On July 2, 2021, the Department of Energy’s Office of Fossil Energy (“DOE/FE”) issued a Notice of Intent (“Notice”) to Prepare a Supplemental Environmental Impact Statement (“SEIS”) for the Alaska LNG Project (“Project”). DOE/FE will evaluate potential environmental impacts of upstream natural gas production on the North Slope of Alaska, and will conduct a life cycle analysis to calculate greenhouse gas (“GHG”) emissions for liquefied natural gas (“LNG”) exported from the Project.
The $38.7 billion Project includes a proposed gas treatment plant on the North Slope of Alaska, 800-mile pipeline, and a liquefaction facility with a planned liquefaction capacity of 20 million metric tons per year. The Federal Energy Regulatory Commission (“FERC”) has issued an order approving the construction and operation of the Project. On August 20, 2020, DOE/FE authorized Alaska LNG Project LLC’s (“Alaska LNG”) request to export LNG to any country with which the United States has not entered into a free trade agreement (“FTA”) requiring national treatment for trade in natural gas (“Non-FTA countries”) in a volume equal to the Project’s planned liquefaction capacity (equivalent to roughly 929 Bcf per year or 2.55 Bcf per day).
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On February 19, 2021, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) upheld a decision by the Federal Energy Regulatory Commission (“FERC” or the “Commission”) cutting transmission incentives previously granted to three electric transmission companies.
The Energy Policy Act of 2005 amended the Federal Power Act to require FERC to promulgate a rule creating incentive-based rate treatment for electric transmission. The rule was intended to “promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all [transmission] facilities, . . . provide a return on equity that attracts new investment in transmission facilities, . . . [and] encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities . . . .” FERC promulgated such a rule, which is codified in the Commission’s regulations. One incentive available to a stand-alone transmission company (a “Transco”) is “[a] return on equity [“ROE”] that both encourages Transco formation and is sufficient to attract investment.”
Because FERC has traditionally viewed independence as a hallmark of a Transco, it considers the ownership and business structure of the Transco to ensure that the Transco operates independently of other market participants when deciding whether to grant such incentives. FERC has declined to establish a particular methodology for reflecting the degree of a Transco’s independence or specific incentive levels. However, the Commission has made clear that it “will consider the level of independence of a Transco as part of our analysis when we determine the proper ROE for the Transco, and evaluate the specific attributes of a particular proposal, including the level of independence, to determine appropriate incentives.”Continue reading “D.C. Circuit Upholds Cutting of Transmission Incentives by FERC”
The energy industry has been at the forefront of the 2020 election, and energy development is an issue that polarizes Americans and our businesses and political leaders in choosing the path for the future. Energy developments are inextricably linked to our economy and national security, and the decisions and policies that will be implemented over the next four years are critical to the nation and our participation and role in world affairs.
On September 10, 2020, the Commodity Futures Trading Commission’s (“CFTC” or “the Commission”) Division of Enforcement (“the Division”) issued guidance for CFTC staff on the factors to be considered when evaluating compliance programs in connection with enforcement matters. The guidance will be inserted in the CFTC Enforcement Manual. Although not binding on the Commission or any other Division of the CFTC, the Compliance Guidance is binding on Enforcement staff.
In recent years, the Division has taken several steps to increase transparency regarding the performance of its enforcement functions. First, the Division published its Enforcement Manual, which is updated periodically and publicly available on the CFTC’s website. On May 20, 2020, the Division issued guidance to staff regarding factors to be considered in recommending a civil monetary penalty in an enforcement action. Those factors include the existence and effectiveness of an existing compliance program, as well as efforts to improve that compliance program following detection of a violation. The recently issued Compliance Guidance provides factors to be used in evaluating such compliance programs.
The Compliance Guidance focuses on whether the compliance program was reasonably designed and implemented to achieve prevention, detection, and remediation of the misconduct at issue. The Compliance Guidance acknowledges that this assessment depends upon the specific facts and circumstances involved and further states that “[a]t all points, the Division will conduct a risk-based analysis, taking into consideration a variety of factors such as the specific entity involved, the entity’s role in the market, and the potential market or customer impact of the underlying misconduct.”
The Compliance Guidance provides a number of factors for staff to consider in determining whether a compliance program was reasonably designed and implemented to achieve the three goals identified above.
On September 3, 2020, the Federal Energy Regulatory Commission (“FERC” or the “Commission”) issued an Order on Remand from the U.S. Court of Appeals for the District of Columbia Circuit, providing a more robust explanation regarding how the NEXUS Gas Transmission, LLC (“NEXUS”) pipeline project, which relied in part on precedent agreements that would export natural gas to Canada, merits authorization under section 7(c) of the Natural Gas Act (“NGA”), thus giving NEXUS eminent domain authority.
On August 25, 2017, the Commission had issued a certificate of public convenience and necessity under section 7(c) to NEXUS. The Certificate Order approved the Project, which allowed for the use of eminent domain to build an approximately 250-mile-long pipeline in Ohio and Michigan. NEXUS had executed eight precedent agreements, accounting for 59 percent of the capacity of the Project, and the Commission found that these agreements demonstrated a need for the Project. Two of the eight precedent agreements were with Canadian companies.
Protesters argued that NEXUS should not be permitted to use eminent domain because some of the project’s capacity would be used to export gas and exports are subject to NGA section 3 authorization, rather than section 7, which does not allow for eminent domain. The Commission affirmed its underlying decision on rehearing and stated that Commission policy did not require FERC to look beyond precedent or service agreements to make judgments about the needs of individual shippers.
Protesters appealed to the D.C. Circuit. In September 2019, the D.C. Circuit, in City of Oberlin v. FERC, 937 F.3d 599, remanded the case to FERC and directed the Commission to supply an explanation for why it allowed the crediting of export precedent agreements with foreign shippers when analyzing market need for a domestic pipeline project. The D.C. Circuit also asked FERC for more robust explanation for why eminent domain was needed or appropriate.
On July 16, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 872 (“Order”), a final rule that significantly revised its rules implementing the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Congress enacted PURPA to reduce the country’s reliance on oil and natural gas by promoting “Qualifying Facilities” (“QFs”) that rely on alternative energy sources or more efficient generation. Since their promulgation, FERC’s regulations implementing PURPA have been largely unaltered. FERC opined that the energy industry has substantially evolved since PURPA was promulgated and that the final rule is necessary to address the changing landscape and more closely align with underlying congressional intent.
Among other things, PURPA requires electric utilities to offer to purchase electric energy from QFs, which are categorized as either small power producers or cogenerators. The rate that a QF may receive for energy must be a rate “not to exceed the incremental cost to the electric utility of alternative electric energy,” which is “the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source.” In other words, “the purchasing utility cannot be required to pay more for power purchased from a QF than it would otherwise pay to generate the power itself or to purchase power from a third party.” This is referred to as the utility’s “avoided cost.”
Rates for energy are generally categorized as either fixed or “as-available.” Fixed rates are generally fixed at the time of the contract or other legally enforceable obligation (“LEO”) between the QF and the utility and do not vary over the term of the contract or LEO. For example, many renewable energy projects, which generally produce only to sell into the market and rely on a fixed revenue stream for financing, often rely on fixed energy rates. Conversely, other types of generators, such as cogeneration facilities, might only sell into the market when they have excess energy and will take the prevailing price at the time of sale. This rate is referred to as an “as-available” energy rate and is variable. Rates for capacity are generally fixed at the time of contract or LEO. QF rates for energy and capacity are set by state commissions.
Order No. 872 follows a technical conference, notice of proposed rulemaking (“NOPR”), and multiple rounds of industry comments. The Order adopts most of the NOPR proposals and substantially alters the rules for QFs.
On July 10, 2020, the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) denied challenges1 to the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) final rule on electric storage participation in Regional Transmission Organization (“RTO”) and Independent System Operator (“ISO”) markets (“Order No. 841”).2
Order No. 841 aimed to facilitate the participation of electric storage resources (“ESRs”) in RTO/ISO markets, with the goals of removing barriers to participation by ESRs, increasing competition within RTO/ISO markets, and ensuring just and reasonable rates. Specifically, FERC ordered RTOs/ISOs to establish participation models that recognize the physical and operational characteristics of and facilitate participation by ESRs.3
An ESR for these purposes is defined as “a resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid,”4 and encompasses storage resources located on the interstate transmission system, on a distribution system, or behind the meter.5 Order No. 841 declined to allow states to decide whether ESRs located behind a retail meter or on a distribution system in their state could participate in RTO/ISO markets.6 On rehearing, the FERC reiterated that it would not provide state opt-out rights, arguing among other things that “establishing the criteria for participation in the RTO/ISO markets of [ESRs], including those resources located on the distribution system or behind the meter, is essential to the Commission’s ability to fulfill its statutory responsibility to ensure that wholesale rates are just and reasonable.”7 FERC further concluded that it was not required under the Federal Power Act (“FPA”) or relevant precedent to provide an opt-out from ESR participation.8
On June 30, 2020, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) struck down the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) practice of issuing tolling orders that extend the time FERC may take to consider applications for rehearing of its orders under the Natural Gas Act (“NGA”). In a recent decision on en banc rehearing in Allegheny Defense Project v. FERC,1 the D.C. Circuit ultimately denied landowners’ and environmental groups’ challenges to FERC’s approval of the Atlantic Sunrise interstate natural gas pipeline on the merits. However, the court’s rejection of FERC’s tolling order practice—which breaks with longstanding precedent and creates a circuit split—significantly affects proceedings under the NGA and likely implicates FERC’s rehearing procedures under the Federal Power Act (“FPA”).
The NGA requires natural gas companies to obtain a certificate of public convenience and necessity from FERC in order to construct and operate an interstate natural gas pipeline.2 Once such a certificate is issued, the NGA confers upon certificate holders eminent domain authority to obtain necessary rights-of-way.3
The NGA further provides that before a party can seek judicial review of a FERC order, it must apply for rehearing of the order.4 Upon receiving such an application, the NGA provides FERC the “power to grant or deny rehearing or to abrogate or modify its order without further hearing.”5 If FERC does not act on the application for rehearing within 30 days, the application “may be deemed to have been denied.”6 Given the complexities inherent in its proceedings, FERC’s practice has often been to issue tolling orders intended to “act upon” the rehearing requests within the 30-day timeframe (i.e., to avoid the requests from being deemed denied), without making a substantive merits decision on such requests. Petitioners in Allegheny Defense Project argued that FERC’s tolling order process unfairly stalls judicial review of FERC’s pipeline approvals, while pipelines are permitted by FERC and district courts to proceed with construction and exercise eminent domain authority, respectively, in the interim.
Stakeholders in the U.S. infrastructure industry should note that ongoing litigation and new court decisions issued in the first half of 2020 are reshaping the development of energy projects.
Energy developers should carefully review the impact of new rulings that have interpreted environmental analyses required for Clean Water Act (“CWA”) permitting as greenhouse gas emissions (“GHG”) on the complex regulation of infrastructure projects. At the same time, several other recent proceedings have raised questions about practices and procedures of the Federal Energy Regulatory Commission (“FERC” or “Commission”) regarding natural gas infrastructure.
Status of Nationwide Permit 12. In Northern Plans Resource Council v. U.S. Army Corps of Engineers, the Montana District Court vacated the U.S. Army Corps of Engineers’ Nationwide (“Corps”) Permit 12 disrupting permitting and enforcement under the CWA. The court later clarified that the ruling applies to new projects and not existing pipeline projects and the Ninth Circuit recently denied a request to stay the implementation of the order pending appeal.
Navigable Waters Protection Rule. Significant litigation is expected to challenge a new restrictive rule of what constitutes “waters of the United States” under the CWA. Infrastructure projects will also be impacted by the Supreme Court’s recent decision in County of Maui v. Hawaii Wildlife Fund.
National Environmental Policy Act GHG Review. The District of Montana ruled in Wildearth Guardians et al. v. U.S. Bureau of Land Management, that the Bureau of Land Management must consider cumulative GHG impacts of oil and gas lease sales. Litigation is expected to challenge whether the Corps has adequately considered GHG for Section 404 permits.
Climate Change Litigation. Many state and local governments continue to file common law lawsuits against oil and gas companies seeking damages for climate change mitigation measures. The 9th and 4th Circuits have rejected arguments that federal law applies to these disputes and similar cases are pending in the 1st, 2nd, and 10th Circuits. Also, in v. Exxon, the District of Massachusetts ruled that a suit alleging Exxon violated state fraud statutes should be litigated in state court.
Precedent Agreements as Evidence of Market Need. In a 2019 case, City of Oberlin v. FERC, the D.C. Circuit held that FERC failed to adequately explain why it is lawful to consider a proposed pipeline’s precedent agreements with foreign shippers serving foreign customers as evidence of market need for the pipeline. FERC recently addressed City of Oberlin and explained why precedent agreements between a proposed pipeline and LNG terminal were lawfully credited as evidence of market need for the pipeline.
FERC’s Tolling Order Practice. In Allegheny Defense Project v. FERC, the D.C. Circuit granted en banc rehearing over whether FERC violated the Natural Gas Act (“NGA”) and landowners’ due process by issuing tolling orders to extend the time to consider rehearing requests of FERC’s pipeline approval, while allowing a pipeline to begin construction and exercise eminent domain. On June 9, FERC issued a final rule to preclude natural gas projects under sections 3 and 7 of the NGA from proceeding with construction until FERC issues a decision on the merits of any request for rehearing.
Pipeline Right-of-Ways (“ROWs”) through the Appalachian Trail. In February, the U.S. Supreme Court heard oral argument over a 4th Circuit ruling that the U.S. Forest Service lacks authority to grant a pipeline ROW across the Appalachian Trail. On June 15, the Supreme Court ruled 7-2 that the Forest Service had authority to issue the pipeline ROW through the Appalachian Trail.
FERC Authority over Pipeline Transportation Service Agreements (“TSAs”) in Bankruptcy. Several pipelines recently have filed petitions for declaratory orders, requesting FERC to declare it has concurrent jurisdiction with bankruptcy courts over natural gas pipeline TSAs and that FERC approval is required to in order to modify or reject such contracts in bankruptcy. We are continuing to follow this area for developments.
We invite you to read, watch, and share the below resources from our recent webinar for further details. Contact any of us if you have questions about the impact of recent cases, decisions, and regulations on your energy project(s).
Please click here for the presentation materials and here to listen to the recording.
On May 21, 2020, the Federal Energy Regulatory Commission (“FERC”) issued two orders addressing methodologies for analyzing the base return on equity (“ROE”) components of rates of FERC-regulated entities. In Opinion No. 569-A, FERC revised the methodology used under section 206 of the Federal Power Act (“FPA”) to evaluate the base ROEs of public utilities.1 In a separate Policy Statement, FERC clarified that the methodology established in Opinion No. 569-A applies, with certain exceptions, to natural gas and oil pipelines.2
To change a public utility’s rates, including ROE, in a complaint proceeding under section 206 of the FPA, FERC must (i) make a finding that an existing rate is unjust and unreasonable; and (ii) determine a just and reasonable rate.3
FERC’s recent order arose from two complaint proceedings challenging the base ROE of Midcontinent Independent System Operator, Inc. (“MISO”) transmission owners.4 In November 2019, FERC issued Opinion No. 569, establishing a revised methodology to determine whether the existing base ROE was unjust and unreasonable under the first prong of FPA section 206, and if so, to establish a new just and reasonable replacement ROE under the second prong.5
Among other things, Opinion No. 569 relied on the discounted cash flow model (“DCF”)6 and capital-asset pricing model (“CAPM”)7 in the first prong of its FPA section 206 analysis, and declined to use two other models—i.e., the Expected Earnings8 and Risk Premium9 models. FERC adopted the use of ranges of presumptively just and reasonable ROEs that would be based on the risk profile of a utility or group of utilities. FERC gave equal weight to the DCF and CAPM models to establish composite zones of reasonableness. Absent evidence to the contrary, an ROE within the zone of reasonableness would be presumptively just and reasonable while an ROE outside this range would be presumptively unjust and unreasonable. FERC also relied on the DCF and CAPM models (and declined to use the Expected Earnings and Risk Premium models) in the second prong of its section 206 analysis in order to establish a new just and reasonable ROE.10