charged with too much conventional power will not qualify for the investment tax credit. Stay tuned for further blog entries from Elliot on energy storage and ideas shared at PowerGen.
In addition, Elliot has organized a free webinar on the Solar M&A market trends on November 19, 2013 at 9a-10a Pacific time. In addition to Elliot, panelists include Carl Weatherly-White from KRoad Power, Alex Ellis from SunEdison and Tarik Bolat from Renewable Energy Trust. This knowledgeable panel will provide market analysis and perspective from recent solar deals and thoughtful perspective about trends going forward. Go to www.greenpowerconferences.com for login information.
The U.S. Court of Appeals for the District of Columbia Circuit this week upheld two Federal Energy Regulatory Commission (FERC) orders allocating the costs associated with mitigating transmission constraints on a Southern California transmission path to multiple neighboring utilities.
Under its FERC Tariff, the California Independent System Operator (CAISO) allocates the costs of relieving transmission constraints through the dispatch of must-offer generation in one of three ways, depending on whether must-offer resources were committed to satisfy local, zonal, or system reliability requirements. Following an evidentiary hearing, an Administrative Law Judge at FERC concluded in 2005 that cost responsibility would fall entirely upon the local load serving entity, Southern California Edison, when must-offer resources were dispatched to relieve constraints on “South of Lugo,” a system of 500 kV transmission paths that feeds power into the Los Angeles basin. FERC affirmed the ALJ’s decision in 2006.
The New York Law Journal has published “Regulatory Uncertainty Remains in Energy Markets,” an article by Akin Gump’s Suedeen Kelly and Julia Sullivan, co-heads of the firm’s energy regulatory practice, and Steven Reich, a partner in the white collar defense and government investigations practice, which examines some of the considerations that Federal Energy Regulatory Commission (FERC) enforcement cases present for compliance officers. Click here to read full article.
The federal courts barred federal common law nuisance actions to obtain money damages or injunctive relief. American Elec. Power Co. v. Connecticut, 131 S. Ct. 2527 (2011)(holding nuisance claims seeking injunctive relief displaced by the Clean Air Act); Native Village of Kivalina v. ExxonMobil Corp., 696 F.3d 849 (9th Cir. 2012)(holding nuisance claims seeking damages displaced by the Clean Air Act). While such actions based on state law remain at least theoretically viable, plaintiffs have recently begun trying to revive and expand an ancient common law theory of relief – the “public trust doctrine.”
The Office of the Comptroller of the Currency (OCC) at the end of October published a fact sheet to clarify the eligibility of wind tax equity investments as public welfare investments for national banks and federal savings associations (federal thrifts). Qualifying as such permits the investment to be held in the bank, rather than a bank holding company. Further, it qualifies the investment for favorable capital weighting under Basel III and qualifies the investment for exceptions to the Volker and Dodd-Frank and real estate limitation rules.
The OCC’s fact sheet is available here.
Here are some key excerpts:
More information about this topic is available in my article here.
Senator Tom Udall (D-NM) sponsored legislation on October 29, 2013, that would institute a nationwide renewable portfolio standard for the country’s investor-owned utilities. The proposal, called the Renewable Electricity Standard Act of 2013, would require utilities that make annual retail sales of more than one million MWh to service a designated portion of their load with power from renewable sources. The threshold starts at six percent in 2014 and gradually escalates to twenty-five percent by 2025. Suppliers would be able to comply with the requirements by purchasing federal renewable energy credits from other entities that have earned credits by producing energy from renewable sources. “Renewable sources” would be defined to include solar, wind, ocean, tidal, geothermal, biomass, landfill gas, hydrokinetic, and incremental hydropower resources. Senators Mark Udall (D-CO) and Benjamin Cardin (D-MD) co-sponsored the legislation.
If passed, the legislation would implement the first national renewable portfolio standard. Twenty-nine states and the District of Columbia currently have established state-level renewable portfolio standards, and eight states have set forth “renewable portfolio goals” (see map). The federal law would not preempt state laws with more ambitious standards than the proposed national plan, such as California’s thirty-three percent renewable requirement by 2020.
A sluggish economy, a desire to cut back on the use of coal-powered electricity, and a worldwide focus on new oil and gas recovery techniques have pushed the South African government to take steps toward diversifying its energy industry and developing its natural resources using best practices from around the world. This week, the South African Department of Mineral Resources took a step towards achieving this goal.
Oil and gas E&P activity in South Africa is fairly limited, as evidenced by the fact that the country relies on imports to meet nearly 95 percent of its crude oil requirements, according to the South African Department of Energy.1 This situation, however, is not due to a complete lack of resources. Exxon Mobil Corp.; Royal Dutch Shell Plc and the South African, state-owned PetroSA have interests in the mostly undeveloped 15 million barrels of proven oil reserves located in the south of the country and in varied waters offshore.2 With the vast majority of South Africa’s energy needs being covered by locally produced coal (28% of which is exported), incentives to develop oil and gas resources have been lacking until now.
To accomplish the goal of safely developing its oil and gas resources, and thus adding these resources to its energy portfolio, the South African Department of Mineral Resources has released proposed regulations to augment existing gaps identified in the current oil and gas E&P regulatory framework, with a particular emphasis on hydraulic fracturing.3 These regulations were released on October 15, 2013, and the South African Department of Mineral Resources is accepting public comments on them until November 14, 2013.
FERC Requires All Generators To File Rate Schedules To Provide Reactive Power Service, Even if the Service Is Uncompensated
In a move that could have a significant impact on electric generators, the Federal Energy Regulatory Commission (FERC) recently clarified its policy with respect to the provision of reactive power service. The provision of reactive power is used to maintain voltage on the bulk transmission system within defined limits. Generators often provide reactive power to transmission providers pursuant to FERC’s pro forma Large Generator Interconnection Agreement, and such service is generally not compensated if the generator is operating within certain power output ranges. In an order dated October 17, 2013, FERC found that all existing and new generators that provide jurisdictional reactive power service must file rate schedules containing the rates, term and conditions of that service, even if the generator receives no compensation.
CPUC Approves On-Bill Repayment Financing for Non-Residential Energy Efficiency, Distributed Generation and Demand Response Projects
On September 19, 2013, the California Public Utilities Commission (“CPUC”) approved a pilot program intended to help attract private capital for investment in energy efficiency retrofits, distributed generation, and demand response projects for nonresidential customers. The program allows nonresidential utility customers to repay third-party lenders through the customer’s utility bill, a financing mechanism called “on-bill repayment” (“OBR”). By bundling repayment of the third-party loan with the customer’s energy costs on its utility bill, the CPUC hopes to reduce the event of loan default or delinquency, thus attracting new private capital and lowering borrowing costs for clean energy projects in the commercial/industrial sector.
Under the CPUC pilot program, California’s large, investor-owned utilities will post on their websites a list of eligible energy efficiency measures, distributed generation, and demand response projects. The utilities’ nonresidential customers may then obtain private capital for eligible projects with repayment of such capital made through an OBR mechanism. The program requires the utilities to use their existing bill collection practices for delinquencies and defaults and allows for termination of service for nonpayment of the OBR obligation. Any partial payments made by customers will be distributed pro rata between the energy charge and the repayment to the third-party lender. The program will not charge fees to the participating financial institutions, nor will it provide any ratepayer-funded credit enhancements.
On October 18, 2013, the Federal Energy Regulatory Commission (“Commission”) approved a Stipulation and Consent Agreement between the Office of Enforcement (“Enforcement”) and Exelon Corporation (“Exelon”) to resolve an investigation of Constellation Energy Commodities Group, Inc. (“CECG”), which Exelon acquired in March 2012. Exelon agreed to pay a civil penalty of $500,000, to disgorge $145,928 in unjust profits, plus interest, and to submit compliance reports to Enforcement through at least April 2015.
CECG purchased and sold energy in the western and California Independent System Operator (“CAISO”) markets with market-based rate authority. From January 22, 2010 through March 24, 2010 (“Relevant Period”), CECG’s trading team looked for CAISO intertie balancing authority areas where price spreads were large enough to cover the transmission costs and attendant charges and fees. CECG designated its bids as Wheeling Through so that if CAISO awarded CECG’s bid, it would award both intertie bids—at the import point and the export point—and CECG would then capture the price spread between them. If CAISO awarded CECG’s bids, CECG would then schedule transmission outside of CAISO from the CAISO export point back to the import point, forming a circular schedule. CECG profited from the Wheeling Through transactions because it was awarded the bid only when the price at the import point (sale) was greater than the price at the export point (purchase) and because it bid a spread great enough to cover its costs. CECG bid this circular scheduling strategy every day and nearly every hour during the Relevant Period. During the investigation, Exelon twice incorrectly asserted to Enforcement that CAISO supported closing the investigation without penalty. Because Exelon failed to ensure that these assertions to Enforcement staff were accurate, it received no cooperation credit in arriving at a penalty.
In a first-of-its-kind move in the United States, a California Public Utilities Commission (CPUC) order made effective today sets specific energy storage procurement targets for 2020 covering enough power to serve approximately 1 million homes. Please view PDF here. The state’s 3 investor-owned utilities (PG&E , SCE and SDG&E) must target obtaining 1,325 MW of energy storage contracts by 2020 with a final installations by 2024. The order requires the utilities to forward move quickly on this – the proposed procurement process must be submitted to the CPUC by March 1, 2014 along with a structure for steady but orderly contracting and implementation. The requirements specify broad integration of storage across the grid with transmission-connected, distribution-connected and customer-side applications that have to be contracted on a graduated basis in 2014, 2016, 2018 and 2020. The order also requires the state’s community choice aggregators and electric service providers to procure energy storage to cover 1% of their 2020 peak load.
This order follows the state’s requirement announced earlier this year that SCE must include 50 MW of energy storage in its western Los Angeles area resource procurement plan. Please view PDF here. This, along with some other existing storage projects will count towards the utilities’ procurement targets under today’s order.
On October 11, 2013, the United States District Court for the District of New Jersey issued its decision in PPL Energyplus, LLC v. Hanna. This case follows a recent decision in which the U.S. District Court for the District of Maryland invalidated the Maryland Public Service Commission’s directive to state utilities to enter into a contract for differences with Competitive Power Ventures, as we reported here on October 2, 2013.
Rep. McKinley Introduces Legislation to Exempt Certain Natural Gas Facilities from Regulation under the Natural Gas Act
On September 27, 2013, Rep. David McKinley (R-WV) introduced H.R. 3208 (To clarify that certain natural gas facilities are not subject to the Natural Gas Act). The proposed legislation is intended to eliminate barriers to greater domestic use of Liquefied Natural Gas (LNG) in transportation and other end-use applications. To do so, the proposed legislation clarifies the scope of Federal Energy Regulatory Commission (FERC) jurisdiction over facilities used to liquefy, store, and deliver natural gas.
The proposed legislation would add a new subsection (e) to Section 1 of the Natural Gas Act (“NGA”) to exempt from NGA regulation any person who constructs or operates “a facility not otherwise subject to [the NGA] that liquefies, stores, processes, or delivers natural gas for vehicular natural gas or other end use purposes,” even if such person re-injects natural gas into an interstate natural gas pipeline, if that re-injection is incidental to the facility’s provision of natural gas for vehicular or other end-use purposes. Such incidental re-injection might involve certain natural gas constituents, such as ethane, rejected from the liquefaction process as byproducts, but which the facility operator cannot consume or reprocess on site.
NGA Section 1(d) already exempts from FERC regulation persons engaged in the sale or transportation of vehicular natural gas. However, a person engaged in liquefying, storing, processing, or delivering natural gas for vehicular or other end-use purposes who takes natural gas from an interstate pipeline or other jurisdictional facility and later re-injects it into an interstate pipeline could be deemed subject to regulation under NGA Section 1(b) as a “natural-gas company” engaged in the “transportation of natural gas in interstate commerce.” The proposed legislation would clarify the existing exemption to prevent divergent outcomes in cases involving the jurisdictional status of certain LNG facilities, which the FERC previously has approached on a case-by-case basis.
Representatives Mike Doyle (D-PA), Bill Johnson (R-OH), and Tim Ryan (D-OH) co-sponsored the bill, which was referred to the House Committee on Energy and Commerce on the day it was introduced.
On September 30, 2013, the United States District Court for the District of Maryland issued its decision in PPL Energyplus, LLC v. Nazarian. The case has been watched by many for its potential implications with respect to the ability of States to direct utilities subject to their jurisdiction to enter into contracts to support the construction of new generating capacity, thereby depressing prices in centralized capacity markets such as those used in the Eastern regions. In recent years, both the New Jersey Board of Public Utilities and Maryland Public Service Commission (“Maryland PSC”) have pursued such actions and, in response, PJM Interconnection, L.L.C. (“PJM”), the operator of the centralized capacity market in their region, has adopted a number of market rule changes to try to mitigate the effects of these actions.
In PPL Energyplus, several incumbent generators with assets in PJM (“Plaintiffs”) challenged an order of the Maryland PSC directing the states utilities1 to enter into a contract for differences with Competitive Power Ventures (“CPV”) under which CPV would construct a 661 megawatt natural gas-fired combined cycle generator in Charles County, Maryland. Under the contract, the actual revenue received by CPV for its sale of energy and capacity in the PJM markets would be compared to what CPV would have received for those sales had the contract prices been controlling, and any difference would be settled between CPV and its utility counterparties.
America’s Power Plan describes itself as a “toolkit” for policymakers. The information that constitutes the toolkit is available here. Its energy finance paper was just published. The paper is available here. Below are key quotations about tax equity and tax policy.
- [T]oday’s electricity markets do not adequately compensate investors for the value provided by two critical services in a high renewables future – avoided pollution and system-wide grid flexibility services.
- At present, compensation for pollution reduction benefits is primarily addressed by federal tax incentives (including production and investment tax credits) and indirectly through state renewable portfolio standards. The tax incentives also compensate investors for bearing risks associated with the scale-up and deployment of a new technology. They have played a critical role in enabling the scale-up of renewable technologies across the country. Along with global technology improvements and economies of scale, they have helped to drive steep cost reductions over the last few years, making wind and solar increasingly competitive. Many investors expect that with sustained policy to drive continued deployment and cost reductions, wind and solar generation will be cost competitive with traditional fossil fuel resources without federal support by the end of this decade.
- [I]ncreasing [economics] rewards [for renewable energy] through temporary tax incentives creates additional risk associated with uncertainty regarding the future of the policy, and leads to financing barriers associated with the relatively small market of investors who can use them.
- [F]inancing for renewable generation relies on tax equity – investors who have enough tax liability to make use of federal tax incentives. However, in part due to the lack of political certainty associated with temporary renewable tax incentives, only 20 tax equity investors actively finance renewable projects in the U.S. today. The transactions are generally bilateral agreements that do not have as much transparency on prices or conditions as larger public debt or equity markets. Further, IRS rules require five years of continuous ownership to “vest” the investment tax credit, which restricts the liquidity of these investments.
- The additional costs of bringing tax equity into a project consume some value of the tax incentives available to a project. The government can get a better “bang for its buck” by instead offering taxable cash or refundable incentives, as described by the Climate Policy Initiative and the Bipartisan Policy Center.
- To provide investors with more certainty …, these tax credits should be extended for a significant length of time, rather than being allowed to expire every few years.
- Though important to the success of renewable energy development, private equity is both expensive and relatively rare. Independent power producers would benefit from having better access to public markets as well. One way to do this would be by allowing renewables companies to organize as MLPs or REITs, both of which are currently off-limits to clean energy. These instruments are publicly traded and have a tax benefit, since MLPs don’t pay corporate taxes and REIT dividends are tax-deductible.
FERC Orders Civil Penalties and Disgorgement for Manipulation of ISO New England Load Response Program
On August 29, 2013, the Federal Energy Regulatory Commission (FERC) issued three orders assessing civil penalties on, and requiring disgorgement of profits by, Lincoln Paper and Tissue, LLC (Lincoln), Competitive Energy Services, LLC (CES), and Dr. Richard Silkman (Silkman), the managing member of CES. FERC found that Lincoln, CES and Silkman violated the energy market manipulation prohibitions in the Federal Power Act and FERC’s regulations, which make unlawful the use of deceptive or manipulative schemes in connection with FERC-jurisdictional activities. Lincoln owns and operates a paper mill in Maine and CES and Silkman provided consulting services to Rumford Paper Company (Rumford), which also owns and operates a paper mill in Maine. In March 2013, Rumford settled FERC’s market manipulation allegations against it, agreeing to a $10,000,000 civil penalty and to disgorge $2,836,419.08 in profits, but neither admitting nor denying FERC’s allegations.
The Department of Energy, Office of Fossil Energy (“DOE”) has issued its fourth order, its third in 2013, authorizing the export of liquefied natural gas (“LNG”) to nations with which the United States does not have a free-trade agreement (“FTA”). On September 11, 2013, the DOE conditionally granted Dominion Cove Point LNG, LP’s (“Dominion’s”) request for authorization to export LNG as an agent from its Cove Point LNG Terminal, located in Calvert County, Maryland.1 Dominion’s request had been pending for nearly two years, since October 3, 2011. On May 2, 2013, Dominion signed export agreements with subsidiaries of Sumitomo Corporation, a Japanese company, and GAIL (India) Limited, an Indian company. Neither Japan nor India is an FTA nation, making non-FTA authorization a necessity to fulfill these contracts. The order is available here.
Today, at the American Wind Energy Association’s Finance & Investment Seminar in Manhattan Attorney-Advisor Christopher Kelley of the U.S. Treasury, speaking on his own behalf, said that the Treasury and IRS are considering further guidance to clarify the requirement that wind projects start construction in 2013 and then pursue continual work towards completion in order to be eligible for production tax credits. His comments were qualified and made it clear that there is a possibility that no further guidance would be provided. It was acknowledged that if such guidance was published in mid-November that it would be too late to spur much in the way of equipment orders.
Another Treasury official on June 17 had written Congress that Treasury “believe[d] that Notice 2013-29 provides the desired degree of certain in the marketplace and allows renewable energy project to move forward.” A blog post discussing this Treasury letter is available here, and client alerts discussing Notice 2013-29 are available here and here. Treasury appears to be having second thoughts as to whether “desired degree of certainty” was in fact provided by Notice 2013-29.
On June 14, 2013, the High Court in London ruled that Heritage should pay Tullow Oil c.$313 million under the terms of a tax indemnity relating to the 2010 transaction that saw it acquire Heritage oil licenses in Lake Albert, Uganda.
The litigation centered on Heritage’s Ugandan capital gains tax (“CGT”) liability arising from that transaction. Heritage realized c.$1.45 billion from the sale and the Ugandan government raised a CGT assessment of c.$434 million, calculated as broadly 30 percent of the transaction value. Heritage disagreed with the amount and paid the Ugandan government only $121.5 million, departing Uganda shortly afterwards.
Originally, the dispute was to be resolved by arbitration and $283 million of the purchase price was placed in escrow pending the conclusion of the dispute. In addition, Heritage paid $121 million to the Ugandan government as a ‘refundable deposit,’ to be returned should the arbitration go in their favor.
Impact of Southern California Edison Company’s Offer of Settlement on FERC Determined Returns on Equity
On August 26, 2013, Southern California Edison Company (SCE) submitted an Offer of Settlement in its long pending Federal Energy Regulatory Commission (FERC or “Commission”) rate case.1 The settlement provides for a base return on equity (ROE) of 9.3 percent, plus an adder for independent system operator participation of 0.5 percent, plus project rate incentive adders as approved by the Commission. Interestingly, the settlement precludes, with certain exceptions, new SCE petitions requesting transmission rate incentives or Commission grants of policy-based incentive rate treatment pursuant to its general discretionary authority prior to January 1, 2018. The limitation on filing new incentive requests for ROE project adders applies only until July 1, 2015.2
Presiding Administrative Law Judge Michael J. Cianci Jr. recently found in his initial decision in Coakley v. Bangor Hydro-Electric Co.,3 the New England Transmission Owners’ (NETOs) current base ROE of 11.14 percent unjust and unreasonable. Relying on the FERC’s traditional discounted cash flow (DCF) analysis prepared on behalf of the NETOs, Judge Cianci found that the just and reasonable prospective base ROE is 9.7 percent. Judge Cianci left modifications to the DCF analysis, adoption of alternative financial models and adjustments to the ROE for policy reasons to the Commission.
On July 28, 2013, the Federal Energy Regulatory Commission (FERC) issued Order 784, which opens new markets for electric energy storage effective in November 2013.1 Order 784 reformed FERC’s so-called “Avista Rule,” which restricts third-party sales of ancillary services at market-based rates.2 In particular, a third party may not sell ancillary services at market-based rates to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers. In order to overcome this restriction, a potential seller must provide a market power study demonstrating a lack of market power for the particular ancillary service in the particular geographic market.
Under Order 784, resources with market-based rate authority to sell energy and capacity can also sell imbalance services and operator reserve services (spinning and supplemental reserve services) if there is an intra-hour scheduling and sales mechanism for that area. As long as the public utility transmission provider allows intra-hour sales in its tariff, storage service providers will be able to provide their storage services under the same market-based rate authority that applies to sellers of energy and capacity. In fact, sellers that already have market-based rate authority will be able to apply that authority to their storage service sales as well.
August is known as the “silly season” in the U.K. media. With a large part of the country on vacation, it is a month in which newspapers struggle to fill column inches. Stories emerge that would typically not receive as much prominence at other times of the year.
Politicians are now better at using this void to promote policies. Two stories have recently emerged on hydraulic fracking. Both emanated from the Conservatives (the senior coalition party). One item was the result of news management intended to promote government policies. The other was a blunder.
On August 9, 2013, President Barack Obama signed into law two bipartisan energy bills intended to streamline the development of small hydroelectric power projects. The Hydropower Regulatory Efficiency Act of 2013 (H.R. 267) and the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act (H.R. 678) modify or remove the regulatory hurdles that proponents of the bills argue have stymied the development of small hydropower projects in the past. Both bills were met with broad bipartisan support and passed both chambers of Congress almost unanimously.
U.S. Senators Express Concern Over Manipulation of Electricity Markets and Request Information Regarding FERC Enforcement
On July 31, 2013, United States Senators Elizabeth Warren and Edward J. Markey submitted a letter to Federal Energy Regulatory Commission (“FERC”) Chairman Jon Wellinghoff, expressing serious concern over the apparent increasing frequency of manipulation in electricity markets. Senators Warren and Markey stated that a recent settlement agreement, pursuant to which FERC ordered JPMorgan Chase to disgorge unjust profits of $125 million and to pay civil penalties of $285 million, for total damages of $410 million, may not be adequate to refund defrauded ratepayers, nor does it punish individual executives who sought to impede FERC’s investigation. The Senators posed a series of seven questions seeking information from FERC regarding the JPMorgan settlement and FERC’s enforcement practices, with the general goal that government settlements provide appropriate relief for consumers and deter future market manipulation:
On August 7, 2013, the U.S. Department of Energy, Office of Fossil Energy (DOE/FE) issued an Order Conditionally Granting Long-Term Multi-Contract Authorization to Export Liquefied Natural Gas by Vessel from the Lake Charles Terminal to Non-Free Trade Agreement Nations (Order). Below is a summary of the Application, DOE/FE’s findings and analysis, and the terms and conditions applicable to the Lake Charles Terminal. Please click here for a copy of the order.
A settlement between the European Union (EU) and the Chinese government on the import of photovoltaic solar cells to the EU became effective on August 6, 2013. The settlement resolves a US $27 billion dumping and subsidy investigation1 of the price of EU imports of photovoltaic modules manufactured with Chinese cells. Under the terms of the pact, up to 7 GW of such modules may be sold in the European Union by participating Chinese companies, with a price floor of .56 Euro cents (US $.75) per watt, which might be subject to modification over time. Imports above the 7 GW volume will be subject to duties of 47.6 percent.2
The Sino-European agreement is the latest turn in a flap over the export of silicon photovoltaic modules from China. Western module manufacturers have alleged that their Chinese competitors sell product in outside markets below the cost of production to gain market share. This allegation formed the basis for unfair trade claims filed before the U.S. Department of Commerce and International Trade Commission in October of 2011 and before the European Commission in Brussels in July 2012.
On August 5, 2013, the Federal Energy Regulatory Commission (FERC) issued an Order to Show Cause and Notice of Proposed Penalty, directing BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, BP) to show cause why they should not be assessed a civil penalty of $28 million plus $800,000 in disgorgement for manipulating the next-day, fixed-price gas market at Houston Ship Channel (HSC).
FERC’s order is based on a report by the Office of Enforcement (Enforcement) Staff. Enforcement Staff concluded that, from September 2008 to November 2008, certain BP traders had a pre-existing spread position that included short index swaps at the HSC and long index swaps at Henry Hub. BP’s financial position benefited when the spread between daily physical gas prices at HSC and Henry Hub grew wider. As a result of Hurricane Ike, HSC gas prices plummeted, which resulted in the BP traders’ spread position suddenly having a potential to be worth millions of dollars. According to Staff, the traders then engaged in a scheme to extend that profit potential after the hurricane by increasing their HSC-Henry Hub spread positions and purchasing more physical gas for two months, in an effort to suppress prices at HSC.
On July 31, 2013, the Senate Finance Subcommittee Energy, Natural Resources, and Infrastructure held a hearing on the Master Limited Partnership Parity Act (S. 765). The bill would extend the master limited partnership (MLP) tax rules to renewable energy assets. The MLP rules provide a means to raise equity from retail investors while avoiding the “corporate” layer of income tax. These rules and the proposed legislation are discussed in the post below. Click here to see a link to our March 12, 2013, blog post.
The bill is sponsored by Senators Coons (D-DE), Moran (R-KA), Murkowski (R-AK) and Stabenow (D-MI). It also has bi partisan support in the House. Senator Stabenow chairs the subcommittee that held the hearing, so she made the opening remarks, and her written comments avoided directly referencing the bill.
Rep. Sensenbrenner Reintroduces the “Powering America for Tomorrow Act” Regarding Regional Planning, Cost Allocation and Federal “Backstop” Siting of Electric Transmission Facilities
On July 19, 2013, Rep. Jim Sensenbrenner (R-WI) reintroduced the Powering America for Tomorrow Act (the Act), which would, among other things, amend section 216 of the Federal Power Act (FPA) to establish new regional electric transmission planning requirements, require the Federal Energy Regulatory Commission (FERC) to promulgate rules regarding regional cost allocation, create a mechanism for FERC to issue certificates of public convenience and necessity for certain regional transmission projects, and provide FERC with “backstop” siting authority for certain regional transmission projects under certain circumstances.
The Act would provide a more robust statutory platform than the existing FPA section 216 for FERC to implement such “backstop” siting authority and, in many respects, would build on, rather than supplant, recent developments at FERC regarding transmission planning and cost allocation. If enacted, the Act could streamline the development of high-voltage electric transmission infrastructure necessary to alleviate congestion, bring remote renewable resources to market and accelerate the deployment of smart grid technologies. Click here for additional information and a summary of the principal provisions of the Act.
In an unexpected about face, BP has canceled the auction of its interest in 16 North American wind farms, a 2,600 MW portfolio valued by some at $1.5 billion. BP’s intent to spin off its wind assets was first announced in April of 2013. The decision to divest was attributed to a number of reasons, including an attempt to raise cash to meet liabilities associated with the 2010 Macondo oil spill in the Gulf of Mexico, a refocusing of BP’s business on conventional power and perhaps as part of a strategy to reduce exposure to the US following the political backlash from the Macondo spill. Three months later BP has canceled the sale.
The announcement of the asset sale seemed to be well timed and the proposed sale seemed to command a lot of attention from prospective buyers. Low interest rates, high demand for assets with stable cash flows and a shortage of contracted wind power projects have created what is conventionally regarded as a seller’s market for operating assets. Other independent power producers have exploited market conditions. Indeed, one week ago the market devoured NRG Energy’s $468 Million yieldco IPO, driving the target share price from $19--$21 per share up to an opening price of $27 per share.
With forecasts that the total GDP of emerging markets could overtake that of the developed economies by 2014,1and at a time where technological advances are transforming the energy business globally, it is easy to see why emerging market energy project explorers and developers (EMEPED) are so excited about their prospects. Since the advent of the global commodity boom in 2000, many emerging markets have experienced substantial growth the growth, creating tremendous potential for investors with long-term investment horizons. At the same time, investing in emerging markets has become increasingly more complex and challenging. One of the emerging market risks expected to become more difficult to manage in the coming years will be the labor challenge.
The demand for highly skilled, highly educated and a highly experienced workforce to implement energy projects is intensifying, and leading to labor shortages in developed economies. Such shortages are amplified in many emerging markets where a workforce skilled in energy matters is often non-existent. Expatriated employees are often utilized to help lift projects off the ground in such markets, but are not always be able to satisfy all such labor demands. Without sufficient skilled labor, risk of an adverse health, safety or environmental incident increase substantially. Going forward, an EMEPED’s success in an emerging market will depend upon its ability to solve labor constraints.
[This is a revised alert reflecting updated information in a July 19 National Energy Technology Laboratory (NETL) media release, which clarified prior NETL statements on the hydraulic fracturing study contained in earlier media reports.]
The Department of Energy's NETL issued a statement July 19 regarding its comprehensive, year-long field study on hydraulic fracturing and drinking water in the Marcellus Shale. NETL stated that it is “in the early stages of collecting, analyzing and validating data,” and “while nothing of concern has been found thus far, the results are far too preliminary to make any firm claims.” In an April 2013 update, NETL said the study at test sites in Washington and Greene Counties in southwestern Pennsylvania “will provide an unbiased, science-based source of information which can guide decisions about shale gas development.” Utilizing seismic testing and “man-made tracers” injected into the hydraulic fracturing fluids in the Marcellus Shale gas wells over 8,000 feet in depth, NETL is monitoring older, shallower, sandstone wells at 4,000 feet – at least 3,000 feet below drinking water aquifers – to determine if there is “communication” between the Marcellus Shale and the sandstone units above. The monitoring project offers the federal government first-of-its-kind access to a company’s drilling operations and, according to NETL, “multiple lines of evidence” in testing for water contamination. NETL geologist Richard Hammack reportedly characterized the large amount of field data that the studies have yielded to date as “the real deal” and likely to be analyzed “for years to come.” NETL said that it expects a final report on the study results by the end of the year.
On Tuesday, the Federal Energy Regulatory Commission (FERC) issued an order assessing $435 million in civil penalties against Barclays Bank PLC (Barclays) for allegedly manipulating western electricity markets in and around California. In addition, Barclays was ordered to disgorge $34.9 million, plus interest, in unjust profits to the Low Income Home Energy Assistance Programs in the states of Arizona, California, Oregon, and Washington. FERC also assessed civil penalties against several individual Barclays traders for their alleged participation in the scheme. Three traders were assessed penalties of $1 million each, and the Managing Director of North American Power, a high-level employee alleged to be the leader of the scheme, was ordered to pay $15 million.
FERC found that Barclays had violated the Federal Power Act (FPA) and FERC’s anti-manipulation rules by intentionally moving the electric energy index price at four different trading nodes in the West. According to FERC, Barclays’s traders would allegedly take large physical positions in the opposite direction of their financial positions and then “flatten” those positions to influence the index price at that trading hub, which would in turn benefit their financial swap positions. The trades at issue took place between November 2006 and December 2008 over 655 product days.
Senators Lisa Murkowski (R-AK) and Mary Landrieu (D-LA) recently reintroduced a bill to amend several federal statutes that govern the treatment of revenues collected by the federal government from entities that hold leases for the exploration, development and production of energy resources. Sens. Murkowski and Landrieu originally introduced a version of the bill in March 2013.
The “Fixing America’s Inequities with Revenues Act of 2013” (or “FAIR Act”) would amend the Outer Continental Shelf Lands Act by requiring the Department of the Interior (Interior) to deposit 37.5 percent of all revenues received in connection with offshore energy development activities into a special account. Interior would distribute 27.5 percent of the collected revenues to coastal states, with the remaining 10 percent to those coastal states that have established funds to support the development of alternative energy research programs. The state of Alaska, and any state along the Atlantic Ocean, Pacific Ocean, or Gulf of Mexico whose coastline is not subject to a leasing moratorium, would qualify to receive revenues through this program. Revenues eligible for allocation to coastal states may come from exploration and development activities for both traditional and alternative energy sources. The revenue sharing program would go into effect beginning in fiscal year 2014.
The California Independent System Operator (CAISO) has been projecting a shortage of downward and upward load-following capability as early as 2017. On July 12, 2013, the Federal Energy Regulatory Commission (FERC) announced a technical conference to be held on July 31, 2013, in Sacramento, California, to address the State of California’s need for flexible capacity and local reliability in the two-to-five-year forward period. In addition, the panelists will address a proposal released by CAISO and the California Public Utilities Commission to (1) augment the existing year-ahead resource adequacy procurement obligations for all load-serving entities (LSEs) by establishing procurement obligations two and three years prior to a delivery year; (2) develop a CAISO-run capacity auction to provide a voluntary platform for LSEs to procure additional forward capacity beyond what they procure bilaterally; and (3) provide an annual long-term reliability planning assessment, focused on the four-to-10-year forward period. The technical conference is a result of FERC’s order in Docket No. ER13-550 earlier this year, encouraging CAISO and its stakeholders “to focus on the development of a durable, market-based mechanism that provides incentives to ensure that resources with the adequacy and operational needs CAISO requires are available to meet system needs.” Such efforts may result in new market opportunities for generation owners.
A copy of the CAISO / CPUC proposal is available here.
On July 10, 2013, the House Energy and Commerce Committee’s Subcommittee on Energy and Power approved the Natural Gas Pipeline Permitting Reform Act (H.R. 1900) to ensure that federal agencies expeditiously review and act on applications for natural gas pipeline projects. Introduced in May by Rep. Mike Pompeo (R-KS), the legislation would add the following new provisions to section 7 of the Natural Gas Act:
- First, the Federal Energy Regulatory Commission (FERC) would be required to approve or deny an application for a gas pipeline project certificate within 12 months after providing public notice of the application.
- Second, other agencies responsible for issuing licenses, permits or approvals in connection with the siting, construction, expansion or operation of a gas pipeline project would be required to approve or deny authorization within 90 days after FERC issues final environmental documents. This deadline may be extended for an additional 30 days upon petition to FERC if circumstances beyond an agency’s control warrant such an extension.
- Third, if such an agency does not approve or deny the issuance of a license, permit or approval within the time period specified above, such authorization shall be deemed approved.
On November 14, 2012, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) seeking comments on what changes, if any, should be made to its regulations under the natural gas market transparency provisions of section 23 of the Natural Gas Act (NGA). FERC is considering imposition of new reporting obligations for next-day and next-month physical gas transactions. Commenters argued that the proposed reporting requirements would not meaningfully enhance market transparency because FERC-jurisdictional transactions comprise only a small portion of total next-day and next-month physical gas sales. In response to these comments, FERC’s Office of enforcement intends to send the following data requests to certain natural gas marketers:
1. What was [X COMPANY’S] total annual volume of United States natural gas sales in 2012?
2. Is [X COMPANY] an affiliate, as defined by section 2(27) of the Natural Gas Policy Act of 1978, of an interstate pipeline, an intrastate pipeline, and/or an LDC? If so, provide the name[s] of such affiliated pipeline[s] or LDC[s].
If the response to Question 2 is affirmative, the marketer will be required to provide the following additional information:
3. Of [X COMPANY’S] total 2012 volumes of United States natural gas sales, what volume consisted of sales in interstate commerce, as defined in section 2(7) of the Natural Gas Act?
4. What volume of the sales identified in response to question 3, consisted of sales to end users, such as industrials or electric generators, who would be expected to be purchasing the gas primarily in order to consume it?
5. Of the 2012 volume of [X COMPANY’S] U.S. natural gas sales remaining after excluding the volume sold to end-users identified in response to question 4, what volume consisted of sales from [X COMPANY’S] own or its affiliates’ production of natural gas?
Responses to FERC’s data requests will be due within 15 days. Gas marketers may request confidential treatment of their responses.
FERC’s order concerning these data requests is available here.
On June 26, 2013, a non-profit association of investors (WIRES) petitioned FERC to initiate a generic proceeding to clarify and reform policies regarding regulated rates of return on equity (or ROE) for existing and future investments in high voltage electric transmission infrastructure. According to WIRES, evolving and unpredictable application of FERC’s discounted cash flow (DCF) methodology for determining allowed ROEs may have unintended consequences by chilling investment in needed transmission facilities, disrupting infrastructure planning and growth, and delaying projects.
WIRES recommends a new policy that (1) standardizes selection of proxy groups; (2) denies complainants a hearing on ROEs for existing facilities unless it is shown that existing returns are at the extremes of the zone of reasonableness; (3) allows consideration of competing infrastructure investments of other industries; (4) permits use of ROE methodologies other than DCF; and (5) supports use of more forward-looking data and modeling.
Regulated ROEs for new and existing transmission infrastructure have been declining in recent years, and FERC has been less inclined to grant ROE adders. Single issue rate cases challenging allowed ROEs have undermined regulatory certainty needed to support infrastructure investment and created uncertainty in capital markets.
A copy of the petition is available here.
On June 17, 2013, the Federal Energy Regulatory Commission (FERC) announced a public technical conference, scheduled for September 25, 2013, on centralized electric generating capacity markets for Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs).
FERC noted that the nation’s generation resource mix has been evolving in response to low natural gas prices, federal and state renewable energy policies and the retirement of older generation assets, and that this changing resource mix could result in electric grid reliability and operational needs that are different than those of the past. In addition, some states have implemented their own resource adequacy policies to foster the development of specific types of generation resources, raising concerns as to how such policies can be reflected and accommodated in the RTO/ISO capacity markets. The conference will examine how centralized capacity market rules and structures (1) support the procurement and retention of generation resources necessary to meet reliability and operational needs in light of evolving resource mixes and market conditions and (2) square with state efforts to foster—and sometimes require—generation resource development. The technical conference is intended to enable capacity market stakeholders to learn more about how market rules and structures achieve resource adequacy, proper long-term price signals and fixed-cost recovery.
FERC will issue a supplemental notice providing additional details and an agenda for the conference.
Oil & Gas Divestitures: Shedding Non-Core Assets Webinar, Courtesy of The Deal
Replay Link: http://ow.ly/lP4RQ
The past few months have seen a surge in A&D activity in the upstream oil and gas markets. Weak natural gas prices and a relatively stable oil price are acting as catalysts for increased deal activity. Whether it’s to raise capital to strengthen balance sheets, develop existing assets or acquire new assets that better fit their longer term strategic goals, oil and gas corporations are focused on shedding their non-core assets.
What’s the likely trajectory of this trend and what factors will continue to drive it? Which buyers are demonstrating the most interest and muscle? Which asset classes will see the most divestiture activity, and what opportunities does it present you and your organization? How will valuations be impacted and how can you be sure to get the best price? Above all, how should you adapt your A&D strategy in light of these market conditions and position your firm to benefit from them?
On June 6th, Claire Poole spoke with leading market experts, including Akin Gump’s Christine LaFollette, about these and other critical questions facing oil and gas dealmakers as they fine-tune their strategies for 2013.
Hearing Examiner Recommends Rejection of Dominion’s Certificate Request for Proposed Brunswick Generation Project
On June 13, 2013, a hearing examiner recommended that the Virginia State Corporation Commission (SCC) reject an application by Dominion Virginia Power (Dominion) for a Certificate of Public Convenience and Necessity (CPCN) to construct, own and operate an approximately 1,358 MW natural gas-fired combined-cycle generating facility in Brunswick County, VA. The examiner concluded, after a lengthy and contested hearing, that Dominion failed to adequately consider third-party market alternatives to its proposed ratepayer-funded investment in the Brunswick project.
On November 2, 2012, Dominion submitted its request for a CPCN for the Brunswick project, including a request for an incentive return on equity (ROE). Virginia law permits utilities in the state to obtain a 100 basis point enhanced ROE for the construction of combined-cycle combustion turbines, such as the Brunswick project.
Dominion was not required under Virginia statute to conduct a formal, competitive Request for Proposal process as condition of obtaining a CPCN to construct its own generation plant. However, the SCC had previously held that evidence relating to the costs of competitive alternatives would nonetheless be relevant in determining the reasonableness of a proposed Dominion generation investment. In addition, when the SCC approved Dominion’s 2011 Integrated Resource Plan in October 2012, the SCC directed Dominion to “adequately consider” third party market alternatives to its self-build proposals. The primary issue litigated at the hearing was whether Dominion met the “adequately considered” standard as set out by the SCC.
In early 2013, many in the solar industry appeared to be thinking that the IRS’s blessing of a solar REIT would be provided within weeks. It is now the middle of 2013, and it appears the thinking from a few months ago was at best irrational exuberance. Three events have triggered a change in perspective on solar REITs.
First, Hannon Armstrong’s private letter ruling request as to its REIT status is now public. Prior to the ruling being made public, the industry scuttlebutt was that the ruling would bless rooftop solar as REIT eligible. However, Hannon Armstrong’s CEO Jeff Eckels best describes the actual substance of the ruling – “We did not ask the IRS about renewables and we did not receive anything from the IRS that mentions renewables.” The article quoting him is available here. What the ruling actually concluded is that certain energy efficiency improvements are able to be included in Hannon Armstrong’s REIT qualification calculations as real estate. The redacted ruling is even more cryptic as to the specifics of those improvements. The redacted ruling is available here.
Seventh Circuit Approves Regional Allocation of Transmission Costs for Delivering Remote Wind Energy and Calls into Question Constitutionality of In-State Renewable Requirements
The Seventh Circuit recently issued a landmark decision upholding a Federal Energy Regulatory Commission (FERC) order approving a plan by the Midwest Independent System Operator (MISO) to allocate the costs of certain high voltage transmission facilities on a region-wide basis.1 The court rejected an argument that the proposed new transmission facilities would provide no benefits to Michigan, which relies on in-state renewable energy to meet its Renewable Portfolio Standard (RPS) requirements. The court concluded that such in-state requirements discriminate against out-of-state renewable energy, in violation of the commerce clause of Article I of the U.S. Constitution.
In July 2010, MISO, the independent administrator of the transmission system in the Midwest, filed a proposal with FERC to establish a new category of transmission projects referred to as Multi-Value Projects (MVPs). To qualify as an MVP, a transmission project must have an expected cost of at least $20 million and must help MISO members meet their state RPS requirements, address system reliability issues, or provide economic benefits in multiple MISO zones. MISO proposed to allocate the costs of MVPs across the entire MISO region based on electricity usage. MISO’s proposal was primarily intended to finance the costs of transmission facilities used to integrate remote western wind energy into Midwest urban load centers by “socializing” those costs among all customers in the region.
President Obama Requires Federal Agencies To Improve Transmission Siting, Permitting, and Review Processes
Concluding that “[m]odernizing our Nation’s electric transmission grid requires improvements in how transmission lines are sited, permitted, and reviewed,” President Obama on June 7, 2013, released a Memorandum directing changes to the process for constructing transmission projects on federal lands. The Memorandum, titled Transforming our Nation’s Electric Grid Through Improved Siting, Permitting, and Review, focuses on federal policies related to energy right-of-way corridors and the application processes across agencies for new projects.
First, the Memorandum directs the secretaries of Agriculture, Commerce, Defense, Energy and the Interior (Secretaries) to collaborate with each other and the Steering Committee on Federal Infrastructure Permitting and Review Process Improvement (Steering Committee) to improve the use of “energy right-of-way corridors” for electric transmission projects. Under the Energy Policy Act of 2005, the secretaries designated energy corridors on federal lands to promote the development of energy resources, including transmission facilities. These corridors are incorporated into relevant federal agencies’ land use and resource management plans. Because the process for establishing energy corridors involves a review of environmental, cultural and local community impacts, the subsequent approval process for specific energy projects within designated corridors is likely to be streamlined.
On June 7, 2013, Southern California Edison (SCE) announced that it would be closing the controversial San Onofre Nuclear Generating Station (SONGS). Located on the California coast line near San Clemente, California, in the vicinity of 7.1 million Californians, the plant has been the subject of a major public safety debate since January of 2012.
Unit one of SONGS commenced operation in 1968, with units two and three respectively following in 1983 and 1984. Unit one was decommissioned in 1992, while units two and three were repowered in 2010. In January of 2012, the plant was taken offline when a small radiation leak resulting from a broken steam generator water tube in unit 3 called the safety of the plant into question. The ensuing analysis of plant performance revealed that faulty design of the 2010 repowering led to excessive steam turbine generator wear.
Since January of 2012 shut down and repair costs soared to over half a billion dollars, regulators were slow to approve a plan for recommencement of service and public concern over the safety of the plant persisted, leading to SCE’s announcement that SONGS would be permanently closed.
Questions over San Onofre now shift to plant decommissioning and SCE’s ability to serve its customer base. The Nuclear Regulatory Agency will oversee the dismantling of units two and three and the safe disposal of spent nuclear fuel. SCE has indicated that it expects to serve customers reliably through the high demand summer months, though major resource or demand shocks could result in power shortages.
The closure of SONGS will create a number of challenges and opportunities for energy generators in California. Initially, one of the challenges is that the loss of the SONGS power in the transmission system creates some uncertainty as to the nature and type of upgrades that may be required for certain projects in order to effectively move their power over the state’s transmission system. Because the system is “balanced” in consideration of all generation, the loss of SONGS can cause either positive or a negative effect on the ability of other projects to transmit power, depending upon their location and other factors. Many projects in development will need to re-review their transmission arrangements and any anticipated curtailment amounts in light of the SONGS closure. In the area of opportunities, before it was shut down, SONGS was producing enough power for about 1.4 million homes. California has been replacing that power through a number of sources, including buying power from out of state. With the permanent shut down of SONGS, new projects (wind, solar and natural gas) to replace the lost SONGS energy will need to be built.
The U.S. Court of Appeals for the D.C. Circuit issued an order on May 10, 2013, upholding the Federal Energy Regulatory Commission’s (FERC) policy of using the median, rather than the midpoint, Return on Equity (ROE) of a proxy group of publicly traded companies to determine the base ROE for a single electric utility with an average risk profile. When Southern California Edison (SoCal Edison) filed to revise its transmission tariff in 2007, FERC’s policy was to use the midpoint to determine a base ROE for electric utilities. Before the FERC issued its order setting SoCal Edison’s ROE, it announced in Golden Spread1 that it was revising its policy to use the median to determine the base ROE for a single electric utility, although it would continue to use the midpoint when groups of utilities filed for a single ROE, as has been the case with the transmission owners in certain independent system operator regions. FERC’s 2010 order on SoCal Edison’s rates applied the policy set out in Golden Spread and used the median to calculate SoCal Edison’s base ROE.2 SoCal Edison’s challenge to FERC’s order was the first time the issue of using the median to calculate the base ROE for an electric utility had come before the court.
The Department of Justice (DOJ) filed a motion for the Court of Federal Claims to dismiss SolarCity’s1 case against Treasury with respect to the administration of the 1603 Cash Grant program. DOJ’s brief in support of its motion is available here.
DOJ’s grounds for dismissal are that the Court of Federal Claims has a specific jurisdiction to hear patent and copyright cases, government contract cases and claims for payments from the federal government (including tax refund cases)2 while SolarCity alleges that Treasury’s administration of Cash Grant program violated the 1603 statute.
Further, DOJ asserts that SolarCity is effectively seeking the court to review Treasury’s Cash Grant guidance for compliance with the Administrative Procedures Act, which is not within the jurisdiction of the Court of Federal Claims’. The Administrative Procedures Act is the federal statute that requires federal agencies to provide notice and an opportunity to comment before promulgating rules.3 Interestingly, the complaint does not actually reference the Administrative Procedure Act, probably because the plaintiffs’ counsel, Covington & Burling, was trying to avoid this jurisdictional issue.
Lloyd MacNeil, a partner in Akin Gump’s global finance practice, spoke extensively with Windpower Monthly for the article “Investors seek security in uncertain world.”
MacNeil told the publication that steady returns are the driving force behind the strong interest among investors. Someone investing for the long term, he said, “is looking for predictability and, if you’re a pension fund, that’s absolutely what you’re looking for.” He added that wind projects with long-term power purchase agreements can provide predictable income “stretching out ten years, 15 years or longer.”
As the NGL market has grown dramatically over recent years, producers have begun to focus more closely on whether they are required to pay royalties to their lessors on the NGLs (natural gas liquids, including ethane, propane, normal butane, isobutene, natural gasoline and other liquids) derived from their gas production. Since the rights of royalty owners and the obligations of lessees are generally governed by the royalty provisions contained in a lease, in order to determine whether a lessee is required to pay royalties either on (a) unprocessed natural gas before it is stripped of NGLs or (b) all of the processed natural gas, including residue gas and NGLs, producers should first look to the language of the underlying lease to answer the question.
For an English delegate attending a recent oil & gas legal conference in Texas there seemed to be a surprising number of talks on shale gas. Americans are understandably excited about these new opportunities. Economic benefits are already being felt in the U.S. at both local and national levels.
Meanwhile, over the water, the U.K. government is monitoring developments in the hope that the American experience with shale can be replicated in Britain. To date the United Kingdom (along with the rest of Europe) has been slower in developing shale. The government recently announced a policy change in the hope of encouraging production. Yet, despite this latest development, expansion of shale production in Britain is likely to be slow and modest.
For parts of the U.S. where discoveries have been made there has been an upturn in local economies as resources (including human capital) are attracted to these areas. However, in common with other petroleum developments (whether conventional or unconventional), there have also been unintended negative social consequences, including a strain on local housing and resources, and difficulty in recruiting public sector workers. Some have also raised concerns about the environmental impact of hydraulic fracturing (or fracking).
In a chapter reminiscent of Bleak House or the recent New York Times series on the Bronx court system,1 the U.S. Environmental Protection Agency (EPA) recently filed comments on the draft Environmental Impact Statement (EIS) for the Keystone XL pipeline project expressing its view that the EIS contained “insufficient information.” http://www.epa.gov/compliance/nepa/keystone-xl-project-epa-comment-letter-20130056.pdf (EPA Comments). The Keystone XL saga bodes ill for the efficient development of domestic energy supplies and strongly supports congressional calls for systematic reform of the permitting programs.
The National Environmental Policy Act (NEPA) and Section 309 of the Clean Air Act (CAA) authorize EPA to review and comment on the draft EIS prepared in conjunction with the application for a Presidential Permit submitted by TransCanada Keystone Pipeline, LP. EPA raised four issues in its comments:
- Analysis of lifecycle greenhouse gas emissions from development of the Canadian oil sands;
- Pipeline safety and spill prevention measures included as permit conditions;
- Analysis of alternative routes for the pipeline; and
- Analysis of environmental justice and community impacts.
Earlier this year, the Internal Revenue Service (the IRS) issued a private letter ruling (PLR) expanding the realm of what constitutes “qualifying income” for certain publicly traded partnerships to include fees received for the expansion of the taxpayer’s terminalling, storage and transportation assets.1
Under Section 7704(a) of the Internal Revenue Code, publicly traded partnerships are generally taxed as corporations, and therefore subject to taxation at the entity level. However, there is an exception for publicly traded partnerships that earn income from certain qualifying sources and through certain qualifying activities. Section 7704(c) of the Code provides an exception to the general rule of corporate treatment for publicly traded partnerships if 90 percent or more of the partnership’s gross income is “qualifying income.” Section 7704(d)(1)(E) of the Code provides that the term “qualifying income” includes “income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy or timber).”
The Bureau of Land Management (BLM) published a final rule in today’s Federal Register that will give priority to wind and solar projects over mining claims on federal lands.
BLM has designated wind and solar development zones in several western states, including Arizona, California, Idaho, Nevada, Oregon, Utah and Wyoming. Within these zones, project developers may apply for rights of way (ROW) to site eligible renewable projects. Through a separate and much quicker process, parties may file a mining claim on federal lands. An applicant for a ROW must compensate the holder of a mining claim if it intends to use the same land.
BLM’s new rule allows the agency to temporarily “segregate” federal lands that are the subject of wind or solar ROW applications or within a designated wind or solar development zone from the application of public land laws, including various mining statutes that allow a party to make a mining claim. The effect of the new rule will be to halt new mining claims on segregated lands for a period of up to two years.
On February 28, 2013, the North American Electric Reliability Corporation (NERC) submitted proposed revisions to its Standard Process Manual (SPM) to the Federal Energy Regulatory Commission (FERC) for approval. The SPM describes the procedures used by NERC in developing Reliability Standards. The proposed changes to the SPM were developed over the course of a year, with a three-stage commenting process providing input from stakeholders. The final stakeholder ballots were returned with over 85 percent approval for the proposed revisions.
The proposed changes would streamline NERC’s standards development process and increase the emphasis on consistency, expert input and results-based outcomes. In addition, a new Section 16, “Waiver,” was added to the SPM, allowing the Standards Committee to modify the development process for good cause and with five days’ notice. Waivers are intended to address situations where the development process is time constrained due to a particular regulatory directive, or to address an urgent reliability issue, including the declaration of a national emergency that involves the reliability of the bulk electric system or a cyber attack on that system.
On May 2, 2013, FERC issued a much anticipated order partially accepting the proposed changes by PJM Interconnection, L.L.C. (PJM) to its Minimum Order Price Rule (MOPR) for certain generation capacity resources seeking to participate in PJM’s capacity market auctions.
The MOPR, which was implemented in 2006, is intended to address the concern that certain resources participating in PJM’s capacity market may have an incentive to suppress clearing prices by offering supply at less than a competitive level. This can occur when a large net-buyer of capacity invests in generation capacity and then offers that capacity into the auction at a reduced price. The MOPR addresses this issue by requiring all new generation resources participating in the capacity market to bid at an established floor price or higher, unless the resource can demonstrate that a lower bid is justified based on the economics of the specific unit.
On May 2, 2013, the New York Supreme Court, Appellate Division, ruled that a zoning ordinance banning “all activities related to the exploration for, and the production or storage of, natural gas and petroleum,” was not preempted by the New York Oil, Gas and Solution Mining Law (OGSML). Norse Energy Corporation USA v. Town of Dryden, No. 515227 (3d Dep’t 2013). If not overturned by the Court of Appeals, or over-ridden by statutory amendment, the Norse Energy decision provides each municipality in New York the power to preclude hydraulic fracturing and related exploration and production activities.
The Third Department’s decision contains several dubious leaps of logic and reason to arrive at a result that seems entirely inconsistent with the OGSML. The statute states that its provisions:
shall supersede all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries, but shall not supersede local government jurisdiction over local roads or the rights of local governments under the [Real Property Tax Law].
FERC Convenes Second Technical Conference On Coordination Between Natural Gas and Electricity Markets
On April 25, 2013, the Federal Energy Regulatory Commission (FERC) convened its second technical conference on coordination between natural gas and electricity markets. The first conference, held on February 13, 2013, addressed the current challenges facing the natural gas and electric industries in the area of information sharing and communications. The conferences arose from a February 3, 2012, Request for Comments issued by Commissioner Moeller, which sought input on the broad issue of the interdependence of the natural gas and electric industries, specifically in the context of electricity generation’s increasing reliance on natural gas to serve load. The Commission’s subsequent notice establishing the proceeding explained that, “[s]ince natural gas is expected to be relied on much more heavily in electricity generation, the interdependence of these industries merits careful attention.”
The U.S. Court of Appeals for the District of Columbia Circuit unanimously upheld the authority asserted by the U.S. Environmental Protection Agency (EPA) to “withdraw” permission to discharge dredge or fill material from a mountaintop coal mine into disposal sites allowed under a permit that had been issued by the U.S. Army Corps of Engineers (Corps) four years previously. Mingo Logan Coal Company v. EPA, __ F.3d ___, No. 12-5150 (D.C. Circuit April 23, 2013)(copy available here). The Court’s decision sent shock waves through the mining industry, introducing enormous regulatory uncertainty for entities operating under Corps-issued dredge and fill permits.
In January 2007, the Corps issued, without objection by EPA, a Clean Water Act (CWA) Section 404 permit to Mingo Logan’s predecessor to discharge material from the company’s Spruce No. 1 Mine into four West Virginia streams and tributaries. In September 2009, EPA requested that the Corps modify the permit to address “new information” about the potential to degrade downstream water quality. The Corps refused and EPA commenced regulatory action to limit the allowable discharge sites. In January 2011, EPA issued a final determination withdrawing certain discharge sites from the permit. Mingo Logan filed suit in U.S. District Court and obtained summary judgment on its claim that EPA lacked the statutory authority to invalidate an existing permit. Mingo Logan Coal Co. v. U.S. EPA, 850 F. Supp. 2d (D.D.C. 2012). EPA appealed to the D.C. Circuit.
New York is moving toward a long-term extension and expansion of its existing solar policy. The State Senate unanimously passed New York Solar Bill (A.5060/S.2522) on Earth Day, April 23, 2013 (the “NY Solar Bill”). The NY Solar Bill would extend the NY-Sun Initiative (NYSI) which currently runs into 2015, through 2023.
The legislation now moves to the State Assembly for consideration. If the Assembly approves the legislation, there is a good chance that Governor Andrew Cuomo, who advocated a ten-year, $1.5 billion commitment to solar and creation of a $1 billion “New York Greenbank” in his January State of the State address, will sign the bill.
The White House by legislative or administrative action intends to expand tax policy with respect to renewable energy. Two areas under consideration by the Administration are (i) Senators Coons (D-Del.) and Jerry Moran’s (R-Kan.) bill to expand the ability of master limited partnerships (MLPs) to invest in renewables by treating renewable energy income as “good” income for purposes of the 90 percent qualifying income test and (ii) permitting solar projects to be “qualifying” assets for real estate investment trusts (REITs). The MLP bill is discussed in the blog post below of March 13.
Heather Zichal, deputy assistant to the President for energy and climate change, made these comments yesterday. The strategy is apparently based on a political judgment that an energy bill would be unlikely to garner sufficient support to be enacted; therefore, changes to tax policy are seen as a viable second choice.1
With respect to REITs, the White House may not need to wait for Congress. As widely reported, Renewable Energy Trust Capital, Inc. has filed a private letter ruling request with respect to utility scale ground mounted solar being effectively “real property” for purposes of the REIT rules. That ruling was expected at the end of January, but there has yet to be a public report of it being issued.
SunRun, Inc. (“SunRun”) has been targeted by a consumer class action lawsuit. Mr. Shawn Reed of California is the named plaintiff in the complaint against SunRun. Mr. Reed and his lawyers, Hagens Berman Sobol Shapiro LLP, seek similarly situated consumers to be designated as a “class” so that they can sue SunRun in a single action. The class action complaint is available here. Akin Gump is not involved in this lawsuit.
The lawsuit has three allegations:
1. It was deceptive for SunRun to include predictions of increased energy prices in California in its marketing materials. SunRun’s marketing materials referenced a 6 percent annual average increase in electricity prices nationwide over the last 30 years. The plaintiff asserts that this fact confused him and caused him to assume that prices would increase in California to make his investment in a home solar system more lucrative.
2. The plaintiff was misled to believe that, if he sold his house and the buyer did not want to continue to pay for the solar system, SunRun would come and remove the system, and he would have no further liability. This is based on SunRun’s contract referencing the fact that, at the end of the stipulated term, SunRun would come and remove the system at no cost to the homeowner (if the homeowner does not purchase the system or renew the contract). The plaintiff thought this provision also applied to a termination during the term, despite there being an express provision in the contract that a termination during the term accelerated the obligation to make the payments due for the remainder of the term.
3. At the time the system was installed on the plaintiff’s home, SunRun did not have a California contractor’s license. SunRun started installing solar systems in 2007, but did not obtain a California contractor’s license until February 2012.
Germany has been praised for its political ambition to shift from nuclear and fossil fuels to renewable sources of energy. Its so-called “Energiewende” has sparked debate on how to address rising costs for consumers while supporting the renewables policy.
At a first joint meeting on February 14, 2013, the federal ministers for the environment and for economics and technology have proposed legislation that would freeze the renewable energy surcharge consumers currently pay through 2014 and cap further increases of the surcharge at 2.5 percent per year as of 2015.
The federal ministers also proposed to partially shift the economic burden of the Energiewende from consumers to producers. Their proposals include a new “energy solidarity tax” charged to new, as well as existing, solar and wind energy generators; the cancellation of a biogas promotion bonus (the so-called “Güllebonus”); higher cost sharing by energy-intensive industries, mandatory direct marketing by large plant operators as opposed to access to fixed feed-in tariffs; and lower reimbursements for curtailment.
The oil and gas industry benefits from the master limited partnership (MLPs) rules. Those rules provide that oil and gas businesses (and certain other businesses) may raise equity in the public markets but without liability for corporate income tax. MLPs enable the oil and gas industry to raise capital from retail investors at tax advantaged rates.
Advocates for the renewable energy industry point out that the Internal Revenue Code requires that 90 perecent of an MLP’s income to come from qualified sources (e.g., oil or gas operations) and income from renewable energy projects is not a qualified source. Thus, the advocates suggest that Congress should amend the definition of qualified sources to include income from renewable energy projects.
The next phase of the conversation is that the industry’s most significant problem is a lack of tax equity providers. And merely making renewable energy eligible for MLP treatment would not address that shortage, because the investors that buy units in the MLP would be mostly individuals: individual investors would still be subject to the passive activity loss rules and the at-risk rules that would prevent them from using the tax credits and accelerated depreciation in an efficient manner.